QEP RESOURCES, INC. - FORM 10-Q

Attached files

file	filename
EX-32.1 - EXHIBIT 32.1 - QEP RESOURCES, INC.	qepr-20160630ex321.htm
EX-31.2 - EXHIBIT 31.2 - QEP RESOURCES, INC.	qepr-20160630ex312.htm
EX-31.1 - EXHIBIT 31.1 - QEP RESOURCES, INC.	qepr-20160630ex311.htm
EX-10.1 - EXHIBIT 10.1 - QEP RESOURCES, INC.	qepr-20160630ex101.htm

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 June 30, 2016



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, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting 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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes oNo ý

At June 30, 2016, there were 239,605,692 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended June 30, 2016

TABLE OF CONTENTS



			Page
PART I. FINANCIAL INFORMATION			2

	ITEM 1.	FINANCIAL STATEMENTS	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2016 AND 2015	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2016 AND 2015	3

		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT JUNE 30, 2016 AND DECEMBER 31, 2015	4

		UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF EQUITY FOR THE SIX MONTHS ENDED JUNE 30, 2016	5

		UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2016 AND 2015	6

		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	7

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	22

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	38

	ITEM 4.	CONTROLS AND PROCEDURES	43

PART II. OTHER INFORMATION			43

	ITEM 1.	LEGAL PROCEEDINGS	43

	ITEM 1A.	RISK FACTORS	43

	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	45

	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	45

	ITEM 4.	MINE SAFETY DISCLOSURES	45

	ITEM 5.	OTHER INFORMATION	45

	ITEM 6.	EXHIBITS	45

SIGNATURES			47

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
REVENUES	(in millions, except per share amounts)
Gas sales	$	79.2		$	111.9		$	164.3		$	233.9
Oil sales	207.7			250.4			351.5			429.2
NGL sales	22.8			26.1			36.4			45.2
Other revenue (loss)	(0.5		)	5.2			1.8			9.6
Purchased gas and oil sales	24.5			181.0			41.0			324.8
Total Revenues	333.7			574.6			595.0			1,042.7
OPERATING EXPENSES
Purchased gas and oil expense	26.8			183.2			43.7			329.1
Lease operating expense	52.6			57.1			112.6			118.9
Gas, oil and NGL transportation and other handling costs	69.5			73.0			143.1			138.1
Gathering and other expense	1.6			1.4			2.9			3.1
General and administrative	43.7			51.3			92.4			98.7
Production and property taxes	20.7			32.7			38.5			60.5
Depreciation, depletion and amortization	209.7			215.8			449.7			411.2
Exploration expenses	0.4			0.8			0.7			1.9
Impairment	0.8			0.5			1,183.2			20.5
Total Operating Expenses	425.8			615.8			2,066.8			1,182.0
Net gain (loss) from asset sales	(0.8		)	24.5			(0.3		)	(6.0		)
OPERATING INCOME (LOSS)	(92.9		)	(16.7		)	(1,472.1		)	(145.3		)
Realized and unrealized gains (losses) on derivative contracts (See Note 7)	(180.5		)	(66.0		)	(129.6		)	14.9
Interest and other income (expense)	(0.3		)	3.8			2.0			1.2
Interest expense	(36.6		)	(36.2		)	(73.3		)	(73.0		)
INCOME (LOSS) BEFORE INCOME TAXES	(310.3		)	(115.1		)	(1,673.0		)	(202.2		)
Income tax (provision) benefit	113.3			38.8			612.2			70.3
NET INCOME (LOSS)	$	(197.0	)	$	(76.3	)	$	(1,060.8	)	$	(131.9	)

Earnings (loss) per common share
Basic	$	(0.90	)	$	(0.43	)	$	(5.21	)	$	(0.75	)
Diluted	$	(0.90	)	$	(0.43	)	$	(5.21	)	$	(0.75	)

Weighted-average common shares outstanding
Used in basic calculation	217.7			176.7			203.7			176.4
Used in diluted calculation	217.7			176.7			203.7			176.4
Dividends per common share	$	—		$	0.02		$	—		$	0.04

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
	(in millions)
Net income (loss)	$	(197.0	)	$	(76.3	)	$	(1,060.8	)	$	(131.9	)
Other comprehensive income, net of tax:
Pension and other postretirement plans adjustments:
Amortization of net actuarial losses ⁽¹⁾	0.2			—			0.3			0.2
Amortization of prior service costs ⁽²⁾	0.2			0.1			0.3			0.6
Other comprehensive income	0.4			0.1			0.6			0.8
Comprehensive income (loss)	$	(196.6	)	$	(76.2	)	$	(1,060.2	)	$	(131.1	)

____________________________


⁽¹⁾	Presented net of income tax expense of $0.2 million and $0.3 million during the three and six months ended June 30, 2016, respectively. Presented net of income tax expense of $0.1 million for the six months ended June 30, 2015.


⁽²⁾	Presented net of income tax of $0.2 million for the three and six months ended June 30, 2016. Presented net of income tax expense of $0.1 million and $0.4 million during the three and six months ended June 30, 2015, respectively.

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2016			December 31, 2015
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	1,038.3		$	376.1
Accounts receivable, net	132.5			278.2
Income tax receivable	170.5			87.3
Fair value of derivative contracts	1.4			146.8
Gas, oil and NGL inventories, at lower of average cost or market	7.2			13.3
Prepaid expenses and other	21.4			30.1
Total Current Assets	1,371.3			931.8
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	13,556.8			13,314.9
Unproved properties	670.2			691.0
Marketing and other	297.9			297.9
Materials and supplies	29.4			38.5
Total Property, Plant and Equipment	14,554.3			14,342.3
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	8,440.6			6,870.2
Marketing and other	95.1			87.5
Total Accumulated Depreciation, Depletion and Amortization	8,535.7			6,957.7
Net Property, Plant and Equipment	6,018.6			7,384.6
Fair value of derivative contracts	—			23.2
Other noncurrent assets	91.8			58.6
TOTAL ASSETS	$	7,481.7		$	8,398.2
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	—		$	29.8
Accounts payable and accrued expenses	213.8			351.7
Production and property taxes	39.7			46.1
Interest payable	37.9			36.4
Fair value of derivative contracts	46.6			0.8
Current portion of long-term debt	176.8			176.8
Total Current Liabilities	514.8			641.6
Long-term debt	2,017.8			2,014.7
Deferred income taxes	920.2			1,479.8
Asset retirement obligations	207.7			204.9
Fair value of derivative contracts	33.1			4.0
Other long-term liabilities	108.0			105.3
Commitments and contingencies (Note 10)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 240.6 million and 177.3 million shares issued, respectively	2.4			1.8
Treasury stock – 1.0 million and 0.5 million shares, respectively	(20.6		)	(14.6		)
Additional paid-in capital	1,352.6			554.8
Retained earnings	2,357.5			3,418.3
Accumulated other comprehensive income	(11.8		)	(12.4		)
Total Common Shareholders' Equity	3,680.1			3,947.9
TOTAL LIABILITIES AND EQUITY	$	7,481.7		$	8,398.2

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENT OF EQUITY

(Unaudited)



	Common Stock			Treasury Stock					Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income(Loss)			Total
	Shares	Amount		Shares		Amount			Additional Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income(Loss)			Total
	(in millions)
Balance at December 31, 2015	177.3	$	1.8	(0.5	)	$	(14.6	)	$	554.8	$	3,418.3		$	(12.4	)	$	3,947.9
Net income (loss)	—	—		—		—			—		(1,060.8		)	—			(1,060.8		)
Equity issuance, net of offering costs	61.0	0.6		—		—			781.0		—			—			781.6
Share-based compensation	2.3	—		(0.5	)	(6.0		)	16.8		—			—			10.8
Change in pension and postretirement liability, net of tax	—	—		—		—			—		—			0.6			0.6
Balance at June 30, 2016	240.6	$	2.4	(1.0	)	$	(20.6	)	$	1,352.6	$	2,357.5		$	(11.8	)	$	3,680.1

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended
	June 30,
	2016			2015
	(in millions)
OPERATING ACTIVITIES
Net income (loss)	$	(1,060.8	)	$	(131.9	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	449.7			411.2
Deferred income taxes	(559.9		)	(29.4		)
Impairment	1,183.2			20.5
Share-based compensation	19.1			15.6
Pension curtailment loss	—			11.2
Amortization of debt issuance costs and discounts	3.2			3.3
Net (gain) loss from asset sales	0.3			6.0
Unrealized (gains) losses on marketable securities	(0.5		)	—
Unrealized (gains) losses on derivative contracts	243.5			181.8
Changes in operating assets and liabilities	(58.2		)	(490.9		)
Net Cash Provided by (Used in) Operating Activities	219.6			(2.6		)
INVESTING ACTIVITIES
Property acquisitions	(23.6		)	—
Acquisition deposit held in escrow	(30.0		)	—
Property, plant and equipment, including dry exploratory well expense	(276.6		)	(651.3		)
Proceeds from disposition of assets	23.7			(2.4		)
Net Cash Provided by (Used in) Investing Activities	(306.5		)	(653.7		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(29.8		)	(47.3		)
Treasury stock repurchases	(3.1		)	(1.9		)
Other capital contributions	0.2			(0.1		)
Dividends paid	—			(7.1		)
Proceeds from issuance of common stock, net	781.6			—
Excess tax (provision) benefit on share-based compensation	0.2			(1.8		)
Net Cash Provided by (Used in) Financing Activities	749.1			(58.2		)
Change in cash and cash equivalents	662.2			(714.5		)
Beginning cash and cash equivalents	376.1			1,160.1
Ending cash and cash equivalents	$	1,038.3		$	445.6

Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	68.6		$	69.7
Cash paid for income taxes	$	32.4		$	548.5
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$	(27.7	)	$	(91.6	)

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 – Basis of Presentation

Nature of Business

QEP Resources, Inc. is an independent natural gas and crude oil exploration and production company focused in two regions of the United States: the Northern Region (primarily in Wyoming, 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 United States Generally Accepted Accounting Principles (GAAP) and with the instructions for Quarterly Reports on Form 10-Q and Regulations S-X and S-K. 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, 2015.

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 six months ended June 30, 2016, are not necessarily indicative of the results that may be expected for the year ending December 31, 2016.

Equity Offerings

In June 2016, QEP issued 23.0 million additional shares of common stock through a public offering and received net proceeds of approximately $413.0 million. QEP intends to use the net proceeds from this offering to partially fund the 2016 Permian Acquisition (defined below). If the acquisition is not consummated, QEP intends to use the net proceeds from this offering for general corporate purposes, which may include, among other things, reducing indebtedness, acquiring properties and funding a portion of our exploration and production activities and working capital.

In March 2016, QEP issued 37.95 million additional shares of common stock through a public offering and received net proceeds of approximately $368.6 million. QEP used the net proceeds from this offering for general corporate purposes.

Termination of Marketing Agreements and QEP Marketing Segment

Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and the Haynesville gathering system. As a result, QEP Energy is directly marketing its own gas, oil and NGL production. While QEP will continue to act as an agent for the sale of gas, oil and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently, is reporting lower resale revenue and expenses than it had in prior periods. In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP has one reportable segment effective January 1, 2016.

