10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 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 September 30, 2017, there were 240,935,039 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended September 30, 2017

TABLE OF CONTENTS

			Page
PART I. FINANCIAL INFORMATION			2
	ITEM 1.	FINANCIAL STATEMENTS	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2017 AND 2016	3
		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT SEPTEMBER 30, 2017 AND DECEMBER 31, 2016	4
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 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	24
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	42
	ITEM 4.	CONTROLS AND PROCEDURES	47
PART II. OTHER INFORMATION			47
	ITEM 1.	LEGAL PROCEEDINGS	47
	ITEM 1A.	RISK FACTORS	47
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	52
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	52
	ITEM 4.	MINE SAFETY DISCLOSURES	52
	ITEM 5.	OTHER INFORMATION	52
	ITEM 6.	EXHIBITS	52
SIGNATURES			54

1

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
REVENUES	(in millions, except per share amounts)
Oil sales	$	218.0		$	201.6		$	655.7		$	553.1
Gas sales	130.7			123.2			399.4			287.5
NGL sales	32.2			19.8			84.0			56.2
Other revenue	3.6			2.5			10.3			4.3
Purchased oil and gas sales	5.6			35.3			44.5			76.3
Total Revenues	390.1			382.4			1,193.9			977.4
OPERATING EXPENSES
Purchased oil and gas expense	6.9			37.1			45.4			80.8
Lease operating expense	76.2			50.7			215.4			163.3
Transportation and processing costs	60.2			75.8			202.6			218.9
Gathering and other expense	1.7			0.9			5.0			3.8
General and administrative	43.4			66.5			108.3			157.9
Production and property taxes	28.5			26.8			86.1			65.3
Depreciation, depletion and amortization	176.9			217.8			560.2			667.5
Exploration expenses	21.3			0.2			21.7			0.9
Impairment	28.3			5.0			28.4			1,188.2
Total Operating Expenses	443.4			480.8			1,273.1			2,546.6
Net gain (loss) from asset sales	185.4			5.3			205.2			5.0
OPERATING INCOME (LOSS)	132.1			(93.1		)	126.0			(1,564.2		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(104.3		)	44.5			163.3			(85.1		)
Interest and other income	0.1			4.6			2.5			5.6
Interest expense	(34.4		)	(35.9		)	(103.1		)	(109.2		)
INCOME (LOSS) BEFORE INCOME TAXES	(6.5		)	(79.9		)	188.7			(1,752.9		)
Income tax (provision) benefit	3.2			29.0			(69.7		)	641.2
NET INCOME (LOSS)	$	(3.3	)	$	(50.9	)	$	119.0		$	(1,111.7	)
Earnings (loss) per common share
Basic	$	(0.01	)	$	(0.21	)	$	0.49		$	(5.15	)
Diluted	$	(0.01	)	$	(0.21	)	$	0.49		$	(5.15	)
Weighted-average common shares outstanding
Used in basic calculation	240.7			239.6			240.5			215.7
Used in diluted calculation	240.7			239.6			240.5			215.7
Dividends per common share	$	—		$	—		$	—		$	—

See Notes accompanying the Condensed Consolidated Financial Statements.

2

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017		2016
	(in millions)
Net income (loss)	$	(3.3	)	$	(50.9	)	$	119.0	$	(1,111.7	)
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			0.2			0.4		0.6
Amortization of actuarial losses(3)	0.1			0.2			0.2		0.4
Other comprehensive income	0.2			0.4			2.2		1.0
Comprehensive income (loss)	$	(3.1	)	$	(50.5	)	$	121.2	$	(1,110.7	)

____________________________

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

⁽²⁾  Presented net of income tax expense of $0.1 million and $0.3 million during the three and nine months endedSeptember 30, 2017, respectively. Presented net of income tax expense of $0.1 million and $0.4 million during the three and nine months endedSeptember 30, 2016, respectively.

⁽³⁾  Presented net of income tax expense of $0.1 million during the nine months endedSeptember 30, 2017. Presented net of income tax expense of $0.1 million and $0.2 million during the three and nine months endedSeptember 30, 2016, respectively.

See Notes accompanying the Condensed Consolidated Financial Statements.

3

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2017			December 31, 2016
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	782.6		$	443.8
Accounts receivable, net	120.4			155.7
Income tax receivable	17.9			18.6
Fair value of derivative contracts	3.8			—
Hydrocarbon inventories, at lower of average cost or net realizable value	6.1			10.4
Prepaid expenses and other	10.2			11.6
Total Current Assets	941.0			640.1
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	11,847.2			14,232.5
Unproved properties	703.6			871.5
Gathering and other	311.0			301.8
Materials and supplies	34.6			32.7
Total Property, Plant and Equipment	12,896.4			15,438.5
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,492.3			8,797.7
Gathering and other	111.9			101.8
Total Accumulated Depreciation, Depletion and Amortization	6,604.2			8,899.5
Net Property, Plant and Equipment	6,292.2			6,539.0
Fair value of derivative contracts	1.7			—
Other noncurrent assets	112.5			66.3
TOTAL ASSETS	$	7,347.4		$	7,245.4
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	—		$	12.3
Accounts payable and accrued expenses	388.6			269.7
Production and property taxes	37.4			30.1
Interest payable	32.8			32.9
Fair value of derivative contracts	13.4			169.8
Current portion of long-term debt	134.0			—
Total Current Liabilities	606.2			514.8
Long-term debt	1,890.6			2,020.9
Deferred income taxes	895.7			825.9
Asset retirement obligations	189.3			225.8
Fair value of derivative contracts	2.4			32.0
Other long-term liabilities	125.7			123.3
Commitments and contingencies (Note 9)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized;  242.8 million and 240.7 million shares issued, respectively	2.4			2.4
Treasury stock – 1.9 million and 1.1 million shares, respectively	(33.2		)	(22.9		)
Additional paid-in capital	1,390.5			1,366.6
Retained earnings	2,292.3			2,173.3
Accumulated other comprehensive income (loss)	(14.5		)	(16.7		)
Total Common Shareholders' Equity	3,637.5			3,502.7
TOTAL LIABILITIES AND EQUITY	$	7,347.4		$	7,245.4

See Notes accompanying the Condensed Consolidated Financial Statements.

4

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
	2017			2016
OPERATING ACTIVITIES	(in millions)
Net income (loss)	$	119.0		$	(1,111.7	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	560.2			667.5
Deferred income taxes	68.5			(581.1		)
Impairment	28.4			1,188.2
Bargain purchase gain from acquisition	0.4			(4.4		)
Other non-cash activity	(9.4		)	—
Dry hole exploratory well expense	21.2			—
Share-based compensation	13.5			29.0
Amortization of debt issuance costs and discounts	4.8			4.8
Net (gain) loss from asset sales	(205.2		)	(5.0		)
Unrealized (gains) losses on marketable securities	(2.1		)	(1.2		)
Unrealized (gains) losses on derivative contracts	(161.6		)	218.6
Changes in operating assets and liabilities	44.1			128.2
Net Cash Provided by (Used in) Operating Activities	481.8			532.9
INVESTING ACTIVITIES
Property acquisitions	(94.5		)	(39.9		)
Acquisition deposit held in escrow	(36.6		)	(30.0		)
Property, plant and equipment, including exploratory well expense	(779.6		)	(411.2		)
Proceeds from disposition of assets	787.9			28.9
Net Cash Provided by (Used in) Investing Activities	(122.8		)	(452.2		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(12.3		)	(25.5		)
Repayment of senior notes	—			(176.8		)
Long-term debt issuance costs paid	(1.1		)	—
Proceeds from credit facility	2.0			—
Repayments of credit facility	(2.0		)	—
Treasury stock repurchases	(6.8		)	(4.1		)
Proceeds from issuance of common stock, net	—			781.6
Excess tax (provision) benefit on share-based compensation	—			0.2
Net Cash Provided by (Used in) Financing Activities	(20.2		)	575.4
Change in cash and cash equivalents	338.8			656.1
Beginning cash and cash equivalents	443.8			376.1
Ending cash and cash equivalents	$	782.6		$	1,032.2
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	96.6		$	107.0
Cash paid (refund received) for income taxes, net	$	0.5		$	(123.3	)
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$	68.0		$	(20.4	)

See Notes accompanying the Condensed Consolidated Financial Statements.

5

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 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 and nine months endedSeptember 30, 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 nine months endedSeptember 30, 2017, QEP recorded impairment charges of $28.4 million, which was primarily related to unproved leasehold acreage in the Central Basin Platform. Refer to Note 4 – Capitalized Exploratory Well Costs for more information.

During the nine months endedSeptember 30, 2016, QEP recorded impairment charges of $1,188.2 million, of which $1,167.9 million was related to proved properties due to lower future oil and gas prices, $16.6 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 Other Southern properties.

Income Taxes

During the three months endedSeptember 30, 2017, QEP’s combined effective federal and state income tax rate was 49.2%. The effective rate is higher than the combined federal and state statutory rate primarily due to a year-to-date adjustment to the tax provision for a permanent adjustment related to marginal well tax credits as well as a change in income between states.

6

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 15, 2017, and early adoption is permitted for periods beginning on or after December 15, 2016. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The Company does not expect net income (loss) or cash flows to be materially impacted by the new standard, however, the Company is currently analyzing whether changes to total revenues and total expenses will be necessary to properly reflect revenue for certain pipeline gathering, transportation and gas processing agreements. The Company continues to evaluate the expected disclosure requirements, changes to relevant business practices, accounting policies and control activities as a result of the adoption of the ASU and has not yet developed estimates of the quantitative impact to the Company's Condensed Consolidated Financial Statements. The Company has selected the modified retrospective method and will adopt this guidance on the effective date of January 1, 2018.

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 disclose 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 was effective prospectively for reporting periods beginning on or 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 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 pension and other postretirement plans.

7

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 consisted 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 $18.8 million and $38.6 million and net income of $3.5 million and $5.4 million were generated from the acquired properties during the three and nine months endedSeptember 30, 2017, respectively, 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 nine months endedSeptember 30, 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 September 30, 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 and nine months endedSeptember 30, 2016. Pro forma results are not provided for the three and nine months endedSeptember 30, 2017, because the 2016 Permian Basin Acquisition occurred during the fourth quarter of 2016, and therefore, the results are included in QEP's results of operations for the three and nine months endedSeptember 30, 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 and nine months endedSeptember 30, 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 and quantifying 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.

8

	Three Months Ended						Nine Months Ended
	September 30, 2016						September 30, 2016
	Actual			Pro forma			Actual			Pro forma
	(in millions, except per share amounts)
Revenues	$	382.4		$	387.3		$	977.4		$	991.9
Net income (loss)	$	(50.9	)	$	(51.3	)	$	(1,111.7	)	$	(1,113.4	)
Earnings (loss) per common share
Basic	$	(0.21	)	$	(0.21	)	$	(5.15	)	$	(5.16	)
Diluted	$	(0.21	)	$	(0.21	)	$	(5.15	)	$	(5.16	)

Other Acquisitions

During the nine months endedSeptember 30, 2017, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill. The goodwill is reported on the Condensed Consolidated Balance Sheets within "Other noncurrent assets".

During the nine months endedSeptember 30, 2016, QEP acquired various oil and gas properties, which primarily included additional interests in QEP's operated wells and additional undeveloped leasehold acreage in the Permian and Williston basins, for an aggregate purchase price of $46.1 million, of which $39.9 million was cash and $6.2 million was non-cash related to the settlement of an accounts receivable balance. In conjunction with these acquisitions, the Company recorded $3.7 million of goodwill, which was subsequently impaired in 2016, and a $4.4 million bargain purchase gain. The bargain purchase gain is reported on the Condensed Consolidated Statement of Operations within "Interest and other income (expense)".

Pinedale Divestiture

In September 2017, QEP closed on its previously announced divestiture of its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $178.8 million which was recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations. As part of the purchase and sale agreement, at the request of the buyer, QEP agreed to enter into derivative contracts covering a portion of Pinedale's future production. Those derivative contracts were novated to the buyer at closing. In addition, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. The fair value of the deficiency charges was measured utilizing an internally developed cash flow model discounted at QEP's weighted average cost of debt. Given the unobservable nature of the inputs, the fair value calculation associated with the deficiency charges is considered Level 3 within the fair value hierarchy. As of September 30, 2017, the liability associated with estimated future payments for this commitment was $35.0 million, of which $28.0 million is reported on the Condensed Consolidated Balance Sheets within "Accounts payable and accrued expenses" and $7.0 million is reported on the Condensed Consolidated Balance Sheets within "Other long-term liabilities".

QEP accounted for revenues and expenses related to Pinedale, including the pre-tax gain on sale of $178.8 million, during the three and nine months endedSeptember 30, 2017 and 2016, as income from continuing operations on the Condensed Consolidated Statements of Operations because the sale of the Pinedale assets did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The Pinedale Divestiture did, however, represent the sale of an individually significant component. For the three and nine months endedSeptember 30, 2017, QEP recorded net income before income taxes related to Pinedale, prior to the divestiture, of $208.2 million and $251.2 million, respectively, which both include the pre-tax gain on sale of $178.8 million. For the three and nine months endedSeptember 30, 2016, QEP recorded net income before income taxes related to Pinedale of $19.2 million and a net loss before income taxes of $1,177.0 million, respectively. The net loss before income taxes was primarily due to an impairment on proved properties of $1,164.0 million recognized in 2016 as a result of a decrease in expected future gas prices.

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As a part of the Pinedale Divestiture, QEP expects to incur restructuring costs of approximately $0.8 million, of which approximately $0.5 million is related to one-time termination benefits and approximately $0.3 million is related to the relocation of certain employees. During the three and nine months endedSeptember 30, 2017, restructuring costs of $0.5 million were incurred related to the Pinedale Divestiture, all of which were related to one-time termination benefits and will be paid in the fourth quarter of 2017. The Company expects to incur an additional $0.3 million of restructuring costs related to the relocation of certain employees within the next twelve months. These restructuring costs were recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statement of Operations.

Other Divestitures

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

During the nine months endedSeptember 30, 2016, QEP received proceeds of $28.9 million and recorded a pre-tax gain on sale of $5.0 million, primarily related to the divestiture of certain non-core properties in the Other Southern area.

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

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 and nine months endedSeptember 30, 2017, there were no anti-dilutive shares. During the three and nine months endedSeptember 30, 2016, there were anti-dilutive shares of 0.2 million and 0.1 million, respectively, not included in diluted common shares outstanding as they were anti-dilutive to QEP's net loss.

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
	(in millions)
Weighted-average basic common shares outstanding	240.7	239.6	240.5	215.7
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—	—
Average diluted common shares outstanding	240.7	239.6	240.5	215.7

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Note 4 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are presented in the table below.

	Capitalized Exploratory Well Costs
	2017
	(in millions)
Balance at January 1,	$	14.2
Additions to capitalized exploratory well costs	10.6
Reclassifications to proved properties	(3.6		)
Capitalized exploratory well costs charged to expense	(21.2		)
Balance at September 30,	$	—

Central Basin Platform exploration project. During the nine months ended September 30, 2017, QEP's exploratory well activity was related to the Central Basin Platform exploration project in the Permian Basin targeting the Woodford Formation. QEP completed a second exploratory well related to this project in the first half of 2017. During the three months endedSeptember 30, 2017, based on the performance of the two exploratory wells that were drilled and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project and would seek to monetize the assets. QEP charged $21.2 million of exploratory well costs to exploration expense. In conjunction with the expensing of the exploratory well costs, QEP charged $28.3 million of the associated unproved leasehold acreage in the Central Basin Platform to impairment expense during the three months endedSeptember 30, 2017. QEP wrote down the Central Basin Platform assets to their fair market value of $3.6 million and reclassified the assets to proved properties.

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 $194.2 million and $231.6 million ARO liability for the periods ended September 30, 2017 and December 31, 2016, respectively, $4.9 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	6.0
Additions	6.2
Revisions	0.2
Liabilities related to assets sold(1)	(40.8		)
Liabilities settled	(9.0		)
ARO liability at September 30,	$	194.2

____________________________

⁽¹⁾   Liabilities related to assets sold for the nine months endedSeptember 30, 2017, includes $34.9 million related to the Pinedale Divestiture (refer to Note 2 – Acquisitions and Divestitures for more information).

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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.

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The fair value of financial assets and liabilities at September 30, 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
	September 30, 2017
Financial Assets	(in millions)
Fair value of derivative contracts – short-term	$	—	$	6.9	$	—	$	(3.1	)	$	3.8
Fair value of derivative contracts – long-term	—		2.5		—		(0.8		)	1.7
Total financial assets	$	—	$	9.4	$	—	$	(3.9	)	$	5.5
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	16.5	$	—	$	(3.1	)	$	13.4
Fair value of derivative contracts – long-term	—		3.2		—		(0.8		)	2.4
Total financial liabilities	$	—	$	19.7	$	—	$	(3.9	)	$	15.8
	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
	September 30, 2017				December 31, 2016
Financial Assets	(in millions)
Cash and cash equivalents	$	782.6	$	782.6	$	443.8	$	443.8
Financial Liabilities
Checks outstanding in excess of cash balances	$	—	$	—	$	12.3	$	12.3
Long-term debt	$	2,024.6	$	2,062.1	$	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.

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

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a periodic basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the nine months endedSeptember 30, 2017, the Company recorded no impairments on proved oil and gas properties. During the nine months endedSeptember 30, 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: (i) estimated quantities of oil, gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) estimated production rates, future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is considered Level 3 within the fair value hierarchy. 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 NYMEX Henry Hub or regional price indices. QEP also enters into oil and gas basis swaps to achieve a fixed-price swap for a portion of its oil and gas sales at prices that reference specific regional index prices.

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

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Derivative Contracts – Production

The following table presents QEP’s volumes and average prices for its commodity derivative swap contracts as of September 30, 2017:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2017	NYMEX WTI	3.6	$	51.51
2018	NYMEX WTI	14.6	$	52.42
2019	NYMEX WTI	3.7	$	50.30
Gas sales		(MMBtu)	($/MMBtu)
2017	NYMEX HH	24.8	$	2.87
2017	IFNPCR	6.4	$	2.49
2018	NYMEX HH	105.9	$	2.99
2019	NYMEX HH	14.6	$	2.87

The following table presents QEP's volumes and average prices for its commodity derivative gas collars as of September 30, 2017:

Year	Index	Total Volumes	Average Price Floor		Average Price Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2017	NYMEX HH	2.8	$	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 September 30, 2017:

Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2017	NYMEX WTI	Argus WTI Midland	1.1	$	(0.67	)
2018 (Full Year)	NYMEX WTI	Argus WTI Midland	7.3	$	(1.06	)
2018 (July through December)	NYMEX WTI	Argus WTI Midland	0.6	$	(0.81	)
2019	NYMEX WTI	Argus WTI Midland	2.2	$	(0.98	)
Gas sales			(MMBtu)	($/MMBtu)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)

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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 September 30, 2017:

Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2017	SWAP	IFNPCR	1.5	$	2.88
2018	SWAP	IFNPCR	0.4	$	3.05
Gas purchases			(MMBtu)	($/MMBtu)
2017	SWAP	IFNPCR	1.1	$	2.68

QEP Derivative Financial Statement Presentation

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

		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	September 30, 2017		December 31, 2016		September 30, 2017		December 31, 2016
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	6.9	$	—	$	16.5	$	169.8
Long-term:
Commodity	Fair value of derivative contracts	2.5		—		3.2		32.0
Total derivative instruments		$	9.4	$	—	$	19.7	$	201.8

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

	Three Months Ended						Nine Months Ended
Derivative contracts not designated as cash flow hedges	September 30,						September 30,
	2017			2016			2017			2016
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	12.1		$	19.1		$	21.6		$	79.8
Gas derivative contracts	(0.4		)	0.4			(19.7		)	50.8
Gas Storage
Gas derivative contracts	—			0.1			(0.2		)	2.9
Realized gains (losses) on commodity derivative contracts	11.7			19.6			1.7			133.5
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(86.1		)	(0.3		)	88.7			(135.9		)
Gas derivative contracts	—			24.8			100.5			(80.0		)
Gas Storage
Gas derivative contracts	—			0.4			2.3			(2.7		)
Unrealized gains (losses) on commodity derivative contracts	(86.1		)	24.9			191.5			(218.6		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts	$	(74.4	)	$	44.5		$	193.2		$	(85.1	)
Derivatives associated with the Pinedale Divestiture(1)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	(1.3	)	$	—		$	(1.3	)	$	—
Gas derivative contracts	(23.5		)	—			(23.5		)	—
NGL derivative contracts	(5.1		)	—			(5.1		)	—
Unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture	$	(29.9	)	$	—		$	(29.9	)	$	—
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(104.3	)	$	44.5		$	163.3		$	(85.1	)

_______________________

⁽¹⁾  The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 2 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations.

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Note 8 – Debt

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

	September 30, 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	(20.4		)	(24.1		)
Total principal amount of debt (including current portion)	2,024.6			2,020.9
Less: current portion of long-term debt	(134.0		)	—
Total long-term debt outstanding	$	1,890.6		$	2,020.9

Of the total debt outstanding on September 30, 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, 4.00 times for the quarters in fiscal year 2018, 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 September 30, 2017 and December 31, 2016, QEP was in compliance with the covenants under the credit agreement.

As of September 30, 2017 and December 31, 2016, QEP had no borrowings outstanding under the credit facility and had $1.0 million and $2.8 million, respectively, in letters of credit outstanding under the credit facility.

Senior Notes

As of September 30, 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.

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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.

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; this conference has been scheduled for November 2017. While no formal federal enforcement action has been commenced in connection with the tank batteries to date, QEP anticipates that resolution of this matter will likely result in monetary penalties and require QEP to incur additional capital expenditures to correct noncompliance issues. We cannot reasonably estimate the loss or range of losses at this preliminary stage.

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 5.1 million shares available for future grants under the LTSIP at September 30, 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					Nine Months Ended
	September 30,					September 30,
	2017			2016		2017			2016
	(in millions)
Stock options	$	0.5		$	0.6	$	1.7		$	1.8
Restricted share awards	5.4			6.0		18.7			18.2
Performance share units	(0.1		)	3.2		(6.9		)	8.8
Restricted share units	—			0.1		—			0.2
Total share-based compensation expense	$	5.8		$	9.9	$	13.5		$	29.0

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.

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The calculated fair value of stock options granted and major assumptions used in the model at the date of grant are listed below for the nine months endedSeptember 30, 2017:

	Stock Option Assumptions
Weighted-average grant date fair value of awards granted during the period	$	6.44
Weighted-average risk-free interest rate	1.81		%
Weighted-average expected price volatility	43.9		%
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	418,752		16.77
Forfeited	(14,172	)	15.33
Canceled	(202,260	)	27.55
Outstanding at September 30, 2017	2,354,277		$	23.62	3.75	$	—
Options Exercisable at September 30, 2017	1,551,861		$	27.90	2.73	$	—
Unvested Options at September 30, 2017	802,416		$	15.33	5.73	$	—

During the nine months endedSeptember 30, 2017 and 2016, there were no exercises of stock options. As of September 30, 2017, $2.1 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.23 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 nine months endedSeptember 30, 2017 and 2016 was $22.9 million and $24.2 million, respectively. The weighted-average grant date fair value of restricted share awards was $14.13 per share and $10.37 per share for the nine months endedSeptember 30, 2017 and 2016, respectively. As of September 30, 2017, $25.2 million of unrecognized compensation cost related to restricted share awards granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.17 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	2,123,016		14.13
Vested	(1,384,011	)	16.54
Forfeited	(240,732	)	14.71
Unvested balance at September 30, 2017	3,706,776		$	13.35

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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 September 30, 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 $16.90 per share and $10.16 per share for the nine months endedSeptember 30, 2017 and 2016, respectively. As of September 30, 2017, $0.2 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.03 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	405,014		16.90
Vested and Paid	(215,439	)	31.63
Forfeited	(17,519	)	13.88
Unvested balance at September 30, 2017	1,199,336		$	14.59

Restricted Share Units

Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards are ultimately 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 nine months endedSeptember 30, 2017 and 2016, respectively. As of September 30, 2017, $0.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 1.43 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 September 30, 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).

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The Pension Plan is a closed, qualified, defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. During the nine months endedSeptember 30, 2017, the Company made contributions of $4.0 million to the Pension Plan and does not expect to make additional contributions to the 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 nine months endedSeptember 30, 2017, the Company made contributions of $1.9 million to its SERP and expects to contribute an additional $0.1 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.

During the nine months endedSeptember 30, 2017, the Company recognized a $0.7 million loss on curtailment related to the SERP in connection with the Pinedale Divestiture, which was recorded on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales".

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 nine months endedSeptember 30, 2017, the Company made contributions of $0.2 million to its Medical Plan and expects to contribute an additional $0.1 million to its Medical Plan during the remainder of 2017. Contributions to the Medical Plan are used to fund current benefit payments.

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

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.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.2		$	0.3		$	0.6		$	0.9
Interest cost	1.2			1.3			3.6			3.9
Expected return on plan assets	(1.3		)	(1.4		)	(4.0		)	(4.2		)
Amortization of prior service costs(1)	0.3			0.3			0.9			0.9
Amortization of actuarial losses(1)	0.1			0.2			0.3			0.6
Curtailment loss(2)	0.7			—			0.7			—
Periodic expense	$	1.2		$	0.7		$	2.1		$	2.1
Medical Plan benefits
Interest cost	$	—		$	0.1		$	0.1		$	0.2
Amortization of prior service costs(1)	(0.1		)	—			(0.2		)	0.1
Periodic expense	$	(0.1	)	$	0.1		$	(0.1	)	$	0.3

____________________________

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

⁽²⁾  A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. These expenses relate to the Pinedale Divestiture and are recognized on the Condensed Consolidated Statements of Operations within "Gain (loss) from asset sales" for the three and nine months endedSeptember 30, 2017.

Note 12 – Subsequent Event

On October 24, 2017, QEP closed on its previously announced acquisition of oil and gas properties in the Permian Basin for an aggregate purchase price of $683.5 million, subject to post-closing purchase price adjustments (the 2017 Permian Basin Acquisition). The 2017 Permian Basin Acquisition consists of approximately 13,000 acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. Approximately 700 additional acres contracted for in the transaction were not included in the closing, but are expected to be acquired by the Company within the next 30 days for an aggregate purchase price not to exceed $38.0 million. Within 10 business days of closing the 2017 Permian Basin Acquisition, QEP is obligated to make offers to various persons who own additional oil and gas interests in certain properties included in the transaction on substantially the same terms and conditions as the purchase described above. If all offers are accepted, the aggregate purchase price is not expected to exceed $65.0 million. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded all of the purchase price with the proceeds from the Pinedale Divestiture.

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

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

The following information updates the discussion of QEP's financial condition provided in its Annual Report on Form 10-K for the year ended December 31, 2016 (2016 Form 10-K) and analyzes the changes in the results of operations between the three and nine months endedSeptember 30, 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 the 2016 Form 10-K.

OVERVIEW

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 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".

The Company has substantial acreage positions and operations in some of the most prolific hydrocarbon resource plays in the continental United States, including the Permian Basin, Williston Basin, Haynesville Shale and Uinta Basin. 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 heavily 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 acquired approximately $3.9 billion of oil-weighted properties and sold gas-weighted properties, such as Pinedale. In addition, beginning in 2012, the Company has invested approximately 60% of its capital expenditures (excluding property acquisitions) on its oil-weighted properties. The Company has emphasized development of its oil-weighted Permian Basin assets by increasing its oil production by 37% during the nine months endedSeptember 30, 2017, compared to the nine months endedSeptember 30, 2016.

Outlook

Since the commodity price downturn in late 2014, the Company has focused on lowering operating costs, reducing per-well drilling costs and managing its liquidity. We believe our strong balance sheet and ample liquidity will allow us to grow oil production, primarily in the Permian Basin, and gas production, primarily in Haynesville/Cotton Valley, during 2017.

Based on current commodity prices, we expect to be able to fund our planned capital program for the remainder of 2017 with cash on hand, cash flow from operating activities and borrowings under our credit facility. Our total capital expenditures (excluding property acquisitions), for 2017 are expected to be approximately $1,075.0 million, an increase of approximately 100% 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.

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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. To simplify its asset portfolio and to provide additional liquidity for future growth, QEP is evaluating the sale of certain upstream and midstream assets.

Acquisitions

During the nine months endedSeptember 30, 2017, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill. During the nine months endedSeptember 30, 2016, QEP acquired various oil and gas properties, which primarily included additional interests in QEP's operated wells and additional undeveloped leasehold acreage in the Permian and Williston basins, for an aggregate purchase price of $46.1 million. In conjunction with the acquisitions, the Company recorded $3.7 million of goodwill, which was subsequently impaired in 2016, and a $4.4 million bargain purchase gain.

In addition, 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 consisted 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.

On October 24, 2017, QEP closed on its previously announced acquisition of oil and gas properties in the Permian Basin for an aggregate purchase price of $683.5 million, subject to post-closing purchase price adjustments (the 2017 Permian Basin Acquisition). The 2017 Permian Basin Acquisition consists of approximately 13,000 acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. Approximately 700 additional acres contracted for in the transaction were not included in the closing, but are expected to be acquired by the Company within the next 30 days for an aggregate purchase price not to exceed $38.0 million. Within 10 business days of closing the 2017 Permian Basin Acquisition, QEP is obligated to make offers to various persons who own additional oil and gas interests in certain properties included in the transaction on substantially the same terms and conditions as the purchase described above. If all offers are accepted, the aggregate purchase price is not expected to exceed $65.0 million. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded all of the purchase price with the proceeds from the Pinedale Divestiture.

Divestitures

In September 2017, QEP closed on its previously announced divestiture of its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $178.8 million which was recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations.

In addition to the Pinedale Divestiture, during the nine months endedSeptember 30, 2017, QEP received proceeds of $69.7 million and recorded a pre-tax gain on sale of $26.4 million, primarily related to the divestiture of certain non-core properties in the Other Northern area. During the nine months endedSeptember 30, 2016, QEP received proceeds of $28.9 million and recorded a pre-tax gain on sale of $5.0 million, primarily related to the divestiture of certain non-core properties in the Other Southern area.

On October 13, 2017, QEP closed on the divestiture of its Central Basin Platform assets and received net cash proceeds of $3.5 million. Refer to Note 4 – Capitalized Exploratory Well Costs, in Item I of Part I of this Quarterly Report on Form 10-Q for more information.

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Financial and Operating Results

During the three months endedSeptember 30, 2017, QEP:

• Closed the Pinedale Divestiture, for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $178.8 million;

• Delivered oil production of 4,827.1 Mbbls, including a record 1,692.8 Mbbls in the Permian Basin and 2,803.3 Mbbls in the Williston Basin;

• Increased gas production in Haynesville/Cotton Valley to 19.9 Bcf, a 64%increase over 2016 volumes, due to a successful refracturing program;

• Reported realized oil prices of $47.67 per bbl, a 9%increase over 2016, realized gas prices of $2.79 per Mcf, a 6%increase over 2016 and realized NGL prices of $21.28 per bbl, a 74%increase over 2016;

• Generated a net loss of $3.3 million, or $0.01 per diluted share; and

• Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $193.1 million, a 14%increase over 2016.

During the nine months endedSeptember 30, 2017, QEP:

• Delivered oil production of 14,380.1 Mbbls, including a record 4,144.1 Mbbls in the Permian Basin and 9,216.5 Mbbls in the Williston Basin;

• Increased gas production in Haynesville/Cotton Valley to 48.8 Bcf, a 62%increase over 2016 volumes, due to a successful refracturing program;

• Reported realized oil prices of $47.10 per bbl, a 15%increase over 2016, realized gas prices of $2.81 per Mcf, an 11%increase over 2016 and realized NGL prices of $19.89 per bbl, a 59%increase over 2016;

• Generated net income of $119.0 million, or $0.49 per diluted share; and

• Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $541.0 million, a 19%increase over 2016.

Factors Affecting Results of Operations

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

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

Changes in the market prices for oil, gas and NGL directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling and completion activity and related capital expenditures, our proved undeveloped (PUD) reserves conversion rate, liquidity, rate of growth, costs of goods and services required to drill, complete and operate wells, and the carrying value of its oil and gas properties. Historically, field-level prices received for QEP’s oil and gas production have been volatile. During the past five years, the posted price for WTI crude oil has ranged from a low of $26.19 per barrel in February 2016 to a high of $110.62 per barrel in September 2013. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. If prices of oil, gas 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 nine months endedSeptember 30, 2017, and will likely continue to reject ethane for the remainder of 2017.

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Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the global economy, including Europe and China's economic outlook; the Organization of Petroleum Exporting Countries (OPEC) countries oil production and policies regarding production quotas; political unrest and economic issues in 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 continues to maintain 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 September 30, 2017, QEP forecasted its 2017 annual production to be approximately 53.2 MMboe and had approximately 71% of its forecasted oil production and 80% of its forecasted gas production covered with fixed-price swaps and collars. See Part 1, Item 3 – "Quantitative and Qualitative Disclosures about Market Risk-Commodity Price Risk Management" for further details on QEP’s commodity derivatives transactions.

