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, 2017



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, 2017, there were 240,504,109 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended March 31, 2017

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, 2017 AND 2016	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE MONTHS ENDED MARCH 31, 2017 AND 2016	3

		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT MARCH 31, 2017 AND DECEMBER 31, 2016	4

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 2017 AND 2016	5

		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	6

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	21

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	35

	ITEM 4.	CONTROLS AND PROCEDURES	40

PART II. OTHER INFORMATION			40

	ITEM 1.	LEGAL PROCEEDINGS	40

	ITEM 1A.	RISK FACTORS	40

	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	41

	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	41

	ITEM 4.	MINE SAFETY DISCLOSURES	41

	ITEM 5.	OTHER INFORMATION	41

	ITEM 6.	EXHIBITS	41

SIGNATURES			43

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended
	March 31,
	2017			2016
REVENUES	(in millions, except per share amounts)
Oil sales	$	221.7		$	143.8
Gas sales	134.5			85.1
NGL sales	29.0			13.6
Other revenue	4.0			2.3
Purchased oil and gas sales	30.9			16.5
Total Revenues	420.1			261.3
OPERATING EXPENSES
Purchased oil and gas expense	29.4			16.9
Lease operating expense	69.2			60.0
Transportation and processing costs	70.2			73.6
Gathering and other expense	1.5			1.3
General and administrative	33.6			48.5
Production and property taxes	29.1			17.8
Depreciation, depletion and amortization	191.8			240.0
Exploration expenses	0.4			0.3
Impairment	0.1			1,182.4
Total Operating Expenses	425.3			1,640.8
Net gain (loss) from asset sales	—			0.5
OPERATING INCOME (LOSS)	(5.2		)	(1,379.0		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	160.9			50.9
Interest and other income (expense)	0.6			2.1
Interest expense	(33.8		)	(36.7		)
INCOME (LOSS) BEFORE INCOME TAXES	122.5			(1,362.7		)
Income tax (provision) benefit	(45.6		)	498.9
NET INCOME (LOSS)	$	76.9		$	(863.8	)

Earnings (loss) per common share
Basic	$	0.32		$	(4.55	)
Diluted	$	0.32		$	(4.55	)

Weighted-average common shares outstanding
Used in basic calculation	240.2			189.7
Used in diluted calculation	240.3			189.7
Dividends per common share	$	—		$	—

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended
	March 31,
	2017		2016
	(in millions)
Net income (loss)	$	76.9	$	(863.8	)
Other comprehensive income, net of tax:
Postretirement medical plan change⁽¹⁾	1.6		—
Pension and other postretirement plans adjustments:
Amortization of prior service costs⁽²⁾	0.1		0.1
Amortization of actuarial losses⁽³⁾	0.2		0.1
Other comprehensive income	1.9		0.2
Comprehensive income (loss)	$	78.8	$	(863.6	)

____________________________


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


⁽²⁾	Presented net of income tax expense of $0.1 million during the three months ended March 31, 2017 and 2016, respectively.


⁽³⁾	Presented net of income tax expense of $0.1 million for the three months ended March 31, 2017 and 2016, respectively.

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31, 2017			December 31, 2016
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	338.4		$	443.8
Accounts receivable, net	136.2			155.7
Income tax receivable	18.6			18.6
Hydrocarbon inventories, at lower of average cost or market	6.5			10.4
Prepaid expenses and other	12.9			11.6
Total Current Assets	512.6			640.1
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	14,492.6			14,232.5
Unproved properties	881.8			871.5
Gathering and other	307.1			301.8
Materials and supplies	33.1			32.7
Total Property, Plant and Equipment	15,714.6			15,438.5
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	8,980.4			8,797.7
Gathering and other	106.6			101.8
Total Accumulated Depreciation, Depletion and Amortization	9,087.0			8,899.5
Net Property, Plant and Equipment	6,627.6			6,539.0
Fair value of derivative contracts	21.1			—
Other noncurrent assets	73.7			66.3
TOTAL ASSETS	$	7,235.0		$	7,245.4
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	9.2		$	12.3
Accounts payable and accrued expenses	296.2			269.7
Production and property taxes	30.7			30.1
Interest payable	32.8			32.9
Fair value of derivative contracts	45.3			169.8
Total Current Liabilities	414.2			514.8
Long-term debt	2,022.4			2,020.9
Deferred income taxes	872.7			825.9
Asset retirement obligations	227.9			225.8
Fair value of derivative contracts	0.3			32.0
Other long-term liabilities	114.5			123.3
Commitments and contingencies (Note 9)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 242.2 million and 240.7 million shares issued, respectively	2.4			2.4
Treasury stock – 1.7 million and 1.1 million shares, respectively	(29.9		)	(22.9		)
Additional paid-in capital	1,375.1			1,366.6
Retained earnings	2,250.2			2,173.3
Accumulated other comprehensive income (loss)	(14.8		)	(16.7		)
Total Common Shareholders' Equity	3,583.0			3,502.7
TOTAL LIABILITIES AND EQUITY	$	7,235.0		$	7,245.4

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended
	March 31,
	2017			2016
OPERATING ACTIVITIES	(in millions)
Net income (loss)	$	76.9		$	(863.8	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	191.8			240.0
Deferred income taxes	45.6			(446.7		)
Impairment	0.1			1,182.4
Bargain purchase gain from acquisition	0.4			—
Share-based compensation	6.0			8.0
Amortization of debt issuance costs and discounts	1.5			1.6
Net (gain) loss from asset sales	—			(0.5		)
Unrealized (gains) losses on marketable securities	(0.8		)	(0.2		)
Unrealized (gains) losses on derivative contracts	(177.3		)	13.5
Changes in operating assets and liabilities	5.2			(52.6		)
Net Cash Provided by (Used in) Operating Activities	149.4			81.7
INVESTING ACTIVITIES
Property acquisitions	(68.2		)	(14.8		)
Property, plant and equipment, including dry exploratory well expense	(177.3		)	(185.8		)
Proceeds from disposition of assets	0.2			22.9
Net Cash Provided by (Used in) Investing Activities	(245.3		)	(177.7		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(3.1		)	(29.8		)
Treasury stock repurchases	(6.4		)	(2.9		)
Other capital contributions	—			0.2
Proceeds from issuance of common stock, net	—			368.6
Excess tax (provision) benefit on share-based compensation	—			0.2
Net Cash Provided by (Used in) Financing Activities	(9.5		)	336.3
Change in cash and cash equivalents	(105.4		)	240.3
Beginning cash and cash equivalents	443.8			376.1
Ending cash and cash equivalents	$	338.4		$	616.4

Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	32.3		$	37.8
Cash paid (refund received) for income taxes, net	$	—		$	32.0
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$	37.0		$	(22.6	)

See 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 focused in two regions of the United States: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the Southern Region (primarily in Texas and Louisiana). 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, 2016.

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, 2017, are not necessarily indicative of the results that may be expected for the year ending December 31, 2017.

Reclassifications

Certain prior period balances on the Condensed Consolidated Statement of Operations have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income, earnings per share, cash flows or retained earnings previously reported.

Impairment of Long-Lived Assets

During the three months ended March 31, 2016, QEP recorded impairment charges of $1,182.4 million, of which $1,167.9 million was related to proved properties due to lower future oil and gas prices, $10.8 million was related to expiring leaseholds on unproved properties and $3.7 million was related to an impairment of goodwill. Of the $1,167.9 million impairment on proved properties, $1,164.0 million related to Pinedale properties, $3.5 million related to Other Northern properties and $0.4 million related to QEP's Other Southern properties.

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 it 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 will be required. The amendment is 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 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 not yet selected a transition method and is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

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 after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-06, Derivatives and hedging (Topic 815): Contingent put and call options in debt instruments, which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Condensed Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment was effective prospectively for reporting periods beginning after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Condensed Consolidated Financial Statements.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the definition of a business, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of businesses. The amendment will be effective prospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In January 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment, which eliminates the requirement to calculate implied fair value of goodwill to measure the goodwill impairment charge. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Condensed Consolidated Financial Statements.

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which changes how employers of a defined benefit plan present net periodic benefit cost in the statement of operations. The amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Condensed Consolidated Financial Statements. See Note 11 – Employee Benefits for additional information regarding the Company's postretirement benefit plan.

Note 2 – Acquisitions and Divestitures

2016 Permian Basin Acquisition

In October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $591.0 million, subject to customary post-closing purchase price adjustments (the 2016 Permian Basin Acquisition). The 2016 Permian Basin Acquisition consists of approximately 9,600 net acres in Martin County, Texas, which are primarily held by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with cash on hand, which included proceeds from an equity offering in June 2016.

The 2016 Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it includes significant proved properties. QEP allocated the cost of the 2016 Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $4.7 million and net income of $1.1 million were generated from the acquired properties during the three months ended March 31, 2017, and are included in QEP's Condensed Consolidated Statements of Operations. In conjunction with the 2016 Permian Basin Acquisition, the Company recorded an $18.2 million bargain purchase gain in 2016. The acquisition resulted in a bargain purchase gain primarily as a result of an increase in future oil prices from the execution of the purchase and sale agreement to the closing date of the acquisition. During the three months ended March 31, 2017, the Company reduced the bargain purchase gain by $0.4 million due to purchase price adjustments. The bargain purchase gain is reported on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)".