Revision of Financial Statements

In the fourth quarter of 2015, the Company determined that certain transactions that had been reported on a gross basis and included in "Purchased gas and oil sales" and "Purchased gas and oil expense" on the Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2015, should have been reported on a net basis, as the transactions were with the same counterparty and were entered into in contemplation of one another. The Company revised its financial statements to reflect the net accounting treatment and assessed the cumulative impact of the revisions on each period affected. The revisions had no effect on the Company’s operating income, net income, earnings per share, cash flows or retained earnings. The Company determined that the impact of the change from gross to net accounting was not material, either individually or in the aggregate, to previously issued financial statements. The Company has, for comparability purposes, recast its Condensed Consolidated Statement of Operations for the three and six months ended June 30, 2015.

The following table details the impact of these revisions for the three and six months ended June 30, 2015, on the Condensed Consolidated Statement of Operations.



	Three Months Ended June 30, 2015							Six Months Ended June 30, 2015
	As reported		As revised		Change			As reported		As revised		Change
	(in millions)
REVENUES
Purchased gas and oil sales	$	215.0	$	181.0	$	(34.0	)	$	382.3	$	324.8	$	(57.5	)
Total Revenues	608.6		574.6		(34.0		)	1,100.2		1,042.7		(57.5		)
OPERATING EXPENSES
Purchased gas and oil expense	$	217.2	$	183.2	$	(34.0	)	$	386.6	$	329.1	$	(57.5	)
Total Operating Expenses	649.8		615.8		(34.0		)	1,239.5		1,182.0		(57.5		)

Reclassifications

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

Impairment of Long-Lived Assets

During the six months ended June 30, 2016, QEP recorded impairment expense of $1,183.2 million, of which $1,167.9 million was related to proved properties due to lower future oil and gas prices, $11.6 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.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (FASB) issued ASU No. 2016-02, Leases (Topic 842), which requires lessees to recognize the lease assets and lease liabilities classified as operating leases on the balance sheet and disclosing key quantitative and qualitative information about leasing arrangements. The amendment will be effective for reporting periods beginning on or after December 15, 2018, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-06, Derivatives and hedging (Topic 815): Contingent put and call options in debt instruments, which clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. The amendment will be effective prospectively for reporting periods beginning on or after December 31, 2016, 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. 2016-08, Revenue from contracts with customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principle versus agent considerations. The amendment will be effective prospectively for reporting periods beginning on or after December 31,

2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In March 2016, the FASB issued ASU No. 2016-09, 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 will be effective prospectively for reporting periods beginning on or after December 15, 2016, and early adoption is permitted. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In April 2016, the FASB issued ASU No. 2016-10, Revenue from contracts with customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In May 2016, the FASB issued ASU No. 2016-11, Revenue recognition (Topic 605) and Derivatives and hedging (Topic 815): Rescission of SEC guidance because of ASU 2014-09 and 2014-16, which rescinds certain SEC staff observer comments that are codified in Topic 605, Revenue Recognition. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

In May 2016, the FASB issued ASU No. 2016-12, Revenue from contracts with customers (Topic 606): Narrow-scope improvements and practical expedients, which intends to reduce the cost and complexity of applying the new revenue standard by narrowing the scope of improvements to the guidance on collectability, non-cash consideration, and completed contracts at transition. This amendment will be effective prospectively for reporting periods beginning on or after December 15, 2017, and early adoption is permitted for periods beginning on or after December 31, 2016. The Company is currently assessing the impact of the ASU on the Company's Condensed Consolidated Financial Statements.

Note 2 – Acquisitions and Divestitures

In June 2016, QEP entered into a purchase and sale agreement to acquire oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $600.0 million, subject to customary purchase price adjustments (the 2016 Permian Acquisition). The 2016 Permian Acquisition consists of approximately 9,400 net acres in Martin County, Texas, which are primarily held by production from 96 vertical wells. The 2016 Permian Acquisition is expected to close in September 2016, and the Company plans to fund the transaction with proceeds from the June 2016 equity offering and cash on hand.

During the six months ended June 30, 2016, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for an aggregate purchase price of $29.8 million, which primarily included additional interests in QEP's operated wells and additional undeveloped leasehold. As a part of the purchase price allocation, the Company recorded $3.7 million of goodwill.

During the six months ended June 30, 2016, QEP received proceeds of $23.7 million and recorded a pre-tax loss on sale of $0.3 million primarily related to the divestiture of certain non-core properties in Other Southern. Additionally, during the six months ended June 30, 2015, QEP recorded a pre-tax loss on sale of $6.0 million, primarily due to post-closing purchase price adjustments related to 2014 divestitures.

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 shares are included in weighted-average basic common shares outstanding because, once the shares are granted, the restricted shares are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted shares 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 stock 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 stock does 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 six months ended June 30, 2016, there were anti-dilutive shares of 0.1 million not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss. During the three and six months ended June 30, 2015, there were no anti-dilutive shares.

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



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015
	(in millions)
Weighted-average basic common shares outstanding	217.7	176.7	203.7	176.4
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	217.7	176.7	203.7	176.4

Note 4 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are presented in the table below. The balance at June 30, 2016, represents the amount of capitalized exploratory well costs that are pending the determination of proved reserves.



	Capitalized Exploratory Well Costs
	2016
	(in millions)
Balance at January 1,	$	2.6
Additions to capitalized exploratory well costs pending the determination of proved reserves	11.0
Reclassification to proved properties after the determination of proved reserves	—
Capitalized exploratory well costs charged to expense	(0.1		)
Balance at June 30,	$	13.5

Note 5 – Asset Retirement Obligations

QEP records asset retirement obligations (ARO) when there are legal obligations 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 $211.0 million and $206.8 million ARO liability for the periods ended June 30, 2016 and December 31, 2015, respectively, $3.3 million and $1.9 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
	2016
	(in millions)
ARO liability at January 1,	$	206.8
Accretion	4.3
Additions	2.4
Liabilities settled	(2.5		)
ARO liability at June 30,	$	211.0

Note 6 – Fair Value Measurements

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

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

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

The fair value of financial assets and liabilities at June 30, 2016 and December 31, 2015, is shown in the table below:



	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments⁽¹⁾			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾
	June 30, 2016
	(in millions)
Financial Assets
Commodity derivative instruments – short-term	$	—	$	7.7	$	—	$	(6.3	)	$	1.4
Commodity derivative instruments – long-term	—		0.6		—		(0.6		)	—
Total financial assets	$	—	$	8.3	$	—	$	(6.9	)	$	1.4

Financial Liabilities
Commodity derivative instruments – short-term	$	—	$	52.9	$	—	$	(6.3	)	$	46.6
Commodity derivative instruments – long-term	—		33.7		—		(0.6		)	33.1
Total financial liabilities	$	—	$	86.6	$	—	$	(6.9	)	$	79.7

	December 31, 2015
	(in millions)
Financial Assets
Commodity derivative instruments – short-term	$	—	$	147.8	$	—	$	(1.0	)	$	146.8
Commodity derivative instruments – long-term	—		23.2		—		—			23.2
Total financial assets	$	—	$	171.0	$	—	$	(1.0	)	$	170.0

Financial Liabilities
Commodity derivative instruments – short-term	$	—	$	1.8	$	—	$	(1.0	)	$	0.8
Commodity derivative instruments – long-term	—		4.0		—		—			4.0
Total financial liabilities	$	—	$	5.8	$	—	$	(1.0	)	$	4.8

_______________________


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

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other Notes accompanying 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
	June 30, 2016				December 31, 2015
	(in millions)
Financial Assets
Cash and cash equivalents	$	1,038.3	$	1,038.3	$	376.1	$	376.1
Financial Liabilities
Checks outstanding in excess of cash balances	$	—	$	—	$	29.8	$	29.8
Long-term debt	$	2,194.6	$	2,150.1	$	2,191.5	$	1,784.6

The carrying amounts of cash and cash equivalents and checks outstanding in excess of cash balances approximate fair value. The fair value of fixed-rate long-term debt is based on the trading levels and dollar prices for the Company’s debt at the end of the quarter. The carrying amount of variable-rate, long-term debt approximates fair value because the floating interest rate paid on such debt was set for periods of one month.

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

Nonrecurring Fair Value Measurements

The provisions of the fair value measurement standard are also applied to the Company's nonrecurring measurements. The Company utilizes fair value on a nonrecurring basis to review its proved oil and gas properties for potential impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. During the six months ended June 30, 2016 and 2015, the Company recorded impairments on certain proved oil and gas properties of $1,167.9 million and $19.4 million, respectively, 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 which 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, proved oil and gas property impairments are considered Level 3 within the fair value hierarchy.

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

Note 7 – Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production from proved reserves, 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 instruments 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 gas or oil 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. Gas price derivative instruments are typically structured as fixed-price swaps or collars at regional price indices. 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. QEP also enters into crude oil and natural 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. Commodity derivative contract counterparties are normally 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 and avoids 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 sets forth QEP’s quantities and average prices for its commodity derivative swap contracts as of June 30, 2016:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Gas sales		(MMBtu)	($/MMBtu)
2016	NYMEX HH	29.4	$	2.78
2016	IFNPCR	36.8	$	2.53
2017	NYMEX HH	73.0	$	2.75
2017	IFNPCR	32.9	$	2.51
2018	NYMEX HH	7.3	$	2.80
Oil sales		(bbls)	($/bbl)
2016	NYMEX WTI	6.1	$	51.24
2017	NYMEX WTI	9.1	$	50.76
2018	NYMEX WTI	1.1	$	53.72

The following table sets forth details of QEP's gas collars as of June 30, 2016:



Year	Index	Total Volume	Average Price Floor		Average Price Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2016	NYMEX HH	3.7	$	2.75	$	3.89
2017	NYMEX HH	11.0	$	2.50	$	3.50

QEP uses gas basis swaps, combined with NYMEX HH fixed price swaps, to achieve fixed price swaps for the location at which it sells its physical production. The following table sets forth details of QEP's gas basis swaps as of June 30, 2016:



Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2016	NYMEX HH	IFNPCR	18.4	$	(0.16	)
2017	NYMEX HH	IFNPCR	51.1	$	(0.18	)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)

Derivative Contracts – Storage

QEP enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage. The following table sets forth QEP’s quantities and average prices for its storage commodity derivative swap contracts as of June 30, 2016:



Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2016	SWAP	IFNPCR	2.3	$	2.57
2017	SWAP	IFNPCR	2.4	$	2.77
Gas purchases
2016	SWAP	IFNPCR	1.8	$	2.43

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 in 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	June 30, 2016		December 31, 2015		June 30, 2016		December 31, 2015
		(in millions)
Current:
Commodity	Fair value of derivative contracts	$	7.7	$	147.8	$	52.9	$	1.8
Long-term:
Commodity	Fair value of derivative contracts	0.6		23.2		33.7		4.0
Total derivative instruments		$	8.3	$	171.0	$	86.6	$	5.8

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						Six Months Ended
Derivative instruments not designated as cash flow hedges	June 30,						June 30,
Derivative instruments not designated as cash flow hedges	2016			2015			2016			2015
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Gas derivative contracts	$	28.9		$	28.1		$	50.4		$	46.0
Oil derivative contracts	19.9			64.5			60.7			148.5
Storage
Gas derivative contracts	0.7			(0.3		)	2.8			2.2
Total realized gains (losses) on commodity derivative contracts	49.5			92.3			113.9			196.7
Unrealized gains (losses) on commodity derivative contracts
Production
Gas derivative contracts	(120.2		)	(34.5		)	(104.8		)	(23.1		)
Oil derivative contracts	(107.7		)	(123.7		)	(135.6		)	(156.8		)
Storage
Gas derivative contracts	(2.1		)	(0.1		)	(3.1		)	(1.9		)
Total unrealized gains (losses) on commodity derivative contracts	(230.0		)	(158.3		)	(243.5		)	(181.8		)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(180.5	)	$	(66.0	)	$	(129.6	)	$	14.9

Note 8 – Restructuring Costs

In April 2016, the Company streamlined its organizational structure, resulting in a reduction of approximately 6% of its total workforce. The Company estimates that the total costs related to the 2016 restructuring will be approximately $1.9 million, all of which is related to one-time termination benefits. During the three and six months ended June 30, 2016, restructuring costs of $1.8 million were incurred and paid related to the 2016 restructuring. The Company estimates that the remaining $0.1 million of restructuring costs related to the 2016 restructuring will be incurred during the remainder of 2016.