Potential for Future Asset Impairments

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

We base our fair value estimates on projected financial information that we believe to be reasonably likely to occur. An assessment of the sensitivity of our capitalized costs to changes in the assumptions in our cash flow calculations is not practicable, given the numerous assumptions (e.g., future oil, gas and NGL prices; production and reserves; pace and timing of development plans; timing of capital expenditures; operating costs; drilling and development costs; and inflation and discount rates) that can materially affect our estimates. Unfavorable adjustments to some of the above listed assumptions would likely be offset by favorable adjustments in other assumptions. For example, the impact of sustained reduced oil, gas and NGL prices on future undiscounted cash flows would likely be offset by lower drilling and development costs and lower operating costs.

During the nine months endedSeptember 30, 2017, QEP recorded impairment charges of $28.4 million, which was primarily related to unproved leasehold acreage in the Central Basin Platform. Refer to Note 4 – Capitalized Exploratory Well Costs, in Item I of Part I of this Quarterly Report on Form 10-Q for more information.

During the nine months endedSeptember 30, 2016, the Company recorded impairments of $1,188.2 million, of which $1,167.9 million was related to proved properties due to lower future prices, primarily in Pinedale, $16.6 million was related to expiring leaseholds on unproved properties and $3.7 million was related to an impairment of goodwill.

If forward oil prices decline from September 30, 2017 levels or we experience negative changes in estimated reserve quantities, as of September 30, 2017, we have proved and unproved property with a net book value of approximately $2.7 billion at risk for impairment, primarily associated with our Williston Basin field. The actual amount of impairment incurred, if any, for these properties will depend on a variety of factors including, but not limited to, subsequent forward price curve changes, the additional risk-adjusted value of probable and possible reserves associated with the properties, weighted-average cost of capital, operating cost estimates and future capital expenditure estimates.

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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. For example, in the Permian Basin QEP utilizes "tank style" development, in which we drill and complete all wells in a given "tank" before any individual well is turned to production. In certain of our producing areas, wells drilled on a pad are not completed and brought into production until all wells on the pad are drilled and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the completion of wells and the commencement of production. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP’s quarterly operating results. In addition, delays in completion of wells may impact planned conversion of PUD reserves to proved developed.

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 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 and nine months endedSeptember 30, 2017:

	Operated Completions				Non-operated Completions
	Three Months Ended		Nine Months Ended		Three Months Ended		Nine Months Ended
	September 30, 2017		September 30, 2017		September 30, 2017		September 30, 2017
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin	8	6.8	31	26.0	6	0.1	20	0.4
Pinedale	12	4.1	20	8.6	—	—	—	—
Uinta Basin	—	—	—	—	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Permian Basin	10	10.0	42	41.7	—	—	—	—
Haynesville/Cotton Valley	—	—	—	—	—	—	8	0.8
Other Southern	—	—	—	—	—	—	—	—

QEP continues to refine its development methodology in the Permian Basin which may result in drilling and/or completion delays that may negatively impact planned PUD reserve conversions during 2017.

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The following table presents operated and non-operated wells in the process of being drilled or waiting on completion at September 30, 2017:

		Operated				Non-operated
	Drilling	Drilling		Waiting on completion		Drilling		Waiting on completion
	Rigs	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Williston Basin	1	1	0.9	1	0.9	—	—	7	0.1
Pinedale	—	—	—	—	—	—	—	—	—
Uinta Basin	—	—	—	—	—	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—	—
Southern Region
Permian Basin(1)(2)	6	38	37.8	29	29.0	—	—	—	—
Haynesville/Cotton Valley	1	1	1	—	—	5	0.3	7	0.1
Other Southern	—	—	—	—	—	—	—	—	—

____________________________

⁽¹⁾  In addition to the drilling rigs in the table above, there is one rig in the Permian Basin drilling salt water disposal wells.

⁽²⁾  The gross operated drilling well count in the Permian Basin includes 21 wells for which surface casing has been set, but as of September 30, 2017, did not have a rig drilling.

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. For example, in the Permian Basin QEP utilizes "tank style" development, in which we drill and complete all wells in a given "tank" before any individual well is turned to production. 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 30 gross operated wells waiting on completion as of September 30, 2017.

RESULTS OF OPERATIONS

Net Income

QEP generated a net loss during the third quarter of 2017 of $3.3 million, or $0.01 per diluted share, compared to a net loss of $50.9 million, or $0.21 per diluted share, in the third quarter of 2016. QEP's decreased net loss was primarily due to a $180.1 millionincrease in net gain from asset sales, of which $178.8 million was due to the Pinedale Divestiture, a 10%increase in average realized prices, a $40.9 milliondecrease in depreciation, depletion and amortization, a $23.1 milliondecrease in general and administrative expenses and a $15.6 milliondecrease in transportation and processing costs. These changes were partially offset by a 2%decrease in oil equivalent production, $140.9 million increase in unrealized derivative losses, a $25.5 millionincrease in lease operating expense and a $23.3 millionincrease in impairment expense in the third quarter of 2017 compared to the third quarter of 2016.

QEP generated net income during the first three quarters of 2017 of $119.0 million, or $0.49 per diluted share, compared to a net loss of $1,111.7 million, or $5.15 per diluted share, in the first three quarters of 2016. QEP's increased net income was primarily due to a decrease in impairment expense of $1,159.8 million, a 14%increase in average realized prices, a $380.2 millionincrease in unrealized derivative gains, a $107.3 milliondecrease in depreciation, depletion and amortization, a $49.6 milliondecrease in general and administrative expenses and a $16.3 milliondecrease in transportation and processing costs. These changes were partially offset by a 2%decrease in oil equivalent production, a $52.1 millionincrease in lease operating expense and a $20.8 millionincrease in production and property tax expense in the first three quarters of 2017 compared to the first three quarters of 2016.

29

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
	(in millions)
Net income (loss)	$	(3.3	)	$	(50.9	)	$	119.0		$	(1,111.7	)
Interest expense	34.4			35.9			103.1			109.2
Interest and other (income) expense	(0.1		)	(4.6		)	(2.5		)	(5.6		)
Income tax provision (benefit)	(3.2		)	(29.0		)	69.7			(641.2		)
Depreciation, depletion and amortization	176.9			217.8			560.2			667.5
Unrealized (gains) losses on derivative contracts	116.0			(24.9		)	(161.6		)	218.6
Exploration expenses	21.3			0.2			21.7			0.9
Net (gain) loss from asset sales	(185.4		)	(5.3		)	(205.2		)	(5.0		)
Impairment	28.3			5.0			28.4			1,188.2
Other(1)	8.2			25.0			8.2			32.7
Adjusted EBITDA	$	193.1		$	169.2		$	541.0		$	453.6

____________________________

⁽¹⁾  Reflects legal expenses and loss contingencies incurred during the three and nine months endedSeptember 30, 2017 and 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 $193.1 million in the third quarter of 2017 from $169.2 million in the third quarter of 2016, primarily due to a 10%increase in average realized prices and a $15.6 milliondecrease in transportation and processing costs. These changes were partially offset by a 2%decrease in oil equivalent production and a $25.5 millionincrease in lease operating expense in the third quarter of 2017 compared to the third quarter of 2016.

Adjusted EBITDA increased to $541.0 million in the first three quarters of 2017 from $453.6 million in the first three quarters of 2016, primarily due to a 14%increase in average realized prices and a $16.3 milliondecrease in transportation and processing costs. These changes were partially offset by a 2%decrease in oil equivalent production, a $52.1 millionincrease in lease operating expense and a $20.8 millionincrease in production and property tax expense in the first three quarters of 2017 compared to the first three quarters of 2016.

30

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 and nine months endedSeptember 30, 2017, compared to the three and nine months endedSeptember 30, 2016:

	Oil			Gas			NGL			Total
	(in millions)
Production revenues
Three months ended September 30, 2016	$	201.6		$	123.2		$	19.8		$	344.6
Changes associated with volumes(1)	(7.9		)	(0.4		)	(1.3		)	(9.6		)
Changes associated with prices(2)	24.3			7.9			13.7			45.9
Three months ended September 30, 2017	$	218.0		$	130.7		$	32.2		$	380.9
Production revenues
Nine months ended September 30, 2016	$	553.1		$	287.5		$	56.2		$	896.8
Changes associated with volumes(1)	(37.0		)	3.7			(3.5		)	(36.8		)
Changes associated with prices(2)	139.6			108.2			31.3			279.1
Nine months ended September 30, 2017	$	655.7		$	399.4		$	84.0		$	1,139.1

____________________________

⁽¹⁾  The revenue variance attributed to the change in volume is calculated by multiplying the change in volume from the three and nine months endedSeptember 30, 2017, as compared to the three and nine months endedSeptember 30, 2016, by the average field-level price for the three and nine months endedSeptember 30, 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 and nine months endedSeptember 30, 2017, as compared to the three and nine months endedSeptember 30, 2016, by the respective volumes for the three and nine months endedSeptember 30, 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 September 30,							Nine Months Ended September 30,
	2017		2016		Change			2017		2016		Change
Total production volumes (Mboe)
Northern Region
Williston Basin	4,252.3		5,256.4		(1,004.1		)	13,660.2		15,421.9		(1,761.7		)
Pinedale	3,010.8		4,007.8		(997.0		)	9,842.4		12,005.2		(2,162.8		)
Uinta Basin	905.3		1,206.5		(301.2		)	2,770.6		3,741.1		(970.5		)
Other Northern	278.1		401.3		(123.2		)	945.6		1,142.4		(196.8		)
Southern Region
Permian Basin	2,351.3		1,505.4		845.9			5,672.9		4,605.3		1,067.6
Haynesville/Cotton Valley	3,321.2		2,037.1		1,284.1			8,160.2		5,082.5		3,077.7
Other Southern	5.1		31.3		(26.2		)	23.1		106.2		(83.1		)
Total production	14,124.1		14,445.8		(321.7		)	41,075.0		42,104.6		(1,029.6		)
Total equivalent prices (per Boe)
Average field-level equivalent price	$	26.97	$	23.86	$	3.11		$	27.73	$	21.30	$	6.43
Commodity derivative impact	0.83		1.35		(0.52		)	0.05		3.10		(3.05		)
Net realized equivalent price	$	27.80	$	25.21	$	2.59		$	27.78	$	24.40	$	3.38

31

Oil Volumes and Prices

	Three Months Ended September 30,							Nine Months Ended September 30,
	2017		2016		Change			2017		2016		Change
Oil production volumes (Mbbl)
Northern Region
Williston Basin	2,803.3		3,625.5		(822.2		)	9,216.5		11,142.8		(1,926.3		)
Pinedale	124.0		161.1		(37.1		)	404.7		486.9		(82.2		)
Uinta Basin	169.7		190.0		(20.3		)	498.3		596.6		(98.3		)
Other Northern	30.0		44.1		(14.1		)	94.2		114.6		(20.4		)
Southern Region
Permian Basin	1,692.8		989.9		702.9			4,144.1		3,018.0		1,126.1
Haynesville/Cotton Valley	6.8		6.3		0.5			19.7		20.2		(0.5		)
Other Southern	0.5		8.2		(7.7		)	2.6		31.9		(29.3		)
Total production	4,827.1		5,025.1		(198.0		)	14,380.1		15,411.0		(1,030.9		)
Oil prices (per bbl)
Northern Region	$	44.63	$	39.21	$	5.42		$	45.07	$	34.90	$	10.17
Southern Region	$	46.13	$	43.76	$	2.37		$	46.88	$	39.86	$	7.02
Average field-level price	$	45.16	$	40.12	$	5.04		$	45.60	$	35.89	$	9.71
Commodity derivative impact	2.51		3.81		(1.30		)	1.50		5.18		(3.68		)
Net realized price	$	47.67	$	43.93	$	3.74		$	47.10	$	41.07	$	6.03

Oil revenues increased $16.4 million, or 8%, in the third quarter of 2017 compared to the third quarter of 2016, due to higher average field-level prices, partially offset by lower oil production volumes. Average field-level oil prices increased 13% in the third quarter of 2017 compared to the third quarter of 2016 primarily driven by an increase in average NYMEX-WTI oil prices for the comparable periods combined with narrowing differentials in our Northern Region properties. The 4%decrease in production volumes was driven by decreases in the Williston and Uinta basins due to a reduction in completion activity as well as operational issues and well shut-ins associated with offset completion activity in the Williston Basin and a decrease in Pinedale as a result of the Pinedale Divestiture, which closed in September 2017. These decreases were partially offset by a production increase in the Permian Basin due to increased completion activity and the additional production from the 2016 Permian Basin Acquisition.

Oil revenues increased $102.6 million, or 19%, in the first three quarters of 2017 compared to the first three quarters of 2016, due to higher average field-level prices, partially offset by lower oil production volumes. Average field-level oil prices increased 27% in the first three quarters of 2017 compared to the first three quarters of 2016 primarily driven by an increase in average NYMEX-WTI oil prices for the comparable periods combined with narrowing differentials in our Northern Region properties. The 7%decrease in production volumes was driven by the Williston and Uinta basins and in Pinedale due to a reduction in completion activity throughout 2016 as well as operational issues and well shut-ins associated with offset completion activity in the Williston Basin as well as the Pinedale Divestiture. These decreases were partially offset by a production increase in the Permian Basin due to increased completion activity and the additional production from the 2016 Permian Basin Acquisition.

32

Gas Volumes and Prices

	Three Months Ended September 30,								Nine Months Ended September 30,
	2017			2016		Change			2017			2016		Change
Gas production volumes (Bcf)
Northern Region
Williston Basin	3.7			4.3		(0.6		)	11.8			11.5		0.3
Pinedale	15.8			21.1		(5.3		)	51.9			62.7		(10.8		)
Uinta Basin	4.1			5.7		(1.6		)	12.9			17.9		(5.0		)
Other Northern	1.4			2.1		(0.7		)	5.0			6.1		(1.1		)
Southern Region
Permian Basin	1.8			1.3		0.5			4.3			4.3		—
Haynesville/Cotton Valley	19.9			12.1		7.8			48.8			30.2		18.6
Other Southern	—			0.2		(0.2		)	0.1			0.4		(0.3		)
Total production	46.7			46.8		(0.1		)	134.8			133.1		1.7
Gas prices (per Mcf)
Northern Region	$	2.74		$	2.62	$	0.12		$	2.95		$	2.14	$	0.81
Southern Region	$	2.86		$	2.65	$	0.21		$	2.97		$	2.22	$	0.75
Average field-level price	$	2.80		$	2.63	$	0.17		$	2.96		$	2.16	$	0.80
Commodity derivative impact	(0.01		)	0.01		(0.02		)	(0.15		)	0.38		(0.53		)
Net realized price	$	2.79		$	2.64	$	0.15		$	2.81		$	2.54	$	0.27

Gas revenues increased $7.5 million, or 6%, in the third quarter of 2017 compared to the third quarter of 2016, due to higher average field-level prices, partially offset by marginally lower gas production volumes. Average field-level gas prices increased 6% in the third quarter of 2017 compared to the third quarter of 2016, primarily driven by an increase in average NYMEX-HH gas prices for the comparable periods. The slight decrease in production volumes was primarily driven by production decreases in Pinedale and the Uinta Basin due to reduced completion activity throughout 2016 and the Pinedale Divestiture. These decreases were partially offset by increased production in Haynesville/Cotton Valley due to an operated well refracturing program that began in 2016 and continued throughout 2017.

Gas revenues increased $111.9 million, or 39%, in the first three quarters of 2017 compared to the first three quarters of 2016, due to higher average field-level prices and higher gas production volumes. Average field-level gas prices increased 37% in the first three quarters of 2017 compared to the first three quarters of 2016, primarily driven by an increase in average NYMEX-HH gas prices for the comparable periods. The 1%increase in production volumes was primarily driven by increased production in Haynesville/Cotton Valley due to an operated well refracturing program that began in 2016 and continued throughout 2017. This increase was partially offset by production decreases in Pinedale and the Uinta Basin due to reduced completion activity throughout 2016 and the Pinedale Divestiture.

33

NGL Volumes and Prices

	Three Months Ended September 30,								Nine Months Ended September 30,
	2017			2016		Change			2017			2016		Change
NGL production volumes (Mbbl)
Northern Region
Williston Basin	834.7			920.8		(86.1		)	2,480.6			2,362.7		117.9
Pinedale	255.5			333.8		(78.3		)	779.5			1,069.9		(290.4		)
Uinta Basin	42.3			56.0		(13.7		)	117.3			157.6		(40.3		)
Other Northern	3.8			7.6		(3.8		)	12.0			17.3		(5.3		)
Southern Region
Permian Basin	376.0			288.6		87.4			823.6			860.9		(37.3		)
Haynesville/Cotton Valley	4.9			6.0		(1.1		)	13.6			20.6		(7.0		)
Other Southern	(1.1		)	3.7		(4.8		)	(0.2		)	13.8		(14.0		)
Total production	1,516.1			1,616.5		(100.4		)	4,226.4			4,502.8		(276.4		)
NGL prices (per bbl)
Northern Region	$	21.89		$	12.43	$	9.46		$	20.52		$	12.87	$	7.65
Southern Region	$	19.43		$	11.52	$	7.91		$	17.35		$	10.95	$	6.40
Average field-level price	$	21.28		$	12.26	$	9.02		$	19.89		$	12.49	$	7.40
Commodity derivative impact	—			—		—			—			—		—
Net realized price	$	21.28		$	12.26	$	9.02		$	19.89		$	12.49	$	7.40

NGL production volumes and revenues represent the sale of liquids derived from the processing of QEP's natural gas production. NGL revenues increased $12.4 million, or 63%, during the third quarter of 2017 compared to the third quarter of 2016, due to higher average field-level prices, partially offset by lower NGL production volumes. NGL prices increased 74% during the third quarter of 2017 compared to the third quarter of 2016, primarily driven by an increase in propane, ethane and other NGL component prices. The 6%decrease in NGL production volumes was driven by decreases in Pinedale due to reduced completion activity throughout 2016, our midstream provider withholding an additional 50.5 Mbbls to meet linefill requirements and the Pinedale Divestiture. The decrease in the Williston Basin is due to lower associated gas volumes and related NGL volumes from reduced completion activity. These decreases were partially offset by a production increase in the Permian Basin due to increased completion activity.

NGL revenues increased $27.8 million, or 49%, during the first three quarters of 2017 compared to the first three quarters of 2016, due to higher average field-level prices, partially offset by lower NGL production volumes. NGL prices increased 59% during the first three quarters of 2017 compared to the first three quarters of 2016, primarily driven by an increase in propane, ethane and other NGL component prices. The 6%decrease in NGL production volumes was driven by a decrease in Pinedale due to reduced completion activity, our midstream provider withholding an additional 50.5 Mbbls to meet linefill requirements and the Pinedale Divestiture. The increase in the Williston Basin is due to the resolution in November 2016 of a dispute with our midstream service provider that had negatively impacted gas volumes and associated NGL volumes in 2016.

34

Resale Margin and Storage Activity

QEP purchases and resells oil and gas primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. The following table is a summary of QEP's financial results from its resale activities.

	Three Months Ended September 30,									Nine Months Ended September 30,
	2017			2016			Change			2017			2016			Change
	(in millions)
Purchased oil and gas sales	$	5.6		$	35.3		$	(29.7	)	$	44.5		$	76.3		$	(31.8	)
Purchased oil and gas expense	(6.9		)	(37.1		)	30.2			(45.4		)	(80.8		)	35.4
Realized gains (losses) on gas storage derivative contracts	—			0.1			(0.1		)	(0.2		)	2.9			(3.1		)
Resale margin	$	(1.3	)	$	(1.7	)	$	0.4		$	(1.1	)	$	(1.6	)	$	0.5

Purchased oil and gas sales decreased by $29.7 million, or 84%, during the third quarter of 2017 compared to third quarter of 2016, due to lower resale volumes, which is the result of increased production in areas where the Company has oil and gas transportation commitments.

Purchased oil and gas sales decreased by $31.8 million, or 42%, during the first three quarters of 2017 compared to first three quarters of 2016, due to lower resale volumes, which is the result of increased production in areas where the Company has oil and gas transportation commitments.

Purchased oil and gas expense, which includes transportation expense, decreased $30.2 million, or 81%, during the third quarter of 2017 compared to the third quarter of 2016, due to lower resale volumes as a result of increased production in areas where the Company has oil and gas transportation commitments.

Purchased oil and gas expense, which includes transportation expense, decreased $35.4 million, or 44%, during the first three quarters of 2017 compared to the first three quarters of 2016, due to lower resale volumes, which is the of result of increased production in areas where the Company has oil and gas transportation commitments.

Operating Expenses

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2017		2016		Change			2017		2016		Change
	(per Boe)
Lease operating expense	$	5.39	$	3.51	$	1.88		$	5.24	$	3.88	$	1.36
Transportation and processing costs	4.26		5.24		(0.98		)	4.93		5.20		(0.27		)
Production and property taxes	2.02		1.86		0.16			2.10		1.55		0.55
Total production costs	$	11.67	$	10.61	$	1.06		$	12.27	$	10.63	$	1.64

Lease operating expense (LOE). QEP’s LOE increased $25.5 million, or $1.88 per Boe, during the third quarter of 2017 compared to the third quarter of 2016. The increase in expense was driven by an increase in workovers in the Williston and Permian basins and in Haynesville/Cotton Valley and increased repairs and maintenance expense in the Williston Basin.

QEP’s LOE increased $52.1 million, or $1.36 per Boe, during the first three quarters of 2017 compared to the first three quarters of 2016. The increase in expense was driven by an increase in workovers in the Williston and Permian basins and in Haynesville/Cotton Valley, increased repairs and maintenance expense in the Williston Basin and increased fuel expense in the Permian Basin.

35

Transportation and processing costs. Transportation and processing costs decreased $15.6 million, or $0.98 per Boe, during the third quarter of 2017 compared to the third quarter of 2016. The decrease in expense was primarily attributable to decreases in Haynesville/Cotton Valley and Pinedale. The decrease in Haynesville/Cotton Valley was primarily related to the recovery of fees for historical unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP had a working interest. The decrease in Pinedale was primarily related to the recovery of historical transportation costs and the Pinedale Divestiture.

Transportation and processing costs decreased $16.3 million, or $0.27 per Boe, during the first three quarters of 2017 compared to the first three quarters of 2016. The decrease in expense was primarily attributable to decreases in Haynesville/Cotton Valley and Pinedale. The decrease in Haynesville/Cotton Valley was primarily related to the recovery of fees for historical unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP had a working interest. The decrease in Pinedale was primarily related to the recovery of historical transportation costs and the Pinedale Divestiture.

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 $1.7 million, or $0.16 per Boe, during the third quarter of 2017 compared to the third quarter of 2016, primarily as a result of increased oil and gas revenues from higher field-level prices, partially offset by lower production.

Production and property taxes increased $20.8 million, or $0.55 per Boe, during the first three quarters of 2017 compared to the first three quarters 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 $40.9 million in the third quarter of 2017 compared to the third quarter of 2016, primarily due to decreased rates in the Permian Basin and Haynesville/Cotton Valley. The lower rates in the Permian Basin and Haynesville/Cotton Valley are the result of higher proved reserves. In addition, QEP did not record DD&A expense in Pinedale during the third quarter of 2017 as the asset was considered held for sale prior to closing the Pinedale Divestiture in September 2017.

DD&A expense decreased $107.3 million in the first three quarters of 2017 compared to the first three quarters of 2016, primarily due to decreased rates in the Permian Basin, Pinedale 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. In addition, QEP did not record DD&A expense in Pinedale during the third quarter of 2017 as the asset was considered held for sale prior to closing the Pinedale Divestiture in September 2017.

Exploration expense. Exploration expense increased $21.1 million during the third quarter of 2017 compared to the third quarter of 2016, primarily as a result of charging $21.2 million of exploratory well costs related to the Central Basin Platform exploration project to exploration expense. During the third quarter of 2017, based on well performance and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project. Refer to Note 4 – Capitalized Exploratory Well Costs, in Item I of Part I of this Quarterly Report on Form 10-Q for more information.

Exploration expense increased $20.8 million during the first three quarters of 2017 compared to the first three quarters of 2016, primarily as a result of charging $21.2 million of exploratory well costs related to the Central Basin Platform exploration project to exploration expense. During the third quarter of 2017, based on well performance and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project. Refer to Note 4 – Capitalized Exploratory Well Costs, in Item I of Part I of this Quarterly Report on Form 10-Q for more information.

Impairment expense. During the third quarter of 2017, QEP recorded impairment charges of $28.3 million, which were primarily related to the impairment of unproved leasehold acreage in the Central Basin Platform. Refer to Note 4 – Capitalized Exploratory Well Costs, in Item I of Part I of this Quarterly Report on Form 10-Q for more information. During the third quarter of 2016, QEP recorded impairment charges of $5.0 million which was related to expiring leaseholds on unproved properties.

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During the first three quarters of 2017, QEP recorded impairment charges of $28.4 million, which were primarily related to the impairment of unproved leasehold acreage in the Central Basin Platform. Refer to Note 4 – Capitalized Exploratory Well Costs, in Item I of Part I of this Quarterly Report on Form 10-Q for more information. During the first three quarters of 2016, QEP recorded impairment charges of $1,188.2 million, of which $1,167.9 million was related to proved properties due to lower future prices, $16.6 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 third quarter of 2017, G&A expense decreased $23.1 million, or 35%, compared to the third quarter of 2016, primarily due to a $18.7 million decrease in legal expenses and loss contingencies, a $5.6 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 $1.0 million decrease in bad debt expense. These decreases were partially offset by increased labor, benefits and employee expenses of $2.4 million.

During the first three quarters of 2017, G&A expense decreased $49.6 million, or 31%, compared to the first three quarters of 2016, primarily due to a $27.4 million decrease in legal expenses and loss contingencies, a $22.9 million decrease in share-based compensation from changes in the mark-to-market value of the Deferred Compensation Wrap Plan and CIP, a $2.1 million decrease in bad debt expense and a $1.6 million decrease in severance and relocation expenses. These decreases were partially offset by increased labor, benefits and employee expenses of $4.3 million.

Net gain (loss) from asset sales. During the third quarter of 2017, QEP recognized a gain on the sale of assets of $185.4 million compared to a gain on the sale of assets of $5.3 million in the third quarter of 2016. The gain on the sale of assets in the third quarter of 2017 primarily related to the Pinedale Divestiture, in which we recorded a pre-tax gain on sale of $178.8 million, and the sale of non-core Other Northern properties. The gain on sale of assets in the third quarter of 2016 primarily related to continued divestitures of non-core Other Southern properties.

During the first three quarters of 2017, QEP recognized a gain on the sale of assets of $205.2 million compared to a gain on the sale of assets of $5.0 million in the first three quarters of 2016. The gain on the sale of assets in the first three quarters of 2017 primarily related to the Pinedale Divestiture, in which we recorded a pre-tax gain on sale of $178.8 million, and the sale of non-core Other Northern properties. The gain on sale of assets in the first three quarters of 2016 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 third quarter of 2017, losses on commodity derivative contracts were $104.3 million, of which $86.1 million were unrealized losses on derivative contracts related to production and storage contracts, $29.9 million were unrealized losses related to the Pinedale Divestiture (Refer to Note 7 – Derivative Contracts, in Item I of Part I of this Quarterly Report on Form 10-Q for more information) and $11.7 million were realized gains. During the third quarter of 2016, gains on commodity derivative contracts were $44.5 million, of which $24.9 million were unrealized gains and $19.6 million were realized gains.

During the first three quarters of 2017, gains on commodity derivative contracts were $163.3 million, of which $191.5 million were unrealized gains on derivative contracts related to production and storage contracts, $29.9 million were unrealized losses related to the Pinedale Divestiture (Refer to Note 7 – Derivative Contracts, in Item I of Part I of this Quarterly Report on Form 10-Q for more information) and $1.7 million were realized gains. During the first three quarters of 2016, losses on commodity derivative contracts were $85.1 million, of which $218.6 million were unrealized losses and $133.5 million were realized gains.

Interest expense. Interest expense decreased $1.5 million, or 4%, during the third quarter of 2017 compared to the third quarter of 2016. The decrease during the third quarter of 2017 was primarily related to the repayment of $176.8 million of senior notes in September 2016.

Interest expense decreased $6.1 million, or 6%, during the first three quarters of 2017 compared to the first three quarters of 2016. The decrease during the first three quarters of 2017 was primarily related to the repayment of $176.8 million of senior notes in September 2016.

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Income tax (provision) benefit. Income tax benefitdecreased $25.8 million during the third quarter of 2017 compared to the third quarter of 2016. The decrease in benefit was the result of a lower net loss, partially offset by a higher combined effective federal and state income tax rate of 49.2% during the third quarter of 2017 compared to a rate of 36.3% during the third quarter of 2016. The increase in income tax rate was primarily the result of recognizing a year to date adjustment for a permanent difference related to marginal well tax credits in the third quarter of 2017 as well as a change in income between different states.

Income tax expenseincreased $710.9 million during the first three quarters of 2017 compared to the first three quarters 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 36.9% during the first three quarters of 2017 compared to a rate of 36.6% during the first three quarters of 2016.

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 borrowings under its revolving credit facility. The Company expects that these sources of cash will be sufficient to fund its operations, capital expenditures and repayment of its senior notes maturing 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 $787.9 million related to the Pinedale Divestiture and the sale of non-core properties during the nine months endedSeptember 30, 2017. On October 24, 2017, QEP closed on its previously announced 2017 Permian Basin Acquisition for approximately $683.5 million and funded all of the purchase price of the acquisition with proceeds from the Pinedale Divestiture. Approximately 700 additional acres contracted for in the transaction were not included in the closing, but are expected to be acquired by the Company within the next 30 days for an aggregate purchase price not to exceed $38.0 million. Within 10 business days of closing the 2017 Permian Basin Acquisition, QEP is obligated to make offers to various persons who own additional oil and gas interests in certain properties included in the transaction on substantially the same terms and conditions as the purchase described above. If all offers are accepted, the aggregate purchase price is not expected to exceed $65.0 million. QEP received aggregate proceeds of approximately $28.9 million related to the sale of non-core properties during the nine months ended and September 30, 2016.

The Company estimates, that with its cash balance as of September 30, 2017, it could incur additional indebtedness of approximately $1.0 billion and continue to be in compliance with the covenants contained in its revolving credit facility. The Company estimates that as of October 24, 2017, after using cash to fund the Permian Basin Acquisition, it could incur additional indebtedness under its revolving credit facility of approximately $550.0 million 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

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, 4.00 times for the quarters in fiscal year 2018, 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.

As of September 30, 2017 and December 31, 2016, QEP had no borrowings outstanding under the credit facility, had $1.0 million and $2.8 million, respectively, in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement. As of October 24, 2017, QEP had no borrowings outstanding under the credit facility,

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had $1.0 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 September 30, 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.

The Company plans to repay its $134.0 million Senior Notes due April 2018 with cash on hand or borrowings under the credit facility.

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:

	Nine Months Ended September 30,
	2017		2016			Change
	(in millions)
Net income (loss)	$	119.0	$	(1,111.7	)	$	1,230.7
Non-cash adjustments to net income (loss)	318.7		1,516.4			(1,197.7		)
Changes in operating assets and liabilities	44.1		128.2			(84.1		)
Net cash provided by (used in) operating activities	$	481.8	$	532.9		$	(51.1	)

Net cash provided by operating activities was $481.8 million during the first three quarters of 2017, which included $119.0 million of net income, $318.7 million of non-cash adjustments to net income and a $44.1 millionincrease in operating assets and liabilities. Non-cash adjustments to net income primarily included DD&A expense of $560.2 million and $68.5 million of deferred income taxes, partially offset by a net gain on asset sales of $205.2 million and unrealized gains on derivative contracts of $161.6 million. The increase in cash from operating assets and liabilities primarily resulted from a decrease in accounts receivable of $18.5 million, an increase in accounts payable and accrued expenses of $17.8 million and an increase in production and property taxes of $7.3 million, partially offset by a decrease in the ARO liability of $3.0 million.

Net cash provided by operating activities was $532.9 million during the first three quarters of 2016, which included a $1,111.7 million net loss, $1,516.4 million of non-cash adjustments to the net loss and a $128.2 millionincrease in operating assets and liabilities. Non-cash adjustments to the net loss primarily included impairment expense of $1,188.2 million, DD&A expense of $667.5 million and unrealized losses on derivative contracts of $218.6 million, partially offset by a decrease in deferred income taxes of $581.1 million. The increase in operating assets and liabilities primarily included a decrease in accounts receivable of $115.4 million and a decrease in income taxes receivable of $64.8 million, primarily related to a federal income tax refund received in the third quarter of 2016, partially offset by a decrease in accounts payable and accrued expenses of $69.0 million.