The following table presents a summary of the Company's purchase accounting entries (in millions) as of March 31, 2017:



Consideration:
Total consideration	$	591.0

Amounts recognized for fair value of assets acquired and liabilities assumed:
Proved properties	$	406.2
Unproved properties	214.2
Asset retirement obligations	(11.6		)
Bargain purchase gain	(17.8		)
Total fair value	$	591.0

The following unaudited, pro forma results of operations are provided for the three months ended March 31, 2016. Pro forma results are not provided for the three months ended March 31, 2017, because the 2016 Permian Basin Acquisition occurred during the fourth quarter of 2016, and therefore the 2016 Permian Basin Acquisition results are included in QEP's results of operations for the three months ended March 31, 2017. These supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the periods presented, or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's condensed consolidated results of operations for the three months ended March 31, 2016, the acquired properties' historical results of operations and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the preliminary purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the 2016 Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.



	Three Months Ended March 31, 2016
	Actual			Pro forma
	(in millions, except per share amounts)
Revenues	$	261.3		$	265.9
Net income (loss)	$	(863.8	)	$	(864.6	)
Earnings (loss) per common share
Basic	$	(4.55	)	$	(4.56	)
Diluted	$	(4.55	)	$	(4.56	)

Other Acquisitions

During the three months ended March 31, 2017, QEP acquired various oil and gas properties, primarily proved and unproved leaseholds 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. The goodwill is reported on the Condensed Consolidated Balance Sheets within "Other noncurrent assets". During the three months ended March 31, 2016, QEP acquired various oil and gas properties, which primarily included additional interests in QEP's operated wells and the associated leasehold in the Permian and Williston basins, for an aggregate purchase price of $21.0 million. In conjunction with the acquisitions, the Company recorded $3.7 million of goodwill, all of which was subsequently impaired in 2016.

Divestitures

During the three months ended March 31, 2016, QEP received proceeds of $22.9 million and recorded a pre-tax gain on sale of $0.5 million, primarily related to the divestiture of certain non-core properties in the Other Southern area. These gains and losses are reported on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales".

Note 3 – Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income 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 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 per common share. During the three months ended March 31, 2017 and 2016, there were no anti-dilutive shares.

A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:



	Three Months Ended
	March 31,
	2017	2016
	(in millions)
Weighted-average basic common shares outstanding	240.2	189.7
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	240.3	189.7

Note 4 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are presented in the table below. The balance at March 31, 2017, represents the amount of capitalized exploratory well costs that are pending the determination of proved reserves.



	Capitalized Exploratory Well Costs
	2017
	(in millions)
Balance at January 1,	$	14.2
Additions to capitalized exploratory well costs pending the determination of proved reserves	3.6
Balance at March 31,	$	17.8

Capitalized exploratory well costs that have been capitalized for a period of one year or less	$	4.0
Capitalized exploratory well costs that have been capitalized for a period greater than one year	13.8
Total capitalized exploratory well costs	$	17.8

Number of projects with exploratory well costs that have been capitalized for a period greater than one year	1

Central Basin Platform exploration project. As of March 31, 2017, QEP had approximately $13.8 million of exploratory well costs older than one year, all of which related to the Central Basin Platform exploration project in the Permian Basin targeting the Woodford Formation. QEP completed one exploratory well related to this project in the first quarter of 2016 and is currently drilling a second exploratory well that is expected to be completed in the first half of 2017. In addition to the exploratory well costs, QEP has $27.7 million of unproved leasehold costs related to the Central Basin Platform exploration project as of March 31, 2017. QEP will continue to evaluate the performance of both wells to determine the ultimate economic feasibility of this exploration project.

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 $234.1 million and $231.6 million ARO liability for the periods ended March 31, 2017 and December 31, 2016, respectively, $6.2 million and $5.8 million, respectively, were included as a liability within "Accounts payable and accrued expenses" 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
	2017
	(in millions)
ARO liability at January 1,	$	231.6
Accretion	2.1
Additions	1.8
Revisions	0.2
Liabilities settled	(1.6		)
ARO liability at March 31,	$	234.1

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 (see 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, 2017 and December 31, 2016, 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, 2017
Financial Assets	(in millions)
Fair value of derivative contracts – short-term	$	—	$	7.6	$	—	$	(7.6	)	$	—
Fair value of derivative contracts – long-term	—		21.7		—		(0.6		)	21.1
Total financial assets	$	—	$	29.3	$	—	$	(8.2	)	$	21.1

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	52.9	$	—	$	(7.6	)	$	45.3
Fair value of derivative contracts – long-term	—		0.9		—		(0.6		)	0.3
Total financial liabilities	$	—	$	53.8	$	—	$	(8.2	)	$	45.6

	December 31, 2016
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	—	$	—	$	—		$	—
Fair value of derivative contracts – long-term	—		—		—		—			—
Total financial assets	$	—	$	—	$	—	$	—		$	—

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	169.8	$	—	$	—		$	169.8
Fair value of derivative contracts – long-term	—		32.0		—		—			32.0
Total financial liabilities	$	—	$	201.8	$	—	$	—		$	201.8

_______________________


⁽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. See 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, 2017				December 31, 2016
Financial Assets	(in millions)
Cash and cash equivalents	$	338.4	$	338.4	$	443.8	$	443.8
Financial Liabilities
Checks outstanding in excess of cash balances	$	9.2	$	9.2	$	12.3	$	12.3
Long-term debt	$	2,022.4	$	2,076.3	$	2,020.9	$	2,104.3

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 initial measurement of ARO at fair value is calculated using discounted cash flow techniques and 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 nonrecurring 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. During the three months ended March 31, 2017, the Company recorded no impairments on proved oil and gas properties. During the three months ended March 31, 2016, the Company recorded impairments on certain proved oil and gas properties of $1,167.9 million resulting in a reduction of the associated carrying value to fair value. The fair value of the property was 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.

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: estimated quantities of oil, gas and NGL reserves; estimates of future commodity prices; and 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. See Note 2 – Acquisitions and Divestitures for additional information on the fair value of acquired properties.

Note 7 – Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production, but generally, QEP enters into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. In addition, 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 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 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, 2017:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2017	NYMEX WTI	10.2	$	51.39
2018	NYMEX WTI	9.1	$	53.61
Gas sales		(MMBtu)	($/MMBtu)
2017	NYMEX HH	74.3	$	2.87
2017	IFNPCR	24.8	$	2.51
2018	NYMEX HH	87.6	$	2.98

The following table presents QEP's volumes and average prices for its commodity derivative gas collars as of March 31, 2017:

Year

Index

Total Volumes

Average Price Floor

Average Price Ceiling

(in millions)

(MMBtu)

($/MMBtu)

2017

NYMEX HH

8.3

2.50

3.50

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, 2017:



Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2017	NYMEX WTI	Argus WTI Midland	3.2	$	(0.66	)
2018	NYMEX WTI	Argus WTI Midland	3.7	$	(1.01	)
Gas sales			(MMBtu)	($/MMBtu)
2017	NYMEX HH	IFNPCR	38.5	$	(0.18	)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)

Derivative Contracts – Gas Storage

QEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table presents QEP’s volumes and average prices for its storage commodity derivative swap contracts as of March 31, 2017:



Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2017	SWAP	IFNPCR	2.2	$	2.71

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, 2017		December 31, 2016		March 31, 2017		December 31, 2016
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	7.6	$	—	$	52.9	$	169.8
Long-term:
Commodity	Fair value of derivative contracts	21.7		—		0.9		32.0
Total derivative instruments		$	29.3	$	—	$	53.8	$	201.8

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,
Derivative contracts not designated as cash flow hedges	2017			2016
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	(2.0	)	$	40.8
Gas derivative contracts	(14.2		)	21.5
Gas Storage
Gas derivative contracts	(0.2		)	2.1
Total realized gains (losses) on commodity derivative contracts	(16.4		)	64.4
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	104.3			(27.9		)
Gas derivative contracts	71.1			15.4
Gas Storage
Gas derivative contracts	1.9			(1.0		)
Total unrealized gains (losses) on commodity derivative contracts	177.3			(13.5		)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	160.9		$	50.9

Note 8 – Debt

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



	March 31, 2017			December 31, 2016
	(in millions)
Revolving Credit Facility due 2019	$	—		$	—
6.80% Senior Notes due 2018	134.0			134.0
6.80% Senior Notes due 2020	136.0			136.0
6.875% Senior Notes due 2021	625.0			625.0
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
Less: unamortized discount and unamortized debt issuance costs	(22.6		)	(24.1		)
Total long-term debt outstanding	$	2,022.4		$	2,020.9

Of the total debt outstanding on March 31, 2017, the 6.80% Senior Notes due April 1, 2018, the 6.80% Senior Notes due March 1, 2020 and the 6.875% Senior Notes due March 1, 2021, will mature within the next five years. In addition, the revolving credit facility matures on December 2, 2019.

Credit Facility

QEP’s revolving credit facility, which matures in December 2019, provides for loan commitments of $1.8 billion from a group of financial institutions. 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 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarters ending on and prior to December 31, 2017, and 3.75 times thereafter and (iii) during a ratings trigger period, a present value coverage ratio which requires that 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, 2018, and 1.50 times at any time on or after January 1, 2018. The Company is currently not subject to the present value coverage ratio. At March 31, 2017 and December 31, 2016, QEP was in compliance with the covenants under the credit agreement.

During the three months ended March 31, 2017 and 2016, QEP had no borrowings under the credit facility. For both March 31, 2017 and December 31, 2016, QEP had no borrowings outstanding under the credit facility and had $2.8 million in letters of credit outstanding under the credit facility.

Senior Notes

At March 31, 2017, the Company had $2,045.0 million principal amount of senior notes outstanding with maturities ranging from April 2018 to May 2023 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 9 – 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.

Claims of Former Limited Partners – The Company received a demand from certain former limited partners of terminated drilling partnerships of the Company (acting as the general partner). The former limited partners allege that distributions to which they were entitled from the drilling partnerships were not made or were calculated incorrectly. Other former limited partners may assert claims. No litigation has been filed, and the Company is in the process of evaluating the allegations and its defenses.