During 2015, QEP had multiple restructuring events, including the closure of its Tulsa office, which occurred in the third quarter of 2015. The Company estimates that the total costs related to the 2015 restructuring events will be approximately $8.5 million, of which approximately $5.3 million is related to one-time termination benefits and approximately $3.2 million is related to relocation of certain employees. During the three and six months ended June 30, 2016, restructuring costs of $0.2 million and $0.5 million, respectively, were incurred and paid related to the Tulsa office closure, all of which were related to the relocation of certain employees. The Company estimates that the remaining $0.3 million of restructuring costs related to the 2015 restructuring events will be incurred during the remainder of 2016.

All restructuring costs were recorded within "General and administrative" expense on the Condensed Consolidated Statement of Operations.

Note 9 – Debt

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



	June 30, 2016			December 31, 2015
	(in millions)
Revolving Credit Facility due 2019	$	—		$	—
6.05% Senior Notes due 2016	176.8			176.8
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	(27.2		)	(30.3		)
Total principal amount of debt (including current portion)	2,194.6			2,191.5
Less: current portion of long-term debt	(176.8		)	(176.8		)
Total long-term debt outstanding	$	2,017.8		$	2,014.7

Of the total debt outstanding on June 30, 2016, the 6.05% Senior Notes due September 1, 2016, 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 provisions and restrictions. The credit agreement contains financial covenants (as defined in the credit agreement) that limit the amount of debt the Company may incur and may limit the amount available to be drawn under the credit facility, including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarters ending on and prior to December 31, 2017, and 3.75 times thereafter and (iii) a present value coverage ratio under which the present value of the Company’s proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2018, and 1.50 times at any time on or after January 1, 2018. At June 30, 2016, QEP was in compliance with the covenants under the credit agreement.

During the six months ended June 30, 2016 and 2015, QEP had no borrowings under the credit facility. Additionally, as of June 30, 2016 and December 31, 2015, QEP had no borrowings outstanding under the credit facility and had $2.8 million and $3.4 million, respectively, in letters of credit outstanding under the credit facility.

Senior Notes

At June 30, 2016, the Company had $2,221.8 million principal amount of senior notes outstanding with maturities ranging from September 2016 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 all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP’s senior notes contain customary events of default and covenants that may limit QEP’s ability to, among other things, place liens on its property or assets.

Note 10 – 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. Because legal proceedings are inherently unpredictable, and unfavorable resolutions can occur, assessing contingencies is highly subjective and requires judgments 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

the potential defenses, procedural status of the matter in question, the presence of complex legal or factual issues, or the ongoing discovery and/or development of information important to the matter.

Litigation

Rocky Mountain Resources Lawsuit – Rocky Mountain Resources, LLC (Rocky Mountain) filed its complaint in March 2011, seeking determination of the existence of a 4% overriding royalty interest in an oil and gas lease. Rocky Mountain alleges that the defendants have failed to pay Rocky Mountain monies associated with the claimed 4% overriding royalty interest since the issuance of the lease by the State of Wyoming in 1980. In February 2015, a jury rendered a verdict against the Company and awarded Rocky Mountain damages in the amount of $16.7 million, including interest. The Company is appealing the verdict to the Wyoming Supreme Court, and, in connection with such appeal, has posted a bond for approximately $20.0 million (representing the amount of the verdict and two years of accrued interest at the statutory rate of 10%). In accordance with the Court’s order, the Company is depositing the future monthly revenues attributable to the 4% overriding royalty interest with the Court as it becomes due and payable. The overriding royalty payments will be subject to the direction of the Court following the conclusion of the appeal. QEP estimates that, notwithstanding the verdict, the range of reasonably possible losses in excess of current accruals, if any, is zero to approximately $20.0 million.

Claims of Former Limited Partners – The Company received a demand from certain former limited partners of terminated drilling partnerships of the Company (acting as the general partner). The former limited partners allege that distributions to which they were entitled from the drilling partnerships were not made or were calculated incorrectly. Other former limited partners may assert claims. No litigation has been filed, and the Company is in the process of evaluating the allegations and its defenses. The Company believes that it is not possible to reasonably estimate a range of possible losses at this time. The cost to settle legal proceedings (alleged or threatened), or satisfy any resulting judgment against the Company in such proceedings could result in a substantial liability, which could materially and adversely impact the Company’s cash flows and operating results for a particular period.

Arbitration Regarding Gas Purchase Agreement – An entity that purchases, gathers and processes natural gas produced from oil wells operated by the Company in the Williston Basin has claimed that the decline in commodity prices has rendered its gathering and processing operations "uneconomic" and demanded that, effective March 1, 2016, QEP pay additional fees for gathering and processing services. The midstream provider has been unwilling to connect new wells unless the Company agrees to pay the increased fees for production from the new wells. QEP initiated arbitration proceedings in May 2016 to enforce the terms of the existing agreement. The Company estimates that, notwithstanding the arbitration outcome, the range of reasonably possible losses in excess of current accruals, if any, is zero to approximately $2.5 million per month, effective March 1, 2016.

Note 11 – Share-Based Compensation

QEP issues stock options, restricted shares 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 shares, restricted share units and performance share units. There were 7.1 million shares available for future grants under the LTSIP at June 30, 2016.

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					Six Months Ended
	June 30,					June 30,
	2016		2015			2016		2015
	(in millions)
Stock options	$	0.5	$	0.7		$	1.2	$	1.5
Restricted share awards	5.7		6.4			12.2		12.7
Performance share units	4.8		(0.6		)	5.6		1.4
Restricted share units	0.1		—			0.1		—
Total share-based compensation expense	$	11.1	$	6.5		$	19.1	$	15.6

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of the 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 measuring the value of options traded on an exchange. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares.

The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below for the six months ended June 30, 2016:



	Stock Option Assumptions
Weighted-average grant date fair value of awards granted during the period	$	3.76
Weighted-average risk-free interest rate	1.15		%
Weighted-average expected price volatility	43.4		%
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, 2015	2,200,776		$	27.94
Granted	436,726		10.12
Canceled	(486,999	)	23.77
Outstanding at June 30, 2016	2,150,503		$	25.27	4.17	$	3.3
Options Exercisable at June 30, 2016	1,348,779		$	30.52	3.03	$	—
Unvested Options at June 30, 2016	801,724		$	16.43	6.07	$	3.3

During the six months ended June 30, 2016, there were no exercises of stock options. During the six months ended June 30, 2015, the total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.1 million. As of June 30, 2016, $2.3 million of unrecognized compensation cost related to stock options granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheet, is expected to be recognized over a weighted-average period of 2.22 years.

Restricted Share Awards

Restricted share 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 stock that vested during the six months ended June 30, 2016 and 2015, was $21.4 million and $18.1 million, respectively. The weighted-average grant date fair value of restricted stock was $10.25 per share and $21.66 per share for the six months ended June 30, 2016 and 2015, respectively. As of June 30, 2016, $28.8 million of unrecognized compensation cost related to restricted shares granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheet, is expected to be recognized over a weighted-average vesting period of 2.34 years.

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



	Restricted Shares Outstanding		Weighted- Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2015	2,008,210		$	24.18
Granted	2,390,046		10.25
Vested	(829,128	)	25.79
Forfeited	(201,802	)	14.27
Unvested balance at June 30, 2016	3,367,326		$	14.49

Performance Share Units

The performance share units' cash payouts 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 June 30, 2016, 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 Sheet. 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 $10.12 per share and $21.69 per share for the six months ended June 30, 2016 and 2015, respectively. As of June 30, 2016, $16.7 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 2.15 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
Unvested balance at December 31, 2015	630,786		$	27.50
Granted	594,245		10.12
Vested and Paid	(178,169	)	30.07
Forfeited	(3,942	)	28.42
Unvested balance at June 30, 2016	1,042,920		$	17.15

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 classified as liabilities and are included within "Other long-term liabilities" on the Condensed Consolidated Balance Sheet. As these awards are dependent upon the Company's stock price, they are remeasured at fair value at the end of each reporting period. The weighted-average grant date fair value of the restricted share units was $10.12 per share for the six months ended June 30, 2016. As of June 30, 2016, $0.3 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 2.86 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
Unvested balance at December 31, 2015	—		$	—
Granted	21,493		10.12
Vested	(193	)	10.12
Forfeited	(3,266	)	10.12
Unvested balance at June 30, 2016	18,034		$	10.12

Note 12 – Employee Benefits

Pension and Other Postretirement Benefits

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

As a result of the Company's divestitures in 2014 and retirements in 2015, the number of active participants in the Pension Plan fell to 50 employees during the year ended December 31, 2015, which is the minimum number of active participants for a plan to be qualified under the Internal Revenue Services' participation rules. In order to prevent disqualification, 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 Pension Plan is a closed, qualified defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. During the six months ended June 30, 2016, 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 2016. Contributions to the Pension Plan increase plan assets.

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. During the six months ended June 30, 2016, the Company made contributions of $1.5 million to its SERP and expects to contribute an additional $2.1 million to its SERP during the remainder of 2016. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and was closed to new participants effective January 1, 2016.

The Medical Plan is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired employees. During the six months ended June 30, 2016, the Company made contributions of $0.1 million to its Medical Plan and expects to contribute an additional $0.2 million to its Medical Plan during the remainder of 2016. Contributions to the Medical Plan are used to fund current benefit payments.

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.4		$	0.4		$	0.6		$	1.0
Interest cost	1.4			1.1			2.6			2.4
Expected return on plan assets	(1.4		)	(1.4		)	(2.8		)	(2.8		)
Amortization of prior service costs ⁽¹⁾	0.3			0.1			0.4			0.9
Amortization of actuarial losses ⁽¹⁾	0.4			—			0.6			0.3
Curtailment loss ⁽²⁾	—			11.2			—			11.2
Periodic expense	$	1.1		$	11.4		$	1.4		$	13.0

Medical Plan benefits
Interest cost	$	—		$	—		$	0.1		$	0.1
Amortization of prior service costs ⁽¹⁾	0.1			0.1			0.1			0.1
Periodic expense	$	0.1		$	0.1		$	0.2		$	0.2

____________________________


⁽¹⁾	Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income are recognized in the Condensed Consolidated Statements of Operations within "General and administrative" 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 are included on the Condensed Consolidated Statements of Operations within "General and administrative" expense for the three and six months ended June 30, 2015.