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Cash Flow from Investing Activities

During the first three quarters of 2017, net cash used in investing activities was $122.8 million compared to net cash used in investing activities of $452.2 million in the first three quarters2016.

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

	Nine Months Ended September 30,
	2017			2016		Change
	(in millions)
Property acquisitions (including acquisition deposits held in escrow)	$	131.1		$	76.1	$	55.0
Property, plant and equipment capital expenditures	847.6			384.6		463.0
Total accrued capital expenditures	978.7			460.7		518.0
Change in accruals and other non-cash adjustments	(68.0		)	20.4		(88.4		)
Total cash capital expenditures	$	910.7		$	481.1	$	429.6

In the first three quarters of 2017, on an accrual basis, the Company invested $847.6 million on property, plant and equipment capital expenditures, excluding property acquisitions, an increase of $463.0 million compared to the first three quarters of 2016. In the first three quarters of 2017, QEP's significant capital expenditures were $489.1 million in the Permian Basin, $195.4 million in the Williston Basin, $121.2 million in Haynesville/Cotton Valley and $24.8 million in Pinedale. In addition, in the first three quarters of 2017, QEP acquired various oil and gas properties, primarily proved and unproved leaseholds and additional surface acreage primarily in the Permian Basin, for an aggregate purchase price of $94.5 million. Lastly, QEP paid a deposit of $36.6 million, which is held in escrow related to the 2017 Permian Basin Acquisition that closed on October 24, 2017. These cash outflows were partially offset by proceeds from the Pinedale Divestiture, which closed in the third quarter of 2017, and the sale of other non-core assets of approximately $787.9 million.

In the first three quarters of 2016, on an accrual basis, the Company invested $384.6 million on property, plant and equipment capital expenditures, excluding property acquisitions, which included $184.0 million in the Williston Basin, $102.0 million in the Permian Basin, $44.9 million in Pinedale, $38.1 million in Haynesville/Cotton Valley and $10.4 million in the Uinta Basin. In addition, during the first three quarters 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 additional undeveloped leasehold acreage, for a total purchase price of $46.1 million, of which $39.9 million was cash and $6.2 million was non-cash related to the settlement of an accounts receivable balance. Lastly, QEP paid a deposit of $30.0 million, which was held in escrow related to the 2016 Permian Basin Acquisition.

The mid-point of our 2017 forecasted capital expenditures (excluding property acquisitions) is $1,075.0 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 $70.0 to $80.0 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 and borrowings under our revolving credit facility. 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 quarters of 2017, net cash used in financing activities was $20.2 million compared to net cash provided by financing activities of $575.4 million in the first three quarters of 2016. During the first three quarters of 2017, QEP had a decrease in checks outstanding in excess of cash balances of $12.3 million, had treasury stock repurchases of $6.8 million and paid long-term debt issuance costs of $1.1 million. During the first three quarters of 2016, QEP had net proceeds from the March and June 2016 equity offerings of approximately $781.6 million, a repayment of senior notes of $176.8 million and a decrease in checks outstanding in excess of cash balances of $25.5 million.

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As of September 30, 2017, the Company did not have any borrowings outstanding under the credit facility and had $2,045.0 million in senior notes outstanding (excluding $20.4 million of net original issue discount and unamortized debt issuance costs).

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP’s primary market risks arise from changes in the market price for oil, gas and NGL and volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. Commodity prices have historically been volatile and are subject to wide fluctuations in response to relatively minor changes in supply and demand. If commodity prices fluctuate significantly, revenues and cash flow may significantly decrease or increase. QEP has long-term contracts for pipeline capacity and is obligated to pay for transportation services with no guarantee that it also will be able to fully utilize the contractual capacity of these transportation commitments. In addition, additional non-cash impairment expense of the Company’s oil and gas properties may be required if future oil and gas commodity prices experience a significant decline. Furthermore, the Company’s credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. To partially manage the Company’s exposure to these risks, QEP enters into commodity derivative contracts in the form of fixed-price and basis swaps and collars to manage commodity price risk and periodically enters into interest rate swaps to manage interest rate risk.

Commodity Price Risk Management

QEP uses commodity derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price and basis swaps and collars. The volume of commodity derivative instruments utilized by the Company may vary from year to year based on QEP's forecasted production. The Company's current derivative instruments do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of September 30, 2017, QEP held commodity price derivative contracts totaling 21.9 million barrels of oil, 154.5 million MMBtu of gas and 0.8 million MMBtu of net gas storage.

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The following tables present QEP's volumes and average prices for its derivative positions as of October 20, 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 September 30, 2017.

Production Commodity Derivative Swaps
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2017	NYMEX WTI	3.6	$	51.51
2018	NYMEX WTI	15.7	$	52.37
2019	NYMEX WTI	4.4	$	50.37
Gas sales		(MMBtu)	($/MMBtu)
2017	NYMEX HH	16.5	$	2.87
2017	IFNPCR	4.3	$	2.49
2018	NYMEX HH	109.5	$	2.99
2019	NYMEX HH	25.6	$	2.87

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	1.1	$	(0.67	)
2018 (Full Year)	NYMEX WTI	Argus WTI Midland	7.3	$	(1.06	)
2018 (July through December)	NYMEX WTI	Argus WTI Midland	0.7	$	(0.75	)
2019	NYMEX WTI	Argus WTI Midland	3.3	$	(0.90	)
Gas sales			(MMBtu)	($/MMBtu)
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	1.4	$	2.89
2018	SWAP	IFNPCR	0.5	$	3.09
Gas purchases			(MMBtu)	($/MMBtu)
2017	SWAP	IFNPCR	0.8	$	2.73

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Changes in the fair value of derivative contracts from December 31, 2016 to September 30, 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	(1.7		)
Change in oil and gas prices on futures markets	200.2
Contracts added	(7.0		)
Net fair value of oil and gas derivative contracts outstanding at September 30, 2017	$	(10.3	)

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

	September 30, 2017
	(in millions)
Net fair value – asset (liability)	$	(10.3	)
Fair value if market prices of oil, gas and basis differentials decline by 10%	$	(11.2	)
Fair value if market prices of oil, gas and basis differentials increase by 10%	$	(9.2	)

Utilizing the actual derivative contractual volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $1.1 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $0.9 million as of September 30, 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 its 2016 Form 10-K. The Company’s revolving credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. At September 30, 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.

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Forward-Looking Statements

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

• estimates of future liability for deficiency charges in connection with the Pinedale Divestiture;

• additional restructuring costs related to the Pinedale Divestiture;

• acquisitions of additional properties after closing of the 2017 Permian Basin Acquisition and expected purchase prices of such properties;

• our growth strategies;

• our strong balance sheet and ample liquidity providing for the ability to grow oil production, primarily in the Permian Basin and gas production, primarily in Haynesville/Cotton Valley;

• funding our planned capital program for the remainder of 2017 with cash on hand, cash flow from operating activities, and borrowings under our credit facility;

• our liquidity and the sufficiency of our cash flows from operations, cash on hand and borrowings under our credit facility to fund our operations, capital expenditures and the repayment of our senior notes maturing in the next 12 months and the foreseeable future;

• evaluating the sale of certain upstream and midstream assets to simplify our asset portfolio and provide additional liquidity for future growth;

• plans and ability to pursue acquisition opportunities;

• our inventory of drilling locations;

• drilling and completion plans and strategies;

• predictability and success of our drilling operations;

• plans to grow oil and gas production;

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

• future development costs;

• estimates of the amount of additional indebtedness we may incur 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 regarding derivative contracts and the anticipated benefits from our derivative contracts;

• divestitures of assets;

• incurring penalties and capital expenditures to address air emission noncompliance issues;

• amount and allocation of forecasted capital expenditures (excluding acquisitions), plans for funding operations and capital investments and adjustments to our capital investment program;

• assumptions regarding share-based compensation;

• settlement of performance share units in cash;

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

• expected contributions to our 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 and volatility to operating results caused by multi-well pad drilling, including "tank-style" development;

• delays in proved undeveloped reserve conversions;

• estimated proved reserves and development of such reserves;

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

• implementation and impact of new accounting pronouncements;

• impact and growth of government regulations;

• impact of shutting in wells;

• potential for asset impairments and factors impacting impairment amounts;

• managing counterparty risk exposure; and

• outcome and impact of various claims.

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

• the risk factors discussed in Item 1A of Part I of the 2016 Form 10-K and Item 1A of Part II of this Quarterly Report on Form 10-Q;

• changes in oil, gas and NGL prices;

• global geopolitical and macroeconomic factors;

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

• 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 and other 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;

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

• estimates of oil and gas reserve quantities;

• reservoir performance;

• operating costs;

• inflation;

• capital costs;

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

• volatility in the securities, capital and credit markets;

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

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

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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 September 30, 2017. Based on such evaluation, such officers have concluded that, as of September 30, 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 Control over Financial Reporting

There were no changes in the Company's internal control over financial reporting that occurred during the quarter ended September 30, 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

EPA Request for Information – In July 2015, QEP received an information request from the EPA pursuant to Section 114(a) of the Clean Air Act. The information request sought facts and data about certain tank batteries in QEP's Williston Basin operations. QEP timely responded to the information requests. In August 2016, the EPA requested a conference to review this matter; this conference has been scheduled for November 2017. While no formal federal enforcement action has been commenced in connection with the tank batteries to date, QEP anticipates that resolution of this matter will likely result in monetary penalties and require QEP to incur additional capital expenditures to correct noncompliance issues. In addition, QEP signed a consent decree with the North Dakota Department of Health effective August 2017. Under the decree, QEP agreed to perform site inspections and repairs and to pay approximately $111,000 (subject to reduction if QEP takes certain remedial actions) to resolve alleged noncompliance associated with emissions from tank batteries.

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 and nine months endedSeptember 30, 2017.

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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.

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

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

Clean Air Act regulations at 40 C.F.R Part 60, Subpart OOOO (Subpart OOOO) became effective in 2012, with further amendments effective in 2013 and 2014. Subpart OOOO imposes air quality controls and requirements upon QEP's operations. Additionally, in June 2016, the Environmental Protection Agency (EPA) finalized closely related rules in new Subpart OOOOa to achieve additional methane and volatile organic compound reductions from certain activities in the oil and gas industry. The new rules include, among others, new requirements for finding and repairing leaks at new well sites and "reduced emission completion" requirements for hydraulically fractured oil and gas wells. The future status of Subpart OOOOa remains uncertain given ongoing litigation and administrative regulatory actions; however, the rules remain in effect as of the filing of this report. The regulatory uncertainty surrounding the implementation of this rule poses some complications for QEP’s operations and compliance efforts. Additionally, many states are adopting air permitting and other air quality control regulations specific to oil and gas exploration, production, gathering and processing that are more stringent than existing requirements under federal regulations.

In June 2016, the EPA also issued a Federal Implementation Plan (FIP) to implement the Federal Minor New Source Review Program on tribal lands for oil and gas production. The FIP primarily impacts QEP’s operations on the Fort Berthold Reservation in the Williston Basin and on the Uintah and Ouray Indian Reservations in the Uinta Basin. The FIP creates a permit-by-rule process for minor sources that also incorporates emission limits and other requirements under various federal air quality standards, applying them to a range of equipment and processes used in oil and gas production. However, the FIP does not apply in areas of ozone non-attainment. As a result, the EPA may impose area-specific regulations in parts of the Uinta Basin identified as tribal lands that may require additional emissions controls on existing equipment as a result of expected designation of a portion of the Uinta Basin as a marginal nonattainment area for ozone. The proposals will likely result in increased operating and compliance costs.

The FERC has jurisdiction over the operation of QEP's Clear Creek underground gas storage facility by virtue of the facility's connection to interstate pipelines (also subject to FERC jurisdiction) at both its inlet and outlet. Clear Creek is subject to specific FERC regulations governing interstate transmission facilities and activities, including but not limited to rates charged for transmission, open access/non-discrimination, and public disclosure via an electronic bulletin board of daily capacity and flows.

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Regulatory requirements to reduce gas flaring and to further restrict emissions could have an adverse effect on our operations. Wells in the Williston Basin of North Dakota and the Permian Basin of Texas, where QEP has significant operations, produce natural gas as well as crude oil. Constraints in third party gas gathering and processing systems in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. In June 2014, the North Dakota Industrial Commission, North Dakota's chief energy regulator adopted a policy to reduce the volume of natural gas flared from oil wells in the Williston Basin. The commission requires operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties may be imposed on certain wells that cannot meet the capture goals. It is possible that other states will require gas capture plans in the future to reduce flaring. Additionally, in November 2016, the Bureau of Land Management (BLM) finalized a new rule related to further controls on the venting and flaring of natural gas on BLM and tribal leases (the 2016 Venting and Flaring Rule). The rule took effect in January 2017. The 2016 Venting and Flaring Rule is the subject of active litigation in the U.S. District Court for the District of Wyoming and the U.S. District Court for the Northern District of California. Some provisions of the rule are in effect, including the royalty provisions. Other provisions, however, including those related to further controls on the venting and flaring of natural gas, do not take effect until January 2018. The BLM's attempted stay of those 2018 compliance dates pursuant to Section 705 of the Administrative Procedure Act was vacated by the U.S. District Court for the Northern District of California. In October 2017, however, the BLM published a proposed rule to temporarily suspend or delay the 2018 compliance dates until January 2019, while the BLM reviews the 2016 Venting and Flaring Rule, to avoid imposing temporary or permanent compliance costs on operators for requirements that might be rescinded or significantly revised in the near future. These state and federal gas capture requirements, and any similar future obligations in North Dakota or our other locations, may increase our operational costs or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

As a result of future legislation, certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated or modified, and QEP may be subject to the imposition of increased or new taxes. Legislation may be proposed in the future that could, if enacted into law, make significant changes to U.S. tax laws. Such changes could include the elimination or modification of U.S. federal income tax provisions currently available to QEP such as: (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain domestic production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, or could generally affect the taxes imposed on QEP, including the imposition of new U.S. federal, state or local taxes (including the imposition of, or increase in, production, severance, environmental, sales, gross receipts, or similar taxes), could increase the cost of exploration and development of oil and gas resources, which would negatively affect QEP’s financial condition and results of operations.

Federal and state hydraulic fracturing legislation or regulatory initiatives could increase QEP's costs and restrict its access to oil and gas reserves. Currently, well construction activities, including hydraulic fracture stimulation, are regulated by state agencies that review and approve all aspects of oil and gas well design and operation. The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the SDWA and issued guidance related tothis asserted regulatory authority. The EPA may be considering its existing regulatory authorities for possible avenues to further regulate hydraulic fracturing fluids and/or the components of those fluids. Additionally, the BLM finalized regulations in March 2015 regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing, on federal and tribal leases (the 2015 Hydraulic Fracturing Rule). The 2015 Hydraulic Fracturing Rule was set aside by the U.S. District Court for the District of Wyoming. The district court’s decision was appealed to the U.S. Court of Appeals for the Tenth Circuit. In September 2017, the Tenth Circuit dismissed the litigation challenging the 2015 Hydraulic Fracturing Rule, noting that it was pointless to proceed given the BLM’s proposal to rescind the rule. The Tenth Circuit also vacated the lower court’s 2016 ruling that struck down the rule. The Tenth Circuit’s ruling, which is expected to become effective in mid-November, reinstates the 2015 Hydraulic Fracturing Rule, unless and until the BLM’s proposal to rescind the rule becomes final. The 2015 Hydraulic Fracturing Rule will increase the cost of drilling and completing any well requiring federal permits and could result in further delays in getting such permits to authorize drilling and completion activities on federal and tribal leases upon which QEP operates.

At the state level, some states have adopted and other states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. If new or more stringent federal, state or local regulations, restrictions or moratoria are adopted in areas where QEP operates, QEP could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling or stimulating wells in some areas.

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The EPA has been collecting information as part of a nationwide study into the effects of hydraulic fracturing on drinking water. In December 2016, the EPA released its final report on the potential impacts to drinking water resources from hydraulic fracturing. The results of this study, which concludes that hydraulic fracturing activities can impact drinking water resources under some circumstances, could result in additional regulations, which could lead to operational burdens similar to those described above. In 2014, the EPA issued an advance notice of proposed rulemaking and initiated a public participation process under the Toxic Substances Control Act to seek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanisms for obtaining this information. It has been reported, however, that the Trump Administration has delayed issuing a proposed rule indefinitely.

Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce. Climate change, the costs that may be associated with its effects and the regulation of greenhouse gas (GHG) emissions have the potential to affect our business in many ways, including increasing the costs to provide our products and services, reducing the demand for and consumption of our products and services (due to changes in both costs and weather patterns) and the economic health of the regions in which we operate, all of which can create financial risks. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. In addition, legislative and regulatory responses related to GHG emissions and climate change may result in increased operating costs, delays in obtaining air pollution and other necessary permits for new or modified facilities and reduced demand for the oil, gas and NGL that QEP produces. Federal and state courts and administrative agencies are considering the scope and scale of climate change regulation under various laws pertaining to the environment, energy use and energy resource development. Federal, state and local governments may also pass laws mandating the use of alternative energy sources, such as wind power and solar energy, or banning the use of gasoline or diesel powered vehicles, which may reduce demand for oil and natural gas. Further, state and local governments may pursue litigation against producers for damages allegedly resulting from climate change, similar to the lawsuits filed by the cities of San Francisco and Oakland, California, in September 2017 against Chevron Corp., ConocoPhillips, Co., ExxonMobil Corp., Royal Dutch Shell Plc and BP p.l.c.. QEP's ability to access and develop new oil and gas reserves may also be restricted by climate change regulation, including GHG reporting and regulation.

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

In December 2015, over 190 countries, including the U.S., reached an agreement in Paris (COP 21) to reduce global emissions of GHG (the Paris Agreement). The Paris Agreement provides for the cutting of carbon emissions every five years, beginning in 2023, and sets a goal of keeping global warming to a maximum limit of two degrees Celsius and a target limit of 1.5 degrees Celsius greater than pre-industrial levels. In June 2017, President Trump announced that the U.S. would initiate the formal process to withdraw from the Paris Agreement. Withdrawal will take a few years to implement due to the Paris Agreement’s legal structure and language. The current state of development of ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties or domestic regulations.

In addition, in several of the states in which QEP operates the regulatory authorities are considering various GHG registration and reduction programs, including methane leak detection monitoring and repair requirements specific to oil and gas facilities. Following the initiation of the United States' withdrawal from the Paris Agreement, state and local regulation efforts are expected to increase. Any local or state success in reducing carbon emissions could adversely impact our business by limiting our ability to develop new oil and gas reserves.

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

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate. Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various species and wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened and endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species as threatened or endangered in areas where we operate could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse effect on our ability to develop and produce our reserves.

Current federal regulations under the National Environmental Policy Act (NEPA) restrict activities during certain times of the year on significant portions of QEP leasehold due to wildlife activity and/or habitat. QEP has worked with federal and state officials in Wyoming to obtain authorization for limited winter drilling activities and has developed measures, such as drilling multiple wells from a single pad location, to minimize the impact of its activities on wildlife and wildlife habitat in its operations on federal lands. Many of QEP's operations are subject to the requirements of NEPA, and are therefore evaluated under NEPA for their direct, indirect and cumulative environmental impacts. This is done in Environmental Assessments or Environmental Impact Statements prepared for a lead agency under Council on Environmental Quality and other agency regulations, usually for the BLM in the areas where QEP operates currently. For example, the Department of Interior’s Fish and Wildlife Service (FWS) plans to issue a proposed rule on whether to list the Lesser Prairie-Chicken as an endangered species. The Lesser Prairie-Chicken is a grouse species native to Texas including parts of the Permian Basin.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be classified as proved reserves if they relate to wells scheduled to be drilled within five years after the date of booking. SEC rules require that, subject to limited exceptions, proved undeveloped (PUD) reserves may only be classified as proved reserves if they are from wells scheduled to be drilled within five years after the date of booking. QEP may be required to write down its PUD reserves if it is not successful in drilling PUD wells within the required five-year time frame. Recovery of PUD reserves requires the expenditure of significant capital and successful drilling operations. At December 31, 2016, approximately 51% of our estimated proved reserves were PUD reserves. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, requiring an estimated $3.1 billion during the five years ending December 31, 2021. The estimated development costs may not be accurate; timing to incur such costs may change; development may not occur as scheduled; and results may not be as estimated.

Multi-well pad drilling may result in volatility in QEP operating results and delay conversion of PUD reserves. QEP utilizes multi-well pad drilling where practical. For example, in the Permian Basin, QEP utilizes “tank-style” development, in which we drill and complete all wells in a given "tank" before any individual well is turned to production. Wells drilled on a pad are not brought into production until all wells on the pad are drilled and cased and the drilling rig is moved from the location. In addition, existing wells that offset newly drilled wells may be temporarily shut-in during the drilling and completion process. As a result, multi-well pad drilling delays the completion of wells and the commencement of production, which may cause volatility in QEP's quarterly operating results. Existing wells that offset new wells being completed by QEP or offset operators may also need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP's quarterly operating results. In addition, delays in completion of wells may impact planned conversion of PUD reserves to proved developed.

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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
July 1, 2017 - July 31, 2017	—	$	—	—	$	—
August 1, 2017 - August 31, 2017	—	$	—	—	$	—
September 1, 2017 - September 30, 2017	48,769	$	7.98	—	$	—

____________________________

⁽¹⁾  All of the 48,769 shares purchased during the three-month period ended September 30, 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

Effective October 23, 2017, the Board of Directors (the "Board") of QEP approved and adopted the Amended and Restated Bylaws of the Company (the "Bylaws"), amending certain provisions of the Company’s existing bylaws.

The Bylaws revise the advance notice disclosure requirements to require the stockholder proposing business or nominating directors to provide information about the stockholder’s ownership of securities in the Company (including ownership of derivative securities) and material litigation, relationships and interests in material agreements with or involving the Company. Further, the Bylaws require the stockholder to provide additional information regarding any candidate the stockholder proposes to nominate for election as a director, including all information with respect to such nominee that would be required to be set forth in a stockholder’s notice if such nominee were a stockholder delivering such notice and a description of any direct or indirect material interest in any material contract or agreement between or among the nominating stockholder and each nominee or his or her respective associates. The Bylaws also require the stockholder to provide information regarding the proposed business and any related agreements between the stockholder and any other beneficial holder.

The Bylaws also include certain technical, conforming, modernizing and clarifying changes.

The foregoing description of the amendments is qualified in its entirety by reference to the full text of the Bylaws, a copy of which is attached as Exhibit 3.2 to this Quarterly Report on Form 10-Q and incorporated herein by reference.

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ITEM 6. EXHIBITS

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

Exhibit No.	Exhibits
3.1	Amended and Restated Certificate of Incorporation dated May 17, 2017 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 18, 2017).
3.2*	Amended and Restated Bylaws, effective October 23, 2017.
10.1*	Purchase and Sale Agreement, dated July 24, 2017, by and between QEP Energy Company, as seller, and Pinedale Energy Partners, LLC, as buyer (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed by the Company with the Securities and Exchange Commission on July 25, 2017); as amended by the First Amendment to Purchase and Sale Agreement, dated September 20, 2017, by and among QEP Energy Company, Pinedale Energy Partners, LLC and Pinedale Energy Partners Operating LLC.
10.2	Purchase and Sale Agreement, dated July 26, 2017, by and between QEP Energy Company, as buyer, and JM Cox Resources, L.P., Alpine Oil Company, and Kelly Cox, collectively as sellers (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on July 26, 2017).
10.3*+	Separation Agreement, dated as of September 15, 2017, between the Company and Matthew T. Thompson.
10.4*+	Amendment to Long Term Incentive Agreements, dated as of September 15, 2017, between the Company and Matthew T. Thompson.
31.1	Certification signed by Charles B. Stanley, QEP Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification signed by Richard J. Doleshek, QEP Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification signed by Charles B. Stanley and Richard J. Doleshek, QEP Resources, Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS**	XBRL Instance Document
101.SCH**	XBRL Schema Document
101.CAL**	XBRL Calculation Linkbase Document
101.LAB**	XBRL Label Linkbase Document
101.PRE**	XBRL Presentation Linkbase Document
101.DEF**	XBRL Definition Linkbase Document

____________________________

+ Indicates a management contract or compensatory plan or arrangement.

* Filed herewith

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

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SIGNATURES

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

	QEP RESOURCES, INC.
	(Registrant)
October 25, 2017	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer
October 25, 2017	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

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EX-3.2

AMENDED AND RESTATED BYLAWS

OF

QEP RESOURCES, INC.

As Amended and Restated on October 23, 2017

ARTICLE I

OFFICES AND RECORDS

Section 1.1Offices. The Company may have offices, either within or without the State of Delaware, as the Board of Directors may from time to time appoint or as the business of the Company may require.

Section 1.2Books and Records.The books and records of the Company may be kept at such location(s) as may from time to time be designated by the Board of Directors.

ARTICLE II

STOCKHOLDERS

Section 2.1Annual Meeting. If required by law, the annual meeting of stockholders shall be held at such date and time as shall be designated from time to time by the Board of Directors and stated in the notice of the meeting, at which meeting stockholders shall elect directors and transact such other business as may properly be brought before the meeting.

Section 2.2Special Meetings. Special meetings of the stockholders, for any proper purpose or purposes, may be called at any time only by (A) the Board of Directors pursuant to a resolution adopted by the affirmative vote of a majority of the total number of directors which the Company would have if there were no vacancies; (B) the Chairman of the Board; or (C) the President, and shall be held at such place, if any, on such date and at such time as they shall fix. Business transacted at all special meetings of the stockholders shall be confined to the purposes stated in the notice.

Section 2.3Place of Meetings. All stockholders meetings shall be held at the office of the Company in Denver, Colorado, or any other convenient location within the United States, or by means of remote communication, as the Board of Directors may fix.

Section 2.4Notice of Meetings. The Secretary shall give, but in case of his or her failure, any other officer of the Company may give, written or printed notice, stating the place, if any, day and hour of each stockholders meeting, the means of remote communications, if any, by which stockholders and proxy holders may be deemed to be present in person and vote at such meeting, the record date for determining the stockholders entitled to vote at the meeting, if such date is different from the record date for determining stockholders entitled to notice of the meeting, and, in the case of a special meeting, the purpose or purposes for which the meeting is called, to each stockholder of record entitled to vote at such meeting as of the record date for determining stockholders entitled to notice of the meeting.  Such notice shall be given not less than ten (10) nor more than sixty (60) days before the date of the meeting, and may be given personally, by mail or private carrier, by electronic transmission, or by any other means recognized under applicable state and federal law.  If given by mail, such notice shall be deemed to be delivered when deposited in the United States mail or private carrier, addressed to the stockholder at his or her address as it appears on the stock transfer books of the Company, with postage prepaid. Meetings may be held without notice if all stockholders entitled to vote are present (except as otherwise provided by law), or if notice is waived by those not present. Any previously scheduled stockholders meeting may be postponed (unless the certificate of incorporation of the Company, as amended and restated from time to time (including any certificates of designation with respect to any preferred stock, the “Certificate of Incorporation”) otherwise provides) and any special meeting of the stockholders may be cancelled by resolution of the Board of Directors upon public notice given prior to the time previously scheduled for such stockholders meeting.

Section 2.5Quorum and Adjournment. Except as otherwise provided by law, the Certificate of Incorporation or these Amended and Restated Bylaws (“Bylaws”), a majority of the outstanding voting power entitled to vote generally in the election of directors, present in person or represented by proxy, shall constitute a quorum at all stockholders meetings for the transaction of business; provided, however, that when specified business is to be voted on by a class or series voting separately as a class or series, a majority of the outstanding voting power of the shares of such class or series shall constitute a quorum for the transaction of such business. If a quorum is present at any stockholders meeting, such quorum shall not be broken by the withdrawal of enough stockholders to leave less than a quorum and the remaining stockholders may continue to transact business until adjournment. Whether or not a quorum is present, the holders of a majority of the outstanding voting power of the shares present in person or represented by proxy and entitled to vote thereon shall have the power to adjourn the meeting from time to

1

time (or, in the case of specified business to be voted on by a class or series, a majority of the outstanding voting power of such class or series present in person or represented by proxy and entitled to vote thereon may adjourn the meeting with respect to such specified business). If the adjournment is for more than thirty (30) days, a notice of the adjourned meeting shall be given to each stockholder of record entitled to vote at the meeting. If after the adjournment a new record date for determination of stockholders entitled to vote is fixed for the adjourned meeting, the Board of Directors shall fix as the record date for determining stockholders entitled to notice of such adjourned meeting the same or an earlier date as that fixed for determination of stockholders entitled to vote at the adjourned meeting, and shall give notice of the adjourned meeting to each stockholder of record as of the record date so fixed for notice of such adjourned meeting. At any adjourned meeting at which a quorum is present in person or represented by proxy, the stockholders entitled to vote at the meeting may transact any business that might have been transacted at the meeting as originally noticed.

Section 2.6Notice of Stockholder Business and Director Nominations.

(A)Annual Meeting of Stockholders.

(1)Nominations of persons for election to the Board of Directors (except as otherwise provided in the Certificate of Incorporation with respect to directors to be elected by the holders of any class or series of preferred stock) and the proposal of other business to be considered by the stockholders may be made at an annual meeting of stockholders only (i) pursuant to the Company’s notice of meeting (or any supplement thereto), (ii) by or at the direction of the Board of Directors (or any duly authorized committee thereof), (iii) by any stockholder of the Company who (a) was a stockholder of record (and, with respect to any beneficial owner, if different, on whose behalf such business is proposed, only if such beneficial owner was the beneficial owner of shares of the Company) at the time of giving of notice provided for in this Section 2.6 and at the time of the annual meeting, (b) is entitled to vote at the meeting and (c) complies with the notice procedures set forth in this Section 2.6 and Section 2.10 as to such nomination or other business or (iv) by any Eligible Stockholder (as defined in Section 2.8) in accordance with the procedures set forth in Section 2.8. Other than matters properly brought under Rule 14a-8 under the Securities Exchange Act of 1934, as amended (including any rules and regulations promulgated thereunder, the “Exchange Act”), and included in the Company’s notice of meeting given by or at the direction of the Board of Directors, the foregoing clauses (iii) and (iv) shall be the exclusive means for a stockholder to make nominations and submit other business before an annual meeting of stockholders. Stockholders shall not be permitted to propose business to be brought before a special meeting of the stockholders, and the only matters that may be brought before a special meeting are the matters specified in the notice of meeting given by or at the direction of the person calling the meeting pursuant to Section 2.2.

(2)Without qualification, for any nominations or other business to be properly brought before an annual meeting by a stockholder pursuant to Section 2.6(A)(1)(iii), the stockholder must provide timely notice thereof in writing to the Secretary of the Company and provide any updates or supplements to such notice at the times and in the forms required by this Section 2.6, and any such proposed business other than the nominations of persons for election to the Board of Directors must constitute a proper matter for stockholder action. To be timely, a stockholder’s notice to the Secretary must be delivered to or mailed and received at the principal executive offices of the Company not later than the close of business on the ninetieth (90^th) day, nor earlier than the close of business on the one hundred twentieth (120^th) day, prior to the first (1^st) anniversary of the immediately preceding year’s annual meeting; provided, however, that in the event that the annual meeting is called for a date that is more than thirty (30) days before or more than sixty (60) days after such anniversary date, notice by the stockholder must be so delivered not earlier than the close of business on the one hundred twentieth (120^th) day prior to such annual meeting and not later than the close of business on the later of the ninetieth (90^th) day prior to such annual meeting or, if the first public announcement of the date of such annual meeting is less than one hundred (100) days prior to the date of such annual meeting, the tenth (10^th) day following the day on which public announcement of the date of such meeting is first made by the Company. In no event shall any adjournment or postponement of an annual meeting or the public announcement thereof commence a new time period (or extend any time period) for the giving of a stockholder’s notice as described above.