Department of Interior Investigation regarding Indian Royalties – Pursuant to regulations published by the Office of Natural Resources Revenue (ONRR) of the Department of the Interior (DOI), certain of the Company’s Indian leases are subject to “dual accounting” and “major portion” requirements. The Company must initially report royalties on production from these leases based upon its actual sales arrangements and, once ONRR publishes the major portion price (approximately 18 months after a calendar year), the Company must recalculate its previously reported royalties for the applicable calendar year and pay additional royalties if the dual accounting or major portion pricing results in higher royalties. In July 2016, the Company was notified that the Office of Inspector General of the DOI is conducting an investigation of the Company’s compliance with ONRR dual accounting and major portion requirements to recalculate royalties for 2013 on production from certain Indian leases. As the investigation continues, there may be penalties imposed.

EPA Request for Information – In July 2015, QEP received an information request from the Environmental Protection Agency (EPA) pursuant to Section 114(a) of the Clean Air Act. The information request sought facts and data about certain tank batteries in QEP’s Williston Basin operations. QEP timely responded to the information requests. In August 2016, the EPA requested a conference to review this matter. In addition, since February 2016, the North Dakota Department of Health (NDDH) has engaged with the oil and gas production industry in North Dakota to address potential noncompliance associated with emissions from tank batteries. QEP has participated in these discussions. While no formal federal or state enforcement action has been commenced in connection with the tank batteries to date, other operators have been assessed penalties following similar information requests. QEP anticipates that resolution of these matters will likely result in penalties and require QEP to incur additional capital expenditures to correct noncompliance issues.

To the extent that the Company can reasonably estimate losses for contingencies where the risk of a material loss (in excess of accruals, if any) is reasonably possible, the Company estimates such losses could total between zero and approximately $25.0 million.

Note 10 – 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 5.5 million shares available for future grants under the LTSIP at March 31, 2017.

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:



	Three Months Ended
	March 31,
	2017			2016
	(in millions)
Stock options	$	0.6		$	0.7
Restricted share awards	7.3			6.5
Performance share units	(1.9		)	0.8
Restricted share units	—			—
Total share-based compensation expense	$	6.0		$	8.0

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 calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below for the three months ended March 31, 2017:



	Stock Option Assumptions
Weighted-average grant date fair value of awards granted during the period	$	6.52
Weighted-average risk-free interest rate	1.81		%
Weighted-average expected price volatility	43.8		%
Expected dividend yield	—		%
Expected term in years at the date of grant	4.5

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, 2016	2,151,957		$	25.26
Granted	409,549		16.98
Canceled	(202,260	)	27.55
Outstanding at March 31, 2017	2,359,246		$	23.63	4.32	$	1.1
Options Exercisable at March 31, 2017	1,535,515		$	28.04	3.30	$	0.4
Unvested Options at March 31, 2017	823,731		$	15.42	6.22	$	0.7

During the three months ended March 31, 2017 and 2016, there were no exercises of stock options. As of March 31, 2017, $3.3 million of unrecognized compensation cost related to stock options granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheets, is expected to be recognized over a weighted-average period of 2.66 years.

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 total fair value of restricted share awards that vested during the three months ended March 31, 2017 and 2016 was $20.3 million and $20.4 million, respectively. The weighted-average grant date fair value of restricted share awards was $17.02 per share and $10.13 per share for the three months ended March 31, 2017 and 2016, respectively. As of March 31, 2017, $34.1 million of unrecognized compensation cost related to restricted share awards granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheets, is expected to be recognized over a weighted-average vesting period of 2.59 years.

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, 2016	3,208,503		$	14.32
Granted	1,443,185		17.02
Vested	(1,235,330	)	16.42
Forfeited	(41,240	)	14.78
Unvested balance at March 31, 2017	3,375,118		$	14.70

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 delivered 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, 2017, 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 $16.98 per share and $10.12 per share for the three months ended March 31, 2017 and 2016, respectively. As of March 31, 2017, $6.8 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.43 years.

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, 2016	1,027,280		$	17.24
Granted	401,480		16.98
Vested and Paid	(215,439	)	31.63
Unvested balance at March 31, 2017	1,213,321		$	14.60

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 delivered 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 $16.98 and $10.12 per share for the three months ended March 31, 2017 and 2016, respectively. As of March 31, 2017, $0.2 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 2.23 years.

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, 2016	18,034		$	10.12
Granted	9,924		16.98
Vested	(6,012	)	10.12
Unvested balance at March 31, 2017	21,946		$	13.22

Note 11 – 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).

During the three months ended March 31, 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 will no longer offer the Medical Plan to retirees and/or spouses that are Medicare eligible. The Company will no longer offer life insurance to anyone retiring on or after July 1, 2017.

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, 2017, the Company made contributions of $2.0 million to the Pension Plan and expects to contribute an additional $2.0 million to its Pension Plan during the remainder of 2017. 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, 2017, the Company made contributions of $1.5 million to its SERP and expects to contribute an additional $0.5 million to its SERP during the remainder of 2017. 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 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, 2017, the Company made contributions of $0.1 million to its Medical Plan and expects to contribute an additional $0.2 million to its Medical Plan during the remainder of 2017. Contributions to the Medical Plan are used to fund current benefit payments.

In accordance with the adoption of ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, the Company recognizes service costs related to SERP and Medical Plan benefits within "General and administrative" expense on the Condensed Consolidated Statements of Operations. All other expenses related to the Pension Plan, SERP and Medical Plan are recognized within "Interest and other income (expense)" on the Condensed Consolidated Statements of Operations.

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,
	2017			2016
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.3		$	0.2
Interest cost	1.2			1.2
Expected return on plan assets	(1.3		)	(1.4		)
Amortization of prior service costs⁽¹⁾	0.3			0.2
Amortization of actuarial losses⁽¹⁾	0.3			0.1
Periodic expense	$	0.8		$	0.3

Medical Plan benefits
Interest cost	$	—		$	0.1
Amortization of prior service costs⁽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 2016 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three months ended March 31, 2017 and 2016. 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 QEP's 2016 Annual Report on Form 10-K.

OVERVIEW

The Company has substantial acreage positions and operations in some of the most prolific hydrocarbon resource plays in the continental United States, including the Williston Basin, Permian Basin, Pinedale Anticline, Uinta Basin and Haynesville Shale. These resource plays are characterized by unconventional oil or gas accumulations in continuous tight sands, carbonates or shales that underlie broad geographic areas. The lateral continuity of such resource plays means that, aside from wells abandoned due to mechanical issues, the Company does not expect to drill many unsuccessful wells as it develops these resource plays. Resource plays allow the Company the opportunity to gain considerable operational efficiencies through high-density, repeatable drilling and completion operations. The Company believes it has a large inventory of lower-risk, predictable development drilling locations across its acreage holdings in the onshore U.S., which provide a solid base for organic growth in production and reserves.

While historically the Company has been more natural gas weighted, in recent years the Company has increased its focus on growing oil production and reserves. Since the beginning of 2012, the Company has made over $3.0 billion of acquisitions of oil-weighted properties and spent approximately 60% of its capital expenditures (excluding property acquisitions) on its oil-weighted properties. QEP's liquids revenue represented approximately 65% of total field-level revenues during the three months ended March 31, 2017 and 2016, respectively.

Outlook

Since the commodity price downturn in late 2014, the Company has reduced operating costs, capital investment and preserved its liquidity. We believe our strong balance sheet will allow us to grow oil production, primarily in the Permian Basin, and gas production during 2017, without the need to incur incremental indebtedness. We remain focused on continuing to grow our oil assets both organically and through acquisitions.

Based on current commodity prices, we expect to be able to fund our 2017 planned capital program with cash on hand and cash flow from operating activities. Our total capital expenditures, (excluding property acquisitions) for 2017 are expected to be approximately $975.0 million, an increase of approximately 80% from 2016 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 QEP believes its 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 its existing areas of operations to add additional acreage and facilitate the drilling of long lateral wells. QEP believes that its experience, expertise and presence in its core operating areas, combined with its low-cost operating model and financial strength, enhances its ability to pursue acquisition opportunities. The Company continuously evaluates potential acquisition, divestiture and joint venture opportunities that align with its strategic objectives. As part of this ongoing process, in April 2017, the Company engaged an advisor to assist with the potential divestiture of its Pinedale asset.

In October 2016, QEP acquired oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $591.0 million, subject to customary post-closing purchase price adjustments (the 2016 Permian Basin Acquisition). The 2016 Permian Basin Acquisition consists of approximately 9,600 net acres in Martin County, Texas, which are primarily held by production from existing vertical wells. The 2016 Permian Basin Acquisition was funded with proceeds from an equity offering in June 2016 and cash on hand.

During the three months ended March 31, 2017, QEP acquired various oil and gas properties, primarily proved and unproved leaseholds 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. During the three months ended March 31, 2016, QEP acquired various oil and gas properties, which primarily included additional interests in QEP's operated wells and associated leaseholds in the Permian and Williston basins, for an aggregate purchase price of $21.0 million. In conjunction with these acquisitions, the Company recorded $3.7 million of goodwill, all of which was subsequently impaired in 2016.