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 a 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 2015 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three and six months ended June 30, 2016 and 2015. For definitions of commonly used oil and gas terms found in this Quarterly Report on Form 10-Q, please refer to the "Glossary of Commonly Used Terms" provided in QEP's 2015 Annual Report on Form 10-K.

OVERVIEW

The Company has substantial acreage positions and operations in some of the most prolific hydrocarbon resource plays in the continental United States, including the Williston Basin, Permian Basin, Pinedale Anticline, Uinta Basin and Haynesville Shale. These resource plays are characterized by unconventional oil or gas accumulations in continuous tight sands 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. that provide a solid base for growth in organic production and reserves.

Outlook

In response to the commodity price environment, we reduced drilling and completion activities, slowed production growth, reduced costs and preserved our liquidity in 2015 and in the first half of 2016, and plans to continue these strategies for the remainder of 2016. We are focused on driving improved operating performance by optimizing reservoir development, enhancing well completion designs, and aggressively pursuing cost reductions.

Based on current commodity prices, we expect to be able to fund our planned capital program with cash flow from operating activities, cash on hand and, if needed, availability under our credit facility. Our total capital expenditures for 2016, primarily related to development and recompletion activities, are expected to be approximately $525.0 million, which includes adding two rigs in the fourth quarter of 2016 associated with the expected closing of the 2016 Permian Acquisition (defined below), a decrease of approximately 50% from 2015 capital expenditures. With this capital program, we expect total equivalent production to be relatively flat compared to 2015, excluding any production from the 2016 Permian Acquisition. We plan to continuously evaluate our level of drilling and completion activity in light of both commodity prices and changes we are able to make to our costs of operations and adjust our capital spending program as appropriate. See "Cash Flow from Investing Activities" for further discussion of our capital expenditures. We will also continue to pursue acquisitions and divest of non-core properties.

Equity Offerings

In June 2016, QEP issued 23.0 million additional shares of common stock through a public offering and received net proceeds of approximately $413.0 million. QEP intends to use the net proceeds from this offering to partially fund the acquisition of additional properties in the Permian Basin. If the acquisition is not consummated, QEP intends to use the net proceeds from this offering for general corporate purposes, which may include, among other things, reducing indebtedness, acquiring properties and funding a portion of our exploration and production activities and working capital.

Termination of Marketing Agreements and QEP Marketing Segment

Effective January 1, 2016, QEP terminated its contracts for resale and marketing transactions between its wholly owned subsidiaries, QEP Marketing Company (QEP Marketing) and QEP Energy Company (QEP Energy). In addition, substantially all of QEP Marketing's third-party purchase and sale agreements and gathering, processing and transportation contracts were assigned to QEP Energy, except those contracts related to natural gas storage activities and the Haynesville gathering system. As a result, QEP Energy is directly marketing its own gas, oil and NGL production. While QEP will continue to act as an agent for the sale of gas, oil and NGL production for other working interest owners, for whom QEP serves as the operator, QEP is no longer the first purchaser of this production. QEP has substantially reduced its marketing activities, and subsequently is reporting lower resale revenue and expenses than it had in prior periods. In conjunction with the changes described above, QEP conducted a segment analysis in accordance with Accounting Standards Codification (ASC) Topic 280, Segment Reporting, and determined that QEP has one reportable segment effective January 1, 2016.

Acquisitions and Divestitures

primarily held by production from 96 vertical wells. The 2016 Permian Acquisition is expected to close in September 2016, and the Company plans to fund the transaction with proceeds from the June 2016 equity offering and cash on hand.

During the six months ended June 30, 2016, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for a total purchase price of $29.8 million, which primarily included additional interests in QEP's operated wells and additional undeveloped leasehold. As a part of the purchase price allocation, the Company recorded $3.7 million of goodwill.

While QEP believes its extensive inventory of identified drilling locations provide a solid base for growth in production and reserves, the Company continues to evaluate acquisition opportunities that it believes will create significant long-term value. QEP believes that its experience, expertise, and presence in its core operating areas, combined with a low-cost operating model and financial strength, enhances its ability to pursue acquisition opportunities.

Financial and Operating Results

During the three months ended June 30, 2016, QEP:


•	Achieved natural gas equivalent production of 83.3 Bcfe, a 3% increase over the same period in 2015;


•	Achieved record oil production of 5,209.5 Mbbls, a 7% increase over the second quarter of 2015, including higher production in both the Permian and Williston basins;


•	Reduced lease operating and transportation and other handling expense by $0.15/Mcfe to $1.46/Mcfe;


•	Generated a net loss of $197.0 million, or $0.90 per diluted share;


•	Achieved Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $168.3 million;


•	Issued 23.0 million additional shares of common stock through a public offering and received net proceeds of approximately $413.0 million; and


•	Maintained $1,038.3 million in cash and cash equivalents and had nothing drawn under our credit facility.

During the six months ended June 30, 2016, QEP:


•	Achieved natural gas equivalent production of 166.0 Bcfe, a 6% increase over the same period in 2015;


•	Increased oil production to 10,385.9 Mbbls, an 11% increase over the first half of 2015, including higher production in both the Permian and Williston basins;


•	Reduced lease operating and transportation and other handling expense by $0.10/Mcfe to $1.54/Mcfe;


•	Generated a net loss of $1,060.8 million, or $5.21 per diluted share;


•	Achieved Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $283.4 million;


•	Incurred impairment expense of $1,183.2 million due to lower future commodity prices; and


•	Issued 60.95 million additional shares of common stock through two public offerings and received net proceeds of approximately $781.6 million.

Factors Affecting Results of Operations

Supply, Demand, Market Risk and its 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 natural 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 gas, oil and NGL directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling and completion activity and related capital expenditures, liquidity, rate of growth, costs of goods and services required to drill, complete and operate wells, and the carrying value of its oil and gas properties. Historically field-level prices received for QEP’s oil and gas production have been volatile. During the past five years, the posted price for WTI crude oil has ranged from a low of $26.19 per barrel in February 2016 to a high of $113.39 per barrel in April 2011. 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 the prices of oil and natural gas continue at current levels or decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected.

NGL Prices

NGL prices have also been affected by increased U.S. hydrocarbon production and insufficient domestic demand and export capacity. Prices of heavier NGL components, typically correlated to crude oil prices, have declined in concert with weakening oil prices. Concurrently, the lighter NGL components, ethane and propane, have experienced declines as a result of growing North American oversupply. In addition to produced 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 an 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 six months ended June 30, 2016, and will likely continue to reject ethane for the remainder of 2016.

Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the global economy, including Europe's economic outlook and the United Kingdom’s vote to exit the European Union; the Organization of Petroleum Exporting Countries (OPEC) countries oil production; political unrest in Europe, the Middle East, and Africa; slowing growth in Asia, particularly in China; the outcome of U.S. federal, state and local elections and ballot initiatives; 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 natural gas, crude oil and NGL supply, demand, prices and the Company's ability to continue its planned drilling programs on federal and Native American lands 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 crude oil. U.S. producers now have access to a wider market, and the U.S. could become a significant exporter of oil if the necessary infrastructure is built to support oil exports. QEP anticipates global oil prices will improve in the coming years as supply growth moderates due to lower level of investment and modest demand increases. 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 increased global economic uncertainty and the corresponding volatility of commodity prices, QEP has built a strong liquidity position to ensure financial flexibility and has reduced drilling and completion activity and planned capital expenditures. 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 June 30, 2016, assuming forecasted 2016 annual production of approximately 320 Bcfe, QEP had approximately 77% of its forecasted gas production and 48% of its forecasted oil production covered with fixed-price swaps and collars. The average swap prices for the derivative contracts settling in 2016, 2017 and 2018 are significantly lower than the average swap prices for the derivative contracts settled prior to 2016 and, therefore, QEP's derivative portfolio may not contribute as much to QEP's net realized prices for current and future production. 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.

Government Regulatory Developments

New 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. For example, in June 2016, the EPA finalized updates to Subpart OOOO 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 oil wells. 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 published a rule under the Clean Air Act regarding source determination and permitting requirements for the onshore oil and gas industry. This rule defines adjacent sources as those within a quarter of a mile of each other that have

shared equipment. Under the new rule, emissions from those sources must be aggregated as a single source. The new rule specifically addresses programs administered by the EPA, such as lands situated in tribal lands. Most states and local agencies will have discretion on adopting similar rules. This ruling could lead to increased emission controls and potentially increased permitting costs and compliance requirements, particularly for operations located in areas where EPA has primary jurisdiction.

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 in Utah identified as tribal lands that may require additional emissions controls on existing equipment. The proposals will likely result in increased operating and compliance costs.

In June 2016, the EPA also issued a proposed Information Collection Request (ICR) to support development of new regulations covering methane emissions at existing oil and gas sites. There will be both an "operator survey" and a "facility survey" with greater detail required in the "facility survey". This process could result in additional regulations on existing oil and gas sites potentially leading to increased operating and compliance costs.

Potential for Future Asset Impairments

The carrying value of the Company's properties is sensitive to declines in natural gas, crude oil and NGL prices. The value of these assets are at risk of impairment if future natural gas, crude oil and/or NGL prices decline and/or drilling and completion costs increase. The cash flow model that the Company uses to assess proved properties for impairment includes numerous assumptions, such as management's estimates of future gas, oil and NGL production, market outlook on forward commodity prices, operating and development costs, and discount rates. During the six months ended June 30, 2016, the Company recorded impairments of $1,183.2 million, of which $1,167.9 million was related to impairments of proved properties due to lower future prices, primarily in Pinedale, $11.6 million was related to expiring leaseholds on unproved properties and $3.7 million was related to an impairment of goodwill. During the six months ended June 30, 2015, impairments were $20.5 million, of which $19.4 million was related to proved properties due to lower future prices and $1.1 million was related to expiring leaseholds on unproved properties. If commodity prices decline during 2016, there could be additional impairment charges to our oil and gas assets or other investments.

Multi-Well Pad Drilling

To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling where practical. In certain of our producing areas, wells drilled on a pad are not brought into production until all wells on the pad are drilled and cased and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the commencement of production. In addition, existing wells that offset new wells being completed by QEP or offset operators may need to be temporarily shut-in during the completion process. Such delays and well shut-ins have caused and may continue to cause volatility in QEP’s quarterly operating results.