(3)To be in proper written form for purposes of Section 2.6(A)(1)(iii), a stockholder’s notice must:

(i)set forth, as to each Proposing Person (as defined below) (a) the name and address of such Proposing Person (as they appear on the Company’s books if such Proposing Person is a record holder); (b) (A) the class or series and number of shares of the Company which are, directly or indirectly, beneficially owned (within the meaning of Rule 13d-3 under the Exchange Act) and of record by such Proposing Person, except that such Proposing Person shall in all events be deemed to beneficially own any shares of any class or series of the Company as to which such Proposing Person has a right to acquire beneficial ownership at any time in the future, (B) the full notional amount of any securities that, directly or indirectly, underlie any “derivative security” (as such term is defined in Rule 16a-1(c) under the Exchange Act) that constitutes a “call equivalent position” (as such term is defined in Rule 16a-1(b) under the Exchange Act) (“Synthetic Equity Position”) and that is, directly or indirectly, held or maintained by such Proposing

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Person with respect to any shares of any class or series of shares of the Company; provided that, for the purposes of the definition of “Synthetic Equity Position,” the term “derivative security” shall also include any security or instrument that would not otherwise constitute a “derivative security” as a result of any feature that would make any conversion, exercise or similar right or privilege of such security or instrument becoming determinable only at some future date or upon the happening of a future occurrence, in which case the determination of the amount of securities into which such security or instrument would be convertible or exercisable shall be made assuming that such security or instrument is immediately convertible or exercisable at the time of such determination; and, provided, further, that any Proposing Person satisfying the requirements of Rule 13d-1(b)(1) under the Exchange Act (other than a Proposing Person that so satisfies Rule 13d-1(b)(1) under the Exchange Act solely by reason of Rule 13d-1(b)(1)(ii)(E)) shall not be deemed to hold or maintain the notional amount of any securities that underlie a Synthetic Equity Position held by such Proposing Person as a hedge with respect to a bona fide derivatives trade or position of such Proposing Person arising in the ordinary course of such Proposing Person's business as a derivatives dealer, (C) any rights to dividends on the shares of the Company owned beneficially by such Proposing Person that are separated or separable from the underlying shares of the Company, (D) any direct or indirect material interest in any material contract or agreement of such Proposing Person with the Company or any affiliate of the Company (including, in any such case, any employment agreement, collective bargaining agreement or consulting agreement), (E) any material pending or threatened legal proceeding in which such Proposing Person is a party or material participant involving the Company or any of its officers or directors, or any affiliate of the Company, (F) any other material relationship between such Proposing Person, on the one hand, and the Company, any affiliate of the Company, on the other hand (the disclosures to be made pursuant to the foregoing clauses (B) through (F) are referred to as “Disclosable Interests”); provided, however, that Disclosable Interests shall not include any such disclosures with respect to the ordinary course business activities of any broker, dealer, commercial bank, trust company or other nominee who is a Proposing Person solely as a result of being the stockholder directed to prepare and submit the notice required by these Bylaws on behalf of a beneficial owner; (c) any other information relating to such Proposing Person that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for, as applicable, the proposal and/or for the election of directors in a contested election pursuant to Section 14 of the Exchange Act and the rules and regulations promulgated thereunder; (d) a representation as to whether such Proposing Person intends or is part of a group which intends (A) to deliver a proxy statement and/or form of proxy to holders of at least the percentage of the Company’s outstanding capital stock required to approve or adopt the proposal or elect the nominee and/or (B) otherwise to solicit proxies from stockholders in support of such proposal or nomination; and (e) a representation that the stockholder is a holder of record of stock of the Company entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to propose such business or nomination;

(ii)if the notice relates to any business other than a nomination of a director or directors that the stockholder proposes to bring before the meeting, set forth (a) a brief description of the business desired to be brought before the meeting (including the text of any resolutions proposed for consideration and, in the event that such business includes a proposal to amend the Bylaws of the Company, the language of the proposed amendment), the reasons for conducting such business at the meeting and any material interest of such Proposing Person in such business, (b) a reasonably detailed description of all agreements, arrangements and understandings (y) between or among any of the Proposing Persons or (z) between or among any Proposing Person and any other person or entity (including their names) in connection with the proposal of such business by such stockholder and (c) any other information relating to such item of business that would be required to be disclosed in a proxy statement or other filing required to be made in connection with solicitations of proxies in support of the business proposed to be brought before the meeting pursuant to Section 14(a) of the Exchange Act; provided, however, that the disclosures required by this paragraph (ii) shall not include any disclosures with respect to any broker, dealer, commercial bank, trust company or other nominee who is a Proposing Person solely as a result of being the stockholder directed to prepare and submit the notice required by these Bylaws on behalf of a beneficial owner; and

(iii)set forth, as to each person, if any, whom the Proposing Person proposes to nominate for election or reelection to the Board of Directors pursuant to Section 2.6(A)(1)(iii), (a) all information with respect to such candidate for nomination that would be required to be set forth in a stockholder’s notice pursuant to this Section 2.6 and Section 2.10 if such candidate for nomination were a Proposing Person, (b) all information relating to such person that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations of proxies for election of directors in a contested election pursuant to Section 14 of the Exchange Act and the rules and regulations promulgated thereunder (including such person’s written consent to being named in the proxy statement as a nominee and to serving as a director if elected) and (c) a description of all direct and indirect compensation and other material monetary agreements, arrangements and understandings during the past three years, and any other material relationships, between or among any Proposing Person, on the one hand, and each proposed nominee, and his or her respective affiliates and associates, on the other hand, including, without limitation, all information that would be

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required to be disclosed pursuant to Rule 404 promulgated under Regulation S-K if the Proposing Person were the “registrant” for purposes of such rule and the nominee were a director or executive officer of such registrant.

(4)Notwithstanding anything in the second sentence of Section 2.6(A)(2) to the contrary, in the event that the number of directors to be elected to the Board of Directors at an annual meeting is increased and there is no public announcement by the Company naming the nominees for the additional directorships at least one hundred (100) days prior to the first (1^st) anniversary of the preceding year’s annual meeting, a stockholder’s notice required by this Section 2.6 shall also be considered timely, but only with respect to nominees for the additional directorships, if it shall be delivered to the Secretary at the principal executive offices of the Company not later than the close of business on the tenth (10^th) day following the day on which such public announcement is first made by the Company.

(B)Special Meetings of Stockholders. Only such business shall be conducted at a special meeting of stockholders as shall have been brought before the meeting pursuant to the Company’s notice of meeting. Nominations of persons for election to the Board of Directors may be made at a special meeting of stockholders at which directors are to be elected pursuant to the Company’s notice of meeting (1) by or at the direction of the Board of Directors (or a duly authorized committee thereof) or (2) provided that the Board of Directors has determined that directors shall be elected at such meeting, by any stockholder of the Company who (i) is a stockholder of record (and, with respect to any beneficial owner, if different, on whose behalf such business is proposed, only if such beneficial owner was the beneficial owner of shares of the Company) at the time of giving of notice provided for in this Section 2.6 and at the time of the special meeting, (ii) is entitled to vote at the meeting and (iii) complies with the notice procedures set forth in this Section 2.6 as to such nomination. In the event the Company calls a special meeting of stockholders for the purpose of electing one or more directors to the Board of Directors, any such stockholder entitled to vote in such election of directors may nominate a person or persons (as the case may be) for election to such position(s) as specified in the Company’s notice of meeting, if the stockholder’s notice required by paragraphs (A)(2) and (A)(3) of this Section 2.6 with respect to any nomination (including the completed and signed questionnaire, representation and agreement required by Section 2.10) shall be delivered to the Secretary at the principal executive offices of the Company not earlier than the close of business on the one hundred twentieth (120^th) day prior to such special meeting and not later than the close of business on the later of the ninetieth (90^th) day prior to such special meeting or if the first public announcement of the date of such special meeting is less than one hundred (100) days prior to the date of such special meeting, the tenth (10^th) day following the day on which public announcement is first made of the date of the special meeting and of the nominees proposed by the Board of Directors to be elected at such meeting. In no event shall any adjournment or postponement of a special meeting or the public announcement thereof commence a new time period (or extend any time period) for the giving of a stockholder’s notice as described above.

(C)General.

(1)Only such persons who are nominated in accordance with the procedures set forth in this Section 2.6 or Section 2.8, as applicable, shall be eligible to be elected at an annual or special meeting of stockholders of the Company to serve as directors and only such business shall be conducted at a stockholders meeting as shall have been brought before the meeting in accordance with the procedures set forth in this Section 2.6. Except as otherwise provided by law, the Certificate of Incorporation or these Bylaws, the chairman of the meeting shall have the power and duty (i) to determine whether a nomination or any business proposed to be brought before the meeting was made or proposed, as the case may be, in accordance with the procedures set forth in this Section 2.6 (including whether the Proposing Person solicited (or is part of a group which solicited) or did not so solicit, as the case may be, proxies in support of such Proposing Person’s nominee or proposal in compliance with such Proposing Person’s representation as required by clause (A)(3)(i)(d) of this Section 2.6) or Section 2.8, as applicable, and (ii) if any proposed nomination or business was not made or proposed in compliance with this Section 2.6 or Section 2.8, as applicable, to declare that such nomination shall be disregarded or that such proposed business shall not be transacted. Notwithstanding the foregoing provisions of this Section 2.6 or Section 2.8, as applicable, unless otherwise required by law, if the stockholder (or a qualified representative of the stockholder) does not appear at the annual or special meeting of stockholders of the Company to present a nomination or proposed business, such nomination shall be disregarded and such proposed business shall not be transacted, notwithstanding that proxies in respect of such vote may have been received by the Company. For purposes of this Section 2.6 or Section 2.8, as applicable, to be considered a qualified representative of the stockholder, a person must be authorized by a writing executed by such stockholder or an electronic transmission delivered by such stockholder to act for such stockholder as proxy at the meeting of stockholders and such person must produce such writing or electronic transmission, or a reliable reproduction of the writing or electronic transmission, at the meeting of stockholders.

(2)For purposes of this Section 2.6 and Section 2.8, as applicable, “public announcement” shall include disclosure in a press release reported by the Dow Jones News Service, Associated Press or comparable national news service or in a document publicly filed by the Company with the Securities and Exchange Commission (the “Commission”) pursuant to Section 13, 14 or 15(d) of the Exchange Act and the rules and regulations promulgated thereunder.

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(3)For purposes of this Section 2.6, the term “Proposing Person”shall mean (i) the stockholder providing the notice of the nomination or other business proposed to be brought before a meeting, (ii) the beneficial owner or beneficial owners, if different, on whose behalf the notice of the nomination or other business proposed to be brought before the meeting is made and (iii) any participant (as defined in paragraphs (a)(ii)-(vi) of Instruction 3 to Item 4 of Schedule 14A) with such stockholder in such solicitation.

(4)A Proposing Person shall further update and supplement its notice pursuant to this Section 2.6, if necessary, so that the information provided or required to be provided in such notice pursuant to this Section 2.6 shall be true and correct as of the record date for stockholders entitled to vote at the meeting and as of the date that is ten (10) business days prior to the meeting or any adjournment or postponement thereof, and such update and supplement shall be delivered to, or mailed and received by, the Secretary at the principal executive offices of the Company not later than five (5) business days after the record date for stockholders entitled to vote at the meeting (in the case of the update and supplement required to be made as of the record date), and not later than eight (8) business days prior to the date for the meeting or, if practicable, any adjournment or postponement thereof (and, if not practicable, on the first practicable date prior to the date to which the meeting has been adjourned or postponed) (in the case of the update and supplement required to be made as of ten (10) business days prior to the meeting or any adjournment or postponement thereof).

(5)Notwithstanding the foregoing provisions of this Section 2.6, a stockholder shall also comply with all applicable requirements of the Exchange Act with respect to the matters set forth in this Section 2.6; provided, however, that any references in these Bylaws to the Exchange Act or the rules and regulations promulgated thereunder are not intended to and shall not limit the requirements applicable to nominations or proposals to any other business to be considered pursuant to this Section 2.6. Nothing in this Section 2.6 shall be deemed to affect any rights (i) of stockholders to request inclusion of proposals or nominations in the Company’s proxy statement pursuant to applicable rules and regulations promulgated under the Exchange Act, (ii) of the holders of any series of preferred stock to elect directors pursuant to any applicable provisions of the Certificate of Incorporation or these Bylaws or (iii) of any Eligible Stockholder to request inclusion of a Nominee (as defined in Section 2.8) in the Company’s proxy statement pursuant to Section 2.8.

Section 2.7Voting of Shares.

(A)Voting Lists.The officer who has charge of the stock ledger shall prepare and make, at least ten (10) days before every stockholders meeting, a complete list of the stockholders entitled to vote at the meeting; provided, however, if the record date for determining the stockholders entitled to vote is less than ten (10) days before the meeting date, the list shall reflect the stockholders entitled to vote as of the tenth (10^th) day before the meeting date, arranged in alphabetical order, and showing the address of each stockholder and the number of shares registered in the name of each stockholder. Such list shall be open to the examination of any stockholder, for any purpose germane to the meeting, at least ten (10) days prior to the meeting (1) on a reasonably accessible electronic network, provided that the information required to gain access to such list is provided with the notice of meeting or (2) during ordinary business hours at the principal place of business of the Company. The list of stockholders must also be open to examination at the meeting as required by applicable law, and may be inspected by any stockholder who is present. Except as otherwise provided by law, the stock ledger shall be the only evidence as to who are the stockholders entitled to examine the list of stockholders required by this Section 2.7(A) or to vote in person or by proxy at any stockholders meeting. Failure to comply with the requirements of this Section 2.7(A) shall not affect the validity of any action taken at said meeting.

(B)Votes Per Share. Except as otherwise provided by or pursuant to the provisions of the Certificate of Incorporation, each stockholder shall have one vote for each share of stock registered in the stockholder’s name on the books of the Company as of the record date set for such meeting.

(C)Manner of Voting. At any stockholders meeting, each stockholder entitled to vote may vote in person or by proxy as provided herein. Voting at any stockholders meeting need not be by ballot.

(D)Proxies. At any stockholders meeting, each stockholder having the right to vote or to express consent without a meeting, or such stockholder’s duly authorized attorney-in-fact, shall be entitled to vote by proxy. Each proxy shall be in writing, executed by the stockholder giving the proxy or by such stockholder’s duly authorized attorney-in-fact, or electronically transmitted to the proxy holder in a manner such that it can be determined that the transmission was authorized by the stockholder. No proxy shall be voted on or after three years from its date, unless the proxy provides for a longer period. The proxy must be filed with the Secretary of the Company or such stockholder’s representative at or before the time of the meeting. Unless and until voted, every proxy shall be revocable at the pleasure of the person who executed it, or such person’s legal representatives or assigns, except in those cases where an irrevocable proxy permitted by statute has been given.

(E)Required Vote. Except as provided in Section 3.4 of these Bylaws, each director shall be elected by the majority of the votes cast with respect to the director at any meeting for the election of directors at which a quorum is present,

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provided that if as of a date that is fourteen (14) days in advance of the date the Company files its definitive proxy statement (regardless of whether or not thereafter revised or supplemented) with the Commission the number of nominees exceeds the number of directors to be elected, the directors shall be elected by the vote of a plurality of the shares represented in person or by proxy at any such meeting and entitled to vote on the election of directors. For purposes of this section, a majority of the votes cast means that the number of shares voted “for” a director must exceed the number of votes cast “against” and/or “withheld” with respect to that director. Except as otherwise provided by the Certificate of Incorporation, these Bylaws, or the rules and regulations applicable to the Company or its securities, all other matters shall be determined by the affirmative vote of a majority of the outstanding voting power of the shares present in person or represented by proxy and entitled to vote on the matter.

(F)Stockholder Action by Written Consent. Any action required or permitted to be taken at any annual or special meeting of stockholders of the Company may be taken without a meeting, without prior notice and without a vote, if a consent or consents in writing, setting forth the action so taken, shall be signed by the holders of outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting at which all shares entitled to vote thereon were present and voted and shall be delivered to the Company by delivery to its registered office in the State of Delaware, its principal place of business, or an officer or agent of the Company having custody of the books in which proceedings of meetings of stockholders are recorded; provided,however, at any time when Questar Corporation is the record owner, in the aggregate, of less than all of the voting power of all outstanding shares of stock of the Company entitled to vote generally in the election of directors, any action required or permitted to be taken at any annual or special meeting of stockholders of the Company must be effected at a duly called annual or special meeting of such holders and may not be effected by any consent in writing by such holders; provided,however, that any action required or permitted to be taken by the holders of preferred stock, voting separately as a series or separately as a class with one or more other such series, may be taken without a meeting, without prior notice and without a vote, to the extent expressly so provided by the applicable certificate of designations relating to such series of preferred stock. Delivery made to the Company shall be by hand or by certified or registered mail, return receipt requested. So long as action by written consent is permitted by this Section 2.7(F), every written consent shall bear the date of signature of each stockholder who signs the consent and no written consent shall be effective to take the corporate action referred to therein unless, within sixty (60) days of the earliest dated consent delivered in the manner required by this Section 2.7(F) to the Company, written consents signed by a sufficient number of holders to take action are delivered to the Company.

(G)Inspectors of Elections. The Board of Directors by resolution shall, if required by law, appoint one or more inspectors, which inspector or inspectors may include individuals who serve the Company in other capacities, including, without limitation, as officers, employees, agents or representatives of the Company, to act at the meeting and make a written report thereof. One or more persons may be designated as alternate inspectors to replace any inspector who fails to act. If no inspector or alternate has been appointed to act, or if all inspectors or alternates who have been appointed are unable to act, at a stockholders meeting, the chairman of the meeting shall appoint one or more inspectors to act at the meeting. Each inspector, before discharging his or her duties, shall take and sign an oath faithfully to execute the duties of inspector with strict impartiality and according to the best of his or her ability. The inspectors shall have the duties prescribed by the General Corporation Law of the State of Delaware (the “DGCL”).

(H)Opening and Closing the Polls. The chairman of the meeting shall fix and announce at the meeting the date and time of the opening and the closing of the polls for each matter upon which the stockholders will vote at a meeting.

Section 2.8Proxy Access.

(A)Subject to the provisions of this Section 2.8, if any Eligible Stockholder or group of up to twenty (20) Eligible Stockholders submits to the Company a Proxy Access Notice that complies with this Section 2.8 and such Eligible Stockholder or group of Eligible Stockholders otherwise satisfies all the terms and conditions of this Section 2.8 (such Eligible Stockholder or group of Eligible Stockholders, a “Nominating Stockholder”), the Company shall include in its proxy statement or on its form of proxy and ballot, as applicable (collectively, “proxy materials”), for any annual meeting of stockholders, in addition to any persons nominated for election by the Board of Directors or any committee thereof:

(1)the name of any person or persons nominated by such Nominating Stockholder for election to the Board of Directors at such annual meeting of stockholders who meets the requirements of this Section 2.8 (a “Nominee”);

(2)disclosure about the Nominee and the Nominating Stockholder required under the rules of the Commission or other applicable law to be included in the proxy materials;

(3)subject to the other applicable provisions of this Section 2.8, a written statement, not to exceed five hundred (500) words, that is not contrary to any of the Commission’s proxy rules, including Rule 14a-9 under the Exchange Act (a “Supporting Statement”), included by the Nominating Stockholder in the Proxy Access Notice intended for inclusion in the proxy materials in support of the Nominee’s election to the Board of Directors; and

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(4)any other information that the Company or the Board of Directors determines, in its discretion, to include in the proxy materials relating to the nomination of the Nominee, including, without limitation, any statement in opposition to the nomination and any of the information provided pursuant to this Section 2.8.

(B)Maximum Number of Nominees.

(1)The Company shall not be required to include in the proxy materials for an annual meeting of stockholders more Nominees than that number of directors constituting twenty percent (20%) of the total number of directors of the Company on the last day on which a Proxy Access Notice may be submitted pursuant to this Section 2.8 (rounded down to the nearest whole number, but not less than two (2)) (the “Maximum Number”). The Maximum Number for a particular annual meeting shall be reduced by: (A) the number of Nominees who are subsequently withdrawn or that the Board of Directors itself decides to nominate for election at such annual meeting of stockholders (including, without limitation, any person who is or will be nominated by the Board of Directors pursuant to any agreement or understanding with one or more stockholders to avoid such person being formally proposed as a Nominee), and (B) the number of incumbent directors who had been Nominees with respect to any of the preceding two (2) annual meetings of stockholders and whose reelection at the upcoming annual meeting of stockholders is being recommended by the Board of Directors (including, without limitation, any person who was nominated by the Board of Directors pursuant to any agreement or understanding with one or more stockholders to avoid such person being formally proposed as a Nominee). In the event that one or more vacancies for any reason occurs on the Board of Directors after the deadline set forth in Section 2.8(D) but before the date of the annual meeting of stockholders, and the Board of Directors resolves to reduce the size of the Board of Directors in connection therewith, the Maximum Number shall be calculated based on the number of directors as so reduced.

(2)Any Nominating Stockholder submitting more than one Nominee for inclusion in the Company’s proxy materials shall rank such Nominees based on the order that the Nominating Stockholder desires such Nominees to be selected for inclusion in the Company’s proxy materials in the event that the total number of Nominees submitted by Nominating Stockholders exceeds the Maximum Number. In the event that the number of Nominees submitted by Nominating Stockholders exceeds the Maximum Number, the highest ranking Nominee from each Nominating Stockholder will be included in the Company’s proxy materials until the Maximum Number is reached, going in order from largest to smallest of the number of shares of common stock of the Company owned by each Nominating Stockholder as disclosed in each Nominating Stockholder’s Proxy Access Notice. If the Maximum Number is not reached after the highest ranking Nominee of each Nominating Stockholder has been selected, this process will be repeated as many times as necessary until the Maximum Number is reached. If, after the deadline for submitting a Proxy Access Notice as set forth in Section 2.8(D), a Nominating Stockholder ceases to satisfy the requirements of this Section 2.8 or withdraws its nomination or a Nominee ceases to satisfy the requirements of this Section 2.8 or becomes unwilling or unable to serve on the Board of Directors, whether before or after the mailing of definitive proxy materials, then the nomination shall be disregarded, and the Company: (A) shall not be required to include in its proxy materials the disregarded Nominee and (B) may otherwise communicate to its stockholders, including without limitation by amending or supplementing its proxy materials, that the Nominee will not be included as a Nominee in the proxy materials and the election of such Nominee will not be voted on at the annual meeting of stockholders.

(C)Eligibility of Nominating Stockholder.

(1)An “Eligible Stockholder” is a person who has either (A) been a record holder of the shares of common stock used to satisfy the eligibility requirements in this Section 2.8(C) continuously for the three-year period specified in Subsection (2) below or (B) provides to the Secretary of the Company, within the time period referred to in Section 2.8(D), evidence of continuous ownership of such shares for such three-year period from one or more securities intermediaries in a form that satisfies the requirements as established by the Commission for a stockholder proposal under Rule 14a-8 under the Exchange Act.

(2)An Eligible Stockholder or group of up to twenty (20) Eligible Stockholders may submit a nomination in accordance with this Section 2.8 only if the person or each member of the group, as applicable, has continuously owned at least the Minimum Number (as defined below) of shares of the Company’s outstanding common stock throughout the three-year period preceding and including the date of submission of the Proxy Access Notice, and continues to own at least the Minimum Number through the date of the annual meeting of stockholders. Two (2) or more funds that are (A) under common management and investment control, (B) under common management and funded primarily by a single employer or (C) a “group of investment companies,” as such term is defined in Section 12(d)(1)(G)(ii) of the Investment Company Act of 1940, as amended, (two (2) or more funds referred to under any of clause (A), (B) or (C), collectively a “Qualifying Fund”) shall be treated as one Eligible Stockholder. For the avoidance of doubt, in the event of a nomination by a group of Eligible Stockholders, any and all requirements and obligations for an individual Eligible Stockholder that are set forth in this Section 2.8, including the minimum holding period, shall apply to each member of such group; provided, however, that the Minimum Number shall apply to the ownership of the group in the aggregate. Should any stockholder withdraw from a group of Eligible Stockholders at any time

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prior to the annual meeting of stockholders, the group of Eligible Stockholders shall only be deemed to own the shares held by the remaining members of the group.

(3)The “Minimum Number” of shares of the Company’s common stock means three percent (3%) of the number of outstanding shares of common stock as of the most recent date for which such amount is given in any filing by the Company with the Commission prior to the submission of the Proxy Access Notice.

(4)For purposes of this Section 2.8, an Eligible Stockholder “owns” only those outstanding shares of the common stock of the Company as to which the Eligible Stockholder possesses both:

(i)the full voting and investment rights pertaining to the shares; and

(ii)the full economic interest in (including the opportunity for profit and risk of loss on) such shares;

provided, that the number of shares calculated in accordance with clauses (1) and (2) shall not include any shares: (a) sold by such Eligible Stockholder or any of its affiliates in any transaction that has not been settled or closed, (b) borrowed by such Eligible Stockholder or any of its affiliates for any purpose or purchased by such Eligible Stockholder or any of its affiliates pursuant to an agreement to resell, or (c) subject to any option, warrant, forward contract, swap, contract of sale, other derivative or similar agreement entered into by such Eligible Stockholder or any of its affiliates, whether any such instrument or agreement is to be settled with shares, cash or other property based on the notional amount or value of outstanding shares of the Company, in any such case which instrument or agreement has, or is intended to have, the purpose or effect of: (A) reducing in any manner, to any extent or at any time in the future, such Eligible Stockholder’s or any of its affiliates’ full right to vote or direct the voting of any such shares, and/or (B) hedging, offsetting, or altering to any degree, gain or loss arising from the full economic ownership of such shares by such Eligible Stockholder or any of its affiliates. An Eligible Stockholder “owns” shares held in the name of a nominee or other intermediary so long as the Eligible Stockholder retains the right to instruct how the shares are voted with respect to the election of directors and possesses the full economic interest in the shares. An Eligible Stockholder’s ownership of shares shall be deemed to continue during any period in which the Eligible Stockholder has delegated any voting power by means of a proxy, power of attorney, or other similar instrument or arrangement that is revocable at any time by the Eligible Stockholder. An Eligible Stockholder’s ownership of shares shall be deemed to continue during any period in which the Eligible Stockholder has loaned such shares; provided that the Eligible Stockholder has the power to recall such loaned shares on no more than three (3) business days’ notice and includes in the Proxy Access Notice an agreement that it will (A) recall such loaned shares as of the record date for determining the stockholders entitled to vote at the annual meeting and (B) continue to hold such recalled shares (including the right to vote such shares) through the date of the annual meeting of stockholders. The terms “owned,” “owning” and other variations of the word “own” shall have correlative meanings. Each Nominating Stockholder shall furnish any other information that may reasonably be required by the Board of Directors to verify such stockholder’s continuous ownership of at least the Minimum Number during the three-year period referred to above.

(5)No person may be in more than one group constituting a Nominating Stockholder, and if any person appears as a member of more than one group, it shall be deemed to be a member of the group that owns the greatest aggregate number of shares of the Company’s common stock as reflected in the Proxy Access Notice, and no shares may be attributed as owned by more than one person constituting a Nominating Stockholder under this Section 2.8.

(D)To nominate a Nominee, the Nominating Stockholder must, no earlier than one hundred twenty (120) calendar days and no later than ninety (90) calendar days before the date of the Company’s proxy materials released to stockholders in connection with the previous year’s annual meeting of stockholders, submit to the Secretary of the Company at the principal executive office of the Company all of the following information and documents (collectively, the “Proxy Access Notice”):

(1)A Schedule 14N (or any successor form) relating to the Nominee, completed and filed with the Commission by the Nominating Stockholder as applicable, in accordance with the Commission’s rules;

(2)A written notice of the nomination of such Nominee that includes the following additional information, agreements, representations and warranties by the Nominating Stockholder (including each group member):

(i)the information, representations and agreements required with respect to the nomination of directors pursuant to Section 2.6 of these Bylaws;

(ii)the details of any relationship that existed within the past three years and that would have been described pursuant to Item 6(e) of Schedule 14N (or any successor item) if it existed on the date of submission of the Schedule 14N;

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(iii)a representation and warranty that the Nominating Stockholder did not acquire, and is not holding, securities of the Company for the purpose or with the effect of influencing or changing control of the Company;

(iv)a representation and warranty that the Nominee’s candidacy or, if elected, Board of Directors membership, would not violate the Certificate of Incorporation, these Bylaws, or any applicable state or federal law or the rules of any stock exchange on which the Company’s common stock is traded;

(v)a representation and warranty that the Nominee:

(a)does not have any direct or indirect material relationship with the Company and otherwise would qualify as an “independent director” under the rules of the primary stock exchange on which the Company’s common stock is traded and any applicable rules of the Commission;

(b)would meet the audit committee independence requirements under the rules of the Commission and of the principal stock exchange on which the Company’s common stock is traded;

(c)would qualify as a “non-employee director” for the purposes of Rule 16b-3 under the Exchange Act (or any successor rule);

(d)would qualify as an “outside director” for the purposes of Section 162(m) of the Internal Revenue Code of 1986, as amended (or any successor provision);

(e)is not and has not been, within the past three years, an officer, director, affiliate or representative of a competitor, as defined under Section 8 of the Clayton Antitrust Act of 1914, as amended, and if the Nominee has held any such position during this period, details thereof; and

(f)is not and has not been subject to any event specified in Rule 506(d)(1) of Regulation D (or any successor rule) under the Securities Act of 1933, as amended, or Item 401(f) of Regulation S-K (or any successor rule) under the Exchange Act, without reference to whether the event is material to an evaluation of the ability or integrity of the Nominee;

(vi)a representation and warranty that the Nominating Stockholder satisfies the eligibility requirements set forth in Section 2.8(C), has provided evidence of ownership to the extent required by Section 2.8(C)(1), and such evidence of ownership is true, complete and correct in all respects;

(vii)a representation and warranty that the Nominating Stockholder intends to continue to satisfy the eligibility requirements described in Section 2.8(C) through the date of the annual meeting of stockholders;

(viii)a statement as to whether or not the Nominating Stockholder intends to continue to hold the Minimum Number of shares for at least one (1) year following the annual meeting of stockholders, which statement may also include a description as to why such Nominating Stockholder is unable to make the foregoing statement;

(ix)a representation and warranty that the Nominating Stockholder will not engage in or support, directly or indirectly, a “solicitation” within the meaning of Rule 14a-1(l) (without reference to the exception in Section 14a-1(l)(2)(iv)) (or any successor rules) with respect to the annual meeting of stockholders, other than a solicitation in support of the Nominee or any nominee of the Board of Directors;

(x)a representation and warranty that the Nominating Stockholder will not use any proxy card other than the Company’s proxy card in soliciting stockholders in connection with the election of a Nominee at the annual meeting of stockholders;

(xi)if desired by the Nominating Stockholder, a Supporting Statement;

(xii)in the case of a nomination by a group, the designation by all group members of one group member that is authorized to act on behalf of all group members with respect to matters relating to the nomination, including withdrawal of the nomination;

(xiii)in the case of any Eligible Stockholder that is a Qualifying Fund consisting of two (2) or more funds, documentation demonstrating that the funds are eligible to be treated as a Qualifying Fund and that each such fund comprising the Qualifying Fund otherwise meets the requirements set forth in this Section 2.8; and

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(xiv)a representation and warranty that the Nominating Stockholder has not nominated and will not nominate for election any individual as director at the annual meeting of stockholders other than its Nominee(s).

(3)An executed agreement pursuant to which the Nominating Stockholder (including each group member) agrees:

(i)to comply with all applicable laws, rules and regulations in connection with the nomination, solicitation and election;

(ii)to file with the Commission any solicitation or other communication with the Company’s stockholders relating to any Nominee or one or more of the Company’s directors or director nominees, regardless of whether any such filing is required under any law, rule or regulation or whether any exemption from filing is available for such materials under any law, rule or regulation;

(iii)to assume all liability stemming from an action, suit or proceeding concerning any actual or alleged legal or regulatory violation arising out of any communication by the Nominating Stockholder with the Company, its stockholders or any other person in connection with the nomination or election of directors, including, without limitation, the Proxy Access Notice;

(iv)to indemnify and hold harmless (jointly and severally with all other group members, in the case of a group member) the Company and each of its directors, officers and employees individually against any liability, loss, damages, expenses, demands, claims or other costs (including reasonable attorneys’ fees and disbursements of counsel) incurred in connection with any threatened or pending action, suit or proceeding, whether legal, administrative or investigative, against the Company or any of its directors, officers or employees arising out of any nomination submitted by the Nominating Stockholder (including, without limitation, relating to any breach or alleged breach of its obligations, agreements, representations or warranties) pursuant to this Section 2.8;

(v)in the event that (a) any information included in the Proxy Access Notice, or any other communication by the Nominating Stockholder (including with respect to any group member) with the Company, its stockholders or any other person in connection with the nomination or election of directors ceases to be true and accurate in all material respects (or omits a material fact necessary to make the statements made not misleading), or (b) the Nominating Stockholder (including any group member) fails to continue to satisfy the eligibility requirements described in Section 2.8(C), the Nominating Stockholder shall promptly (and in any event within 48 hours of discovering such misstatement, omission or failure) (A) in the case of clause (a) above, notify the Company and any other recipient of such communication of the misstatement or omission in such previously provided information and of the information that is required to correct the misstatement or omission, and (B) in the case of clause (b) above, notify the Company why, and in what regard, the Nominating Stockholder fails to comply with the eligibility requirements described in Section 2.8(C) (it being understood that providing any such notification referenced in clauses (A) and (B) above shall not be deemed to cure any defect or limit the Company’s rights to omit a Nominee from its proxy materials as provided in this Section 2.8); and

(4)An executed agreement by the Nominee:

(i)to provide to the Company a completed copy of the Company’s director questionnaire and such other information as the Company may reasonably request;

(ii)that the Nominee (a) consents to be named in the proxy materials as a nominee and, if elected, to serve on the Board of Directors and (b) has read and agrees to adhere to the Company’s Corporate Governance Guidelines and any other Company policies and guidelines applicable to directors generally; and

(iii)that the Nominee is not and will not become a party to (a) any agreement, arrangement or understanding with any person or entity other than the Company with respect to any direct or indirect compensation, reimbursement or indemnification (a “Compensation Agreement”) in connection with the Nominee’s nomination or candidacy as a director of the Company that has not been disclosed to the Company in writing, (b) any Compensation Agreement in connection with the Nominee’s service or action as a director of the Company, (c) any Voting Commitment that has not been disclosed to the Company in writing, or (d) any Voting Commitment that could limit or interfere with the Nominee’s ability to comply, if elected as a director of the Company, with its fiduciary duties under applicable law or with the Company’s Corporate Governance Guidelines and any other Company policies and guidelines applicable to directors generally.