Financial and Operating Results

During the three months ended March 31, 2017, QEP:


•	Reported oil production of 4,682.7 Mbbls, including 1,001.7 Mbbls in the Permian Basin and 3,336.7 Mbbls in the Williston Basin;


•	Increased gas production over 2016 in the Haynesville/Cotton Valley by 34% to 12.2 Bcf due to a successful refracturing program;


•	Reported realized oil prices of $46.92 per bbl, a 32% increase over 2016;


•	Reported realized gas prices of $2.84 per Mcf, a 15% increase and realized NGL prices of $21.36 per bbl, a 114% increase over 2016;


•	Generated net income of $76.9 million, or $0.32 per diluted share;


•	Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $170.7 million, a 48% increase over 2016; and


•	Ended with $338.4 million in cash and cash equivalents and had no borrowings under its credit facility.

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, 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 and 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 volatile due to increased U.S. hydrocarbon production and insufficient domestic demand and export capacity. 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. In instances where QEP can make an election, QEP rejected ethane during the three months ended March 31, 2017, and will likely continue to reject ethane for the remainder of 2017.

Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the global economy, including Europe's economic outlook and the impact of the United Kingdom’s vote to exit the European Union; the Organization of Petroleum Exporting Countries (OPEC) countries oil production and policies regarding production quotas; upcoming elections in France; political unrest and economic issues in certain countries in South America, Asia, Europe, the Middle East, and Africa; slowing growth in certain emerging market economies; actions taken by the U.S. Congress and the president of the United States; the U.S. federal budget deficit; changes in regulatory oversight policy; commodity price volatility; 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 maintained a strong 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, 2017, QEP forecasted its 2017 annual production to be approximately 58.5 MMboe and had approximately 63% of its forecasted oil production and 73% 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 value of the Company's properties is sensitive to declines in oil, gas and NGL prices. These assets are at risk of impairment if future prices for oil, gas or NGL decline and/or drilling and completion costs increase. The cash flow model that the Company uses to assess proved properties for impairment includes numerous assumptions, such as management's estimates of future oil, gas and NGL production, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate.

During the three months ended March 31, 2016, the Company recorded impairments of $1,182.4 million, of which $1,167.9 million was related to proved properties due to lower future prices, primarily in Pinedale, $10.8 million was related to expiring leaseholds on unproved properties and $3.7 million was related to an impairment of goodwill.

Multi-Well Pad Drilling

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. 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 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.

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 9 – 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 2016 Annual Report on Form 10-K. The Company's Condensed Consolidated Financial Statements are prepared in accordance with GAAP. The preparation of the Company's Condensed Consolidated Financial Statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP's accounting policies on oil and gas reserves, successful efforts accounting for oil and gas operations, impairment of long-lived assets, asset retirement obligations, revenue recognition, litigation and other contingencies, 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 and Completion Activity

The following table presents operated and non-operated well completions for the three months ended March 31, 2017:



	Operated Completions		Non-operated Completions
	Gross	Net	Gross	Net
Northern Region
Williston Basin	15	12.8	5	0.1
Pinedale	—	—	—	—
Uinta Basin	—	—	—	—
Other Northern	—	—	—	—
Southern Region
Permian Basin	9	9.0	—	—
Haynesville/Cotton Valley	—	—	8	0.8
Other Southern	—	—	—	—

The following table presents operated and non-operated wells in the process of being drilled or waiting on completion at March 31, 2017:



		Operated				Non-operated
	Drilling Rigs	Drilling		Waiting on completion		Drilling		Waiting on completion
	Drilling Rigs	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin	1	3	2.0	6	5.0	—	—	12	0.3
Pinedale	1	1	0.2	15	7.5	—	—	—	—
Uinta Basin	—	—	—	—	—	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—	—
Southern Region
Permian Basin	5	8	8.0	16	15.7	—	—	—	—
Haynesville/Cotton Valley	—	—	—	—	—	—	—	5	0.5
Other Southern	—	—	—	—	—	—	—	—	—

The term "gross" refers to all wells or acreage in which QEP has at least a partial working interest and the term "net" refers to QEP's ownership represented by that working interest. Each gross well completed in more than one producing zone is counted as a single well. QEP typically utilizes multi-well pad drilling where practical. Wells drilled are not completed and brought into production until all wells on the pad are drilled and the drilling rig is moved from the location. QEP sometimes suspends completion activities due to adverse weather conditions, operational factors or other macroeconomic circumstances, such as low commodity prices. QEP had 37 gross operated wells waiting on completion as of March 31, 2017.

RESULTS OF OPERATIONS

Net Income

QEP generated net income during the first quarter of 2017 of $76.9 million, or $0.32 per diluted share, compared to a net loss of $863.8 million, or $4.55 per diluted share, in the first quarter of 2016. QEP's increased net income was primarily due to a decrease in impairment expense of $1,182.3 million, a 27% increase in average realized prices, a $190.8 million increase in unrealized derivative gains and a 31% decrease in general and administrative expenses. These changes were partially offset by a 5% decrease in oil equivalent production, a 63% increase in production and property tax expense and a 15% increase in lease operating expense in the first quarter of 2017 compared to the first quarter of 2016.

Adjusted EBITDA

Management defines Adjusted EBITDA 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,
	2017			2016
	(in millions)
Net income (loss)	$	76.9		$	(863.8	)
Interest expense	33.8			36.7
Interest and other (income) expense	(0.6		)	(2.1		)
Income tax provision (benefit)	45.6			(498.9		)
Depreciation, depletion and amortization	191.8			240.0
Unrealized (gains) losses on derivative contracts	(177.3		)	13.5
Exploration expenses	0.4			0.3
Net (gain) loss from asset sales	—			(0.5		)
Impairment	0.1			1,182.4
Other⁽¹⁾	—			7.7
Adjusted EBITDA	$	170.7		$	115.3

____________________________


⁽¹⁾	Reflects legal expenses incurred during the three months ended March 31, 2016. The Company believes that these amounts do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded these amounts from the calculation of Adjusted EBITDA.

Adjusted EBITDA increased to $170.7 million in the first quarter of 2017 from $115.3 million in the first quarter of 2016, primarily due to a 27% increase in the average realized prices and a 31% decrease in general and administrative expenses. These changes were partially offset by a 5% decrease in oil equivalent production, a 63% increase in production and property tax expense and a 15% increase in lease operating expense in the first quarter of 2017 compared to the first quarter of 2016.

Revenue

Revenue, Volume and Price Variance Analysis

The following table shows volume and price related changes for each of QEP’s production-related revenue categories for the three months ended March 31, 2017, compared to the three months ended March 31, 2016:



	Oil			Gas			NGL			Total
	(in millions)
Production revenues
Three months ended March 31, 2016	$	143.8		$	85.1		$	13.6		$	242.5
Changes associated with volumes⁽¹⁾	(13.8		)	(2.2		)	(0.1		)	(16.1		)
Changes associated with prices⁽²⁾	91.7			51.6			15.5			158.8
Three months ended March 31, 2017	$	221.7		$	134.5		$	29.0		$	385.2

____________________________


⁽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, 2017, as compared to the three months ended March 31, 2016, by the average field-level price for the three months ended March 31, 2016.

⁽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, 2017, as compared to the three months ended March 31, 2016, by the respective volumes for the three months ended March 31, 2017. 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,
	2017			2016		Change
Total production volumes (Mboe)
Northern Region
Williston Basin	4,834.0			4,892.6		(58.6		)
Pinedale	3,514.9			4,192.5		(677.6		)
Uinta Basin	968.3			1,223.6		(255.3		)
Other Northern	330.4			378.7		(48.3		)
Southern Region
Permian Basin	1,389.5			1,521.3		(131.8		)
Haynesville/Cotton Valley	2,046.7			1,523.2		523.5
Other Southern	6.5			44.6		(38.1		)
Total production	13,090.3			13,776.5		(686.2		)

Total equivalent prices (per Boe)
Average field-level equivalent price	$	29.43		$	17.60	$	11.83
Commodity derivative impact	(1.24		)	4.52		(5.76		)
Net realized equivalent price	$	28.19		$	22.12	$	6.07

Oil Volumes and Prices



	Three Months Ended March 31,
	2017			2016		Change
Oil production volumes (Mbbl)
Northern Region
Williston Basin	3,336.7			3,718.0		(381.3		)
Pinedale	143.0			176.3		(33.3		)
Uinta Basin	166.1			208.3		(42.2		)
Other Northern	26.9			36.4		(9.5		)
Southern Region
Permian Basin	1,001.7			1,019.4		(17.7		)
Haynesville/Cotton Valley	7.2			6.6		0.6
Other Southern	1.1			11.4		(10.3		)
Total production	4,682.7			5,176.4		(493.7		)
Oil prices (per bbl)
Northern Region	$	46.58		$	26.72	$	19.86
Southern Region	$	50.14		$	31.99	$	18.15

Average field-level price	$	47.35		$	27.77	$	19.58
Commodity derivative impact	(0.43		)	7.87		(8.30		)
Net realized price	$	46.92		$	35.64	$	11.28

Oil revenues increased $77.9 million, or 54%, in the first quarter of 2017 compared to the first quarter of 2016, due to higher average field-level prices, partially offset by lower volumes. Average field-level oil prices increased 71% in the first quarter of 2017 compared to the first quarter of 2016 primarily driven by an increase in average NYMEX-WTI oil prices for the comparable periods. The 10% decrease in production volumes was driven by the Williston, Permian and Uinta basins and in Pinedale due to reduced completion activity throughout 2016 and due to the majority of first quarter 2017 completions occurring near the end of the quarter.