Midstream Services

QEP's ability to produce its wells depends in substantial part on the availability and capacity of gathering, transportation and gas processing facilities owned and operated by third parties. Due to market conditions, many midstream companies are attempting to renegotiate their gathering, processing and transportation agreements with their upstream counterparties. For example, an entity that purchases, gathers and processes natural gas produced from oil wells operated by QEP in the Williston Basin has claimed that the decline in commodity prices has rendered its gathering and processing operations "uneconomic" and demanded that QEP pay additional fees for gathering and processing services. The midstream provider has been unwilling to connect recently drilled and completed wells on the Company's South Antelope acreage of the Williston Basin unless QEP agrees to pay the increased fees, which has negatively impacted completion activities and production volumes. Due to this dispute, the pace at which the Company is able to complete additional drilled and uncompleted wells during the third quarter 2016 at South Antelope may be impacted. QEP initiated arbitration proceedings in May 2016 to enforce the terms of the existing agreement. The Company anticipates the arbitration will likely be concluded in the fourth quarter of 2016.

Critical Accounting Estimates

QEP's significant accounting policies are described in Item 7 of Part II of its 2015 Annual Report on Form 10-K. The Company's Condensed Consolidated Financial Statements are prepared in accordance with GAAP. The preparation of the Company's Condensed Consolidated Financial Statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP's accounting policies on oil and gas reserves, successful efforts accounting for oil and gas operations, impairment of long-lived assets, asset retirement obligations, revenue recognition, litigation and other contingencies, environmental obligations, derivative contracts, pension and other postretirement benefits, share-based compensation, income taxes and purchase price allocations, among others, may involve a high degree of complexity and judgment on the part of management.

Drilling Activity

The following table presents operated and non-operated well completions for the three and six months ended June 30, 2016:



	Operated Completions				Non-operated Completions
	Three Months Ended		Six Months Ended		Three Months Ended		Six Months Ended
	June 30, 2016		June 30, 2016		June 30, 2016		June 30, 2016
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	4	3.4	4	3.4	—	—	—	—
Williston Basin	1	1.0	18	17.8	4	0.0	7	0.0
Uinta Basin	—	—	8	8.0	—	—	2	0.0
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	4	0.7	9	1.8
Permian Basin	6	6.0	13	12.7	—	—	—	—
Other Southern	—	—	—	—	—	—	—	—

The following table presents operated and non-operated wells drilling or waiting on completion at June 30, 2016:



	Operated				Non-operated
	Drilling		Waiting on completion		Drilling		Waiting on completion
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	8	3.9	32	17.1	—	—	—	—
Williston Basin	2	2.0	28	24.7	—	—	25	1.6
Uinta Basin	—	—	—	—	—	—	1	0.0
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	2	0.3	7	0.4
Permian Basin	1	1.0	2	2.0	—	—	—	—
Other Southern	—	—	—	—	—	—	—	—

The term "gross" refers to all wells or acreage in which QEP has at least a partial working interest and the term "net" refers to QEP's ownership represented by that working interest. Each gross well completed in more than one producing zone is counted as a single well. QEP typically utilizes multi-well pad drilling where practical. Wells drilled are not brought into production until all wells on the pad are drilled and completed 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. As a result, QEP had 62 gross operated wells waiting on completion as of June 30, 2016.

RESULTS OF OPERATIONS

Net Income

QEP generated a net loss during the second quarter of 2016 of $197.0 million, or $0.90 per diluted share, compared to a net loss of $76.3 million, or $0.43 per diluted share, in the second quarter of 2015. QEP's increased net loss was primarily due to a 27% decrease in realized prices and a $71.7 million increase in unrealized derivative losses. These changes were partially offset by a 3% increase in natural gas equivalent production and lower operating expenses in the second quarter of 2016 compared to the second quarter of 2015.

QEP generated a net loss during the first half of 2016 of $1,060.8 million, or $5.21 per diluted share, compared to a net loss of $131.9 million, or $0.75 per diluted share, in the first half of 2015. QEP's increased net loss was primarily due to an increase in impairment expense of $1,162.7 million, a 31% decrease in realized prices, a $61.7 million increase in unrealized derivative losses and a $38.5 million increase in depreciation, depletion and amortization. These changes were partially offset by a 6% increase in natural gas equivalent production and lower production and property tax expense in the first half of 2016 compared to the first half of 2015.

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 non-cash and/or non-recurring items. Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure of the Company's financial and operating performance that allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources.



	Three Months Ended June 30,						Six Months Ended June 30,
	2016			2015			2016			2015
	(in millions)
Net income (loss)	$	(197.0	)	$	(76.3	)	$	(1,060.8	)	$	(131.9	)
Interest expense	36.6			36.2			73.3			73.0
Interest and other (income) expense	0.3			(3.8		)	(2.0		)	(1.2		)
Income tax provision (benefit)	(113.3		)	(38.8		)	(612.2		)	(70.3		)
Depreciation, depletion and amortization	209.7			215.8			449.7			411.2
Unrealized (gains) losses on derivative contracts	230.0			158.3			243.5			181.8
Exploration expenses	0.4			0.8			0.7			1.9
Net (gain) loss from asset sales	0.8			(24.5		)	0.3			6.0
Impairment	0.8			0.5			1,183.2			20.5
Other ⁽¹⁾	—			11.2			7.7			11.2
Adjusted EBITDA	$	168.3		$	279.4		$	283.4		$	502.2

____________________________

⁽¹⁾

Reflects a non-cash pension curtailment loss that was incurred during the three and six months ended June 30, 2015, due to changes in the Company's pension plan (see Note 12 – Employee Benefits for additional information) and additional legal expenses incurred during the six months ended June 30, 2016. The Company believes that these costs do not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded the losses from the calculation of Adjusted EBITDA.

Adjusted EBITDA decreased to $168.3 million in the second quarter of 2016 from $279.4 million in the second quarter of 2015, due to a 27% decrease in the average realized prices, partially offset by a 3% increase in natural gas equivalent production and lower operating expenses in the second quarter of 2016 compared to the second quarter of 2015.

Adjusted EBITDA decreased to $283.4 million in the first half of 2016 from $502.2 million in the first half of 2015, due to a 31% decrease in the average realized prices, partially offset by a 6% increase in natural gas equivalent production and lower production and property tax expense in the first half of 2016 compared to the first half of 2015.

Revenue, Volume and Price Variance Analysis

The following table shows volume and price related changes for each of QEP’s major revenue categories for the three and six months ended June 30, 2016, compared to the three and six months ended June 30, 2015:



	Gas			Oil			NGL			Total
	(in millions)
Production revenues
Three months ended June 30, 2015 revenues	$	111.9		$	250.4		$	26.1		$	388.4
Changes associated with volumes ⁽¹⁾	(4.0		)	17.1			7.0			20.1
Changes associated with prices ⁽²⁾	(28.7		)	(59.8		)	(10.3		)	(98.8		)
Three months ended June 30, 2016 revenues	$	79.2		$	207.7		$	22.8		$	309.7

Production revenues
Six months ended June 30, 2015 revenues	$	233.9		$	429.2		$	45.2		$	708.3
Changes associated with volumes ⁽¹⁾	(1.8		)	47.1			15.4			60.7
Changes associated with prices ⁽²⁾	(67.8		)	(124.8		)	(24.2		)	(216.8		)
Six months ended June 30, 2016 revenues	$	164.3		$	351.5		$	36.4		$	552.2

____________________________


⁽¹⁾	The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three and six months ended June 30, 2016, as compared to the three and six months ended June 30, 2015, by the average field-level price for the three and six months ended June 30, 2015.

⁽²⁾

The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level prices from the three and six months ended June 30, 2016, as compared to the three and six months ended June 30, 2015, by volumes for the three and six months ended June 30, 2016. Pricing changes are driven by changes in commodity field-level prices, excluding the impact from commodity derivatives.

Total Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
Production volumes (Bcfe)
Northern Region
Pinedale	22.8		24.9		(2.1		)	48.0		46.7		1.3
Williston Basin	31.6		28.6		3.0			61.0		54.0		7.0
Uinta Basin	7.9		7.3		0.6			15.2		14.2		1.0
Other Northern	2.1		2.4		(0.3		)	4.4		5.1		(0.7		)
Southern Region
Haynesville/Cotton Valley	9.2		10.4		(1.2		)	18.3		22.1		(3.8		)
Permian Basin	9.5		6.2		3.3			18.6		11.1		7.5
Other Southern	0.2		1.1		(0.9		)	0.5		2.9		(2.4		)
Total production	83.3		80.9		2.4			166.0		156.1		9.9
Total equivalent prices (per Mcfe)
Average equivalent field-level price	$	3.72	$	4.80	$	(1.08	)	$	3.33	$	4.54	$	(1.21	)
Commodity derivative impact	0.59		1.14		(0.55		)	0.67		1.25		(0.58		)
Net realized equivalent price	$	4.31	$	5.94	$	(1.63	)	$	4.00	$	5.79	$	(1.79	)

Gas Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
Gas production volumes (Bcf)
Northern Region
Pinedale	19.9		21.5		(1.6		)	41.6		40.5		1.1
Williston Basin	4.0		3.0		1.0			7.2		5.7		1.5
Uinta Basin	6.4		5.7		0.7			12.2		10.6		1.6
Other Northern	2.0		2.1		(0.1		)	4.0		4.5		(0.5		)
Southern Region
Haynesville/Cotton Valley	9.0		10.3		(1.3		)	18.1		21.9		(3.8		)
Permian Basin	1.6		1.2		0.4			3.0		1.9		1.1
Other Southern	—		0.7		(0.7		)	0.2		2.0		(1.8		)
Total production	42.9		44.5		(1.6		)	86.3		87.1		(0.8		)
Gas prices (per Mcf)
Northern Region	$	1.80	$	2.49	$	(0.69	)	$	1.89	$	2.66	$	(0.77	)
Southern Region	1.97		2.59		(0.62		)	1.94		2.75		(0.81		)

Average field-level price	$	1.84	$	2.52	$	(0.68	)	$	1.90	$	2.69	$	(0.79	)
Commodity derivative impact	0.67		0.63		0.04			0.58		0.53		0.05
Net realized price	$	2.51	$	3.15	$	(0.64	)	$	2.48	$	3.22	$	(0.74	)

Gas revenues decreased $32.7 million, or 29%, in the second quarter of 2016 compared to the second quarter of 2015, due to lower field-level prices and lower gas production. Average field-level gas prices decreased 27% in the second quarter of 2016 compared to the second quarter of 2015 driven by a decrease in average NYMEX-HH natural gas prices for the comparable period. The 4% decrease in production volumes was primarily driven by a production decrease in Pinedale due to the suspension of well completions until late in the second quarter of 2016, in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program and in Other Southern due to the continued divestitures of non-core properties. These decreases were partially offset by production increases in the Uinta, Permian and Williston basins due to continued development drilling.

Gas revenues decreased $69.6 million, or 30%, in the first half of 2016 compared to the first half of 2015, due to lower field-level prices and lower gas production. Average field-level gas prices decreased 29% in the first half of 2016 compared to the first half of 2015 driven by a decrease in average NYMEX-HH natural gas prices for the comparable period. The 1% decrease in production volumes was primarily driven by a production decrease in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program and in Other Southern due to the continued divestitures of non-core properties. These decreases were partially offset by production increases in Pinedale and the Uinta, Permian and Williston basins due to continued development drilling.