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The information and documents required by this Section 2.8(D) shall be: (A) provided with respect to and executed by each group member, in the case of information applicable to group members; and (B) provided with respect to the persons specified in Instruction 1 to Items 6(c) and (d) of Schedule 14N (or any successor item) if and to the extent applicable to a Nominating Stockholder or group member. The Proxy Access Notice shall be deemed submitted on the date on which all the information and documents referred to in this Section 2.8(D) (other than such information and documents contemplated to be provided after the date the Proxy Access Notice is provided) have been delivered to or, if sent by mail, received by the Secretary of the Company. For the avoidance of doubt, in no event shall any adjournment or postponement of an annual meeting of stockholders or the public announcement thereof commence a new time period for the giving of a Proxy Access Notice pursuant to this Section 2.8.

(E)Conditional Resignation of Nominee.

(1)Any Nominee who is included in the Company’s proxy materials for election at an annual meeting of stockholders pursuant to this Section 2.8 shall, upon its election as a Director, deliver to the Company an executed, irrevocable resignation as a director of the Company, in a form to be provided to the Nominee by the Company, which resignation shall automatically be effective upon a determination by the Board of Directors or any committee thereof that (i) the information provided pursuant to this Section 2.8 to the Company by such Nominee or the Nominating Stockholder (or each member of any group of Eligible Stockholders comprising such Nominating Stockholder) was untrue in any material respect or omitted to state a material fact necessary in order to make the statements made, in light of the circumstances under which they were made, not misleading, or (ii) such Nominee or the Nominating Stockholder (or any member of any group of Eligible Stockholders comprising such Nominating Stockholder) shall have breached or failed to comply in any material respect with its agreements, representations or warranties pursuant to these By-laws, including this Section 2.8.

(F)Exceptions and Clarifications.

(1)Notwithstanding anything to the contrary contained in this Section 2.8, (a) the Company may omit from its proxy materials any Nominee and any information concerning such Nominee (including a Nominating Stockholder’s Supporting Statement), (b) any nomination shall be disregarded, and (c) no vote on such Nominee will occur (notwithstanding that proxies in respect of such vote may have been received by the Company), and the Nominating Stockholder may not, after the last day on which a Proxy Access Notice would be timely, cure in any way any defect preventing the nomination of the Nominee, if:

(i)the Company receives a notice pursuant to Section 2.6 of these Bylaws that a stockholder intends to nominate a candidate for director at the annual meeting of stockholders;

(ii)the Nominating Stockholder or the designated lead group member, as applicable, or any qualified representative thereof, does not appear at the annual meeting of stockholders to present the nomination submitted pursuant to this Section 2.8 or the Nominating Stockholder withdraws its nomination prior to the annual meeting of stockholders;

(iii)the Board of Directors determines that such Nominee’s nomination or election to the Board of Directors would result in the Company violating or failing to be in compliance with the Certificate of Incorporation, these Bylaws or any applicable law, rule or regulation to which the Company is subject, including any rules or regulations of any stock exchange on which the Company’s common stock is traded;

(iv)the Nominee was nominated for election to the Board of Directors pursuant to this Section 2.8 at one of the Company’s two preceding annual meetings of stockholders and (i) its nomination was withdrawn or, (ii) such Nominee became ineligible to serve as a Nominee or as a Director or (iii) such Nominee received a vote of less than twenty-five percent (25%) of the shares of common stock entitled to vote for such Nominee; or

(v)(a) the Nominating Stockholder fails to continue to satisfy the eligibility requirements described in Section 2.8(C), (b) any of the representations and warranties made in the Proxy Access Notice cease to be true, complete and correct in all material respects (or omits to state a material fact necessary to make the statements made therein not misleading), (c) the Nominee becomes unwilling or unable to serve on the Board of Directors or (d) the Nominating Stockholder or the Nominee materially violates or breaches any of its agreements, representations or warranties in this Section 2.8;

(2)Notwithstanding anything to the contrary contained in this Section 2.8, the Company may omit from its proxy materials, or may supplement or correct, any information, including all or any portion of the Supporting Statement included in the Proxy Access Notice, if: (i) such information is not true and correct in all material respects or omits a material statement necessary to make the statements therein not misleading; (ii) such information directly or indirectly impugns the character, integrity or personal reputation of, or, without factual foundation, directly or indirectly makes charges concerning

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improper, illegal or immoral conduct or associations with respect to, any person; or (iii) the inclusion of such information in the proxy materials would otherwise violate the Commission’s proxy rules or any other applicable law, rule or regulation. Once submitted with a Proxy Access Notice, a Supporting Statement may not be amended, supplemented or modified by the Nominee or Nominating Stockholder.

(3)For the avoidance of doubt, the Company may solicit against, and include in the proxy materials its own statement relating to, any Nominee.

(4)This Section 2.8 provides the exclusive method for a stockholder to include nominees for election to the Board of Directors in the Company’s proxy materials (including, without limitation, any proxy card or written ballot). The interpretation of, and compliance with, any provision of this Section 2.8, including the representations, warranties and covenants contained herein, shall be determined by the Board of Directors or, in the discretion of the Board of Directors, one or more of its designees, in each case acting reasonably and in good faith.

Section 2.9Conduct of Meetings. The Board of Directors may adopt by resolution such rules and regulations for the conduct of the meeting of stockholders as it shall deem appropriate. Except to the extent inconsistent with such rules and regulations as adopted by the Board of Directors, the person presiding over any meeting of stockholders shall have the right and authority to convene and (for any or no reason) to recess and/or adjourn the meeting, to prescribe such rules, regulations and procedures and to do all such acts as, in the judgment of such presiding person, are appropriate for the proper conduct of the meeting. Such rules, regulations or procedures, whether adopted by the Board of Directors or prescribed by the presiding person of the meeting, may include, without limitation, the following: (i) the establishment of an agenda or order of business for the meeting; (ii) rules and procedures for maintaining order at the meeting and the safety of those present; (iii) limitations on attendance at or participation in the meeting to stockholders entitled to vote at the meeting, their duly authorized and constituted proxies or such other persons as the presiding person of the meeting shall determine; (iv) restrictions on entry to the meeting after the time fixed for the commencement thereof; and (v) limitations on the time allotted to questions or comments by participants. The presiding person at any meeting of stockholders, in addition to making any other determinations that may be appropriate to the conduct of the meeting, shall, if the facts warrant, determine and declare to the meeting that a matter or business was not properly brought before the meeting and if such presiding person should so determine, such presiding person shall so declare to the meeting and any such matter or business not properly brought before the meeting shall not be transacted or considered. Unless and to the extent determined by the Board of Directors or the person presiding over the meeting, meetings of stockholders shall not be required to be held in accordance with the rules of parliamentary procedure.

Section 2.10Additional Requirements For Valid Nomination of Candidates to Serve as Director and, If Elected, to Be Seated as Directors.

(A)Submission of Questionnaire, Representation and Agreement.To be eligible to be a nominee for election or reelection as a director of the Company at an annual or special meeting, a candidate must be nominated pursuant to Section 2.6 and the candidate for nomination, whether nominated by the Board of Directors or by a stockholder of record, must have previously delivered (in accordance with the time period prescribed for delivery in a notice to such candidate given by or on behalf of the Board of Directors) to the Secretary of the Company at the principal executive offices of the Company a completed written questionnaire with respect to the background, qualifications, stock ownership and independence of such person (which questionnaire shall be provided by the Secretary upon written request) and a written representation and agreement (in the form provided by the Secretary upon written request) that such person (1) is not and, if elected as a director during his or her term of office, will not become a party to (i) any agreement, arrangement or understanding with, and has not given any commitment or assurance to, any person or entity as to how such person, if elected as a director of the Company, will act or vote on any issue or question (a “Voting Commitment”) or (ii) any Voting Commitment that could limit or interfere with such person’s ability to comply, if elected as a director of the Company, with such person’s fiduciary duties under applicable law; (2) is not and will not become a party to any agreement, arrangement or understanding with any person or entity other than the Company with respect to any direct or indirect compensation, reimbursement or indemnification in connection with service or action as a director that has not been disclosed therein, and (3) in such person’s individual capacity and on behalf of any person or entity on whose behalf the nomination is being made, would be in compliance, if elected as a director of the Company, and will comply with all applicable corporate governance, conflict of interest, confidentiality and stock ownership and trading policies and guidelines of the Company applicable to directors and in effect during such person’s term in office as a director (and, if requested by any candidate for nomination, the Secretary of the Company shall provide to such candidate for nomination all such policies and guidelines then in effect).

(B)Determining Independence. The Board of Directors may also require any proposed candidate for nomination as a director to furnish such other information as may reasonably be requested by the Board of Directors in writing prior to the meeting of stockholders at which such candidate’s nomination is to be acted upon in order for the Board of Directors

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to determine the eligibility of such candidate for nomination to be an independent director of the Company in accordance with the Company’s Corporate Governance Guidelines.

(C)Duty to Update. A candidate for nomination as a director shall further update and supplement the materials delivered pursuant to this Section 2.10, if necessary, so that the information provided or required to be provided pursuant to this Section 2.10 shall be true and correct as of the record date for stockholders entitled to vote at the meeting and as of the date that is ten (10) business days prior to the meeting or any adjournment or postponement thereof, and such update and supplement shall be delivered to, or mailed and received by, the Secretary at the principal executive offices of the Company (or any other office specified by the Company in any public announcement) not later than five (5) business days after the record date for stockholders entitled to vote at the meeting (in the case of the update and supplement required to be made as of such record date), and not later than eight (8) business days prior to the date for the meeting or, if practicable, any adjournment or postponement thereof (and, if not practicable, on the first practicable date prior to the date to which the meeting has been adjourned or postponed) (in the case of the update and supplement required to be made as of ten (10) business days prior to the meeting or any adjournment or postponement thereof).

(D)Eligibility of Candidates.No candidate shall be eligible for nomination as a director of the Company unless such candidate for nomination and the Proposing Person seeking to place such candidate’s name in nomination has complied with Section 2.6 and this Section 2.10, as applicable. The presiding officer at the meeting shall, if the facts warrant, determine that a nomination was not properly made in accordance with Section 2.6 and this Section 2.10, and if he or she should so determine, he or she shall so declare such determination to the meeting, the defective nomination shall be disregarded and any ballots cast for the candidate in question (but in the case of any form of ballot listing other qualified nominees, only the ballots case for the nominee in question) shall be void and of no force or effect. Notwithstanding anything in these Bylaws to the contrary, no candidate for nomination shall be eligible to be seated as a director of the Company unless nominated and elected in accordance with this Section 2.10.

ARTICLE III

BOARD OF DIRECTORS

Section 3.1General Powers. The business and affairs of the Company shall be managed by or under the direction of the Board of Directors.  In addition to the powers and authority expressly conferred upon it by these Bylaws, the Board of Directors may exercise all such powers of the Company and do all such lawful acts and things as are not by statute of the State of Delaware, or by the Certificate of Incorporation, or by these Bylaws directed or required to be exercised or done by others.

Section 3.2Number and Term. Subject to the provisions of the Certificate of Incorporation, the number of directors shall be determined from time to time by resolution adopted by the Board of Directors. The term of office of directors shall be as provided in Article V of the Certificate of Incorporation. Subject to the provisions of the Certificate of Incorporation, a director shall hold office until his or her successor shall be elected and shall qualify, subject, however, to prior death, resignation, retirement, disqualification or removal from office.

Section 3.3Resignation. Any director may resign at any time by giving notice in writing or by electronic transmission to the Board of Directors, the Chairman of the Board, the President or the Secretary of the Company. Such resignation shall take effect on the date of receipt of such notice or at any later time specified therein. The acceptance of such resignation, unless otherwise required by the terms thereof, shall not be necessary to make it effective.

Section 3.4Vacancies. Subject to the rights of any series of preferred stock then outstanding, vacancies and newly created directorships may be filled as provided in Article V of the Certificate of Incorporation.

Section 3.5Removal. Subject to the rights of the holders of any series of preferred stock then outstanding, any director may be removed as provided in Article V of the Certificate of Incorporation.

Section 3.6Compensation. Directors, as such, shall not receive any salary for their services, but the Board of Directors by resolution shall fix the fees to be allowed and paid to directors, as such, for their services and provide for the payment of the expenses of the directors incurred by them in performing their duties.  Nothing herein contained, however, shall be considered to preclude any director from serving the Company in any other capacity and receiving compensation therefor. Fees to members of committees of the Board of Directors and expenses incurred by them in the performance of their duties shall also be fixed and allowed by resolution of the Board of Directors.

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ARTICLE IV

MEETINGS OF THE BOARD OF DIRECTORS

Section 4.1Regular Meetings. Regular meetings of the Board of Directors may be held without notice at such time and place, whether within or without Delaware, as shall from time to time be determined by the Board of Directors.

Section 4.2Special Meetings. Special meetings of the Board of Directors shall be called at the request of the Chairman of the Board, the President or a majority of the Board of Directors. Such request shall state the purpose or purposes of the proposed meeting. Such meetings may be held at any place, whether within or without Delaware. Notice of each such meeting shall be given to each director at least twenty-four (24) hours prior to the meeting. The notice shall set forth the time and place at which the meeting is to be held and the purpose or purposes thereof and may be given to each director in person, by telephone, by electronic transmission, or by any other means recognized under applicable law to the address for such director listed in the corporate records of the Company.  No such notice of any given meeting need be given to any director who waives notice thereof, either before or after the meeting.

Section 4.3Quorum; Required Vote. At all meetings of the Board of Directors a majority of the directors shall be necessary and sufficient to constitute a quorum for the transaction of business. The act of a majority of the directors present at any meeting at which there is a quorum shall be the act of the Board of Directors, except as may be otherwise specifically provided by statute, by the Certificate of Incorporation, or by these Bylaws.

Section 4.4Action by Written Consent. Unless the Certificate of Incorporation provides otherwise, any act required or permitted to be taken by the Board of Directors, or a committee thereof, may be taken without a meeting if all members of the Board of Directors or such committee, as the case may be, consent thereto in writing or by electronic transmission and the writing or writings or electronic transmission or transmissions are filed with the minutes of proceedings of the Company or the committee, as applicable. A signed consent has the effect of a meeting vote and may be described as such in any document.

ARTICLE V

COMMITTEES OF THE BOARD

Section 5.1Establishment. The Board of Directors may, by resolution or resolutions, establish, name or dissolve one or more committees, each committee to consist of one or more of the directors of the Company. For the avoidance of doubt, the Company opts to be governed by Section 141(c)(2) of the DGCL. Each such committee shall keep minutes of its proceedings and shall report such proceedings to the Board of Directors at the meeting of the Board of Directors following any such proceedings. The Company shall have the following committees, which committees shall have and may exercise the following powers:

(A)Audit Committee. The Audit Committee shall from time to time, but no less than two (2) times per year, meet to review and monitor the financial and cost accounting practices and procedures of the Company and all of its subsidiaries. The duties of the Audit Committee shall be set forth in its charter.

(B)Compensation Committee. The Compensation Committee shall from time to time meet to review the various compensation plans, policies and practices of the Company and all of its subsidiaries. The duties of the Compensation Committee shall be set forth in its charter.

(C)Governance Committee. The Governance Committee shall from time to time meet to review and develop the corporate governance policies of the Company and all of its subsidiaries, to identify individuals qualified to become members of the Board of Directors, to select, or recommend that the Board of Directors select, the director nominees for the next annual meeting of stockholders, and to consider any nominations submitted by the stockholders to the Secretary in accordance with these Bylaws, the Company’s corporate governance guidelines or applicable law. The duties of the Governance Committee shall be set forth in its charter.

Section 5.2Available Powers. Any committee, to the extent permitted by law and to the extent provided in the resolution of the Board of Directors, shall have and may exercise all the powers and authority of the Board of Directors in the management of the business and affairs of the corporation, and may authorize the seal of the Company to be affixed to all papers which may require it.

Section 5.3Unavailable Powers. No committee of the Board of Directors shall have the power or authority to (A) approve, adopt, or recommend to the stockholders, any action or matter expressly required by the DGCL to be submitted to stockholders for approval (other than the election and removal of directors) or (B) adopt, amend or repeal any provision in these Bylaws.

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Section 5.4Alternate Members. The Board of Directors may designate one or more directors as alternate members of any committee, who may replace any absent or disqualified member at any meeting of the committee. In the absence or disqualification of a member of the committee, the member or members thereof present at any meeting and not disqualified from voting, whether or not such member or members constitute a quorum, may unanimously appoint another member of the Board of Directors to act at the meeting in place of any such absent or disqualified member.

Section 5.5Procedures. Time, place and notice, if any, of meetings of a committee shall be determined by such committee. At meetings of a committee, a majority of the number of members designated by the Board of Directors shall constitute a quorum for the transaction of business. The act of a majority of the members present at any meeting at which a quorum is present shall be the act of the committee, except as otherwise specifically provided by law, the Certificate of Incorporation or these Bylaws. If a quorum is not present at a meeting of a committee, the members present may adjourn the meeting from time to time, without notice other than an announcement at the meeting, until a quorum is present. Each committee shall keep regular minutes for its proceedings and report the same to the Board of Directors when required.

ARTICLE VI

OFFICERS

Section 6.1General. The officers of the Company shall consist of such of the following as the Board of Directors shall from time to time elect or appoint: a Chairman of the Board, a President, a Chief Financial Officer, one or more Vice Presidents, a Secretary, an Assistant Secretary, a Treasurer and an Assistant Treasurer. The Board of Directors may elect or appoint such other officers as it may deem necessary, and all officers shall exercise such powers and perform such duties as generally pertain to their respective officers, subject to the specific provisions of this Article VI. Two (2) or more offices may be held by the same person, and officers of the Company may simultaneously serve as officers of subsidiaries or divisions thereof. The Chairman of the Board and the President shall be chosen by the directors from their own numbers. The salaries of all officers of the Company shall be fixed by the Board of Directors.

Section 6.2Election and Term of Office. The Board of Directors shall elect or appoint officers of the Company at its first regular meeting after each annual meeting of stockholders. If the election or appointment of officers shall not be held at such regular meeting, such election or appointment shall be held as soon thereafter as convenient. Subject to Section 6.12, each officer shall hold office until such officer’s successor shall have been duly elected and shall have qualified or until such officer’s death or resignation.

Section 6.3Chairman of the Board. The Chairman of the Board shall preside at all meetings of the stockholders and of the Board of Directors.  He or she shall have supervision of such matters as may be designated to him or her by the Board of Directors.

Section 6.4President. Unless another officer is so designated by the Board of Directors, the President shall be the Chief Executive Officer of the Company and shall perform the following duties:

(A)In the absence of the Chairman of the Board, the President shall preside at all meetings of the stockholders and of the Board of Directors.

(B)The President shall have general and active management of the business of the Company, and see that all orders and resolutions of the Board of Directors are carried into effect.

(C)The President shall execute bonds, mortgages and other contracts requiring the seal, under the seal of the Company.

(D)The President shall have the general powers and duties of supervision and management usually vested in the office of a president of a corporation. If another officer is designated by the Board of Directors as Chief Executive Officer, the President shall have supervision of such matters as shall be designated to him or her by the Board of Directors and/or the Chief Executive Officer.

Section 6.5Chief Financial Officer. The Chief Financial Officer shall have responsibility for development and administration of the Company’s financial plans and all financial arrangements, its cash deposits and short-term investments, its accounting policies and its federal and state tax returns. The Chief Financial Officer shall also be responsible for the Company’s internal control procedures and for its relationship with the financial community. The Chief Financial Officer shall perform all the duties incident to the office of chief financial officer of a corporation, those duties assigned to him or her by other provisions of these Bylaws and such other duties as may be assigned to him or her either directly or indirectly by the Board of Directors, the Chairman of the Board or the President, or as may be provided by law.

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Section 6.6Vice President. Each Vice President shall perform the duties prescribed by the President or the Board of Directors.  The Board of Directors may appoint one or more of the Vice Presidents as Senior Vice Presidents and one or more as Executive Vice Presidents.

Section 6.7Secretary. The Secretary shall attend all meetings of the Board of Directors and all meetings of the stockholders and record all votes and the minutes of all proceedings in a book to be kept for that purpose and shall perform like duties for the committees of the Board of Directors when required.  The Secretary shall give or cause to be given notice of all meetings of the stockholders and of the Board of Directors, and shall perform such other duties as may be prescribed by the Board of Directors or President, under whose supervision he or she shall serve.  The Secretary shall keep in safe custody the seal of the Company and shall affix the seal to any instrument requiring it and shall attest it.

Section 6.8Assistant Secretary

. The Assistant Secretary shall be vested with all the powers and authorized to perform all the duties of the Secretary at the request of or in the absence or disability of the Secretary. The performance of any act or the execution of any instrument by an Assistant Secretary in any instance in which such performance or execution would customarily have been accomplished by the Secretary shall constitute conclusive evidence of the request, absence or disability of the Secretary. The Assistant Secretary shall perform such other duties as may be prescribed from time to time by the Board of Directors, the President or the Secretary.

Section 6.9Treasurer. The Treasurer shall have the custody of the corporate funds and securities and shall keep full and accurate account of receipts and disbursements in moneys and other valuable effects in the name and to the credit of the Company in such depositories as may be designated by the Board of Directors.  The Treasurer shall disburse the funds of the Company as may be ordered by the Board of Directors, taking proper vouchers for such disbursements, and shall render to the President and directors at the regular meeting of the Board of Directors, or whenever they may require it, an account of all his or her transactions as Treasurer and of the financial condition of the Company.

Section 6.10Assistant Treasurer. The Assistant Treasurer shall be vested with all the powers and authorized to perform all the duties of the Treasurer at the request of or in the absence or disability of the Treasurer. The performance of any act or the execution of any instrument by an Assistant Treasurer in any instance in which such performance or execution would customarily have been accomplished by the Treasurer shall constitute conclusive evidence of the request, absence or disability of the Treasurer. The Assistant Treasurer shall perform such other duties as may be prescribed from time to time by the Board of Directors, the President or the Treasurer.

Section 6.11Resignation. Any elected or appointed officer may resign at any time upon written notice, or notice by electronic transmission, to the Chairman of the Board, the President or the Secretary of the Company. Such resignation shall take effect upon the date of its receipt or at such later time as may be specified therein, and unless otherwise required by the terms thereof, no acceptance of such resignation shall be necessary to make it effective.

Section 6.12Removal; Vacancies. Any officer elected or appointed by the Board of Directors may be removed, with or without cause, at any time by the Board of Directors.  Any such removal shall be without prejudice to the contractual rights of such officer, if any, with the Company, but the election or appointment of any officer shall not itself create contractual rights. If the office of any officer or officers becomes vacant for any reason, the vacancy shall be filled by the Board of Directors.

Section 6.13Duties of Officers May Be Delegated. In case of the absence of any officer of the Company, or for any other reason that the Board of Directors may deem sufficient, the Board of Directors may delegate, for the time being, the power or duties, or any of them, of such officer to any other officer, or to any director, provided a majority of the entire Board of Directors concur therein.

ARTICLE VII

STOCK CERTIFICATES AND TRANSFERS

Section 7.1Certificates of Stock; Uncertificated Shares. Every holder of stock in the Company shall be entitled to have a certificate; provided that the Board of Directors may provide by resolution or resolutions that some or all of any or all classes or series of its stock shall be uncertificated shares. Any such resolution shall not apply to shares represented by a certificate until such certificate is surrendered to the Company. Every holder of stock represented by a stock certificate shall be entitled to have a certificate signed by or in the name of the Company by any two authorized officers of the Company, including without limitation, the Chairman of the Board, the Vice Chairman of the Board, the President, any Vice President, the Secretary, an Assistant Secretary, the Treasurer or an Assistant Treasurer, certifying the number of shares owned by him. Any and all of the signatures on the certificate may be a facsimile. In case any officer, transfer agent or registrar who has signed or whose facsimile signature has been placed upon a certificate shall have ceased to be such officer, transfer agent or registrar before such certificate is issued, it may be issued by the Company with the same effect as if he or she were such officer, transfer agent or registrar at the date of

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issue. The Board of Directors or the President shall determine the form of stock certificate of the Company. The certificates of stock of the Company shall be numbered and shall be entered in the books of the Company as they are issued.

Section 7.2Transfers of Stock. Transfers of stock shall be made on the books (whether physically or electronically) of the Company only by the holder thereof, or by such holder’s attorney, lawfully constituted in writing, and upon surrender of the certificate therefor (or, with respect to uncertificated shares, by delivery of duly executed instructions or any other manner permitted by applicable law), and upon the payment of any transfer tax or transfer fees which may be imposed by law or by the Board of Directors; provided, however, that such transfer is not prohibited by the Certificate of Incorporation, these Bylaws, applicable law or contract.

Section 7.3Registered Stockholders. The Company shall be entitled to treat the holder of record of any share or shares of stock as the holder in fact and accordingly shall not be bound to recognize any equitable or other claim to or interest in such share on the part of any person, whether or not it shall have express or other notice thereof, except as expressly provided by the laws of the State of Delaware.

Section 7.4Transfer Agents and Registrars. The Board of Directors, the Chairman of the Board or the President, as appropriate, may appoint responsible banks or trust companies from time to time to act as transfer agents and registrars of the stock of the Company, as may be required by and in accordance with applicable laws, rules and regulations. Except as otherwise provided by the Board of Directors, the Chairman of the Board or the President, as appropriate, in respect of temporary certificates, no certificates for shares of capital stock of the Company shall be valid unless countersigned by a transfer agent and registered by one of such registrars.

Section 7.5Additional Regulations. The Board of Directors, the Chairman of the Board or the President, as appropriate, may make such additional rules and regulations as they may deem expedient concerning the issue, transfer and registration of certificates for shares of the capital stock of the Company.

Section 7.6Lost, Stolen or Destroyed Certificates. When authorized by the Secretary of the Company in writing, the duly appointed stock transfer agent may issue and the duly appointed registrar may register, new or duplicate stock certificates to replace lost, stolen or destroyed certificates and for the same number of shares as those lost, stolen or destroyed, upon delivery to the Company of an affidavit of loss and indemnity bond or other undertaking acceptable to both the Secretary and legal counsel representing the Company’s interests.

ARTICLE VIII

INDEMNIFICATION AND ADVANCEMENT OF EXPENSES

Section 8.1Right to Indemnification. The Company shall indemnify and hold harmless, to the fullest extent permitted by applicable law as it presently exists or may hereafter be amended, any person (an “Indemnitee”) who was or is made or is threatened to be made a party or is otherwise involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative (a “proceeding”), by reason of the fact that he or she, or a person for whom he or she is the legal representative, is or was a director or officer of the Company or, while a director or officer of the Company, is or was serving at the request of the Company as a director, officer, employee or agent of another corporation or of a partnership, joint venture, trust, enterprise or nonprofit entity, including service with respect to employee benefit plans, against all liability and loss suffered and expenses (including attorneys’ fees) reasonably incurred by such Indemnitee. Notwithstanding the preceding sentence, except as otherwise provided in Section 8.3, the Company shall be required to indemnify an Indemnitee in connection with a proceeding (or part thereof) commenced by such Indemnitee only if the commencement of such proceeding (or part thereof) by the Indemnitee was authorized by the Board of Directors of the Company. The Company may, in its discretion and on terms as the Company may determine, indemnify any person who was or is made or is threatened to be made a party or is otherwise involved in any proceeding by reason of the fact that he or she is or was an employee or agent of the Company or, while an employee or agent of the Company, is or was serving at the request of the Company as an employee or agent of another corporation or of a partnership, joint venture, trust, enterprise or nonprofit entity, including service with respect to employee benefit plans, against all liability and loss suffered and expenses (including attorneys’ fees) reasonably incurred by such employee or agent.

Section 8.2Prepayment of Expenses. The Company shall to the fullest extent not prohibited by applicable law pay the expenses (including attorneys’ fees) incurred by an Indemnitee in defending any proceeding in advance of its final disposition, provided, however, that, to the extent required by law, such payment of expenses in advance of the final disposition of the proceeding shall be made only upon receipt of an undertaking by the Indemnitee to repay all amounts advanced if it should be ultimately determined that the Indemnitee is not entitled to be indemnified under this Article VIII or otherwise. The Company may, in its discretion, pay the expenses (including attorneys’ fees) incurred by an employee or agent of the Company, such expenses may be so paid upon such terms and conditions, if any, as the Company deems appropriate.

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Section 8.3Claims. If a claim for indemnification or payment of expenses under this Article VIII is not paid in full within sixty (60) days, with respect to indemnification, or twenty (20) days, with respect to payment of expenses, after a written claim therefor by the Indemnitee has been received by the Company, the Indemnitee may file suit to recover the unpaid amount of such claim and, if successful in whole or in part, shall be entitled to be paid the expense of prosecuting such claim to the fullest extent permitted by law. In any such action the Company shall have the burden of proving that the Indemnitee is not entitled to the requested indemnification or payment of expenses under applicable law.

Section 8.4Nonexclusivity of Rights. The rights conferred on any Indemnitee by this Article VIII shall not be exclusive of any other rights which such Indemnitee may have or hereafter acquire under any statute, provision of the Certificate of Incorporation, these Bylaws, agreement, vote of stockholders or disinterested directors or otherwise.

Section 8.5Other Sources. The Company’s obligation, if any, to indemnify or to advance expenses to any Indemnitee who was or is serving at its request as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, enterprise or nonprofit entity shall be reduced by any amount such Indemnitee may collect as indemnification or advancement of expenses from such other corporation, partnership, joint venture, trust, enterprise or nonprofit enterprise.

Section 8.6Amendment or Repeal. Any right to indemnification or to advancement of expenses of any Indemnitee arising hereunder shall not be eliminated or impaired by an amendment to or repeal of this Article VIII after the occurrence of the act or omission that is the subject of any proceeding for which indemnification or advancement of expenses is sought.

Section 8.7Other Indemnification and Prepayment of Expenses. This Article VIII shall not limit the right of the Company, to the extent and in the manner permitted by law, to indemnify and to advance expenses to persons other than Indemnitees when and as authorized by appropriate corporate action.

Section 8.8Insurance. The Company may purchase and maintain liability insurance on behalf of a person who is or was a director, officer, employee or agent of the Company, or who, while serving as a director, officer, employee or agent of the Company, is or was serving at the request of the Company as a director, officer, employee or agent of another corporation or of a partnership, joint venture, trust, enterprise or nonprofit entity, including service with respect to employee benefit plans, against any liability asserted against him or her and incurred by him or her in that capacity or arising from his or her status as a director, officer, employee or agent, whether or not the Company has the power to indemnify him or her against the same liability under applicable law.

ARTICLE IX

MISCELLANEOUS

Section 9.1Fixing Record Date.

(A)In order that the Company may determine the stockholders entitled to notice of any meeting of stockholders or any adjournment thereof, the Board of Directors may fix a record date, which record date shall not precede the date upon which the resolution fixing the record date is adopted by the Board of Directors, and which record date shall, unless otherwise required by law, not be more than sixty (60) nor less than ten (10) days before the date of such meeting. If the Board of Directors so fixes a date, such date shall also be the record date for determining the stockholders entitled to vote at such meeting unless the Board of Directors determines, at the time it fixes such record date, that a later date on or before the date of the meeting shall be the date for making such determination. If no record date is fixed by the Board of Directors, the record date for determining stockholders entitled to notice of or to vote at a meeting of stockholders shall be at the close of business on the day next preceding the day on which notice is given, or, if notice is waived, at the close of business on the day next preceding the day on which the meeting is held. A determination of stockholders of record entitled to notice of or to vote at a meeting of stockholders shall apply to any adjournment of the meeting; provided, however, that the Board of Directors may fix a new record date for determination of stockholders entitled to vote at the adjourned meeting, and in such case shall also fix as the record date for stockholders entitled to notice of such adjourned meeting the same or an earlier date as that fixed for determination of stockholders entitled to vote in accordance herewith at the adjourned meeting.