Gas Volumes and Prices



	Three Months Ended March 31,
	2017			2016		Change
Gas production volumes (Bcf)
Northern Region
Williston Basin	4.0			3.2		0.8
Pinedale	18.5			21.7		(3.2		)
Uinta Basin	4.6			5.8		(1.2		)
Other Northern	1.8			2.0		(0.2		)
Southern Region
Permian Basin	1.2			1.4		(0.2		)
Haynesville/Cotton Valley	12.2			9.1		3.1
Other Southern	—			0.2		(0.2		)
Total production	42.3			43.4		(1.1		)
Gas prices (per Mcf)
Northern Region	$	3.22		$	1.98	$	1.24
Southern Region	$	3.09		$	1.91	$	1.18

Average field-level price	$	3.18		$	1.96	$	1.22
Commodity derivative impact	(0.34		)	0.50		(0.84		)
Net realized price	$	2.84		$	2.46	$	0.38

Gas revenues increased $49.4 million, or 58%, in the first quarter of 2017 compared to the first quarter of 2016, due to higher average field-level prices, partially offset by lower gas production. Average field-level gas prices increased 62% in the first quarter of 2017 compared to the first quarter of 2016, primarily driven by an increase in average NYMEX-HH gas prices for the comparable periods. The 3% decrease in production volumes was primarily driven by a production decrease in Pinedale and the Uinta Basin due to reduced completion activity throughout 2016 and in the first quarter of 2017. These decreases were partially offset by a production increase in Haynesville/Cotton Valley primary due to a well refracturing program throughout 2016 and continuing in 2017.

NGL Volumes and Prices



	Three Months Ended March 31,
	2017		2016		Change
NGL production volumes (Mbbl)
Northern Region
Williston Basin	823.2		639.5		183.7
Pinedale	292.5		402.0		(109.5		)
Uinta Basin	41.4		44.3		(2.9		)
Other Northern	4.3		3.7		0.6
Southern Region
Permian Basin	187.8		262.1		(74.3		)
Haynesville/Cotton Valley	6.0		8.4		(2.4		)
Other Southern	0.2		5.0		(4.8		)
Total production	1,355.4		1,365.0		(9.6		)
NGL prices (per bbl)
Northern Region	$	22.13	$	10.37	$	11.76
Southern Region	$	16.78	$	8.40	$	8.38

Average field-level price	$	21.36	$	9.97	$	11.39
Commodity derivative impact	—		—		—
Net realized price	$	21.36	$	9.97	$	11.39

NGL production volumes and revenues represent the sale of product derived from the processing of QEP's natural gas production. NGL revenues increased $15.4 million, or 113%, during the first quarter of 2017 compared to the first quarter of 2016, due to higher average field-level prices, partially offset by lower production volumes. NGL prices increased 114% during the first quarter of 2017 compared to the first quarter of 2016, primarily driven by increase in propane, ethane and butane prices. The 1% decrease in NGL production volumes was driven by decreases in Pinedale and the Permian Basin due to reduced completion activity throughout 2016 and due to the majority of first quarter 2017 Permian Basin completions occurring near the end of the quarter. The increase in the Williston Basin is due to additional gas and related NGLs recovered by midstream providers.

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,
	2017			2016			Change
	(in millions)
Purchased oil and gas sales	$	30.9		$	16.5		$	14.4
Purchased oil and gas expense	(29.4		)	(16.9		)	(12.5		)
Realized gains (losses) on gas storage derivative contracts	(0.2		)	2.1			(2.3		)
Resale margin	$	1.3		$	1.7		$	(0.4	)

Purchased oil and gas sales increased by $14.4 million, or 87%, during the first quarter of 2017 compared to first quarter of 2016, due to a $14.6 million increase in resale oil sales offset by a $0.2 million decrease in resale gas sales.

Purchased oil and gas expense, which includes transportation expense, increased $12.5 million, or 74%, during the first quarter of 2017 compared to the first quarter of 2016, due to a $14.3 million increase in resale oil purchases partially offset by a $1.8 million decrease in resale gas purchases.

Operating Expenses

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



	Three Months Ended March 31,
	2017		2016		Change
	(per Boe)
Lease operating expense	$	5.29	$	4.36	$	0.93
Transportation and processing costs	5.36		5.34		0.02
Production and property taxes	2.23		1.29		0.94
Total production costs	$	12.88	$	10.99	$	1.89

Lease operating expense (LOE). QEP’s LOE increased $9.2 million, or $0.93 per Boe, during the first quarter of 2017 compared to the first quarter of 2016. The increase was driven by an increase in workovers in the Williston and Permian basins and in Haynesville/Cotton Valley and increased fuel costs in the Permian Basin.

Transportation and processing costs. Transportation and processing costs decreased $3.4 million, but increased $0.02 per Boe, during the first quarter of 2017 compared to the first quarter of 2016. The decrease in expense was primarily attributable to Pinedale from lower volumes and the Permian Basin from lower volumes and rate, partially offset by the Williston Basin due to a higher rate.

Production and property taxes. In most states in which QEP operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Production and property taxes increased $11.3 million, or $0.94 per Boe, during the first quarter of 2017 compared to the first quarter of 2016, primarily as a result of increased oil and gas revenues from higher field-level prices partially offset by lower production.

Depreciation, depletion and amortization (DD&A). DD&A expense decreased $48.2 million in the first quarter of 2017 compared to the first quarter of 2016, due to decreased rates in Pinedale, Permian Basin and Haynesville/Cotton Valley. The Pinedale lower rate is a result of the 2016 impairment while the lower rates in the Permian Basin and Haynesville/Cotton Valley are a result of higher proved reserves at the end of 2016. DD&A expense also decreased in Pinedale and Permian and Uinta basins due to lower production.

Impairment expense. During the first quarter of 2017, QEP recorded impairment charges of $0.1 million for the first quarter of 2017, which was related to expiring leaseholds on unproved properties. During the first quarter of 2016, QEP recorded impairment charges of $1,182.4 million, of which $1,167.9 million was related to proved properties due to lower future prices, $10.8 million was related to expiring leaseholds on unproved properties and $3.7 million related to an impairment of goodwill. Of the $1,167.9 million impairment on proved properties, $1,164.0 million related to Pinedale properties, $3.5 million related to Other Northern properties and $0.4 million related to Other Southern properties.

General and administrative (G&A) expense. During the first quarter of 2017, G&A expense decreased $14.9 million, or 31%, compared to the first quarter of 2016, primarily due to a $8.1 million decrease in legal expenses, a $5.8 million decrease in share-based compensation from changes in the mark-to-market value of the Deferred Compensation Wrap Plan and Cash Incentive Plan (CIP) and a $0.8 million decrease in bad debt expense.

Net gain (loss) from asset sales. During the first quarter of 2016, QEP recognized a gain on the sale of assets of $0.5 million primarily related to continued divestitures of non-core Other Southern properties.

Non-operating Expenses

Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative contracts are comprised of both realized and unrealized gains and losses on QEP’s commodity derivative contracts, which are marked-to-market each quarter. During the 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. During the first quarter of 2016, gains on commodity derivative contracts were $50.9 million, of which $64.4 million were realized gains and $13.5 million were unrealized losses.

Interest expense. Interest expense decreased $2.9 million, or 8%, during the first quarter of 2017 compared to the first quarter of 2016. The decrease during the first quarter of 2017 was primarily related to the repayment of senior notes on September 1, 2016.

Income tax (provision) benefit. Income tax expense increased $544.5 million during the first quarter of 2017 compared to the first quarter of 2016. The increase in expense was the result of net income before income taxes compared to a net loss, partially offset by a higher combined effective federal and state income tax rate of 37.2% during the first quarter of 2017 compared to a rate of 36.6% during the first quarter of 2016. The increase in income tax rate was primarily the result of being subject to a higher state tax rate in 2017 due to a change in the composition of income between subsidiaries.

LIQUIDITY AND CAPITAL RESOURCES

QEP strives to maintain a strong liquidity position to ensure financial flexibility, withstand commodity price volatility and fund its development projects, operations and capital expenditures. 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, if needed, 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.

To provide additional liquidity, QEP also periodically accesses debt and equity markets and sells properties. In 2016, QEP issued 60.95 million shares of common stock through two public offerings and received net proceeds of approximately $781.4 million, which the Company used to fund the 2016 Permian Basin Acquisition and for general corporate purposes. QEP received aggregate proceeds of approximately $0.2 million and $22.9 million related to the sale of non-core properties during the three months ended March 31, 2017 and 2016, respectively.

The Company estimates, that with its cash balance as of March 31, 2017, it could incur additional indebtedness of approximately $1.1 billion and continue to 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

For both March 31, 2017 and December 31, 2016, QEP had no borrowings outstanding under the credit facility, had $2.8 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement. As of April 21, 2017, QEP had no borrowings outstanding under the credit facility, had $2.8 million of 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, 2017, totaled $2,045.0 million principal amount and are comprised of five issuances as follows:


•	$134.0 million 6.80% Senior Notes due April 2018;


•	$136.0 million 6.80% Senior Notes due March 2020;


•	$625.0 million 6.875% Senior Notes due March 2021;


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


•	$650.0 million 5.25% Senior Notes due May 2023.

Cash Flow from Operating Activities

Cash flows from operating activities are primarily affected by oil, 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,
	2017		2016			Change
	(in millions)
Net income (loss)	$	76.9	$	(863.8	)	$	940.7
Non-cash adjustments to net income (loss)	67.3		998.1			(930.8		)
Changes in operating assets and liabilities	5.2		(52.6		)	57.8
Net cash provided by (used in) operating activities	$	149.4	$	81.7		$	67.7

Net cash provided by operating activities was $149.4 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 $5.2 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 cash from operating assets and liabilities primarily resulted from a decrease in accounts receivable of $18.3 million partially offset by a decrease in accounts payable and accrued expenses of $9.8 million and a decrease in the ARO liability of $0.9 million.