Oil Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
Oil production volumes (Mbbl)
Northern Region
Pinedale	149.5		176.0		(26.5		)	325.8		321.5		4.3
Williston Basin	3,799.3		3,769.2		30.1			7,517.3		7,200.7		316.6
Uinta Basin	198.3		202.0		(3.7		)	406.6		423.6		(17.0		)
Other Northern	34.1		44.3		(10.2		)	70.5		89.4		(18.9		)
Southern Region
Haynesville/Cotton Valley	7.3		8.9		(1.6		)	13.9		16.7		(2.8		)
Permian Basin	1,008.7		628.1		380.6			2,028.1		1,199.9		828.2
Other Southern	12.3		47.4		(35.1		)	23.7		105.5		(81.8		)
Total production	5,209.5		4,875.9		333.6			10,385.9		9,357.3		1,028.6
Oil prices (per bbl)
Northern Region	$	38.86	$	50.60	$	(11.74	)	$	32.82	$	44.93	$	(12.11	)
Southern Region	43.99		55.85		(11.86		)	37.96		51.47		(13.51		)

Average field-level price	$	39.88	$	51.34	$	(11.46	)	$	33.84	$	45.86	$	(12.02	)
Commodity derivative impact	3.81		13.24		(9.43		)	5.84		15.88		(10.04		)
Net realized price	$	43.69	$	64.58	$	(20.89	)	$	39.68	$	61.74	$	(22.06	)

Oil revenues decreased $42.7 million, or 17%, in the second quarter of 2016 compared to the second quarter of 2015, due to lower average field-level prices, partially offset by higher volumes. Average field-level oil prices decreased 22% in the second quarter of 2016 compared to the second quarter of 2015 driven by a decrease in average NYMEX-WTI and ICE Brent oil prices for the comparable periods. The 7% increase in production volumes was driven by increases in the Permian and Williston basins due to continued development drilling. These increases were partially offset by production decreases in Other Southern due to the continued divestitures of non-core properties and in Pinedale due to suspension of well completions until late in the second quarter of 2016.

Oil revenues decreased $77.7 million, or 18%, in the first half of 2016 compared to the first half of 2015, due to lower average field-level prices, partially offset by higher volumes. Average field-level oil prices decreased 26% in the first half of 2016 compared to the first half of 2015 driven by a decrease in average NYMEX-WTI and ICE Brent oil prices for the comparable periods. The 11% increase in production volumes was primarily driven by increases in the Permian and Williston basins due to continued development drilling. These production increases were partially offset by a production decrease in Other Southern due to the continued divestitures of non-core properties.

NGL Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
NGL production volumes (Mbbl)
Northern Region
Pinedale	334.1		403.8		(69.7		)	736.1		716.8		19.3
Williston Basin	802.4		482.8		319.6			1,441.9		841.6		600.3
Uinta Basin	57.3		70.3		(13.0		)	101.6		179.7		(78.1		)
Other Northern	6.0		6.5		(0.5		)	9.7		9.2		0.5
Southern Region
Haynesville/Cotton Valley	6.2		6.8		(0.6		)	14.6		13.9		0.7
Permian Basin	310.2		209.0		101.2			572.3		328.8		243.5
Other Southern	5.1		18.8		(13.7		)	10.1		55.4		(45.3		)
Total production	1,521.3		1,198.0		323.3			2,886.3		2,145.4		740.9
NGL prices (per bbl)
Northern Region	$	15.61	$	23.41	$	(7.80	)	$	13.11	$	22.44	$	(9.33	)
Southern Region	12.61		14.59		(1.98		)	10.67		14.57		(3.90		)

Average field-level price	$	14.97	$	21.68	$	(6.71	)	$	12.61	$	20.98	$	(8.37	)
Commodity derivative impact	—		—		—			—		—		—
Net realized price	$	14.97	$	21.68	$	(6.71	)	$	12.61	$	20.98	$	(8.37	)

NGL revenues decreased $3.3 million, or 13%, during the second quarter of 2016 compared to the second quarter of 2015, due to lower average field-level prices, partially offset by increased production volumes. NGL prices decreased 31% during the second quarter of 2016 compared to the second quarter of 2015, which was primarily driven by receiving an increased percentage of ethane from a midstream provider on our Williston Basin production during the second quarter of 2016 compared to the second quarter of 2015. The increased percentage of ethane is a result of a midstream provider electing to operate their gas processing plant in ethane recovery. The 27% increase in total NGL production volumes was driven by increases in the Williston and Permian basins. The increase in the Williston Basin is due to the additional ethane recovered combined with continued development drilling and the increase in the Permian Basin is due to continued development drilling. These increases were partially offset by a production decrease in Pinedale due to the suspension of well completions until late in the second quarter of 2016.

NGL revenues decreased $8.8 million, or 20%, during the first half of 2016 compared to the first half of 2015, due to lower average field-level prices, partially offset by increased production volumes. NGL prices decreased 40% during the first half of 2016 compared to the first half of 2015, which was primarily driven by receiving an increased percentage of ethane from a midstream provider on our Williston Basin production during the first half of 2016 compared to the first half of 2015. The increased percentage of ethane is a result of a midstream provider electing to operate their gas processing plant in ethane recovery. The 35% increase in total NGL production volumes was driven by increases in the Williston and Permian basins. The increase in the Williston Basin is due to the additional ethane recovered combined with continued development drilling and the increase in the Permian Basin is due to continued development drilling. These increases were partially offset by a production decrease in the Uinta Basin due to refrigeration processing of gas in the first half of 2016 compared to cryogenic processing during a portion of the first half of 2015.

Resale Margin and Storage Activity

QEP purchases and resells gas and oil primarily to mitigate losses on unutilized capacity related to firm transportation commitments and storage activities. The difference between the price of products purchased and sold, net of transportation costs, creates a resale margin that represents a gain or loss for the Company. The following table is a summary of QEP's financial results from its resale activities.



	Three Months Ended June 30,									Six Months Ended June 30,
	2016			2015			Change			2016			2015			Change
	(in millions)
Purchased gas and oil sales	$	24.5		$	181.0		$	(156.5	)	$	41.0		$	324.8		$	(283.8	)
Purchased gas and oil expense	(26.8		)	(183.2		)	156.4			(43.7		)	(329.1		)	285.4
Realized gains (losses) on storage derivative instruments	0.7			(0.3		)	1.0			2.8			2.2			0.6
Resale margin	$	(1.6	)	$	(2.5	)	$	0.9		$	0.1		$	(2.1	)	$	2.2

As a result of the termination of QEP Marketing agreements effective January 1, 2016, QEP is no longer the first purchaser of other working interest owner production. As such, QEP is reporting lower resale revenue and expenses in the first half of 2016 than it had in prior periods. For additional details, see Note 1 – Basis of Presentation, in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Operating Expenses

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



	Three Months Ended June 30,							Six Months Ended June 30,
	2016		2015		Change			2016		2015		Change
	(per Mcfe)
Lease operating expense	$	0.63	$	0.71	$	(0.08	)	$	0.68	$	0.76	$	(0.08	)
Gas, oil and NGL transportation and other handling costs	0.83		0.90		(0.07		)	0.86		0.88		(0.02		)
Production and property taxes	0.25		0.40		(0.15		)	0.23		0.39		(0.16		)
Total production costs	$	1.71	$	2.01	$	(0.30	)	$	1.77	$	2.03	$	(0.26	)

Lease operating expense (LOE). QEP’s LOE was $52.6 million, a decrease of $4.5 million, or $0.08 per Mcfe, during the second quarter of 2016 compared to the second quarter of 2015. The decrease was driven by a decrease in the Permian Basin as a result of lower chemical and compression expenses and a decrease in Other Southern as a result of continued divestitures of non-core properties. Partially offsetting the decrease was an increase in the Williston Basin due to increased maintenance, repairs, workover and produced water disposal expenses.

QEP’s LOE was $112.6 million, a decrease of $6.3 million, or $0.08 per Mcfe, during the first half of 2016 compared to the first half of 2015. The decrease was driven by a decrease in the Permian Basin as a result of lower chemical, maintenance, repairs and workover expenses and a decrease in Other Southern as a result of continued divestitures of non-core properties. Partially offsetting the decrease was an increase in the Williston Basin due to increased maintenance, repairs, workover and produced water disposal expenses.

Gas, oil and NGL transportation and other handling costs. Gas, oil and NGL transportation and other handling costs were $69.5 million, a decrease of $3.5 million, or $0.07 per Mcfe, during the second quarter of 2016 compared to the second quarter of 2015. The $3.5 million decrease in expense was primarily attributable to a decrease in Haynesville/Cotton Valley due to declining production volumes and a decrease in the Williston Basin due to lower rates. These decreases were partially offset by an increase in the Permian Basin, primarily due to an increase in production volumes and slightly higher rates.

Gas, oil and NGL transportation and other handling costs were $143.1 million, an increase of $5.0 million, during the first half of 2016 compared to the first half of 2015, primarily attributable to production increases in Pinedale and the Williston, Permian and Uinta basins. Gas, oil and NGL transportation and other handling costs, on a per Mcfe basis, was down $0.02, primarily driven by rate decreases in the Williston and Uinta basins.

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 were $20.7 million, a decrease of $12.0 million, or $0.15 per Mcfe, during the second quarter of 2016 compared to the second quarter of 2015 primarily as a result of decreased gas, oil and NGL revenues from lower field-level prices and production tax refunds.

Production and property taxes were $38.5 million, a decrease of $22.0 million, or $0.16 per Mcfe, during the first half of 2016 compared to the first half of 2015 primarily as a result of decreased gas, oil and NGL revenues from lower field-level prices and production tax refunds.

Depreciation, depletion and amortization (DD&A). DD&A expense was $209.7 million, a decrease of $6.1 million in the second quarter of 2016 compared to the second quarter of 2015, due to decreases in Pinedale and the Williston Basin, partially offset by an increase in the Permian Basin. The decrease in Pinedale is primarily due to a decrease in production and a rate decrease due to a first quarter 2016 impairment. The decrease in the Williston Basin is primarily due to a rate decrease from increased proved reserves, partially offset by an increase in production. The increase in the Permian Basin is primarily due to a rate increase from decreased proved reserves and an increase in production.

DD&A expense was $449.7 million, an increase of $38.5 million in the first half of 2016 compared to the first half of 2015, due to increases in the Permian and Uinta basins, partially offset by decreases in Pinedale and the Williston Basin. The increases in the Permian and Uinta basins were primarily due to increased rates due to a decrease in proved reserves, combined with increased production. The decrease in Pinedale is primarily the result of a rate decrease due to a first quarter 2016 impairment, while the decrease in the Williston Basin is the result of a rate decrease from increased proved reserves, partially offset by an increase in production.

Impairment expense. Impairment expense was $0.8 million for the second quarter of 2016, and $0.5 million for the second quarter of 2015, all of which was related to expiring leaseholds on unproved properties.

Impairment expense was $1,183.2 million for the first half of 2016, of which $1,167.9 million was related to proved properties due to lower future prices, $11.6 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. Impairment expense was $20.5 million for the first half of 2015, of which $19.4 million was related to proved properties due to lower future prices and $1.1 million was related to expiring leaseholds on unproved properties. Of the $19.4 million impairment on proved properties, $14.5 million related to Other Southern properties and $4.9 million related to Other Northern properties.