(B)In order that the Company may determine the stockholders entitled to receive payment of any dividend or other distribution or allotment of any rights, or entitled to exercise any rights in respect of any change, conversion or exchange of stock or for the purpose of any other lawful action, the Board of Directors may fix a record date, which shall not be more than sixty (60) days prior to such other action. If no such record date is fixed, the record date for determining stockholders for any such purpose shall be at the close of business on the day on which the Board of Directors adopts the resolution relating thereto.

(C)Unless otherwise restricted by the Certificate of Incorporation, in order that the Company may determine the stockholders entitled to express consent to corporate action in writing without a meeting, the Board of Directors may fix a record date, which record date shall not precede the date upon which the resolution fixing the record date is adopted by the Board

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of Directors, and which record date shall not be more than ten (10) days after the date upon which the resolution fixing the record date is adopted by the Board of Directors. If no record date for determining stockholders entitled to express consent to corporate action in writing without a meeting is fixed by the Board of Directors, (i) when no prior action of the Board of Directors is required by law, the record date for such purpose shall be the first (1^st) date on which a signed written consent setting forth the action taken or proposed to be taken is delivered to the Company in accordance with applicable law, and (ii) if prior action by the Board of Directors is required by law, the record date for such purpose shall be at the close of business on the day on which the Board of Directors adopts the resolution taking such prior action.

Section 9.2Attendance Via Communications Equipment. Unless otherwise restricted by applicable law, the Certificate of Incorporation, or these Bylaws, members of the Board of Directors, any committee thereof, or the stockholders may hold a meeting by means of conference telephone or other method of remote communications by means of which all persons participating in the meeting can effectively communicate with each other. Such participation in a meeting shall constitute presence in person at the meeting, except where a person participates in the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called or convened.

Section 9.3Fiscal Year. The fiscal year shall begin the first (1^st) day of January in each year.

Section 9.4Seal. The corporate seal shall be inscribed with the name of the Company, the year of its organization, and the words “Corporate Seal, Delaware.”  The seal may be used by causing it, or a facsimile thereof, to be impressed, affixed or reproduced.

Section 9.5Notice. Whenever, under the provisions of the Certificate of Incorporation, these Bylaws or the laws of the State of Delaware, notice is required to be given to any director, officer or stockholder, it shall not be construed to mean personal notice, but such notice may be given in writing, by mail or private carrier, by electronic transmission, or by any other means recognized under applicable state or federal law.  If given by mail, the notice shall be mailed on a prepaid basis and shall be addressed to such director, officer or stockholder, at such address as appears on the books of the Company. Any stockholder, director or officer may waive any notice required to be given under the Certificate of Incorporation or these Bylaws.

Section 9.6Books and Records; Inspection of Books. The Company shall maintain permanent records of the minutes of all meetings of its stockholders and Board of Directors, all actions taken by the Board of Directors without a meeting and all actions taken by each committee of the Board of Directors in place of the Board of Directors on behalf of the Company.  The Company shall also maintain appropriate accounting records.

Section 9.7Bank Accounts. All checks, demands for money, or other transactions involving the Company’s bank accounts shall be signed by such officers or other responsible persons as the Board of Directors may designate.  No third party is allowed access to the Company’s bank accounts without express written authorization by the Board of Directors.

Section 9.8Contracts and Negotiable Instruments. Except as otherwise provided by applicable law or these Bylaws, any contract or other instrument relative to the business of the Company may be executed and delivered in the name of the Company and on its behalf by the Chairman of the Board or the President. The Board of Directors may authorize any other officer of the Company to enter into any contract or execute and deliver any contract in the name and on behalf of the Company, and such authority may be general or confined to specific instances as the Board of Directors may by resolution determine. All bills, notes, checks, or other instruments for the payment of money shall be signed or countersigned by such officer or officers and in such manner as are permitted by these Bylaws and/or as, from time to time, may be prescribed by resolution (whether general or special) of the Board of Directors.

Section 9.9Proxies in Respect of Securities of Other Corporations. Unless otherwise provided by resolution adopted by the Board of Directors, the Chairman of the Board, the President or any Vice President may, from time to time, appoint an attorney or attorneys or agent or agents of the Company, in the name and on behalf of the Company, to cast votes which the Company may be entitled to cast as the holder of stock or other securities in any other corporation or other entity, any of whose stock or other securities may be held by the Company, at meetings of the holders of the stock or other securities of such other corporation or other entity, or to consent in writing, in the name of the Company as such holder, to any action by such other corporation or entity, and may instruct the person or persons so appointed as to the manner of casting such votes or giving such consent, and may execute or cause to be executed in the name and on behalf of the Company and under its corporate seal or otherwise, all such written proxies or other instruments as he or she may deem necessary or proper in the premises.

Section 9.10Amendments. These Bylaws may be adopted, amended or repealed (A) by the Board of Directors or (B) by the affirmative vote of a majority of the outstanding voting power entitled to vote generally in the election of directors; provided, however, that in the case of clause (B), notice of the proposed amendment is contained in the notice of the meeting. In addition to any vote required by any other provision of these Bylaws, the Certificate of Incorporation or any applicable law, if such amendment is to be adopted by the stockholders, the affirmative vote of holders of a majority of the shares outstanding shall

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be required for any amendment that amends or repeals, or adopts any provisions inconsistent with Section 2.7(F), Article III, Article VIII or this Section 9.10.

Section 9.11Forum for Adjudication of Disputes. Unless the Company consents in writing to the selection of an alternative forum, the Court of Chancery (the “Chancery Court”) of the State of Delaware (or, in the event that the Chancery Court does not have jurisdiction, the federal district court for the District of Delaware or other state courts of the State of Delaware) shall, to the fullest extent permitted by law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the Company, (ii) any action asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of the Company to the Company or the Company’s stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, the Certificate of Incorporation or these Bylaws (as either may be amended from time to time), or (iv) any action asserting a claim governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in shares of capital stock of the Company shall be deemed to have notice of and to have consented to this provision. If any action, the subject matter of which is within the scope of the preceding sentence, is filed in a court other than a court located within the State of Delaware (a “Foreign Action”) in the name of any stockholder, such stockholder shall be deemed to have consented to (i) the personal jurisdiction of the state and federal courts located within the State of Delaware in connection with any action brought in any such court to enforce the preceding sentence and (ii) having service of process made upon such stockholder in any such action by service upon such stockholder’s counsel in the Foreign Action as agent for such stockholder.

Section 9.12Construction. All references and uses herein of the masculine pronouns “he”, “his” or “chairman” shall have equal applicability to and shall also mean their feminine counterpart pronouns, such as “she”, “her” or “chairwoman.”

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EX-10.1

FIRST AMENDMENT TO PURCHASE AND SALE AGREEMENT

THIS FIRST AMENDMENT TO PURCHASE AND SALE AGREEMENT (this “First Amendment”) is executed and effective on September 20, 2017, by and among QEP Energy Company, a Texas corporation (“Seller”), Pinedale Energy Partners, LLC, a Delaware limited liability company (“Buyer”), and Pinedale Energy Partners Operating, LLC, a Delaware limited liability company (“PEPO”). Seller, Buyer and PEPO are sometimes referred to herein individually as a “Party” and collectively as the “Parties.”

Recitals:

A. Seller and Buyer entered into that certain Purchase and Sale Agreement on July 24, 2017 (the “Purchase Agreement”).

B. Pursuant to that certain Assignment of Rights and Assumption of Obligations (the “Assignment Agreement”) dated of even date herewith between Buyer and PEPO, and as permitted by Section 15.3 of the Purchase Agreement, Buyer has assigned to PEPO, and PEPO has accepted and assumed from Buyer, certain rights and obligations of Buyer under the Purchase Agreement, upon the terms and conditions therein set forth.

C. The Parties desire to make certain modifications to the Purchase Agreement as provided further herein.

Agreements:

NOW THEREFORE, for good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

1.Definitions and Interpretation. All capitalized terms used herein, unless otherwise expressly defined herein, shall have the meanings ascribed to them in the Purchase Agreement.

2.Replacement of Exhibit A. Exhibit A attached hereto hereby replaces Exhibit A attached to the Purchase Agreement in its entirety and shall replace the Exhibit A originally attached to the Purchase Agreement. All references to Exhibit A in the Purchase Agreement shall be deemed a reference to Exhibit A attached hereto.

3.Replacement of Exhibit D-2. Exhibit D-2 attached hereto replaces Exhibit D-2 attached to the Purchase Agreement in its entirety and shall replace the Exhibit D-2 originally attached to the Purchase Agreement. All references to Exhibit D-2 in the Purchase Agreement shall be deemed a reference to Exhibit D-2 attached hereto.

4.Replacement of Exhibit F. Exhibit F attached hereto hereby replaces Exhibit F attached to the Purchase Agreement in its entirety and shall replace the Exhibit F originally attached to the Purchase Agreement. All references to Exhibit F in the Purchase Agreement shall be deemed a reference to Exhibit F attached hereto.

5.Amendment to Exhibit G. The Parties hereby agree and acknowledge that, in accordance with the Assignment Agreement and as permitted by Section 15.3 of the Purchase Agreement, PEPO shall be the Grantee under the Deed.

6.Amendment to Section 3.3(a)(i). Section 3.3(a)(i) of the Purchase Agreement is hereby revised by deleting the reference to “$701,322.00” therein and inserting in lieu thereof “683,322.00”.

7.Replacement of Schedule 3.3(a)(i). Schedule 3.3(a)(i) attached hereto replaces Schedule 3.3(a)(i) attached to the Purchase Agreement in its entirety and shall replace the Schedule 3.3(a)(i) originally attached to the Purchase Agreement. All references to Schedule 3.3(a)(i) in the Purchase Agreement shall be deemed a reference to Schedule 3.3(a)(i) attached hereto.

8.Amendment to Schedule 4.4. Part B of Schedule 4.4 to the Purchase Agreement is hereby amended by (a) deleting “12/31/2035” in the row containing QEP File Number WY 11079000 and inserting in lieu thereof “5/28/2022”, and (b) adding the following items:

QEP File Number	Name	Granting Authority	Original Grantee	Eff. Date	Exp. Date	Purpose	Legal Description
WY11238000	ST WY TUP 1949	State of Wyoming, Board of Land Commissioners	Questar Exploration and Production Company	6/1/2009	6/1/2017	Stockpile site for equipment and supplies for oil and gas operations	T32N-R109W Sec. 16: SE4SE4
WY11097000	Surface Use and Surface Impact Agreement	Gros Ventre Investment Company	Questar Exploration and Production Company	7/15/2009	cessation of production	Surface use	T32N-R109 Sec. 16: All

9.Amendment to Schedule 4.12. Schedule 4.12 attached hereto hereby replaces the Imbalances (Wells) Part of Schedule 4.12 attached to the Purchase Agreement in its entirety and shall replace the Imbalances (Wells) Part of Schedule 4.12 originally attached to the Purchase Agreement.

10.Amendment of Section 5.8. The Parties hereby agree and acknowledge that Section 5.8 of the Purchase Agreement is deleted in its entirety and replaced with the following:

5.8 Regulatory. Buyer and Pinedale Energy Partners Operating, LLC, a Delaware limited liability company and a member of the ORNR Group (“PEPO”), as applicable, are or will be at Closing qualified per applicable Law to own and assume operatorship of the Assets in all jurisdictions where the Assets are located, and the consummation of the transactions contemplated by this Agreement will not cause Buyer or PEPO to be disqualified as such an owner or operator. To the extent required by any applicable Laws, as of Closing, Buyer and/or PEPO shall maintain lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, all applicable Laws governing the ownership and operation of the Assets and as of Closing shall file any and all required reports necessary for such ownership and/or operation with all Governmental Authorities having jurisdiction over such ownership and/or operation.

11.Amendment of Section 6.2. The Parties hereby agree and acknowledge that Section 6.2 of the Purchase Agreement is deleted in its entirety and replaced with the following:

6.2 Successor Operator. While Buyer acknowledges that it desires to have PEPO succeed Seller (or its Affiliate) as operator of those Assets or portions thereof that Seller (or its Affiliate) may presently operate, Buyer acknowledges and agrees that Seller cannot and does not covenant or warrant that PEPO shall become successor operator of such Assets since the Assets or portions thereof may be subject to operating or other agreements that control the appointment of a successor operator. Seller agrees, however, that, as to the Assets it (or its Affiliate) operates, it shall use its commercially reasonable efforts to support PEPO’s efforts to become successor operator of such Assets (to the extent permitted under any applicable joint operating agreement or other applicable agreement) effective as of Closing (at Buyer’s sole cost and expense) and to designate and/or appoint, to the extent legally possible and permitted under, and subject to any Third Party’s right to resume operatorship under, any applicable joint operating agreement or other applicable agreement, PEPO as successor operator of such Assets effective as of Closing.

12.Amendment to Section 6.3(a). The Parties hereby agree and acknowledge that the language “Buyer shall obtain, or cause to be obtained in the name of Buyer,” in Section 6.3(a) of the Purchase Agreement is deleted and replaced with the following:

“Buyer shall obtain, or cause to be obtained in the name of Buyer and/or PEPO,”

13.Amendment to Section 8.5. The Parties hereby agree and acknowledge that the language “Buyer shall have obtained, in the name of Buyer,” in Section 8.5 of the Purchase Agreement is deleted and replaced with the following:

“Buyer shall have obtained, in the name of Buyer and/or PEPO,”

14.Amendment to Section 9.3(j). The Parties hereby agree and acknowledge that that the language “Seller and Buyer shall deliver federal and state change of operator forms designating Buyer as the operator” in Section 9.3(j) of the Purchase Agreement is deleted and replaced with the following:

“Seller and Buyer shall deliver federal and state change of operator forms designating PEPO as the operator”

15.Amendment to Schedule 6.8. The Parties hereby agree and acknowledge that the following row shall be added to Schedule 6.8 to the Purchase Agreement.

Title	Number	Office Location
Manager, Operations	1	Pinedale, Wyoming

16.Consideration. Each of the Parties acknowledges and agrees that it has received good, valuable and adequate consideration, and shall receive substantial benefit from, the execution and delivery of this First Amendment.

17.Purchase Agreement in Full Force and Effect. Except to the extent expressly set forth in this First Amendment, the Parties agree that the Purchase Agreement shall remain in full force and effect in accordance with its terms following the execution of this First Amendment. Except as expressly provided herein, in the Purchase Agreement or in the Assignment Agreement, this First Amendment shall not release, waive or excuse, and each Party shall remain responsible and liable for, such Party’s respective rights and obligations (or breach thereof) under the Purchase Agreement, as amended by this First Amendment, arising prior to, on or after the date hereof.

18.Entire Agreement. All references to the Purchase Agreement in any document, instrument, agreement, or writing delivered pursuant to the Purchase Agreement (as amended hereby) shall hereafter be deemed to refer to the Purchase Agreement as amended hereby.

19.Governing Law. This First Amendment and any claim, controversy or dispute arising under or related to this First Amendment shall be governed by and construed and enforced in accordance with the Laws of the State of Texas, excluding any conflicts of law, rule or principle that might refer construction of provisions to the Laws of another jurisdiction.

20.Counterparts. This First Amendment may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile or other electronic transmission shall be deemed an original signature hereto.

21.Exhibits. All of the Exhibits referred to in this First Amendment are hereby incorporated in this First Amendment by reference and constitute a part of this First Amendment.

22.Severability. If any term or other provision of this First Amendment is invalid, illegal or incapable of being enforced by any rule of Law or public policy, all other conditions and provisions of this First Amendment shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner to any Party. Upon such determination that any term or other provision is invalid, illegal or incapable of being enforced, the Parties shall negotiate in good faith to modify this First Amendment so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

IN WITNESS WHEREOF, the Parties have executed this First Amendment as of the date first written above.

	SELLER:
	QEP ENERGY COMPANY
	a Texas Corporation
By:	/s/ Michael C. Puchalski
Name:	Michael C. Puchalski
Title:	Vice President of Business Development

	BUYER:
	Pinedale Energy Partners, LLC
By:	/s/ J. Chris Jacobsen
Name:	J. Chris Jacobsen
Title:	President and Chief Executive Officer

	PEPO:
	Pinedale Energy Partners Operating, LLC
	a Delaware limited liability company
By:	/s/ J. Chris Jacobsen
Name:	J. Chris Jacobsen
Title:	President and Chief Executive Officer

EX-10.3

SEPARATION AGREEMENT AND WAIVER AND RELEASE OF CLAIMS

This Separation Agreement and Waiver and Release of Claims ("Agreement") is made and entered into by and between Matthew T. Thompson (hereinafter "Employee"), and QEP Energy Company ("Company"). Employee and the Company shall be jointly referred to herein as the "Parties." Employee does freely and voluntarily enter into this Agreement. The Parties acknowledge that the Effective Date of this Agreement is the Separation Date, regardless of the date the Parties execute the Agreement.

WITNESSETH:

WHEREAS, Employee has been advised that his employment with the Company will end on September 15, 2017 ("Separation Date"); and

WHEREAS, subject to the terms and conditions below, the Company agrees to pay Employee a total severance of $387,900 ("Severance Pay") in exchange and consideration for Employee’s execution of this Agreement and Employee’s waiver and release of all claims against the Company; and

WHEREAS, in exchange for the promises set forth herein, the Company agrees to provide Employee up to twelve (12) months of subsidized COBRA premiums for the health (medical, dental and/or vision) coverage in which he is currently enrolled and up to twelve (12) months of subsidized outplacement services as set forth herein; and

WHEREAS, in exchange for the promises set forth herein, Company agrees to accelerate the vesting of a prorated number of shares of QEP restricted stock and Employee agrees to forfeit the remaining shares as set forth on Exhibit A, attached hereto and incorporated herein, and

WHEREAS, in exchange for the promises set forth herein, Company agrees to accelerate a prorated portion of Performance Share Units and Employee agrees to forfeit the remaining Performance Share Units as set forth on Exhibit A, attached hereto and incorporated herein, and

WHEREAS, in exchange for the promises set forth herein, Company agrees to accelerate the vesting of a prorated portion of option awards and Employee agrees to forfeit the remaining option awards as set forth on Exhibit A, attached hereto and incorporated herein, and

WHEREAS, the Parties wish to resolve any and all actual or potential issues between them by mutual agreement and therefore enter into this Agreement; and

NOW, THEREFORE, in consideration of the premises, the mutual promises herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, it is agreed as follows:

1.RELEASE. In exchange and consideration for the Severance Pay, up to twelve (12) months of subsidized COBRA premiums and outplacement services, and accelerated vesting of a prorated number of shares of QEP restricted stock, Performance Share Units and option awards, Employee, Employee’s heirs, executors, administrators, and assigns, hereby unconditionally releases and forever discharges the Company, and any and all of its respective owners, shareholders, administrators, past or present predecessors, successors, assigns, agents, directors, officers, partners, principals, employees, representatives, attorneys, divisions, subsidiaries, parent companies, and affiliates (hereinafter the "Releasees") from any and all charges, complaints, claims, liabilities, obligations, promises, agreements, controversies, damages, injuries, actions, causes of action, suits, rights, demands, costs, attorneys’ fees,

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losses, debts and/or expenses, of any nature whatsoever, whether known or unknown, with respect to, resulting from, or arising out of Employee’s employment or relationship with the Company, as well as the termination of such employment, including any and all rights or claims arising under any agreement with the Company or under any federal, state or local laws. This release includes, but is not limited to: claims pursuant to Title VII of the Civil Rights Act of 1964, as amended by the Civil Rights Act of 1991 (42 U.S.C. § 2000e, et seq.), which prohibits discrimination in employment based on race, color, national origin, religion or sex; the Civil Rights Act of 1866 (42 U.S.C. §§1981, 1983 and 1985), which prohibits violations of civil rights; the Employee Retirement Income Security Act of 1974, as amended (29 U.S.C. § 1001, et seq.), which protects certain employee benefits; the Age Discrimination in Employment Act of 1967, as amended, and as further amended by the Older Workers Benefit Protection Act (29 U.S.C. § 621, et seq.), which prohibits age discrimination in employment; the Americans with Disabilities Act of 1990, as amended (42 U.S.C. § 12101, et seq.), which prohibits discrimination against the disabled; the Family Medical Leave Act of 1993 (29 U.S.C. § 2601, et seq.) which provides medical and family leave; the Fair Labor Standards Act (29 U.S.C. § 201, et seq.) including the wage and hour laws relating to payment of wages, including but not limited to, severance and vacation payments; and all other federal, state and local laws and regulations prohibiting employment discrimination and/or governing payment of wages, benefits, and other forms of compensation. Employee acknowledges and affirms that he has no pay due that has not been paid to Employee, and has no claim for any additional payment of any wages whatsoever, including any payments for overtime compensation under the Fair Labor Standards Act. Employee further acknowledges that he has not been deprived of any leave under the Family Medical Leave Act and has not been affected in any way because Employee has taken any leave under that Act. This release also includes, but is not limited to, a release of any claims for breach of contract, mental pain, suffering and anguish, emotional upset, impairment of economic opportunities, unlawful interference with employment rights, defamation, intentional or negligent infliction of emotional distress, fraud, wrongful termination, wrongful discharge in violation of public policy, breach of any express or implied covenant of good faith and fair dealing, that Company has dealt with Employee unfairly or in bad faith, and all other common law contract and tort claims. Employee does not, however, waive any rights or claims that may arise and accrue after the date this Agreement is executed by Employee. Further, Employee understands and agrees that this Agreement does not cover, affect, or alter any rights that cannot, by law, be released by private agreement.

2.SEVERANCE PAY. Employee acknowledges that the Severance Pay constitutes a monetary payment to the Employee to which Employee is not otherwise entitled under any Company plan, program, or prior agreement, and that any and all claims or potential claims Employee has (or may have) against the Company or any of the Releasees shall be resolved, settled, unconditionally and irrevocably waived and released on the basis of the Company’s payment of the Severance Pay to the Employee. The Severance Pay will be paid to Employee within thirty (30) days after Employee’s execution of this Agreement or the Separation Date (whichever is later), by way of one check payable to Employee. The Parties agree to bear their own costs and attorneys’ fees incurred in relation to Employee’s execution of this Agreement. Employee acknowledges and agrees that no representative of the Company has made any representations to Employee regarding the tax consequences of the Severance Pay. Employee agrees and understands that the Severance Pay will be subject to applicable state and federal withholdings, and will be reported to the Internal Revenue Service via an IRS Form W-2, and further agrees that Employee will pay any and all local, state or federal taxes which may be due by virtue of the Severance Pay. No voluntary deductions, such as 401(k), will be withheld from the Severance Pay. Employee understands that the Company is under no obligation to offer, pay, or tender the Severance Pay unless and until Employee executes and signs this Agreement and knowingly and voluntarily releases the claims described herein.

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3.RELEASE AS TO UNVESTED SHARES OF QEP RESOURCES, INC. RESTRICTED STOCK, PERFORMANCE SHARE UNITS AND OPTION AWARDS. The Company has granted Employee unvested shares of QEP Resources, Inc. ("QEP") restricted stock and Performance Share Units. These shares and units are scheduled to vest at various dates after the Separation Date. The Company agrees to accelerate the vesting of a prorated number of shares and units as set forth on Exhibit A, attached hereto and incorporated herein. Employee releases and forever discharges the Company from any and all claims he has to the remaining unvested shares of QEP restricted stock and Performance Share Units as set forth in Exhibit A. Additionally, the Company has granted Employee option awards. These option awards are scheduled to vest at various dates after the Separation Date. The Company agrees to accelerate the vesting of a prorated portion of the option awards as set forth on Exhibit A, attached hereto and incorporated herein. Employee releases and forever discharges the Company from any and all claims he has to the remaining unvested option awards.

4.WAGES AND BENEFITS.

(a)Wages. Employee will be paid Employee’s final paycheck for wages earned through Employee’s Separation Date as required by state law. Employee will also be paid in accordance with the Company’s paid time off policy, accrued paid time off balance as of the Separation Date, less legally required taxes, deductions and withholding. The Company shall credit Employee’s 401(k) for service up to the date of Employee’s termination of employment. Except for wages and benefits earned through the Separation Date, Employee acknowledges that Employee has received payment for all wages due, including reimbursement for any and all business related expenses, and that no other money is owed by the Company to Employee on any obligation of any type.

(b)Benefits. Employee understands that any coverage the Employee may have for himself and his dependents under the Company’s group health, dental and/or vision plan will end on the last day of the month in which the Separation Date occurs ("Benefit End Date") as a result of the termination of employment with the Company. For employees that are currently participating in the medical, dental, and/or vision plans, the Company will subsidize the Consolidated Omnibus Budget Reconciliation Act of 1985 ("COBRA") premium under the terms and conditions of said plans for a period of twelve (12) months after the Benefit End Date. Thereafter, Employee will be entitled to continue COBRA coverage in accordance with applicable and timely premium payment. Employee acknowledges that if the Employee is a participant in the medical, dental and/or vision plans, Employee’s COBRA rights and the requirements for coverage continuation will be explained in a separate notice provided to Employee. All other benefits shall cease in accordance with each plan’s eligibility provisions.

(c)Outplacement. Employee may choose to use authorized outplacement services provided by Challenger, Gray & Christmas, Inc. for a period of up to twelve (12) months at no cost to Employee.

5.COVENANT NOT TO SUE. By signing this Agreement, Employee covenants, agrees, represents and warrants that Employee has not filed and will not in the future file any lawsuits, complaints, petitions or accusatory pleadings in a court of law or in conjunction with a dispute resolution program against the Company, based upon, arising out of or in any way related to any event or events occurring prior to the signing of this Agreement, including, without limitation, Employee’s employment with the Company or the termination thereof. Nothing in this Agreement shall limit Employee’s right to file a charge or complaint with any state or federal agency or to participate or cooperate in such a matter. However, Employee expressly waives all rights to recover for any damages awarded as a result of any suit or proceeding brought by any third party or governmental agency on Employee’s behalf. Notwithstanding the foregoing, nothing in this Agreement prohibits or is intended to prevent Employee from participating or cooperating in any investigation before any government agency and does not limit Employee’s right to

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receive a whistleblower reward or bounty for providing information to the Securities Exchange Commission or any other government agency which by law allows such rewards or bounty.

6.CONFIDENTIAL RECORDS AND INFORMATION. Employee agrees that Employee will not, unless required or otherwise permitted by law, disclose or divulge to any other person or entity, directly or indirectly, any confidential records or information regarding the Company, including but not limited to the following: (i) practices, policies and or procedures; (ii) trade secrets; (iii) customer names; (iv) any information regarding existing or prospective future business, planning, or development; (v) contracts or proposed contracts; (vi) financial information; (vii) staffing or personnel utilization; (viii) salary or wage levels; (ix) privileged communications; and (x) other information deemed confidential or proprietary not herein listed. Employee further covenants that he has returned all property of the Company to the Company, including but not limited to computers, cell phones, computer files and peripherals, notebooks, data, documents of all kinds regardless of the medium in which they are maintained, equipment, Company credit and fuel cards, keys, files, lists and all other Company belongings, and has no confidential, proprietary information of the Company in Employee’s possession, either in hard copy or in electronic form. Further Employee covenants that Employee has not exported any Company electronic information to anyone or to Employee’s home computer or any other computer

7.NON-DISPARAGEMENT. The Parties shall refrain from making any disparaging statements or causing any disparaging statements to be made about the other Party, directly or indirectly, orally or in writing, to any individual, agency, organization, company, corporation, or other entity, including but not limited to representatives of the media and prospective employers.

8.COOPERATION OF EMPLOYEE.    Employee shall cooperate with the Company and will be readily available to the Company as the Company may reasonably request, to assist the Company in any matter, including litigation or potential litigation or administrative claim or arbitration, about which Employee has knowledge, information or special expertise related to the claim or claims. Company agrees to pay Employee reasonable compensation and prompt reimbursement for any such services, costs, or time rendered on behalf of Company.

9.COOPERATION DURING TRANSITION. To effect an orderly transition of Employee’s job duties and responsibilities, Employee shall assist and cooperate in the transition of Employee’s job duties and responsibilities until the Separation Date. A breach of this Section 9 shall constitute a material breach of this Agreement.

10.UNEMPLOYMENT BENEFITS. The Company agrees that it will not contest any claim filed by Employee for unemployment benefits.

11.GENERAL PROVISIONS:

(a)        Confidentiality. Employee agrees and represents that the terms, contents, conditions, proceedings, discussions and negotiations of this Agreement are strictly confidential and that this confidentiality provision is a material term of this Agreement. Employee shall not make statements or representations relating thereto, except to Employee’s attorney or tax advisor, Employee’s spouse or as may be required by law. Employee further agrees that if Employee discusses this Agreement with Employee’s attorney, tax advisor, spouse or anyone as required by law, Employee will advise them of the confidential nature of this Agreement and instruct them not to discuss the terms and conditions set forth herein with any person.

(b)        Law Governing. This Agreement shall be governed by and construed in accordance with the laws of the State of Colorado, and shall be enforced exclusively before the courts of the State of Colorado.

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(c)        Invalid Provisions. If any provision of this Agreement is held to be illegal, invalid or unenforceable under present or future laws effective during the term hereof, such provision shall be fully severable and this Agreement shall be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof; and the remaining provisions hereof shall remain in full force and effect and shall not be affected by the illegal, invalid or unenforceable provision or by its severance here from. Furthermore, in lieu of such illegal, invalid or unenforceable provision there shall be added automatically as part of this Agreement a provision as similar in terms to such illegal, invalid or unenforceable provision as may be possible and still be legal, valid or enforceable.

(d)        Entire Agreement. This Agreement sets forth the entire understanding of the Parties and supersedes all prior agreements or understandings, whether written or oral, with respect to the subject matter hereof, and that the Company has not made any promise or offered any other agreement, except those expressed in this Agreement, to induce Employee to enter into this Agreement. The Parties agree to bear their own costs and attorneys’ fees incurred in relation to Employee’s employment with the Company, the termination of such employment, and/or the preparation and execution of this Agreement.

(e)        Waiver. The waiver by either Party hereto of a breach of any term or provision of this Agreement shall not operate or be construed as a waiver of a subsequent breach of the same provisions by either Party or of the breach of any other term or provision of this Agreement.

12.NO ADMISSION OF LIABILITY. The Release shall not be construed as an admission by Company of any liability whatsoever, or as an admission by Company of a violation of Employee’s rights or any other person’s rights, or any violation of any order, law, statute, duty or contract.

13.NON-SOLICITATION. For a period of twelve (12) months after the Separation Date, Employee agrees not to induce, attempt to induce or solicit any employee of Company to leave the employ of Company or any of its related entities, or hire any such employee in any business or other capacity.

14.AMENDMENT. This Agreement may not be amended, modified or waived except by written instrument executed and delivered by both Parties.

15.INDEPENDENT ADVICE. Employee acknowledges that he has been advised by the Company to seek independent legal advice concerning the provisions of this Agreement prior to signing the Agreement. Employee has freely and knowingly entered into this Agreement. Employee further acknowledges, understands and affirms that:

(a) This Agreement is a binding legal document;

(b) Employee has been extended a period of twenty-one (21) calendar days in which to consider this Agreement.

(c) Employee understands that for a period of seven (7) calendar days following execution of the Agreement, Employee may revoke this Agreement as to Employee’s release of claims under the ADEA and OWBPA only by notifying the Company, in writing, of Employee’s desire to do so. Employee understands that after the seven (7) calendar day period has elapsed, this Agreement shall become effective and enforceable as to all claims arising under the ADEA and OWBPA.

(d) Employee voluntarily signs and enters into this Agreement without reservation after having given the matter full and careful consideration; and    

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(e) This Agreement is written in layman’s terms, and Employee understands and comprehends the terms of this Agreement, specifically acknowledges Employee’s understanding that this Agreement includes a release of all known and unknown claims.

16.BINDING EFFECT. This Agreement is binding upon and shall inure to the benefit of the Parties hereto and their respective successors, assigns, personal representatives, officers, directors, agents, attorneys, parents, subsidiaries, partners, principals, and affiliates. However, if Employee’s execution of this Agreement is not received by Lauren Miller, QEP Energy Company, 1050 17^th Street, Suite 800, Denver, CO 80265 by 5:00 p.m. prevailing Mountain Time by September 28, 2017, then this offer shall automatically terminate and be of no further force and effect. Employee’s failure to execute this Agreement will not affect Employee’s right to receive the salary and benefits described in Section 4 herein, except for up to twelve (12) months of subsidized COBRA and outplacement services.

EMPLOYEE ACKNOWLEDGES AND AFFIRMS THAT EMPLOYEE HAS CAREFULLY READ THE AGREEMENT, UNDERSTANDS THE CONTENTS HEREOF AND THAT EMPLOYEE SIGNS THIS AGREEMENT VOLUNTARILY, KNOWINGLY, AND WITHOUT ANY DURESS OR COERCION.

IN WITNESS WHEREOF, and intending to be legally bound hereby, the Parties to this Agreement hereby knowingly and voluntarily execute this Agreement by signing below.