Net cash provided by operating activities was $81.7 million during the first three months of 2016, which included an $863.8 million net loss, $998.1 million of non-cash adjustments to the net loss and a $52.6 million decrease in operating assets and liabilities. Non-cash adjustments to the net loss primarily included impairment expense of $1,182.4 million and DD&A expense of $240.0 million, partially offset by a decrease in deferred income taxes of $446.7 million. The decrease in operating assets and liabilities primarily included a decrease in accounts payable and accrued expenses of $119.6 million and an increase in income taxes receivable of $82.8 million, partially offset by a decrease in accounts receivable of $135.0 million.

Cash Flow from Investing Activities

A comparison of capital expenditures for the first three months of 2017 and 2016, are presented in the table below:



	Three Months Ended March 31,
	2017			2016		Change
	(in millions)
Property acquisitions	$	68.2		$	21.0	$	47.2
Property, plant and equipment capital expenditures	214.3			157.0		57.3
Total accrued capital expenditures	282.5			178.0		104.5
Change in accruals and other non-cash adjustments	(37.0		)	22.6		(59.6		)
Total cash capital expenditures	$	245.5		$	200.6	$	44.9

In the first three months of 2017, on an accrual basis, the Company invested $214.3 million on property, plant and equipment capital expenditures, excluding property acquisitions, an increase of $57.3 million compared to the first three months of 2016. In the first three months of 2017, QEP's primary capital expenditures were $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, in the first three months of 2017, QEP acquired various oil and gas properties, primarily proved and unproved leaseholds and additional surface acreage primarily in the Permian Basin, for an aggregate purchase price of $68.2 million.

In the first three months of 2016, on an accrual basis, the Company invested $157.0 million on property, plant and equipment capital expenditures, excluding property acquisitions, which included $83.7 million in the Williston Basin, $42.4 million in the Permian Basin, $10.6 million in the Uinta Basin, $9.6 million in Pinedale and $9.1 million in Haynesville/Cotton Valley. In addition, during the first three months of 2016, QEP acquired various oil and gas properties in the Williston and Permian basins, primarily to acquire additional interests in QEP's operated wells and the associated leasehold, for a total purchase price of $21.0 million, of which $14.8 million was cash and $6.2 million was non-cash related to the settlement of an accounts receivable balance.

The mid-point of our 2017 forecasted capital expenditures (excluding property acquisitions) is $975.0 million with the majority of the funds directed towards drilling and completion activity. Nearly 60% of our planned capital investment is allocated to the Permian Basin, and approximately $50.0 to $60.0 million of investment is budgeted for midstream infrastructure, primarily in the Permian Basin. Based on current commodity prices, QEP intends to fund its 2017 forecasted capital expenditures (excluding acquisitions) with cash flow from operating activities and cash on hand. The aggregate levels of capital expenditures for 2017 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 2017, net cash used in financing activities was $9.5 million compared to net cash provided by financing activities of $336.3 million in the first three months of 2016. During the first three months of 2017, QEP had a decrease in treasury stock repurchases of $6.4 million and a decrease in checks outstanding in excess of cash balances of $3.1 million. During the first three months of 2016, QEP had net proceeds from an equity offering in March 2016 of approximately $368.6 million and had a decrease in checks outstanding in excess of cash balances of $29.8 million.

As of March 31, 2017, the Company did not have any borrowings outstanding under the credit facility and had $2,045.0 million in senior notes outstanding (excluding $22.6 million of net original issue discount and unamortized debt issuance costs).

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 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, 2017, QEP held commodity price derivative contracts totaling 19.3 million barrels of oil, 195.0 million MMBtu of gas and 2.2 million MMBtu of gas storage.

The following tables present QEP's volumes and average prices for its derivative positions as of April 21, 2017. See 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, 2017.



Production Commodity Derivative Swaps
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2017	NYMEX WTI	10.7	$	51.50
2018	NYMEX WTI	9.9	$	53.59
Gas sales		(MMBtu)	($/MMBtu)
2017	NYMEX HH	66.2	$	2.87
2017	IFNPCR	22.1	$	2.51
2018	NYMEX HH	91.3	$	2.98

Production Commodity Derivative Gas Collars

Year

Index

Total Volumes

Average Price Floor

Average Price Ceiling

(in millions)

(MMBtu)

($/MMBtu)

2017

NYMEX HH

7.4

2.50

3.50



Production Commodity Derivative Basis Swaps
Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2017	NYMEX WTI	Argus WTI Midland	3.2	$	(0.66	)
2018	NYMEX WTI	Argus WTI Midland	3.7	$	(1.01	)
Gas sales			(MMBtu)	($/MMBtu)
2017	NYMEX HH	IFNPCR	34.3	$	(0.18	)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)



Gas Storage Commodity Derivative Swaps
Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2017	SWAP	IFNPCR	1.8	$	2.75

Changes in the fair value of derivative contracts from December 31, 2016 to March 31, 2017, are presented below:



	Commodity derivative contracts
	(in millions)
Net fair value of oil and gas derivative contracts outstanding at December 31, 2016	$	(201.8	)
Contracts settled	16.4
Change in oil and gas prices on futures markets	156.4
Contracts added	4.5
Net fair value of oil and gas derivative contracts outstanding at March 31, 2017	$	(24.5	)

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, 2017
	(in millions)
Net fair value – asset (liability)	$	(24.5	)
Fair value if market prices of oil, gas and basis differentials decline by 10%	$	(22.0	)
Fair value if market prices of oil, gas and basis differentials increase by 10%	$	(26.9	)

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $2.4 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $2.5 million as of March 31, 2017. 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, see 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 the Company’s Annual Report on Form 10-K for the year ended December 31, 2016. 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, 2017, the Company did not have any borrowings outstanding under its revolving credit facility.

The remaining $2,045.0 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, see Note 8 – 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:


•	our growth strategies;


•	strong liquidity position providing financial flexibility and the ability to grow production;


•	our liquidity and the sufficiency of our cash flows from operations and cash on hand to fund our operations and forecasted capital expenditures for 2017;


•	plans and ability to pursue acquisition opportunities;


•	our inventory of drilling locations;


•	drilling and completion plans and strategies;


•	results from planned drilling operations and production operations;


•	plans to increase oil and gas production;


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


•	future development costs;


•	ability to incur additional indebtedness under our revolving credit facility;


•	loss contingencies;


•	expectations regarding oil, gas and NGL prices;


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


•	pro forma results for acquired properties;


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


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


•	impact of global geopolitical and macroeconomic events;


•	plans to enter into derivative contracts and the anticipated benefits from our derivative contracts;


•	divestitures of assets;


•	need for capital expenditures to address air emission issues;


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


•	assumptions regarding equity compensation;


•	settlement of performance share units in cash;


•	recognition of compensation costs related to equity compensation grants;


•	expected contributions to our employee benefit plans;


•	changes to employee benefit plans;


•	the usefulness of Adjusted EBITDA (a non-GAAP financial measure) and adjustments made to net income to arrive at Adjusted EBITDA;


•	delays caused by multi-well pad drilling;


•	fair values and critical accounting estimates, including estimated asset retirement obligations;


•	implementation and impact of new accounting pronouncements;


•	impact of shutting in wells;


•	potential for asset impairments and impact of impairments on financial statements;


•	potential divestiture of Pinedale assets;


•	managing counterparty risk exposure; and


•	outcome and impact of various claims.

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 Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2016, and Part II, Item 1A of this Quarterly Reporting 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;


•	asset impairments;


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


•	drilling and completion strategies, methods and results;


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


•	shortages of oilfield equipment, services and personnel;


•	lack of available pipeline, processing and refining capacity;


•	processing volumes and pipeline throughput;


•	the risks and liabilities associated with acquired assets;


•	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 financial 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;


•	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;


•	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; 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) under the Securities Exchange Act of 1934, as amended, the Exchange Act) as of March 31, 2017. Based on such evaluation, such officers have concluded that, as of March 31, 2017, the Company’s disclosure controls and procedures are designed and effective to ensure that information required to be disclosed 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 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 Controls over Financial Reporting

There were no changes in the Company's internal controls over financial reporting that occurred during the quarter ended March 31, 2017, 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.

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, 2016. Below are material changes to such risk factors that have occurred during the three months ended March 31, 2017.

QEP may be unable to dispose of assets on financially attractive terms, resulting in reduced cash proceeds. QEP continually evaluates its portfolio of assets relative to capital investments, divestitures and joint venture opportunities. The success of such activity depends, in part, upon QEP’s ability to identify suitable buyers or joint venture partners; assess potential transaction terms; negotiate agreements; and, if applicable, obtain required approvals. Various factors could materially affect QEP's ability to dispose of assets on terms acceptable to QEP. Such factors include, but are not limited to, current commodity prices, laws, regulations and the permitting process impacting oil and gas operations in the areas where the assets are located, covenants under QEP's credit agreement, tax impacts, willingness of the purchaser to assume certain liabilities such as asset retirement obligations, QEP's willingness to indemnify buyers for certain matters, and other factors. Inability to achieve a desired price for assets, or underestimation of amounts of retained liabilities or indemnification obligations, can result in a reduction of cash proceeds, a loss on sale due to an excess of the asset's net book value over proceeds, or liabilities that must be settled in the future at amounts that are higher than QEP had expected.

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

The following repurchases of QEP shares were made by QEP in association with vested restricted share awards withheld for

taxes.



Period	Total shares purchased⁽¹⁾	Weighted-average price paid per share		Total shares purchased as part of publicly announced plans or programs	Remaining dollar amount that may be purchased under the plans or programs
January 1, 2017 - January 31, 2017	—	$	—	—	$	—
February 1, 2017 - February 28, 2017	1,462	$	16.85	—	$	—
March 1, 2017 - March 31, 2017	460,306	$	13.86	—	$	—

____________________________


⁽¹⁾	All of the 461,768 shares purchased during the three-month period ended March 31, 2017, were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting of restricted share grants.