General and administrative expense (G&A). During the second quarter of 2016, G&A expense was $43.7 million, a decrease of $7.6 million, or 15%, compared to the second quarter of 2015, primarily due to a pension curtailment expense of $11.2 million recognized in the second quarter of 2015 (see Note 12 – Employee Benefits, in Item 1 of Part I of this Quarterly Report on Form 10-Q), a $2.6 million decrease in legal, professional and outside services expenses, a $1.5 million decrease in bad debt expense and a $1.2 million decrease in labor, benefits and employee expenses. These decreases were partially offset by a $7.8 million increase in share-based compensation primarily due to an increase in the mark-to-market value of the Deferred Compensation Wrap Plan and Cash Incentive Plan (CIP) and a $1.3 million increase in severance payments primarily related to the April 2016 restructuring (see Note 8 – Restructuring Costs, in Item 1 of Part I of this Quarterly Report on Form 10-Q).

During the first half of 2016, G&A expense was $92.4 million, a decrease of $6.3 million, or 6%, compared to the first half of 2015, primarily due to a pension curtailment expense of $11.2 million recognized in the second quarter of 2015 (see Note 12 – Employee Benefits, in Item 1 of Part I of this Quarterly Report on Form 10-Q), a $4.3 million decrease in labor, benefits and employee expenses and a $1.8 million decrease in bad debt expense. These decreases were partially offset by a $5.7 million increase in legal, professional and outside services expenses and a $7.6 million increase in share-based compensation primarily due to an increase in the mark-to-market value of the Deferred Compensation Wrap Plan and Cash Incentive Plan (CIP).

Net gain (loss) from asset sales. QEP recognized a loss on the sale of assets of $0.8 million during the second quarter of 2016 compared to a gain on sale of $24.5 million in the second quarter of 2015. The loss on sale of assets in the second quarter of 2016 was primarily related to continued divestitures of non-core Other Southern properties. The gain on sale of assets recognized during the second quarter of 2015 was primarily due to a $26.6 million gain recognized on the sale of QEP's Other Southern non-core properties, partially offset by losses related to post-closing adjustments on the sale of QEP's interest in non-core Other Southern properties in 2014.

QEP recognized a loss on the sale of assets of $0.3 million during the first half of 2016 compared to a loss on the sale of assets of $6.0 million in the first half of 2015. The loss on sale of assets in the first half of 2016 was primarily related to continued divestitures of non-core Other Southern properties. The loss on sale of assets of $6.0 million recognized during the first half of 2015 was primarily due to post-closing adjustments related to sales of QEP's interest in 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 second quarter of 2016, losses on commodity derivative contracts were $180.5 million, of which $230.0 million were unrealized losses, partially offset by $49.5 million of realized gains. During the second quarter of 2015, losses on commodity derivative contracts were $66.0 million, of which $158.3 million were unrealized losses, partially offset by $92.3 million of realized gains.

During the first half of 2016, losses on commodity derivative contracts were $129.6 million, of which $243.5 million were unrealized losses, partially offset by $113.9 million of realized gains. During the first half of 2015, gains on commodity derivative contracts were $14.9 million, of which $196.7 million were realized gains, partially offset by $181.8 million of unrealized losses.

Interest expense. Interest expense was $36.6 million during the second quarter of 2016 compared to $36.2 million during the second quarter of 2015.

Interest expense was $73.3 million during the first half of 2016 compared to $73.0 million during the first half of 2015.

Income tax (provision) benefit. Income tax benefit was $113.3 million during the second quarter of 2016 compared to $38.8 million of benefit during the second quarter of 2015. The income tax rate was 36.5% during the second quarter of 2016 compared to a rate of 33.7% during the second quarter of 2015. The increase in income tax rate was primarily the result of a lower state tax rate in 2015 due to a change in the composition of income between subsidiaries.

Income tax benefit was $612.2 million during the first half of 2016 compared to $70.3 million of benefit during the first half of 2015. The income tax rate was 36.6% during the first half of 2016 compared to a rate of 34.8% during the first half of 2015. The increase in income tax rate was primarily the result of a lower state tax rate in 2015 due to a change in the composition of income between subsidiaries.

LIQUIDITY AND CAPITAL RESOURCES

QEP plans to fund its development projects by employing a capital structure and financing strategy that will provide sufficient liquidity to withstand commodity price volatility. As a part of this strategy, QEP maintains a commodity price derivative strategy to reduce the financial impact of commodity price volatility and to provide some certainty to QEP's cash flows. In response to the current commodity price environment, QEP reduced drilling and completion activity, slowed production growth and preserved liquidity in 2015 and in the first half of 2016 and plans to continue these strategies for the remainder of 2016. In February 2016, the Board of Directors indefinitely suspended the payment of quarterly dividends.

Generally, QEP funds its operations, capital expenditures and working capital requirements with cash flow from its operating activities, cash on hand and, if needed, borrowings under its credit facility. To provide additional liquidity, QEP also periodically accesses debt and equity markets and sells non-core assets. In 2016, QEP issued 60.95 million shares of common stock through two public offerings and received net proceeds of approximately $781.6 million, which the Company plans to use for general corporate purposes and to fund the 2016 Permian Acquisition, if consummated. The Company plans to repay its $176.8 million Senior Notes due in September 2016 with cash on hand. Further, the Company expects cash flow from operations, cash on hand and availability under its credit facility will be sufficient to fund the Company’s planned capital expenditures, operating expenses and any potential obligations related to loss contingencies (see Note 10 – Contingencies, in Item 1 of Part I of this Quarterly Report on Form 10-Q) during the next 12 months and the foreseeable future.

The Company estimates that, as of June 30, 2016, it could incur additional indebtedness of approximately $1.0 billion and continue to be in compliance with the covenants contained in its credit facility. The Company expects that its ability to incur additional indebtedness will decrease significantly throughout the remainder of 2016 as lower commodity prices continue to impact the financial results that are used to calculate the amount of indebtedness the Company can incur while remaining in compliance with the covenants contained in its credit facility (see Credit Facility discussion below). 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 (as defined in the credit agreement) that limit the amount of debt the Company may incur and may limit the amount available to be drawn under the credit facility including: (i) a net funded debt to capitalization ratio that may not exceed 60%, (ii) a leverage ratio under which net funded debt may not exceed 4.25 times consolidated EBITDA (as defined in the credit agreement) for the fiscal quarters ending on and prior to December 31, 2017, and 3.75 times thereafter and (iii) a present value coverage ratio under which the present value of the Company’s proved reserves must exceed net funded debt by 1.25 times at any time prior to January 1, 2018, and 1.50 times at any time on or after January 1, 2018.

As of June 30, 2016 and December 31, 2015, QEP had no borrowings outstanding under the credit facility, had $2.8 million and $3.4 million, respectively, in letters of credit outstanding under the credit facility, and was in compliance with the covenants under the credit agreement. As of July 22, 2016, QEP had no borrowings outstanding under the credit facility, had $2.8 million of letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.

Senior Notes

The Company’s senior notes outstanding as of June 30, 2016, totaled $2,221.8 million principal amount and are comprised of six issuances as follows:


•	$176.8 million 6.05% Senior Notes due September 2016;


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


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


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


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


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

Cash Flow from Operating Activities

Cash flows from operations are primarily affected by gas, oil 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 gas, oil and NGL production for the next 12 to 36 months.

Net cash from operating activities is presented below:



	Six Months Ended June 30,
	2016			2015			Change
	(in millions)
Net income (loss)	$	(1,060.8	)	$	(131.9	)	$	(928.9	)
Non-cash adjustments to net income (loss)	1,338.6			620.2			718.4
Changes in operating assets and liabilities	(58.2		)	(490.9		)	432.7
Net cash provided by (used in) operating activities	$	219.6		$	(2.6	)	$	222.2

Net cash provided by operating activities was $219.6 million during the first half of 2016, which included a $1,060.8 million net loss, $1,338.6 million of non-cash adjustments to the net loss and a $58.2 million decrease in operating assets and liabilities. Non-cash adjustments to the net loss primarily included impairment expense of $1,183.2 million, DD&A expense of $449.7 million and unrealized losses on derivative contracts of $243.5 million, partially offset by a decrease in deferred income taxes of $559.9 million. The decrease in operating assets and liabilities primarily included a decrease in accounts payable and accrued expenses of $106.2 million and an increase in income taxes receivable of $83.2 million, partially offset by a decrease in accounts receivable of $118.5 million.

Net cash used in operating activities was $2.6 million during the first half of 2015, which included a $131.9 million net loss, $620.2 million of non-cash adjustments to the net loss and a $490.9 million decrease in operating assets and liabilities. Non-cash adjustments to the net loss primarily included DD&A expense of $411.2 million, unrealized losses on derivative contracts of $181.8 million and impairment expense of $20.5 million, partially offset by a decrease in deferred income taxes of $29.4 million. The decrease in operating assets and liabilities primarily included a decrease in accounts payable and accrued expenses of $25.1 million and a decrease in income taxes payable of $587.8 million, primarily related to income taxes payable from the gain on the sale of substantially all of QEP's midstream business, which was paid in the first half of 2015. These changes were partially offset by a decrease in accounts receivable of $103.1 million.

Cash Flow from Investing Activities

A comparison of capital expenditures for the first half of 2016 and 2015, are presented in the table below:



	Six Months Ended June 30,
	2016		2015		Change
	(in millions)
Property acquisitions and acquisition deposit held in escrow	$	59.8	$	—	$	59.8
Property, plant and equipment capital expenditures	242.7		559.7		(317.0		)
Total accrued capital expenditures	302.5		559.7		(257.2		)
Change in accruals and other non-cash adjustments	27.7		91.6		(63.9		)
Total cash capital expenditures	$	330.2	$	651.3	$	(321.1	)

In the first half of 2016, on an accrual basis, the Company invested $242.7 million on property, plant and equipment capital expenditures, a decrease of $317.0 million compared to the first half of 2015. In the first half of 2016, QEP's capital expenditures were $119.4 million in the Williston Basin, $72.0 million in the Permian Basin, $21.9 million in Haynesville/Cotton Valley, $15.9 million in Pinedale and $10.4 million in the Uinta Basin. In addition, in the first half of 2016, QEP acquired various oil and gas properties in the Williston and Permian basins, primarily additional interests in QEP's operated wells and additional undeveloped leasehold, for a total purchase price of $29.8 million, of which $23.6 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 that is held in escrow related to the 2016 Permian Acquisition that is expected to close in the third quarter of 2016.

In the first half of 2015, on an accrual basis, the Company invested $559.7 million on property, plant and equipment capital expenditures, which included $282.1 million in the Williston Basin, $122.3 million in the Permian Basin, $88.2 million in Pinedale, $34.1 million in the Uinta Basin and $26.0 million in Haynesville/Cotton Valley.