Matthew T. Thompson	QEP Energy Company
By: /s/ Matthew T. Thompson	By: /s/ Margo Fiala
	Margo Fiala, Vice President Human Resources
Dated this 14 day of September, 2017	Dated this 14 day of September, 2017

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EX-10.4

AMENDMENT TO LONG TERM INCENTIVE AGREEMENTS

under the QEP Resources, Inc. Long-Term Stock Incentive Plan and Cash Incentive Plan

Granted to Matthew Thompson

This Amendment to the Restricted Stock Agreements, Performance Share Unit Agreements, and Option Agreements is effective as of September 15, 2017 and is between QEP Resources, Inc. (Company) and Matthew Thompson (Grantee).

The parties represent as follows:

A. Company and Grantee previously entered into restricted stock agreements (the “Restricted Stock Agreements”), performance share unit agreements (the “Performance Share Unit Agreements”) and option agreements (the “Option Agreements”), pursuant to which Grantee was granted 31,036 currently unvested restricted shares, 36,960 currently unvested performance share units, and 30,033 currently unvested options and options that have previously vested.

B. The parties desire to amend the Restricted Stock Agreements, Performance Share Unit Agreements, and Option Agreements to modify the vesting and expiration provisions as described below.

Therefore, the parties agree that the Restricted Stock Agreements, Performance Share Unit Agreements, and Option Agreements be amended as follows:

The vesting provisions of the Restricted Stock Agreements are amended to provide that 16,860 of the restricted shares granted to the Grantee shall vest in full within thirty (30) days of receipt of a fully executed Separation Agreement, Waiver and Release of All Claims in the form provided by the Company to the Grantee and expiration of the revocation period, if applicable, or the Separation Date, whichever is later without Grantee having revoked such agreement. An applicable number of shares may be withheld to cover the taxes associated with the vesting. Except as expressly set forth in this Amendment, Grantee acknowledges that all restricted shares that are unvested as of the date of Grantee’s termination of employment are forfeited as of such date.

The vesting provisions of the Performance Share Unit Agreements are amended to provide that the Grantee shall remain eligible to receive a pro rata portion (as outlined below) of the Performance Share Units that would otherwise have been received for each applicable Performance Period based upon actual performance results measured in accordance with the terms of the Performance Share Unit Agreements, subject to Grantee’s execution of a fully executed Separation Agreement, Waiver and Release of All Claims in the form provided by the Company to the Grantee and expiration of the revocation period, if applicable, without Grantee having revoked such agreement, and subject to annual certification by the Committee.

i. 2015 Performance Share Unit Agreements: 4,967

ii. 2016 Performance Share Unit Agreement: 11,529

iii. 2017 Performance Share Unit Agreement: 2,945

The vesting provisions of the Option Agreements are amended to provide that a pro rata portion (as outlined below) of the option awards granted to the Grantee shall vest in full within thirty (30) days of receipt of a fully executed Separation Agreement, Waiver and Release of All Claims in the form provided by the Company to the Grantee and expiration of the revocation period, if

applicable, or the Separation Date, whichever is later without Grantee having revoked such agreement.

i. Options granted February 12, 2015: 4,339

ii. Options granted February 16, 2016: 6,998

iii. Options granted February 13, 2017: 4,524

The expiration provisions of the Option Agreements are amended to provide that all vested options shall expire on their original expiration date or twelve (12) months from the date of separation, whichever is earlier, but subject to all other provisions of the Option Agreements and the Company’s 2010 Long-Term Stock Incentive Plan, including provisions allowing for early termination of options in connection with a corporate event.

This Amendment shall be and is hereby incorporated in and forms a part of each Restricted Stock Agreement, Performance Share Unit Agreement, and Option Agreement, as applicable. Except as expressly provided by this Amendment, all terms and conditions of the Restricted Stock Agreements, Performance Share Unit Agreements and Option Agreements shall remain in full force and effect.

The obligations and covenants of the Parties set forth in this Amendment are subject to the terms and conditions stated herein. Except as expressly set forth in this Amendment, the Grantee acknowledges that all restricted shares, performance share units and options that are unvested as of the date of the Grantee’s termination of employment are forfeited as of such date. In the event the Grantee does not execute a Separation Agreement, Waiver and Release of All Claims in the form provided by the Company to the Grantee or if the Grantee revokes such agreement during any applicable revocation period, this Amendment shall be null and void and of no force or effect and the Restricted Stock Agreements, Performance Share Unit Agreements and Option Agreements shall remain unchanged hereby.

QEP RESOURCES, INC.
By /s/ Charles B. Stanley	September 14, 2017
Charles B. Stanley	Date
Chairman, President and CEO
/s/ Matthew T. Thompson	September 14, 2017
Matthew T. Thompson	Date

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Charles B. Stanley, certify that:

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

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

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

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

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

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

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

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

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

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

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

October 25, 2017

/s/ Charles B. Stanley

Charles B. Stanley

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Richard J. Doleshek, certify that:

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

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

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

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

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

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

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

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

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

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

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

October 25, 2017

/s/ Richard J. Doleshek

Richard J. Doleshek

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of QEP Resources, Inc. (the Company) on Form 10-Q for the period ended September 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the Report), Charles B. Stanley, Chairman, President and Chief Executive Officer of the Company, and Richard J. Doleshek, Executive Vice President and Chief Financial Officer, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

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

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

	QEP RESOURCES, INC.
October 25, 2017
	/s/ Charles B. Stanley
	Charles B. Stanley
	Chairman, President and Chief Executive Officer
October 25, 2017
	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President and Chief Financial Officer

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 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	240,935,039
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2017

XML

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
REVENUES
Oil sales	$ 218.0	$ 201.6	$ 655.7	$ 553.1
Gas sales	130.7	123.2	399.4	287.5
NGL sales	32.2	19.8	84.0	56.2
Other revenue	3.6	2.5	10.3	4.3
Purchased oil and gas sales	5.6	35.3	44.5	76.3
Total Revenues	390.1	382.4	1,193.9	977.4
OPERATING EXPENSES
Purchased oil and gas expense	6.9	37.1	45.4	80.8
Lease operating expense	76.2	50.7	215.4	163.3
Transportation and processing costs	60.2	75.8	202.6	218.9
Gathering and other expense	1.7	0.9	5.0	3.8
General and administrative	43.4	66.5	108.3	157.9
Production and property taxes	28.5	26.8	86.1	65.3
Depreciation, depletion and amortization	176.9	217.8	560.2	667.5
Exploration expenses	21.3	0.2	21.7	0.9
Impairment	28.3	5.0	28.4	1,188.2
Total operating expenses	443.4	480.8	1,273.1	2,546.6
Net gain (loss) from asset sales	185.4	5.3	205.2	5.0
OPERATING INCOME (LOSS)	132.1	(93.1)	126.0	(1,564.2)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	(104.3)	44.5	163.3	(85.1)
Interest and other income (expense)	0.1	4.6	2.5	5.6
Interest expense	(34.4)	(35.9)	(103.1)	(109.2)
INCOME (LOSS) BEFORE INCOME TAXES	(6.5)	(79.9)	188.7	(1,752.9)
Income tax (provision) benefit	3.2	29.0	(69.7)	641.2
NET INCOME (LOSS)	$ (3.3)	$ (50.9)	$ 119.0	$ (1,111.7)
Earnings per common share
Earnings Per Share, Basic	$ (0.01)	$ (0.21)	$ 0.49	$ (5.15)
Earnings Per Share, Diluted	$ (0.01)	$ (0.21)	$ 0.49	$ (5.15)
Weighted-average common shares outstanding
Used in basic calculation (in shares)	240.7	239.6	240.5	215.7
Used in diluted calculation (in shares)	240.7	239.6	240.5	215.7
Dividends per common share (in dollars per share)	$ 0.00	$ 0.00	$ 0.00	$ 0.00

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ (3.3)	$ (50.9)	$ 119.0	$ (1,111.7)
Postretirement medical plan change	[1]	0.0	0.0	1.6	0.0
Pension and other postretirement plans adjustments:
Amortization of prior service costs	[2]	0.1	0.2	0.4	0.6
Amortization of net actuarial losses	[3]	0.1	0.2	0.2	0.4
Other comprehensive income		0.2	0.4	2.2	1.0
Comprehensive income (loss)		(3.1)	(50.5)	121.2	(1,110.7)
Postretirement medical plan changes, income tax expense		0.0	0.0	(1.0)	0.0
Amortization of prior service cost, income tax expense		(0.1)	(0.1)	(0.3)	(0.4)
Amortization of net actuarial loss, income tax expense		$ 0.0	$ (0.1)	$ (0.1)	$ (0.2)

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

[2] Presented net of income tax expense of $0.1 million and $0.3 million during the three and nine months ended September 30, 2017, respectively. Presented net of income tax expense of $0.1 million and $0.4 million during the three and nine months ended September 30, 2016, respectively.

[3] Presented net of income tax expense of $0.1 million during the nine months ended September 30, 2017. Presented net of income tax expense of $0.1 million and $0.2 million during the three and nine months ended September 30, 2016, respectively.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Postretirement medical plan changes, income tax expense	$ 0.0	$ 0.0	$ (1.0)	$ 0.0
Pension and other postretirement plans adjustments:
Amortization of prior service cost, income tax expense	(0.1)	(0.1)	(0.3)	(0.4)
Amortization of net actuarial loss, income tax expense	$ 0.0	$ (0.1)	$ (0.1)	$ (0.2)

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 782.6	$ 443.8
Accounts receivable, net	120.4	155.7
Income tax receivable	17.9	18.6
Fair value of derivative contracts	3.8	0.0
Hydrocarbon inventories, at lower of average cost or market	6.1	10.4
Prepaid expenses and other	10.2	11.6
Total Current Assets	941.0	640.1
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	11,847.2	14,232.5
Unproved properties	703.6	871.5
Gathering and other	311.0	301.8
Material and supplies	34.6	32.7
Total Property, Plant and Equipment	12,896.4	15,438.5
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,492.3	8,797.7
Gathering and other	111.9	101.8
Total Accumulated Depreciation, Depletion and Amortization	6,604.2	8,899.5
Net Property, Plant and Equipment	6,292.2	6,539.0
Fair value of derivative contracts	1.7	0.0
Other noncurrent assets	112.5	66.3
TOTAL ASSETS	7,347.4	7,245.4
Current Liabilities
Checks outstanding in excess of cash balances	0.0	12.3
Accounts payable and accrued expenses	388.6	269.7
Production and property taxes	37.4	30.1
Interest payable	32.8	32.9
Fair value of derivative contracts	13.4	169.8
Current portion of long-term debt	134.0	0.0
Total Current Liabilities	606.2	514.8
Long-term debt	1,890.6	2,020.9
Deferred income taxes	895.7	825.9
Asset retirement obligations	189.3	225.8
Fair value of derivative contracts	2.4	32.0
Other long-term liabilities	125.7	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	(33.2)	(22.9)
Additional paid-in capital	1,390.5	1,366.6
Retained earnings	2,292.3	2,173.3
Accumulated other comprehensive income (loss)	(14.5)	(16.7)
Total Shareholders' Equity	3,637.5	3,502.7
TOTAL LIABILITIES AND EQUITY	$ 7,347.4	$ 7,245.4

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares shares in Millions	Sep. 30, 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)	242.8	240.7
Treasury stock (in shares)	1.9	1.1

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
OPERATING ACTIVITIES
Net income (loss)	$ 119.0	$ (1,111.7)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	560.2	667.5
Deferred income taxes	68.5	(581.1)
Impairment	28.4	1,188.2
Bargain purchase gain from acquisition	0.4	(4.4)
Other non-cash activity	(9.4)	0.0
Dry hole exploratory well expense	21.2	0.0
Share-based compensation	13.5	29.0
Amortization of debt issuance costs and discounts	4.8	4.8
Net (gain) loss from asset sales	(205.2)	(5.0)
Unrealized (gains) losses on marketable securities	(2.1)	(1.2)
Unrealized (gains) losses on derivative contracts	(161.6)	218.6
Changes in operating assets and liabilities	44.1	128.2
Net Cash Provided by (Used in) Operating Activities	481.8	532.9
INVESTING ACTIVITIES
Property acquisitions	(94.5)	(39.9)
Acquisition deposit held in escrow	(36.6)	(30.0)
Property, plant and equipment, including dry exploratory well expense	(779.6)	(411.2)
Proceeds from disposition of assets	787.9	28.9
Net Cash Provided by (Used in) Investing Activities	(122.8)	(452.2)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(12.3)	(25.5)
Repayments of senior notes	0.0	(176.8)
Long-term debt issuance costs paid	(1.1)	0.0
Proceeds from credit facility	2.0	0.0
Repayments of credit facility	(2.0)	0.0
Treasury stock repurchases	(6.8)	(4.1)
Proceeds from issuance of common stock, net	0.0	781.6
Excess tax (provision) benefit on share-based compensation	0.0	0.2
Net Cash Provided by (Used in) Financing Activities	(20.2)	575.4
Change in cash and cash equivalents	338.8	656.1
Beginning cash and cash equivalents	443.8	376.1
Ending cash and cash equivalents	782.6	1,032.2
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	96.6	107.0
Cash paid (refund received) for income taxes	0.5	(123.3)
Non-cash Investing Activities
Change in capital expenditure accruals and other non-cash adjustments	$ 68.0	$ (20.4)

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Basis of Presentation

9 Months Ended

Sep. 30, 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 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 and nine months endedSeptember 30, 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 nine months endedSeptember 30, 2017, QEP recorded impairment charges of $28.4 million, which was primarily related to unproved leasehold acreage in the Central Basin Platform. Refer to Note 4 – Capitalized Exploratory Well Costs for more information.

During the nine months endedSeptember 30, 2016, QEP recorded impairment charges of $1,188.2 million, of which $1,167.9 million was related to proved properties due to lower future oil and gas prices, $16.6 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 Other Southern properties.

Income Taxes

During the three months endedSeptember 30, 2017, QEP’s combined effective federal and state income tax rate was 49.2%. The effective rate is higher than the combined federal and state statutory rate primarily due to a year-to-date adjustment to the tax provision for a permanent adjustment related to marginal well tax credits as well as a change in income between states.

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 15, 2017, and early adoption is permitted for periods beginning on or after December 15, 2016. The two permitted transition methods under the new standard are the full retrospective method, in which case the standard would be applied to each prior reporting period presented, or the modified retrospective method, in which case the cumulative effect of applying the standard would be recognized at the date of initial application. The Company does not expect net income (loss) or cash flows to be materially impacted by the new standard, however, the Company is currently analyzing whether changes to total revenues and total expenses will be necessary to properly reflect revenue for certain pipeline gathering, transportation and gas processing agreements. The Company continues to evaluate the expected disclosure requirements, changes to relevant business practices, accounting policies and control activities as a result of the adoption of the ASU and has not yet developed estimates of the quantitative impact to the Company's Condensed Consolidated Financial Statements. The Company has selected the modified retrospective method and will adopt this guidance on the effective date of January 1, 2018.

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 disclose 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 was effective prospectively for reporting periods beginning on or 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 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 pension and other postretirement plans.

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Acquisitions & Divestitures

9 Months Ended

Sep. 30, 2017

Business Combinations [Abstract]

Acquisitions & Divestitures [Text Block]

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 consisted 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 $18.8 million and $38.6 million and net income of $3.5 million and $5.4 million were generated from the acquired properties during the three and nine months endedSeptember 30, 2017, respectively, 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 nine months endedSeptember 30, 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 September 30, 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 and nine months endedSeptember 30, 2016. Pro forma results are not provided for the three and nine months endedSeptember 30, 2017, because the 2016 Permian Basin Acquisition occurred during the fourth quarter of 2016, and therefore, the results are included in QEP's results of operations for the three and nine months endedSeptember 30, 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 and nine months endedSeptember 30, 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 and quantifying 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						Nine Months Ended
	September 30, 2016						September 30, 2016
	Actual			Pro forma			Actual			Pro forma
	(in millions, except per share amounts)
Revenues	$	382.4		$	387.3		$	977.4		$	991.9
Net income (loss)	$	(50.9	)	$	(51.3	)	$	(1,111.7	)	$	(1,113.4	)
Earnings (loss) per common share
Basic	$	(0.21	)	$	(0.21	)	$	(5.15	)	$	(5.16	)
Diluted	$	(0.21	)	$	(0.21	)	$	(5.15	)	$	(5.16	)

Other Acquisitions

During the nine months endedSeptember 30, 2017, QEP acquired various oil and gas properties, which primarily included proved and unproved leasehold acreage and additional surface acreage in the Permian Basin, for an aggregate purchase price of $94.5 million. In conjunction with these acquisitions, the Company recorded $5.3 million of goodwill. The goodwill is reported on the Condensed Consolidated Balance Sheets within "Other noncurrent assets".

During the nine months endedSeptember 30, 2016, QEP acquired various oil and gas properties, which primarily included additional interests in QEP's operated wells and additional undeveloped leasehold acreage in the Permian and Williston basins, for an aggregate purchase price of $46.1 million, of which $39.9 million was cash and $6.2 million was non-cash related to the settlement of an accounts receivable balance. In conjunction with these acquisitions, the Company recorded $3.7 million of goodwill, which was subsequently impaired in 2016, and a $4.4 million bargain purchase gain. The bargain purchase gain is reported on the Condensed Consolidated Statement of Operations within "Interest and other income (expense)".

Pinedale Divestiture

In September 2017, QEP closed on its previously announced divestiture of its assets in Pinedale (the Pinedale Divestiture), for net cash proceeds (after purchase price adjustments) of $718.2 million, subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $178.8 million which was recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations. As part of the purchase and sale agreement, at the request of the buyer, QEP agreed to enter into derivative contracts covering a portion of Pinedale's future production. Those derivative contracts were novated to the buyer at closing. In addition, QEP agreed to reimburse the buyer for certain deficiency charges it incurs related to gas processing and NGL transportation and fractionation contracts, if any, between the effective date of the sale and December 31, 2019, in an aggregate amount not to exceed $45.0 million. The fair value of the deficiency charges was measured utilizing an internally developed cash flow model discounted at QEP's weighted average cost of debt. Given the unobservable nature of the inputs, the fair value calculation associated with the deficiency charges is considered Level 3 within the fair value hierarchy. As of September 30, 2017, the liability associated with estimated future payments for this commitment was $35.0 million, of which $28.0 million is reported on the Condensed Consolidated Balance Sheets within "Accounts payable and accrued expenses" and $7.0 million is reported on the Condensed Consolidated Balance Sheets within "Other long-term liabilities".

QEP accounted for revenues and expenses related to Pinedale, including the pre-tax gain on sale of $178.8 million, during the three and nine months endedSeptember 30, 2017 and 2016, as income from continuing operations on the Condensed Consolidated Statements of Operations because the sale of the Pinedale assets did not cause a strategic shift for the Company and as a result, did not qualify as discontinued operations under ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The Pinedale Divestiture did, however, represent the sale of an individually significant component. For the three and nine months endedSeptember 30, 2017, QEP recorded net income before income taxes related to Pinedale, prior to the divestiture, of $208.2 million and $251.2 million, respectively, which both include the pre-tax gain on sale of $178.8 million. For the three and nine months endedSeptember 30, 2016, QEP recorded net income before income taxes related to Pinedale of $19.2 million and a net loss before income taxes of $1,177.0 million, respectively. The net loss before income taxes was primarily due to an impairment on proved properties of $1,164.0 million recognized in 2016 as a result of a decrease in expected future gas prices.

As a part of the Pinedale Divestiture, QEP expects to incur restructuring costs of approximately $0.8 million, of which approximately $0.5 million is related to one-time termination benefits and approximately $0.3 million is related to the relocation of certain employees. During the three and nine months endedSeptember 30, 2017, restructuring costs of $0.5 million were incurred related to the Pinedale Divestiture, all of which were related to one-time termination benefits and will be paid in the fourth quarter of 2017. The Company expects to incur an additional $0.3 million of restructuring costs related to the relocation of certain employees within the next twelve months. These restructuring costs were recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statement of Operations.

Other Divestitures

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

During the nine months endedSeptember 30, 2016, QEP received proceeds of $28.9 million and recorded a pre-tax gain on sale of $5.0 million, primarily related to the divestiture of certain non-core properties in the Other Southern area.

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

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Earnings Per Share

9 Months Ended

Sep. 30, 2017

Earnings Per Share [Abstract]

Earnings Per Share [Text Block]

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 and nine months endedSeptember 30, 2017, there were no anti-dilutive shares. During the three and nine months endedSeptember 30, 2016, there were anti-dilutive shares of 0.2 million and 0.1 million, respectively, not included in diluted common shares outstanding as they were anti-dilutive to QEP's net loss.

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
	(in millions)
Weighted-average basic common shares outstanding	240.7	239.6	240.5	215.7
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—	—
Average diluted common shares outstanding	240.7	239.6	240.5	215.7

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Capitalized Exploratory Well Costs

9 Months Ended

Sep. 30, 2017

Capitalized Exploratory Well Costs [Line Items]

Capitalized Exploratory Well Costs [Text Block]

Net changes in capitalized exploratory well costs are presented in the table below.

	Capitalized Exploratory Well Costs
	2017
	(in millions)
Balance at January 1,	$	14.2
Additions to capitalized exploratory well costs	10.6
Reclassifications to proved properties	(3.6		)
Capitalized exploratory well costs charged to expense	(21.2		)
Balance at September 30,	$	—

Central Basin Platform exploration project. During the nine months ended September 30, 2017, QEP's exploratory well activity was related to the Central Basin Platform exploration project in the Permian Basin targeting the Woodford Formation. QEP completed a second exploratory well related to this project in the first half of 2017. During the three months endedSeptember 30, 2017, based on the performance of the two exploratory wells that were drilled and the analysis of the ultimate economic feasibility of this exploration project, QEP determined it would no longer pursue the development of the Central Basin Platform exploration project and would seek to monetize the assets. QEP charged $21.2 million of exploratory well costs to exploration expense. In conjunction with the expensing of the exploratory well costs, QEP charged $28.3 million of the associated unproved leasehold acreage in the Central Basin Platform to impairment expense during the three months endedSeptember 30, 2017. QEP wrote down the Central Basin Platform assets to their fair market value of $3.6 million and reclassified the assets to proved properties.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations [Text Block]

QEP records asset retirement obligations (ARO) associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $194.2 million and $231.6 million ARO liability for the periods ended September 30, 2017 and December 31, 2016, respectively, $4.9 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	6.0
Additions	6.2
Revisions	0.2
Liabilities related to assets sold(1)	(40.8		)
Liabilities settled	(9.0		)
ARO liability at September 30,	$	194.2

____________________________

⁽¹⁾   Liabilities related to assets sold for the nine months endedSeptember 30, 2017, includes $34.9 million related to the Pinedale Divestiture (refer to Note 2 – Acquisitions and Divestitures for more information).

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Fair Value Measurements

9 Months Ended

Sep. 30, 2017

Fair Value Disclosures [Abstract]

Fair Value Measurements [Text Block]

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

QEP has determined that its commodity derivative instruments are Level 2. The Level 2 fair value of commodity derivative contracts (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 September 30, 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
	September 30, 2017
Financial Assets	(in millions)
Fair value of derivative contracts – short-term	$	—	$	6.9	$	—	$	(3.1	)	$	3.8
Fair value of derivative contracts – long-term	—		2.5		—		(0.8		)	1.7
Total financial assets	$	—	$	9.4	$	—	$	(3.9	)	$	5.5
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	16.5	$	—	$	(3.1	)	$	13.4
Fair value of derivative contracts – long-term	—		3.2		—		(0.8		)	2.4
Total financial liabilities	$	—	$	19.7	$	—	$	(3.9	)	$	15.8
	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
	September 30, 2017				December 31, 2016
Financial Assets	(in millions)
Cash and cash equivalents	$	782.6	$	782.6	$	443.8	$	443.8
Financial Liabilities
Checks outstanding in excess of cash balances	$	—	$	—	$	12.3	$	12.3
Long-term debt	$	2,024.6	$	2,062.1	$	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 is based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO includes plugging costs and reserve lives. A reconciliation of the Company’s ARO is presented in Note 5 – Asset Retirement Obligations.

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a periodic basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the nine months endedSeptember 30, 2017, the Company recorded no impairments on proved oil and gas properties. During the nine months endedSeptember 30, 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: (i) estimated quantities of oil, gas and NGL reserves; (ii) estimates of future commodity prices; and (iii) estimated production rates, future operating and development costs, which are based on the Company's historic experience with similar properties. In some instances, market comparable information of recent transactions is used to estimate fair value of unproved acreage. Due to the unobservable characteristics of the inputs, the fair value of the acquired properties is considered Level 3 within the fair value hierarchy. See Note 2 – Acquisitions and Divestitures for additional information on the fair value of acquired properties.

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Derivative Contracts

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

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

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

Derivative Contracts – Production

The following table presents QEP’s volumes and average prices for its commodity derivative swap contracts as of September 30, 2017:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2017	NYMEX WTI	3.6	$	51.51
2018	NYMEX WTI	14.6	$	52.42
2019	NYMEX WTI	3.7	$	50.30
Gas sales		(MMBtu)	($/MMBtu)
2017	NYMEX HH	24.8	$	2.87
2017	IFNPCR	6.4	$	2.49
2018	NYMEX HH	105.9	$	2.99
2019	NYMEX HH	14.6	$	2.87

The following table presents QEP's volumes and average prices for its commodity derivative gas collars as of September 30, 2017:

Year	Index	Total Volumes	Average Price Floor		Average Price Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2017	NYMEX HH	2.8	$	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 September 30, 2017:

Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2017	NYMEX WTI	Argus WTI Midland	1.1	$	(0.67	)
2018 (Full Year)	NYMEX WTI	Argus WTI Midland	7.3	$	(1.06	)
2018 (July through December)	NYMEX WTI	Argus WTI Midland	0.6	$	(0.81	)
2019	NYMEX WTI	Argus WTI Midland	2.2	$	(0.98	)
Gas sales			(MMBtu)	($/MMBtu)
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 September 30, 2017:

Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2017	SWAP	IFNPCR	1.5	$	2.88
2018	SWAP	IFNPCR	0.4	$	3.05
Gas purchases			(MMBtu)	($/MMBtu)
2017	SWAP	IFNPCR	1.1	$	2.68

QEP Derivative Financial Statement Presentation

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

		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	September 30, 2017		December 31, 2016		September 30, 2017		December 31, 2016
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	6.9	$	—	$	16.5	$	169.8
Long-term:
Commodity	Fair value of derivative contracts	2.5		—		3.2		32.0
Total derivative instruments		$	9.4	$	—	$	19.7	$	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						Nine Months Ended
Derivative contracts not designated as cash flow hedges	September 30,						September 30,
	2017			2016			2017			2016
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	12.1		$	19.1		$	21.6		$	79.8
Gas derivative contracts	(0.4		)	0.4			(19.7		)	50.8
Gas Storage
Gas derivative contracts	—			0.1			(0.2		)	2.9
Realized gains (losses) on commodity derivative contracts	11.7			19.6			1.7			133.5
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(86.1		)	(0.3		)	88.7			(135.9		)
Gas derivative contracts	—			24.8			100.5			(80.0		)
Gas Storage
Gas derivative contracts	—			0.4			2.3			(2.7		)
Unrealized gains (losses) on commodity derivative contracts	(86.1		)	24.9			191.5			(218.6		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts	$	(74.4	)	$	44.5		$	193.2		$	(85.1	)
Derivatives associated with the Pinedale Divestiture(1)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	(1.3	)	$	—		$	(1.3	)	$	—
Gas derivative contracts	(23.5		)	—			(23.5		)	—
NGL derivative contracts	(5.1		)	—			(5.1		)	—
Unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture	$	(29.9	)	$	—		$	(29.9	)	$	—
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(104.3	)	$	44.5		$	163.3		$	(85.1	)

_______________________

⁽¹⁾  The unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture are comprised of derivatives entered into in conjunction with the execution of the Pinedale purchase and sale agreement, which were subsequently novated to the buyer upon the closing of the sale in September 2017. Refer to Note 2 – Acquisitions and Divestitures for more information. The unrealized gains (losses) on commodity derivatives associated with the Pinedale Divestiture are offset by an equal amount recorded within "Net gain (loss) from asset sales" on the Condensed Consolidated Statements of Operations.

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Debt

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Debt [Text Block]

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

	September 30, 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	(20.4		)	(24.1		)
Total principal amount of debt (including current portion)	2,024.6			2,020.9
Less: current portion of long-term debt	(134.0		)	—
Total long-term debt outstanding	$	1,890.6		$	2,020.9

Of the total debt outstanding on September 30, 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, 4.00 times for the quarters in fiscal year 2018, 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 September 30, 2017 and December 31, 2016, QEP was in compliance with the covenants under the credit agreement.

As of September 30, 2017 and December 31, 2016, QEP had no borrowings outstanding under the credit facility and had $1.0 million and $2.8 million, respectively, in letters of credit outstanding under the credit facility.

Senior Notes

As of September 30, 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.

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Commitment and Contingencies

9 Months Ended

Sep. 30, 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.

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; this conference has been scheduled for November 2017. While no formal federal enforcement action has been commenced in connection with the tank batteries to date, QEP anticipates that resolution of this matter will likely result in monetary penalties and require QEP to incur additional capital expenditures to correct noncompliance issues. We cannot reasonably estimate the loss or range of losses at this preliminary stage.

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Share-Based Compensation

9 Months Ended

Sep. 30, 2017

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

Share-Based Compensation [Text Block]

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 5.1 million shares available for future grants under the LTSIP at September 30, 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					Nine Months Ended
	September 30,					September 30,
	2017			2016		2017			2016
	(in millions)
Stock options	$	0.5		$	0.6	$	1.7		$	1.8
Restricted share awards	5.4			6.0		18.7			18.2
Performance share units	(0.1		)	3.2		(6.9		)	8.8
Restricted share units	—			0.1		—			0.2
Total share-based compensation expense	$	5.8		$	9.9	$	13.5		$	29.0

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 stock options granted and major assumptions used in the model at the date of grant are listed below for the nine months endedSeptember 30, 2017:

	Stock Option Assumptions
Weighted-average grant date fair value of awards granted during the period	$	6.44
Weighted-average risk-free interest rate	1.81		%
Weighted-average expected price volatility	43.9		%
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	418,752		16.77
Forfeited	(14,172	)	15.33
Canceled	(202,260	)	27.55
Outstanding at September 30, 2017	2,354,277		$	23.62	3.75	$	—
Options Exercisable at September 30, 2017	1,551,861		$	27.90	2.73	$	—
Unvested Options at September 30, 2017	802,416		$	15.33	5.73	$	—

During the nine months endedSeptember 30, 2017 and 2016, there were no exercises of stock options. As of September 30, 2017, $2.1 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.23 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 nine months endedSeptember 30, 2017 and 2016 was $22.9 million and $24.2 million, respectively. The weighted-average grant date fair value of restricted share awards was $14.13 per share and $10.37 per share for the nine months endedSeptember 30, 2017 and 2016, respectively. As of September 30, 2017, $25.2 million of unrecognized compensation cost related to restricted share awards granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.17 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	2,123,016		14.13
Vested	(1,384,011	)	16.54
Forfeited	(240,732	)	14.71
Unvested balance at September 30, 2017	3,706,776		$	13.35

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 September 30, 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 $16.90 per share and $10.16 per share for the nine months endedSeptember 30, 2017 and 2016, respectively. As of September 30, 2017, $0.2 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.03 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	405,014		16.90
Vested and Paid	(215,439	)	31.63
Forfeited	(17,519	)	13.88
Unvested balance at September 30, 2017	1,199,336		$	14.59

Restricted Share Units

Employees may elect to defer their grants of restricted share awards and these deferred awards are designated as restricted share units. Restricted share units vest over a three-year period and are deferred into the Company's nonqualified, unfunded deferred compensation plan at the time of vesting. These awards are ultimately 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 nine months endedSeptember 30, 2017 and 2016, respectively. As of September 30, 2017, $0.1 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 1.43 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 September 30, 2017	21,946		$	13.22

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Employee Benefits

9 Months Ended

Sep. 30, 2017

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

Employee Benefits [Text Block]

Pension and Other Postretirement Benefits

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

The Pension Plan is a closed, qualified, defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. During the nine months endedSeptember 30, 2017, the Company made contributions of $4.0 million to the Pension Plan and does not expect to make additional contributions to the 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 nine months endedSeptember 30, 2017, the Company made contributions of $1.9 million to its SERP and expects to contribute an additional $0.1 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.

During the nine months endedSeptember 30, 2017, the Company recognized a $0.7 million loss on curtailment related to the SERP in connection with the Pinedale Divestiture, which was recorded on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales".

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 nine months endedSeptember 30, 2017, the Company made contributions of $0.2 million to its Medical Plan and expects to contribute an additional $0.1 million to its Medical Plan during the remainder of 2017. Contributions to the Medical Plan are used to fund current benefit payments.