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		Certificate of Incorporation dated May 18, 2010 (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 24, 2010)
3.2		Certificate of Elimination with respect to Series A Junior Participating Preferred Stock of QEP Resources, Inc. (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 16, 2012)
3.3		Amended and Restated Bylaws, effective December 15, 2016 (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 December 15, 2016)
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

____________________________


*	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 26, 2017	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer

April 26, 2017	/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, 2017 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	240,504,109
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017


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, 2017	Mar. 31, 2016
REVENUES
Oil sales	$ 221.7	$ 143.8
Gas sales	134.5	85.1
NGL sales	29.0	13.6
Other revenue	4.0	2.3
Purchased oil and gas sales	30.9	16.5
Total Revenues	420.1	261.3
OPERATING EXPENSES
Purchased oil and gas expense	29.4	16.9
Lease operating expense	69.2	60.0
Transportation and processing costs	70.2	73.6
Gathering and other expense	1.5	1.3
General and administrative	33.6	48.5
Production and property taxes	29.1	17.8
Depreciation, depletion and amortization	191.8	240.0
Exploration expenses	0.4	0.3
Impairment	0.1	1,182.4
Total operating expenses	425.3	1,640.8
Net gain (loss) from asset sales	0.0	0.5
OPERATING INCOME (LOSS)	(5.2)	(1,379.0)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	160.9	50.9
Interest and other income (expense)	0.6	2.1
Interest expense	(33.8)	(36.7)
INCOME (LOSS) BEFORE INCOME TAXES	122.5	(1,362.7)
Income tax (provision) benefit	(45.6)	498.9
NET INCOME (LOSS)	$ 76.9	$ (863.8)
Earnings per common share
Earnings Per Share, Basic	$ 0.32	$ (4.55)
Earnings Per Share, Diluted	$ 0.32	$ (4.55)
Weighted-average common shares outstanding
Used in basic calculation (in shares)	240.2	189.7
Used in diluted calculation (in shares)	240.3	189.7
Dividends per common share (in dollars per share)	$ 0.00	$ 0.00

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Postretirement medical plan changes, income tax expense	$ (1.0)	$ 0.0
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss, income tax expense	(0.1)	(0.1)
Amortization of prior service cost, income tax expense	$ (0.1)	$ (0.1)

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 338.4	$ 443.8
Accounts receivable, net	136.2	155.7
Income tax receivable	18.6	18.6
Hydrocarbon inventories, at lower of average cost or market	6.5	10.4
Prepaid expenses and other	12.9	11.6
Total Current Assets	512.6	640.1
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	14,492.6	14,232.5
Unproved properties	881.8	871.5
Gathering and other	307.1	301.8
Material and supplies	33.1	32.7
Total Property, Plant and Equipment	15,714.6	15,438.5
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	8,980.4	8,797.7
Gathering and other	106.6	101.8
Total Accumulated Depreciation, Depletion and Amortization	9,087.0	8,899.5
Net Property, Plant and Equipment	6,627.6	6,539.0
Fair value of derivative contracts	21.1	0.0
Other noncurrent assets	73.7	66.3
TOTAL ASSETS	7,235.0	7,245.4
Current Liabilities
Checks outstanding in excess of cash balances	9.2	12.3
Accounts payable and accrued expenses	296.2	269.7
Production and property taxes	30.7	30.1
Interest payable	32.8	32.9
Fair value of derivative contracts	45.3	169.8
Total Current Liabilities	414.2	514.8
Long-term debt	2,022.4	2,020.9
Deferred income taxes	872.7	825.9
Asset retirement obligations	227.9	225.8
Fair value of derivative contracts	0.3	32.0
Other long-term liabilities	114.5	123.3
Commitments and contingencies (Note 9)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 242.2 million and 240.7 million shares issued, respectively	2.4	2.4
Treasury stock – 1.7 million and 1.1 million shares, respectively	(29.9)	(22.9)
Additional paid-in capital	1,375.1	1,366.6
Retained earnings	2,250.2	2,173.3
Accumulated other comprehensive income (loss)	(14.8)	(16.7)
Total Shareholders' Equity	3,583.0	3,502.7
TOTAL LIABILITIES AND EQUITY	$ 7,235.0	$ 7,245.4

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares shares in Millions	Mar. 31, 2017	Dec. 31, 2016
EQUITY
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	500.0	500.0
Common stock, shares issued (in shares)	242.2	240.7
Treasury stock (in shares)	1.7	1.1

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
OPERATING ACTIVITIES
Net income (loss)	$ 76.9	$ (863.8)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	191.8	240.0
Deferred income taxes	45.6	(446.7)
Impairment	0.1	1,182.4
Bargain purchase gain from acquisition	0.4	0.0
Share-based compensation	6.0	8.0
Amortization of debt issuance costs and discounts	1.5	1.6
Net (gain) loss from asset sales	0.0	(0.5)
Unrealized (gains) losses on marketable securities	(0.8)	(0.2)
Unrealized (gains) losses on derivative contracts	(177.3)	13.5
Changes in operating assets and liabilities	5.2	(52.6)
Net Cash Provided by (Used in) Operating Activities	149.4	81.7
INVESTING ACTIVITIES
Property acquisitions	(68.2)	(14.8)
Property, plant and equipment, including dry exploratory well expense	(177.3)	(185.8)
Proceeds from disposition of assets	0.2	22.9
Net Cash Provided by (Used in) Investing Activities	(245.3)	(177.7)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(3.1)	(29.8)
Treasury stock repurchases	(6.4)	(2.9)
Other capital contributions	0.0	0.2
Proceeds from issuance of common stock, net	0.0	368.6
Excess tax (provision) benefit on share-based compensation	0.0	0.2
Net Cash Provided by (Used in) Financing Activities	(9.5)	336.3
Change in cash and cash equivalents	(105.4)	240.3
Beginning cash and cash equivalents	443.8	376.1
Ending cash and cash equivalents	338.4	616.4
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	32.3	37.8
Cash paid (refund received) for income taxes	0.0	32.0
Non-cash Investing Activities
Change in capital expenditure accruals and other non-cash adjustments	$ 37.0	$ (22.6)

Basis of Presentation	3 Months Ended
Basis of Presentation	Mar. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation [Text Block]	Nature of Business QEP Resources, Inc. is an independent crude oil and natural gas exploration and production company focused in two regions of the United States: the Northern Region (primarily in North Dakota, Wyoming and Utah) and the Southern Region (primarily in Texas and Louisiana). 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, 2016. 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, 2017, are not necessarily indicative of the results that may be expected for the year ending December 31, 2017. Reclassifications Certain prior period balances on the Condensed Consolidated Statement of Operations have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company's net income, earnings per share, cash flows or retained earnings previously reported. Impairment of Long-Lived Assets During the three months ended March 31, 2016, QEP recorded impairment charges of $1,182.4 million, of which $1,167.9 million was related to proved properties due to lower future oil and gas prices, $10.8 million was related to expiring leaseholds on unproved properties and $3.7 million was related to an impairment of goodwill. Of the $1,167.9 million impairment on proved properties, $1,164.0 million related to Pinedale properties, $3.5 million related to Other Northern properties and $0.4 million related to QEP's Other Southern properties. 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 it 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 will be required. The amendment is 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 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 not yet selected a transition method and is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements. 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 after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements. In March 2016, the FASB issued ASU No. 2016-06, Derivatives and hedging (Topic 815): Contingent put and call options in debt instruments, which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Condensed Consolidated Financial Statements. In March 2016, the FASB issued ASU No. 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to employee share-based payment accounting, which includes provisions intended to simplify various aspects related to how share-based compensation payments are accounted for and presented in the financial statements. This amendment was effective prospectively for reporting periods beginning after December 15, 2016, and early adoption was permitted. The Company adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Condensed Consolidated Financial Statements. In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the definition of a business, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of businesses. The amendment will be effective prospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements. In January 2017, the FASB issued ASU No. 2017-04, Intangibles – Goodwill and Other (Topic 350): Simplifying the test for goodwill impairment, which eliminates the requirement to calculate implied fair value of goodwill to measure the goodwill impairment charge. The amendment will be effective prospectively for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Condensed Consolidated Financial Statements. In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the presentation of net periodic pension cost and net periodic postretirement benefit cost, which changes how employers of a defined benefit plan present net periodic benefit cost in the statement of operations. The amendment will be effective retrospectively for reporting periods beginning after December 15, 2017, and early adoption is permitted. The Company early adopted this standard in the first quarter of 2017 and the adoption of this new standard did not have a material impact on the Company's Condensed Consolidated Financial Statements. See Note 11 – Employee Benefits for additional information regarding the Company's postretirement benefit plan.