QEP has significantly reduced its planned capital expenditures for 2016 as compared to its capital expenditures in 2015. Due to efficiency gains, strong well performance, and ongoing cost-reduction initiatives, QEP expects total equivalent production to be relatively flat compared to 2015, excluding any production from the 2016 Permian Acquisition. The mid-point of our forecasted capital expenditures for 2016, primarily for development and recompletion activities, is $525.0 million, which includes adding two rigs in the fourth quarter of 2016 associated with the 2016 Permian Acquisition. QEP intends to fund capital expenditures with cash flow from operating activities, cash on hand and, if needed, borrowings under its credit facility. The aggregate levels of capital expenditures for 2016 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, gas, oil 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 half of 2016, net cash provided by financing activities was $749.1 million compared to net cash used in financing activities of $58.2 million in the first half of 2015. During the first half of 2016, QEP had net proceeds from the March and June 2016 equity offerings of approximately $781.6 million and had a decrease in checks outstanding in excess of cash balances of $29.8 million. During the first half of 2015, QEP had a decrease in checks outstanding in excess of cash balances of $47.3 million and paid $7.1 million of quarterly dividend payments.

As of June 30, 2016, the Company did not have any borrowings outstanding under the credit facility and had $2,221.8 million in senior notes outstanding (excluding $27.2 million of net original issue discount and unamortized debt issuance costs).

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP’s primary market risks arise from changes in the market price for gas, oil 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 price 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 June 30, 2016, QEP held commodity price derivative contracts totaling 277.4 million MMBtu of gas and 16.3 million barrels of oil.

The following table presents QEP's derivative positions as of July 22, 2016. See Note 7 – Derivative Contracts in Part 1, Item 1 of this Quarterly Report on Form 10-Q for open derivative positions as of June 30, 2016.



Production Commodity Derivative Swap Positions
Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Gas sales		(MMBtu)	($/MMBtu)
2016	NYMEX HH	24.5	$	2.78
2016	IFNPCR	30.6	$	2.53
2017	NYMEX HH	76.7	$	2.77
2017	IFNPCR	32.9	$	2.51
2018	NYMEX HH	11.0	$	2.87
Oil Sales		(bbls)	($/bbl)
2016	NYMEX WTI	6.1	$	51.24
2017	NYMEX WTI	9.9	$	50.74
2018	NYMEX WTI	1.8	$	53.41



Production Gas Collars
Year	Index	Total Volume	Average Price Floor		Average Price Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2016	NYMEX HH	3.1	$	2.75	$	3.89
2017	NYMEX HH	11.0	$	2.50	$	3.50



Production Gas Basis Swaps
Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2016	NYMEX HH	IFNPCR	15.3	$	(0.16	)
2017	NYMEX HH	IFNPCR	51.1	$	(0.18	)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)



Storage Commodity Derivative Positions
Year	Type of Contract	Index	Total Volumes	Average Swap Price per MMBtu
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2016	SWAP	IFNPCR	2.4	$	2.59
2017	SWAP	IFNPCR	2.8	$	2.80
Gas purchases
2016	SWAP	IFNPCR	2.4	$	2.46

Changes in the fair value of derivative contracts from December 31, 2015 to June 30, 2016, are presented below:



	Commodity derivative contracts
	(in millions)
Net fair value of gas and oil derivative contracts outstanding at December 31, 2015	$	165.2
Contracts settled	(113.9		)
Change in gas and oil prices on futures markets	(111.8		)
Contracts added	(17.8		)
Net fair value of gas and oil derivative contracts outstanding at June 30, 2016	$	(78.3	)

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



	June 30, 2016
	(in millions)
Net fair value – asset (liability)	$	(78.3	)
Fair value if market prices of gas and oil and basis differentials decline by 10%	$	(86.1	)
Fair value if market prices of gas and oil and basis differentials increase by 10%	$	(70.5	)

Utilizing the actual derivative volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $7.8 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $7.8 million as of June 30, 2016. However, a gain or loss eventually would be offset by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company’s commodity derivative transactions, see Note 7 – Derivative Contracts in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Interest Rate Risk Management

The Company’s ability to borrow and the rates offered by lenders can be adversely affected by illiquid credit markets and the Company's credit rating, as described in the risk factors in Item 1A of Part I of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015. The Company’s credit facility has a floating interest rate, which exposes QEP to interest rate risk if QEP has borrowings outstanding. At June 30, 2016, the Company did not have any borrowings outstanding under its credit facility.

The remaining $2,221.8 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 9 – Debt, in Item I of Part I of this Quarterly Report on Form 10-Q.

Forward-Looking Statements

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


•	our growth strategies;


•	strong liquidity position providing financial flexibility and plans to preserve liquidity;


•	our liquidity and sufficiency of cash flow from operations, cash on hand and availability under our credit facility to fund the 2016 Permian Acquisition, our planned capital expenditures, operating expenses and repayment of maturing debt;


•	plans and ability to pursue acquisition opportunities;


•	the funding and closing of the 2016 Permian Acquisition;


•	our inventory of drilling locations;


•	drilling and completion plans;


•	focus on improving operating performance by optimizing reservoir development, enhancing well completion designs and aggressively pursuing cost reductions;


•	results from planned drilling operations and production operations;


•	plans to reduce drilling and completion activities, slow production growth, reduce costs and preserve liquidity;


•	ability to incur additional indebtedness;


•	loss contingencies;


•	sufficiency of accruals;


•	impact of government regulations;


•	expectations regarding gas, oil and NGL prices;


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


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


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


•	impact of global geopolitical and macroeconomic events;


•	exports of oil from the U.S.;


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


•	divestitures of non-core assets;


•	amount and allocation of forecasted capital expenditures and plans for funding capital expenditures, operating expenses, repayment of maturing debt and working capital requirements;


•	resale revenues and expenses;


•	assumptions regarding equity compensation;


•	settlement of performance share units in cash;


•	recognition of compensation costs related to equity compensation grants;


•	expected contributions to our employee benefit plans;


•	employee benefit plan gains or losses;


•	the importance of Adjusted EBITDA (a non-GAAP financial measure) as a measure of performance;


•	delays caused by transportation, processing, storage and refining capacity issues;


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


•	implementation and impact of new accounting pronouncements;


•	impact of shutting in wells;


•	factors impacting our ability to transport oil and gas;


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


•	the timing and estimated costs of restructurings;


•	managing counterparty risk exposure;


•	ability to meet delivery and sales commitments;


•	value of pension plan assets and plans regarding additional contributions to the pension plan;


•	changes to production plans, operating costs and capital expenditures; and


•	use of proceeds from the March 2016 and June 2016 public offerings of common stock.

Any or all forward-looking statements may turn out to be incorrect. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and

uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to the following:


•	the risk factors discussed in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015, and Part II, Item 1A of this Quarterly Reporting on Form 10-Q;


•	changes in gas, oil 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 methods and results;


•	shortages of oilfield equipment, services and personnel;


•	lack of available pipeline, processing and refining capacity;


•	our ability to successfully integrate acquired assets;


•	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 laws or regulations;

•

changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning: the environment, climate change, greenhouse gas or other emissions, natural resources, fish and wildlife, hydraulic fracturing, water use and drilling and completion techniques, as well as the risk of legal proceedings arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;


•	derivative activities;


•	volatility in the commodity-futures market;


•	failure of internal controls and procedures;


•	failure of our information technology infrastructure or applications;


•	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 volumes;


•	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


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

QEP undertakes no obligation to publicly correct or update the forward-looking statements in this Quarterly Report on Form 10-Q, in other documents, or on the Company's website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, the Exchange Act) as of June 30, 2016. Based on such evaluation, such officers have concluded that, as of June 30, 2016, the Company’s disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in the Company’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information is accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

In designing and evaluating the Company’s disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that the Company’s controls will succeed in achieving their goals under all potential future conditions.

Changes in Internal Controls.

There were no changes in the Company's internal controls over financial reporting that occurred during the quarter ended June 30, 2016, 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

None.

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, 2015. Below are material changes to such risk factors that have occurred during the six months ended June 30, 2016.

Renegotiation of gathering, processing and transportation agreements may result in higher costs and/or delays in selling production. Due to market conditions, many midstream companies are attempting to renegotiate their gathering, processing and transportation agreements with their upstream counterparties. If QEP agrees to renegotiate its midstream agreements, the costs QEP pays for midstream services may increase. If QEP and any of its midstream service providers cannot agree on revised terms to these agreements, the midstream service providers may assert that continued performance of their obligations under these contracts is uneconomic and attempt to terminate or alter the agreements, which could hinder QEP's access to gas, oil and NGL markets, increase costs and/or delay production from its wells. Disputes over termination or changes to the agreement could result in arbitration or litigation, causing uncertainty about the status of the agreements and further delays. For example, an entity that purchases, gathers and processes natural gas produced from oil wells operated by QEP in the Williston Basin has claimed that the decline in commodity prices has rendered its gathering and processing operations "uneconomic" and demanded that QEP pay additional fees for gathering and processing services. QEP initiated arbitration proceedings in May 2016 to enforce the terms of the existing agreement. If QEP is not successful and must pay these additional fees, QEP would incur higher transportation and handling costs which would result in reduced net income.

The Company is involved in legal proceedings that may result in substantial liabilities. Like many oil and gas companies, the Company is involved in various legal proceedings, including threatened claims, such as title, royalty, and contractual disputes. For example, the Company has received a demand from certain former limited partners of drilling partnerships, for which the Company acted as general partner. The former limited partners allege that the Company failed to make, or calculated incorrectly, distributions to which they were entitled. No litigation has been filed, and the Company has not fully evaluated the allegations or its defenses. Accordingly, the Company is unable to determine the extent of any potential liability or its impact on the Company’s business, financial condition or results of operations. The cost to settle legal proceedings (alleged or threatened), or satisfy any resulting judgment against the Company in such proceedings could result in a substantial liability, which could materially and adversely impact the Company’s cash flows and operating results for a particular period. Judgments and estimates to determine accruals or range of losses related to legal proceedings could change from one period to the next and such changes could be material. Current accruals may be insufficient.

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
April 1, 2016 - April 30, 2016	7,875	$	16.03	—	$	—
May 1, 2016 - May 31, 2016	3,567	$	17.38	—	$	—
June 1, 2016 - June 30, 2016	3,221	$	18.63	—	$	—

____________________________


⁽¹⁾	All of the 14,663 shares purchased during the three-month period ended June 30, 2016, were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted share grants.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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



Exhibit No.		Exhibits
1.1		Underwriting Agreement, dated as of June 21, 2016, by and among QEP Resources, Inc., J.P. Morgan Securities LLC and Deutsche Bank Securities Inc. (incorporated by reference to Exhibit 1.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on June 27, 2016.
3.1		Certificate of Incorporation, dated May 18, 2010 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 24, 2010)
3.2		Amended and Restated Bylaws, deemed effective October 27, 2014 (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 October 29, 2014)
10.1		Purchase and Sale Agreement, dated June 21, 2016, by and among QEP Energy Company, as purchaser, and RK Petroleum Corp. and various other owners of certain oil and gas properties in the Permian Basin, as sellers.
31.1		Certification signed by Charles B. Stanley, QEP Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification signed by Richard J. Doleshek, QEP Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification signed by Charles B. Stanley and Richard J. Doleshek, QEP Resources, Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.LAB*		XBRL Label Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document
101.DEF*		XBRL Definition Linkbase Document

____________________________


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

SIGNATURES

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



	QEP RESOURCES, INC.
	(Registrant)

July 27, 2016	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer

July 27, 2016	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

Attached files

QEP RESOURCES, INC. Reports

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