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

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						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.2		$	0.3		$	0.6		$	0.9
Interest cost	1.2			1.3			3.6			3.9
Expected return on plan assets	(1.3		)	(1.4		)	(4.0		)	(4.2		)
Amortization of prior service costs(1)	0.3			0.3			0.9			0.9
Amortization of actuarial losses(1)	0.1			0.2			0.3			0.6
Curtailment loss(2)	0.7			—			0.7			—
Periodic expense	$	1.2		$	0.7		$	2.1		$	2.1
Medical Plan benefits
Interest cost	$	—		$	0.1		$	0.1		$	0.2
Amortization of prior service costs(1)	(0.1		)	—			(0.2		)	0.1
Periodic expense	$	(0.1	)	$	0.1		$	(0.1	)	$	0.3

____________________________

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

⁽²⁾  A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. These expenses relate to the Pinedale Divestiture and are recognized on the Condensed Consolidated Statements of Operations within "Gain (loss) from asset sales" for the three and nine months endedSeptember 30, 2017.

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Subsequent Event (Notes)

9 Months Ended

Sep. 30, 2017

Subsequent Event [Line Items]

Subsequent Events [Text Block]

On October 24, 2017, QEP closed on its previously announced acquisition of oil and gas properties in the Permian Basin for an aggregate purchase price of $683.5 million, subject to post-closing purchase price adjustments (the 2017 Permian Basin Acquisition). The 2017 Permian Basin Acquisition consists of approximately 13,000 acres, mainly in Martin County, Texas, which are held by production from existing vertical wells. Approximately 700 additional acres contracted for in the transaction were not included in the closing, but are expected to be acquired by the Company within the next 30 days for an aggregate purchase price not to exceed $38.0 million. Within 10 business days of closing the 2017 Permian Basin Acquisition, QEP is obligated to make offers to various persons who own additional oil and gas interests in certain properties included in the transaction on substantially the same terms and conditions as the purchase described above. If all offers are accepted, the aggregate purchase price is not expected to exceed $65.0 million. QEP structured the transaction as a like-kind exchange under Section 1031 of the Internal Revenue Service Code and funded all of the purchase price with the proceeds from the Pinedale Divestiture.

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Acquisitions & Divestitures Purchase Accounting Entries (Tables)

9 Months Ended

Sep. 30, 2017

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

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

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Acquisitions & Divestitures Pro Forma (Tables)

9 Months Ended

Sep. 30, 2017

Business Combinations [Abstract]

Business Acquisition, Pro Forma Information [Table Text Block]

	Three Months Ended						Nine Months Ended
	September 30, 2016						September 30, 2016
	Actual			Pro forma			Actual			Pro forma
	(in millions, except per share amounts)
Revenues	$	382.4		$	387.3		$	977.4		$	991.9
Net income (loss)	$	(50.9	)	$	(51.3	)	$	(1,111.7	)	$	(1,113.4	)
Earnings (loss) per common share
Basic	$	(0.21	)	$	(0.21	)	$	(5.15	)	$	(5.16	)
Diluted	$	(0.21	)	$	(0.21	)	$	(5.15	)	$	(5.16	)

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2017

Earnings Per Share [Abstract]

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

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2017	2016	2017	2016
	(in millions)
Weighted-average basic common shares outstanding	240.7	239.6	240.5	215.7
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-Term Stock Incentive Plan	—	—	—	—
Average diluted common shares outstanding	240.7	239.6	240.5	215.7

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Capitalized Exploratory Well Costs (Tables)

9 Months Ended

Sep. 30, 2017

Capitalized Exploratory Well Costs [Abstract]

Capitalized Exploratory Well Costs [Table Text Block]

Net changes in capitalized exploratory well costs are presented in the table below.

	Capitalized Exploratory Well Costs
	2017
	(in millions)
Balance at January 1,	$	14.2
Additions to capitalized exploratory well costs	10.6
Reclassifications to proved properties	(3.6		)
Capitalized exploratory well costs charged to expense	(21.2		)
Balance at September 30,	$	—

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2017

Asset Retirement Obligation [Abstract]

Asset retirement obligations rollforward [Table Text Block]

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

	Asset Retirement Obligations
	2017
	(in millions)
ARO liability at January 1,	$	231.6
Accretion	6.0
Additions	6.2
Revisions	0.2
Liabilities related to assets sold(1)	(40.8		)
Liabilities settled	(9.0		)
ARO liability at September 30,	$	194.2

____________________________

⁽¹⁾   Liabilities related to assets sold for the nine months endedSeptember 30, 2017, includes $34.9 million related to the Pinedale Divestiture (refer to Note 2 – Acquisitions and Divestitures for more information).

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2017

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

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

The fair value of financial assets and liabilities at September 30, 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
	September 30, 2017
Financial Assets	(in millions)
Fair value of derivative contracts – short-term	$	—	$	6.9	$	—	$	(3.1	)	$	3.8
Fair value of derivative contracts – long-term	—		2.5		—		(0.8		)	1.7
Total financial assets	$	—	$	9.4	$	—	$	(3.9	)	$	5.5
Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	16.5	$	—	$	(3.1	)	$	13.4
Fair value of derivative contracts – long-term	—		3.2		—		(0.8		)	2.4
Total financial liabilities	$	—	$	19.7	$	—	$	(3.9	)	$	15.8
	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

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

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

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	September 30, 2017				December 31, 2016
Financial Assets	(in millions)
Cash and cash equivalents	$	782.6	$	782.6	$	443.8	$	443.8
Financial Liabilities
Checks outstanding in excess of cash balances	$	—	$	—	$	12.3	$	12.3
Long-term debt	$	2,024.6	$	2,062.1	$	2,020.9	$	2,104.3

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Derivative Contracts (Tables)

9 Months Ended

Sep. 30, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

Derivative Contracts – Production

The following table presents QEP’s volumes and average prices for its commodity derivative swap contracts as of September 30, 2017:

Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Oil sales		(bbls)	($/bbl)
2017	NYMEX WTI	3.6	$	51.51
2018	NYMEX WTI	14.6	$	52.42
2019	NYMEX WTI	3.7	$	50.30
Gas sales		(MMBtu)	($/MMBtu)
2017	NYMEX HH	24.8	$	2.87
2017	IFNPCR	6.4	$	2.49
2018	NYMEX HH	105.9	$	2.99
2019	NYMEX HH	14.6	$	2.87

The following table presents QEP's volumes and average prices for its commodity derivative gas collars as of September 30, 2017:

Year	Index	Total Volumes	Average Price Floor		Average Price Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2017	NYMEX HH	2.8	$	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 September 30, 2017:

Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Oil sales			(bbls)	($/bbl)
2017	NYMEX WTI	Argus WTI Midland	1.1	$	(0.67	)
2018 (Full Year)	NYMEX WTI	Argus WTI Midland	7.3	$	(1.06	)
2018 (July through December)	NYMEX WTI	Argus WTI Midland	0.6	$	(0.81	)
2019	NYMEX WTI	Argus WTI Midland	2.2	$	(0.98	)
Gas sales			(MMBtu)	($/MMBtu)
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 September 30, 2017:

Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2017	SWAP	IFNPCR	1.5	$	2.88
2018	SWAP	IFNPCR	0.4	$	3.05
Gas purchases			(MMBtu)	($/MMBtu)
2017	SWAP	IFNPCR	1.1	$	2.68

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

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

		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	September 30, 2017		December 31, 2016		September 30, 2017		December 31, 2016
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	6.9	$	—	$	16.5	$	169.8
Long-term:
Commodity	Fair value of derivative contracts	2.5		—		3.2		32.0
Total derivative instruments		$	9.4	$	—	$	19.7	$	201.8

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

	Three Months Ended						Nine Months Ended
Derivative contracts not designated as cash flow hedges	September 30,						September 30,
	2017			2016			2017			2016
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Oil derivative contracts	$	12.1		$	19.1		$	21.6		$	79.8
Gas derivative contracts	(0.4		)	0.4			(19.7		)	50.8
Gas Storage
Gas derivative contracts	—			0.1			(0.2		)	2.9
Realized gains (losses) on commodity derivative contracts	11.7			19.6			1.7			133.5
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	(86.1		)	(0.3		)	88.7			(135.9		)
Gas derivative contracts	—			24.8			100.5			(80.0		)
Gas Storage
Gas derivative contracts	—			0.4			2.3			(2.7		)
Unrealized gains (losses) on commodity derivative contracts	(86.1		)	24.9			191.5			(218.6		)
Total realized and unrealized gains (losses) on commodity derivative contracts related to production and storage contracts	$	(74.4	)	$	44.5		$	193.2		$	(85.1	)
Derivatives associated with the Pinedale Divestiture(1)
Unrealized gains (losses) on commodity derivative contracts
Production
Oil derivative contracts	$	(1.3	)	$	—		$	(1.3	)	$	—
Gas derivative contracts	(23.5		)	—			(23.5		)	—
NGL derivative contracts	(5.1		)	—			(5.1		)	—
Unrealized gains (losses) on commodity derivative contracts related to the Pinedale Divestiture	$	(29.9	)	$	—		$	(29.9	)	$	—
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(104.3	)	$	44.5		$	163.3		$	(85.1	)

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Debt (Tables)

9 Months Ended

Sep. 30, 2017

Debt Disclosure [Abstract]

Debt Outstanding [Table Text Block]

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

	September 30, 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	(20.4		)	(24.1		)
Total principal amount of debt (including current portion)	2,024.6			2,020.9
Less: current portion of long-term debt	(134.0		)	—
Total long-term debt outstanding	$	1,890.6		$	2,020.9

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Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2017

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

Share-based Compensation Expense [Table Text Block]

Share-based compensation expense is recognized within "General and administrative" expense on the Condensed Consolidated Statements of Operations and is summarized in the table below:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2017			2016		2017			2016
	(in millions)
Stock options	$	0.5		$	0.6	$	1.7		$	1.8
Restricted share awards	5.4			6.0		18.7			18.2
Performance share units	(0.1		)	3.2		(6.9		)	8.8
Restricted share units	—			0.1		—			0.2
Total share-based compensation expense	$	5.8		$	9.9	$	13.5		$	29.0

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

The calculated fair value of stock options granted and major assumptions used in the model at the date of grant are listed below for the nine months endedSeptember 30, 2017:

	Stock Option Assumptions
Weighted-average grant date fair value of awards granted during the period	$	6.44
Weighted-average risk-free interest rate	1.81		%
Weighted-average expected price volatility	43.9		%
Expected dividend yield	—		%
Expected term in years at the date of grant	4.5

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

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

	Options Outstanding		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
			(per share)		(in years)	(in millions)
Outstanding at December 31, 2016	2,151,957		$	25.26
Granted	418,752		16.77
Forfeited	(14,172	)	15.33
Canceled	(202,260	)	27.55
Outstanding at September 30, 2017	2,354,277		$	23.62	3.75	$	—
Options Exercisable at September 30, 2017	1,551,861		$	27.90	2.73	$	—
Unvested Options at September 30, 2017	802,416		$	15.33	5.73	$	—

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

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	2,123,016		14.13
Vested	(1,384,011	)	16.54
Forfeited	(240,732	)	14.71
Unvested balance at September 30, 2017	3,706,776		$	13.35

	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 September 30, 2017	21,946		$	13.22

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

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

	Performance Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2016	1,027,280		$	17.24
Granted	405,014		16.90
Vested and Paid	(215,439	)	31.63
Forfeited	(17,519	)	13.88
Unvested balance at September 30, 2017	1,199,336		$	14.59

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Employee Benefits (Tables)

9 Months Ended

Sep. 30, 2017

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.2		$	0.3		$	0.6		$	0.9
Interest cost	1.2			1.3			3.6			3.9
Expected return on plan assets	(1.3		)	(1.4		)	(4.0		)	(4.2		)
Amortization of prior service costs(1)	0.3			0.3			0.9			0.9
Amortization of actuarial losses(1)	0.1			0.2			0.3			0.6
Curtailment loss(2)	0.7			—			0.7			—
Periodic expense	$	1.2		$	0.7		$	2.1		$	2.1
Medical Plan benefits
Interest cost	$	—		$	0.1		$	0.1		$	0.2
Amortization of prior service costs(1)	(0.1		)	—			(0.2		)	0.1
Periodic expense	$	(0.1	)	$	0.1		$	(0.1	)	$	0.3

____________________________

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

⁽²⁾  A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. These expenses relate to the Pinedale Divestiture and are recognized on the Condensed Consolidated Statements of Operations within "Gain (loss) from asset sales" for the three and nine months endedSeptember 30, 2017.

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Basis of Presentation Impairment of Long-Lived Assets (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment	$ 28.3	$ 5.0	$ 28.4	$ 1,188.2
Proved Property [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment				1,167.9
Unproved Property [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment				16.6
Pinedale [Member] | Proved Property [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment				1,164.0
Other Northern [Member] | Proved Property [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment				3.5
Other Southern [Member] | Proved Property [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment				0.4
Williston & Permian Basins [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Goodwill impairment				$ 3.7

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Basis of Presentation Income Taxes (Details)	3 Months Ended
	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Effective income tax rate	49.20%

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Acquisitions & Divestitures 2016 Permian Basin Acquisition (Details) $ in Millions	3 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2017 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($) a	Dec. 31, 2016 USD ($)
Business Acquisition [Line Items]
Bargain purchase gain from acquisition		$ (0.4)	$ 4.4
2016 Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Payments for acquisitions		591.0
Net acres | a			9,600
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	$ 18.8	38.6
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual	$ 3.5	5.4
Bargain purchase gain from acquisition		$ (0.4)		$ (18.2)

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Acquisitions & Divestitures Purchase Accounting Entries (Details) - 2016 Permian Basin Acquisition [Member] $ in Millions	Sep. 30, 2017 USD ($)
Business Combination, Separately Recognized Transactions [Line Items]
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)

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Acquisitions & Divestitures Pro Forma (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Revenues	$ 390.1	$ 382.4	$ 1,193.9	$ 977.4
Net income (loss)	$ (3.3)	$ (50.9)	$ 119.0	$ (1,111.7)
Earnings Per Share, Basic	$ (0.01)	$ (0.21)	$ 0.49	$ (5.15)
Earnings Per Share, Diluted	$ (0.01)	$ (0.21)	$ 0.49	$ (5.15)
2016 Permian Basin Acquisition [Member]
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Revenues		$ 382.4		$ 977.4
Net income (loss)		$ (50.9)		$ (1,111.7)
Earnings Per Share, Basic		$ (0.21)		$ (5.15)
Earnings Per Share, Diluted		$ (0.21)		$ (5.15)
Pro Forma Revenue		$ 387.3		$ 991.9
Pro Forma Net Income (Loss)		$ (51.3)		$ (1,113.4)
Pro Forma Earnings Per Share, Basic		$ (0.21)		$ (5.16)
Pro Forma Earnings Per Share, Diluted		$ (0.21)		$ (5.16)

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Acquisitions & Divestitures Other Acquisitions (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Business Acquisition [Line Items]
Bargain purchase gain from acquisition	$ (0.4)	$ 4.4
Payments to acquire oil and gas property	94.5	39.9
Other Acquisitions [Member]
Business Acquisition [Line Items]
Bargain purchase gain from acquisition		4.4
Acquisition Costs, Period Cost	94.5	46.1
Goodwill	$ 5.3	3.7
Cash [Member] | Other Acquisitions [Member]
Business Acquisition [Line Items]
Payments to acquire oil and gas property		39.9
Accounts Receivable [Member] | Other Acquisitions [Member]
Business Acquisition [Line Items]
Payments to acquire oil and gas property		$ (6.2)

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Acquisitions & Divestitures Pinedale Divestiture (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			$ 787.9	$ 28.9
Net gain (loss) from asset sales	$ 185.4	$ 5.3	205.2	5.0
Minimum volume commitment			45.0
INCOME (LOSS) BEFORE INCOME TAXES	(6.5)	(79.9)	188.7	(1,752.9)
Total [Member]
Divestitures [Line Items]
Minimum volume commitment remaining	35.0		35.0
Short-term [Member]
Divestitures [Line Items]
Minimum volume commitment remaining	28.0		28.0
Long-term [Member]
Divestitures [Line Items]
Minimum volume commitment remaining	7.0		7.0
Pinedale Divestiture [Member]
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			718.2
Net gain (loss) from asset sales			178.8
INCOME (LOSS) BEFORE INCOME TAXES	208.2	$ 19.2	251.2	(1,177.0)
Restructuring costs, expected cost	0.8		0.8
One-time Termination Benefits [Member] | Pinedale Divestiture [Member]
Divestitures [Line Items]
Restructuring costs, expected cost	0.5		0.5
Restructuring costs, cost incurred to date	0.5		0.5
Employee Relocation [Member] | Pinedale Divestiture [Member]
Divestitures [Line Items]
Restructuring costs, expected cost	$ 0.3		$ 0.3
Proved Property [Member]
Divestitures [Line Items]
Impairment				1,167.9
Proved Property [Member] | Pinedale [Member]
Divestitures [Line Items]
Impairment				$ 1,164.0

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Acquisitions & Divestitures Other Divestitures (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			$ 787.9	$ 28.9
Net gain (loss) from asset sales	$ 185.4	$ 5.3	205.2	5.0
Payments to acquire oil and gas property			94.5	$ 39.9
Non-core properties Divestitures [Member]
Divestitures [Line Items]
Proceeds from Sale of Oil and Gas Property and Equipment			69.7
Net gain (loss) from asset sales			$ 26.4

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Earnings Per Share Components of Basic and Diluted Shares Used In EPS Calculation (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share [Abstract]
Anti-dilutive shares	0.0	0.2	0.0	0.1
Weighted-average basic common shares outstanding	240.7	239.6	240.5	215.7
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	0.0	0.0	0.0	0.0
Average diluted common shares outstanding	240.7	239.6	240.5	215.7

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Earnings Per Share Earnings per share (non-printing) (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Earnings Per Share [Abstract]
Anti-dilutive shares	0.0	0.2	0.0	0.1

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Capitalized Exploratory Well Costs (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Capitalized Exploratory Well Costs [Line Items]
Capitalized exploratory well costs charged to expense			$ 21.2	$ 0.0
Impairment	$ 28.3	$ 5.0	28.4	$ 1,188.2
Central Basin Platform [Member]
Capitalized Exploratory Well Costs [Line Items]
Reclassifications to proved properties			(3.6)
Capitalized exploratory well costs charged to expense			(21.2)
Impairment			$ 28.3

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Capitalized Exploratory Well Costs Capitalized Exploratory Well Costs Table (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Capitalized Exploratory Well Costs [Line Items]
Capitalized exploratory well costs, beginning balance	$ 14.2
Additions to capitalized exploratory well costs	10.6
Capitalized exploratory well costs charged to expense	21.2	$ 0.0
Capitalized exploratory well costs, ending balance	0.0
Central Basin Platform [Member]
Capitalized Exploratory Well Costs [Line Items]
Reclassifications to proved properties	(3.6)
Capitalized exploratory well costs charged to expense	$ (21.2)

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Asset Retirement Obligations (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2017	Dec. 31, 2016
Divestitures [Line Items]
Asset Retirement Obligation, Current		$ 4.9	$ 5.8
ARO Liability [Roll Forward]
ARO liability, Beginning Balance		231.6
Accretion		6.0
Additions		6.2
Revisions		0.2
Liabilities related to assets sold	[1]	(40.8)
Liabilities settled		(9.0)
ARO liability, Ending Balance		194.2
Pinedale Divestiture [Member]
ARO Liability [Roll Forward]
Liabilities related to assets sold		$ 34.9

[1] Liabilities related to assets sold for the nine months ended September 30, 2017, includes $34.9 million related to the Pinedale Divestiture (refer to Note 2 – Acquisitions and Divestitures for more information).

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Fair Value Measurements Fair Value of Financial Assets and Liabilities (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2017	Dec. 31, 2016
Financial Assets
Derivative Asset			$ 5.5	$ 0.0
Net amount of derivative assets presented on condensed consolidated balance sheets	[1]		(3.9)	0.0
Derivative Liability			15.8	201.8
Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross			0.0	0.0
Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			9.4	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross			19.7	201.8
Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross			0.0	0.0
Long-term [Member]
Financial Assets
Derivative Asset			1.7	0.0
Net amount of derivative assets presented on condensed consolidated balance sheets	[1]		(0.8)	0.0
Derivative Liability			2.4	32.0
Long-term [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross			0.0	0.0
Long-term [Member] | Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			2.5	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross			3.2	32.0
Long-term [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross			0.0	0.0
Short-term [Member]
Financial Assets
Derivative Asset			3.8	0.0
Net amount of derivative assets presented on condensed consolidated balance sheets	[1]		(3.1)	0.0
Derivative Liability			13.4	169.8
Short-term [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross			0.0	0.0
Short-term [Member] | Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			6.9	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross			16.5	169.8
Short-term [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross			$ 0.0	$ 0.0
Proved Property [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Impairment		$ 1,167.9

[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.

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Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - USD ($) $ in Millions	Sep. 30, 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	$ 782.6	$ 443.8
Checks outstanding in excess of cash balances	0.0	12.3
Long-term debt	2,024.6	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	782.6	443.8
Checks outstanding in excess of cash balances	0.0	12.3
Long-term debt, fair value	$ 2,062.1	$ 2,104.3

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Derivative Contracts (Narrative) (Details)	9 Months Ended
	Sep. 30, 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%

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Derivative Contracts Schedule Of Commodity Derivative Contracts (Details) MMBTU in Millions	9 Months Ended
	Sep. 30, 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	1.1
Weighted-Average Differential | $ / MMBTU	(0.67)
Oil Basis Swaps [Member] | Production [Member] | Year 2018 [Member] | NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	7.3
Weighted-Average Differential | $ / MMBTU	(1.06)
Oil Basis Swaps [Member] | Production [Member] | Year 2018 (July through December) [Member] | NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	0.6
Weighted-Average Differential | $ / MMBTU	(0.81)
Oil Basis Swaps [Member] | Production [Member] | Year 2019 [Member] | NYMEX WTI less Argus WTI Midland [Member]
Derivative [Line Items]
Derivative Volumes	2.2
Weighted-Average Differential | $ / MMBTU	(0.98)
Gas Swaps [Member] | Production [Member] | Year 2017 [Member] | NYMEX HH [Member]
Derivative [Line Items]
Derivative Volumes	24.8
Average Swap Price per Unit | $	$ 2.87
Gas Swaps [Member] | Production [Member] | Year 2017 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative Volumes	6.4
Average Swap Price per Unit | $	$ 2.49
Gas Swaps [Member] | Production [Member] | Year 2018 [Member] | NYMEX HH [Member]
Derivative [Line Items]
Derivative Volumes	105.9
Average Swap Price per Unit | $	$ 2.99
Gas Swaps [Member] | Production [Member] | Year 2019 [Member] | NYMEX HH [Member]
Derivative [Line Items]
Derivative Volumes	14.6
Average Swap Price per Unit | $	$ 2.87
Gas Swaps [Member] | Storage [Member] | Year 2017 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative Volumes	1.5
Average Swap Price per Unit | $	$ 2.88
Gas Swaps [Member] | Storage [Member] | Year 2018 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative Volumes	0.4
Average Swap Price per Unit | $	$ 3.05
Oil Swaps [Member] | Production [Member] | Year 2017 [Member] | NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	3.6
Average Swap Price per Unit | $	$ 51.51
Oil Swaps [Member] | Production [Member] | Year 2018 [Member] | NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	14.6
Average Swap Price per Unit | $	$ 52.42
Oil Swaps [Member] | Production [Member] | Year 2019 [Member] | NYMEX WTI [Member]
Derivative [Line Items]
Derivative Volumes	3.7
Average Swap Price per Unit | $	$ 50.30
Gas Collars [Member] | Production [Member] | Year 2017 [Member] | NYMEX HH [Member]
Derivative [Line Items]
Derivative Volumes	2.8
Derivative Average Price Floor | $	$ 2.50
Derivative Average Price Ceiling | $	$ 3.50
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)
Gas Purchase Swaps [Member] | Storage [Member] | Year 2018 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative Volumes	1.1
Average Swap Price per Unit | $	$ 2.68

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Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) - Fair Value, Inputs, Level 2 [Member] - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 9.4	$ 0.0
Derivative Liability, Fair Value, Gross	19.7	201.8
Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	6.9	0.0
Derivative Liability, Fair Value, Gross	16.5	169.8
Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2.5	0.0
Derivative Liability, Fair Value, Gross	3.2	32.0
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	9.4	0.0
Derivative Liability, Fair Value, Gross	19.7	201.8
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	6.9	0.0
Derivative Liability, Fair Value, Gross	16.5	169.8
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	2.5	0.0
Derivative Liability, Fair Value, Gross	$ 3.2	$ 32.0

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Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments		$ 11.7	$ 19.6	$ 1.7	$ 133.5
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		(86.1)	24.9	191.5	(218.6)
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments		(104.3)	44.5	163.3	(85.1)
Oil derivative contracts [Member] | Production [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments		12.1	19.1	21.6	79.8
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		(86.1)	(0.3)	88.7	(135.9)
Natural gas derivative contracts [Member] | Production [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments		(0.4)	0.4	(19.7)	50.8
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		0.0	24.8	100.5	(80.0)
Natural gas derivative contracts [Member] | Storage [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments		0.0	0.1	(0.2)	2.9
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments		0.0	0.4	2.3	(2.7)
Pinedale Divestiture [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	[1]	(29.9)	0.0	(29.9)	0.0
Pinedale Divestiture [Member] | NGL derivative contracts [Member] | Production [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	[1]	(5.1)	0.0	(5.1)	0.0
Pinedale Divestiture [Member] | Oil derivative contracts [Member] | Production [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	[1]	(1.3)	0.0	(1.3)	0.0
Pinedale Divestiture [Member] | Natural gas derivative contracts [Member] | Production [Member]
Derivative [Line Items]
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	[1]	(23.5)	0.0	(23.5)	0.0
Total [Member]
Derivative [Line Items]
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments		$ (74.4)	$ 44.5	$ 193.2	$ (85.1)

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

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Debt (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 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	1.0	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

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Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Less unamortized discount	$ (20.4)	$ (24.1)
Long-term debt	2,024.6	2,020.9
Total long-term debt outstanding	1,890.6	2,020.9
Less: current portion of long-term debt	(134.0)	0.0
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	0.0	0.0
6.80% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	134.0	134.0
6.80% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	136.0	136.0
6.875% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	625.0	625.0
5.375% Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	500.0	500.0
5.25% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 650.0	$ 650.0

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Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for future grants	5.1
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	$ 2.1
Weighted average vesting period	2 years 2 months 23 days
Restricted Share Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 14.13	$ 10.37
Unrecognized compensation costs	$ 25.2
Weighted average vesting period	2 years 2 months 1 day
Award vesting period	3 years
Total fair value of stock that vested during the period	$ 22.9	$ 24.2
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 16.90	$ 10.16
Unrecognized compensation costs	$ 0.2
Weighted average vesting period	2 years 11 days
Restricted Share Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants	$ 16.98	$ 10.12
Unrecognized compensation costs	$ 0.1
Weighted average vesting period	1 year 5 months 5 days

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Share-Based Compensation Share-based compensation expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Expense [Line Items]
Share-based Compensation	$ 5.8	$ 9.9	$ 13.5	$ 29.0
Stock Options [Member]
Share-based Compensation Expense [Line Items]
Share-based Compensation	0.5	0.6	1.7	1.8
Restricted Share Awards [Member]
Share-based Compensation Expense [Line Items]
Share-based Compensation	5.4	6.0	18.7	18.2
Performance Share Units [Member]
Share-based Compensation Expense [Line Items]
Share-based Compensation	(0.1)	3.2	(6.9)	8.8
Restricted Share Units (RSUs) [Member]
Share-based Compensation Expense [Line Items]
Share-based Compensation	$ 0.0	$ 0.1	$ 0.0	$ 0.2

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Share-Based Compensation Fair Value Of Options Granted And Major Assumptions Used (Details)	9 Months Ended
	Sep. 30, 2017 $ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted-average grant-date fair value of awards granted during the period	$ 6.44
Weighted-average risk-free interest rate	1.81%
Weighted-average expected price volatility	43.90%
Expected dividend yield	0.00%
Expected term in years at the date of grant	4 years 6 months

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Share-Based Compensation Schedule Of Stock Option Transactions (Details) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding at beginning of period | shares	2,151,957
Options granted | shares	418,752
Options forfeited | shares	(14,172)
Options canceled | shares	(202,260)
Outstanding at end of period | shares	2,354,277
Options exercisable, shares | shares	1,551,861
Unvested options, shares | shares	802,416
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted average exercise price, beginning of year | $ / shares	$ 25.26
Weighted average exercise price, granted in period | $ / shares	16.77
Weighted average exercise price, forfeited in period | $ / shares	15.33
Weighted average exercise price, canceled in period | $ / shares	27.55
Weighted average exercise price, end of year | $ / shares	23.62
Options exercisable, weighted average exercise price | $ / shares	27.90
Unvested options, weighted average exercise price | $ / shares	$ 15.33
Weighted average remaining contractual term, options outstanding	3 years 9 months
Weighted average remaining contractual term, options exercisable	2 years 8 months 23 days
Weighted average remaining contractual term, options unvested	5 years 8 months 23 days
Aggregate intrinsic value, options outstanding | $	$ 0.0
Aggregate intrinsic value, options exercisable | $	0.0
Aggregate intrinsic value, options unvested | $	$ 0.0

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Share-Based Compensation Schedule of Restricted Share Awards Transactions (Details) - Restricted Share Awards [Member] - $ / shares	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period	3,208,503
Shares granted	2,123,016
Shares vested	(1,384,011)
Shares forfeited	(240,732)
Unvested balance at end of period	3,706,776
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted average grant date fair value, beginning of period	$ 14.32
Weighted average grant date fair value, grants	14.13	$ 10.37
Weighted average grant date fair value, vested	16.54
Weighted average grant date fair value, forfeited	14.71
Weighted average grant date fair value, end of period	$ 13.35

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Share-Based Compensation Schedule Of Performance Share Unit Transactions (Details) - Performance Share Units [Member] - $ / shares	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period	1,027,280
Shares granted	405,014
Shares vested	(215,439)
Shares forfeited	(17,519)
Unvested balance at end of period	1,199,336
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted average grant date fair value, beginning of period	$ 17.24
Weighted average grant date fair value, grants	16.90	$ 10.16
Weighted average grant date fair value, vested	31.63
Weighted average grant date fair value, forfeited	13.88
Weighted average grant date fair value, end of period	$ 14.59

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Share-Based Compensation Schedule of Restricted Share Unit Transactions (Details) - Restricted Share Units (RSUs) [Member] - $ / shares	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested balance at beginning of period	18,034
Shares granted	9,924
Shares vested	(6,012)
Unvested balance at end of period	21,946
Weighted average grant date fair value, beginning of period	$ 10.12
Weighted average grant date fair value, grants	16.98	$ 10.12
Weighted average grant date fair value, vested	10.12
Weighted average grant date fair value, end of period	$ 13.22

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Employee Benefits (Narrative) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($)
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer	$ 4.0
SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer	1.9
Estimated Future Employer Contributions in Current Fiscal Year	0.1
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by Employer	0.2
Estimated Future Employer Contributions in Current Fiscal Year	0.1
Pinedale Divestiture [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Curtailment loss	$ 0.7

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Employee Benefits Schedule of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Pension Plan and SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost		$ 0.2	$ 0.3	$ 0.6	$ 0.9
Interest cost		1.2	1.3	3.6	3.9
Expected return on plan assets		(1.3)	(1.4)	(4.0)	(4.2)
Amortization of prior service costs	[1]	0.3	0.3	0.9	0.9
Amortization of actuarial losses	[1]	0.1	0.2	0.3	0.6
Curtailment loss	[2]	0.7	0.0	0.7	0.0
Periodic expense		1.2	0.7	2.1	2.1
Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Interest cost		0.0	0.1	0.1	0.2
Amortization of prior service costs	[1]	(0.1)	0.0	(0.2)	0.1
Periodic expense		$ (0.1)	$ 0.1	$ (0.1)	$ 0.3

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

[2] A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. These expenses relate to the Pinedale Divestiture and are recognized on the Condensed Consolidated Statements of Operations within "Gain (loss) from asset sales" for the three and nine months ended September 30, 2017.

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Subsequent Event (Details) $ in Millions	9 Months Ended
	Sep. 30, 2017 USD ($) a
2017 Permian Basin Acquisition [Member]
Subsequent Event [Line Items]
Payments for acquisitions	$ 683.5
Net acres | a	13,000
Permian Basin Acquisition [Member]
Subsequent Event [Line Items]
Payments for acquisitions	$ 38.0
Net acres | a	700
Additional acquisitions in the Permian Basin [Member]
Subsequent Event [Line Items]
Payments for acquisitions	$ 65.0