Commitment and Contingencies	3 Months Ended
Commitment and Contingencies	Mar. 31, 2017
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. Claims of Former Limited Partners – The Company received a demand from certain former limited partners of terminated drilling partnerships of the Company (acting as the general partner). The former limited partners allege that distributions to which they were entitled from the drilling partnerships were not made or were calculated incorrectly. Other former limited partners may assert claims. No litigation has been filed, and the Company is in the process of evaluating the allegations and its defenses. Department of Interior Investigation regarding Indian Royalties – Pursuant to regulations published by the Office of Natural Resources Revenue (ONRR) of the Department of the Interior (DOI), certain of the Company’s Indian leases are subject to “dual accounting” and “major portion” requirements. The Company must initially report royalties on production from these leases based upon its actual sales arrangements and, once ONRR publishes the major portion price (approximately 18 months after a calendar year), the Company must recalculate its previously reported royalties for the applicable calendar year and pay additional royalties if the dual accounting or major portion pricing results in higher royalties. In July 2016, the Company was notified that the Office of Inspector General of the DOI is conducting an investigation of the Company’s compliance with ONRR dual accounting and major portion requirements to recalculate royalties for 2013 on production from certain Indian leases. As the investigation continues, there may be penalties imposed. EPA Request for Information – In July 2015, QEP received an information request from the Environmental Protection Agency (EPA) pursuant to Section 114(a) of the Clean Air Act. The information request sought facts and data about certain tank batteries in QEP’s Williston Basin operations. QEP timely responded to the information requests. In August 2016, the EPA requested a conference to review this matter. In addition, since February 2016, the North Dakota Department of Health (NDDH) has engaged with the oil and gas production industry in North Dakota to address potential noncompliance associated with emissions from tank batteries. QEP has participated in these discussions. While no formal federal or state enforcement action has been commenced in connection with the tank batteries to date, other operators have been assessed penalties following similar information requests. QEP anticipates that resolution of these matters will likely result in penalties and require QEP to incur additional capital expenditures to correct noncompliance issues. To the extent that the Company can reasonably estimate losses for contingencies where the risk of a material loss (in excess of accruals, if any) is reasonably possible, the Company estimates such losses could total between zero and approximately $25.0 million.

Basis of Presentation Impairment of Long-Lived Assets (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment	$ 0.1	$ 1,182.4
Goodwill, Acquired During Period	$ 5.3	3.7
Proved Property [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		1,167.9
Unproved Property [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		10.8
Pinedale [Member] \| Proved Property [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		1,164.0
Other Northern [Member] \| Proved Property [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		3.5
Other Southern [Member] \| Proved Property [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Oil and Gas Properties		0.4
Williston & Permian Basins [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Goodwill, Acquired During Period		$ 3.7

Acquisitions & Divestitures (Narrative) (Details) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017 USD ($) a	Mar. 31, 2016 USD ($)	Dec. 31, 2016 USD ($)
Business Combinations [Abstract]
Proceeds from Sale of Oil and Gas Property and Equipment	$ 0.2	$ 22.9
Net gain (loss) from asset sales	0.0	0.5
Business Acquisition [Line Items]
Acquisition Costs, Period Cost	68.2	21.0
Bargain purchase gain from acquisition	(0.4)	0.0
Goodwill, Acquired During Period	5.3	3.7
Williston & Permian Basins [Member]
Business Acquisition [Line Items]
Goodwill, Acquired During Period		$ 3.7
2016 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Revenue of Acquiree since Acquisition Date, Actual	4.7
Earnings or Loss of Acquiree since Acquisition Date, Actual	1.1
Payments to Acquire Businesses, Gross	$ 591.0
Gas and Oil Area, Developed, Net \| a	9,600
Bargain purchase gain from acquisition	$ 0.4		$ (18.2)

Acquisitions & Divestitures Purchase Accounting Entries (Details) - 2016 Permian Basin Acquisition [Member] $ in Millions	3 Months Ended
	Mar. 31, 2017 USD ($)
Business Combination, Separately Recognized Transactions [Line Items]
Payments to Acquire Businesses, Gross	$ 591.0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	591.0
Proved Property [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	406.2
Unproved Property [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	214.2
Asset Retirement Obligation Costs [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	(11.6)
Bargain Purchase Gain [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ (17.8)

Acquisitions & Divestitures Pro Forma (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Net income (loss)	$ 76.9	$ (863.8)
Earnings Per Share, Basic	$ 0.32	$ (4.55)
Earnings Per Share, Diluted	$ 0.32	$ (4.55)
Revenues	$ 420.1	$ 261.3
2016 Permian Basin Acquisition [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Net income (loss)		$ (863.8)
Earnings Per Share, Basic		$ (4.55)
Earnings Per Share, Diluted		$ (4.55)
Pro Forma Revenue		$ 265.9
Pro Forma Net Income (Loss)		$ (864.6)
Pro Forma Earnings Per Share, Basic		$ (4.56)
Pro Forma Earnings Per Share, Diluted		$ (4.56)
Revenues		$ 261.3

Earnings Per Share Components of Basic and Diluted Shares Used In EPS Calculation (Details) - shares shares in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Earnings Per Share [Abstract]
Weighted-average basic common shares outstanding	240.2	189.7
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	0.1	0.0
Average diluted common shares outstanding	240.3	189.7

Capitalized Exploratory Well Costs (Details) $ in Millions	3 Months Ended
Capitalized Exploratory Well Costs (Details) $ in Millions	Mar. 31, 2017 USD ($)
Capitalized Exploratory Well Costs [Abstract]
Capitalized exploratory well costs, beginning balance	$ 14.2
Additions to capitalized exploratory well costs pending the determination of proved reserves	3.6
Capitalized exploratory well costs, ending balance	17.8
Capitalized exploratory well costs that have been capitalized for a period of one year or less	4.0
Capitalized exploratory well costs that have been capitalized for a period greater than one year	$ 13.8
Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	1
Project with exploratory well costs capitalized for more than one year, unproved leasehold costs	27.7

Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation, Current	$ 6.2	$ 5.8
ARO Liability [Roll Forward]
ARO liability, Beginning Balance	231.6
Accretion	2.1
Additions	1.8
Revisions	0.2
Liabilities settled	(1.6)
ARO liability, Ending Balance	$ 234.1

Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	$ 338.4	$ 443.8
Checks outstanding in excess of cash balances	9.2	12.3
Long-term debt	2,022.4	2,020.9
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	338.4	443.8
Checks outstanding in excess of cash balances	9.2	12.3
Long-term debt, fair value	$ 2,076.3	$ 2,104.3

Derivative Contracts (Narrative) (Details)	3 Months Ended
Derivative Contracts (Narrative) (Details)	Mar. 31, 2017
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, 2017 USD ($) MMBTU $ / MMBTU
Oil Basis Swaps [Member] \| Production [Member] \| Year 2017 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	3.2
Weighted-Average Differential \| $ / MMBTU	(0.66)
Oil Basis Swaps [Member] \| Production [Member] \| Year 2018 [Member] \| NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	3.7
Weighted-Average Differential \| $ / MMBTU	(1.01)
Gas Swaps [Member] \| Production [Member] \| Year 2017 [Member] \| NYMEX HH [Member]
Derivative [Line Items]
Derivative Volumes	74.3
Average Swap Price per Unit \| $	$ 2.87
Gas Swaps [Member] \| Production [Member] \| Year 2017 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative Volumes	24.8
Average Swap Price per Unit \| $	$ 2.51
Gas Swaps [Member] \| Production [Member] \| Year 2018 [Member] \| NYMEX HH [Member]
Derivative [Line Items]
Derivative Volumes	87.6
Average Swap Price per Unit \| $	$ 2.98
Gas Swaps [Member] \| Storage [Member] \| Year 2017 [Member] \| IFNPCR [Member]
Derivative [Line Items]
Derivative Volumes	2.2
Average Swap Price per Unit \| $	$ 2.71
Oil Swaps [Member] \| Production [Member] \| Year 2017 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	10.2
Average Swap Price per Unit \| $	$ 51.39
Oil Swaps [Member] \| Production [Member] \| Year 2018 [Member] \| NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	9.1
Average Swap Price per Unit \| $	$ 53.61
Gas Collars [Member] \| Production [Member] \| Year 2017 [Member] \| NYMEX HH [Member]
Derivative [Line Items]
Derivative Volumes	8.3
Derivative Average Price Floor \| $	$ 2.50
Derivative Average Price Ceiling \| $	$ 3.50
Gas Basis Swaps [Member] \| Production [Member] \| Year 2017 [Member] \| NYMEX HH LESS IFNPCR [Member]
Derivative [Line Items]
Derivative Volumes	38.5
Weighted-Average Differential \| $ / MMBTU	(0.18)
Gas Basis Swaps [Member] \| Production [Member] \| Year 2018 [Member] \| NYMEX HH LESS IFNPCR [Member]
Derivative [Line Items]
Derivative Volumes	7.3
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, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 29.3	$ 0.0
Derivative Liability, Fair Value, Gross	53.8	201.8
Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	7.6	0.0
Derivative Liability, Fair Value, Gross	52.9	169.8
Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	21.7	0.0
Derivative Liability, Fair Value, Gross	0.9	32.0
Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	29.3	0.0
Derivative Liability, Fair Value, Gross	53.8	201.8
Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member] \| Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	7.6	0.0
Derivative Liability, Fair Value, Gross	52.9	169.8
Fair Value, Measurements, Recurring [Member] \| Commodity Contract [Member] \| Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	21.7	0.0
Derivative Liability, Fair Value, Gross	$ 0.9	$ 32.0

Debt (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended
Debt (Narrative) (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Debt Maturity Period	5 years
Principal amount of senior notes outstanding	$ 2,045.0
Debt Instrument, Maturity Date Range, Start	Apr. 01, 2018
Debt Instrument, Maturity Date Range, End	May 01, 2023
Senior Notes, stated interest rate, minimum (in hundredths)	5.25%
Senior Notes, stated interest rate, maximim (in hundredths)	6.875%
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0.0	$ 0.0
Maturity date of long-term debt	Dec. 02, 2019
Borrowing capacity	$ 1,800.0
Letters of credit outstanding	2.8
6.80% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 134.0	134.0
Long-term debt, interest rate (in hundredths)	6.80%
Maturity date of long-term debt	Apr. 01, 2018
6.80% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 136.0	136.0
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	$ 625.0	$ 625.0
Long-term debt, interest rate (in hundredths)	6.875%
Maturity date of long-term debt	Mar. 01, 2021