QEP RESOURCES, INC. - FORM 10-Q

Attached files

file	filename
EX-31.1 - EXHIBIT 31.1 - QEP RESOURCES, INC.	qepr-20160930ex311.htm
EX-32.1 - EXHIBIT 32.1 - QEP RESOURCES, INC.	qepr-20160930ex321.htm
EX-31.2 - EXHIBIT 31.2 - QEP RESOURCES, INC.	qepr-20160930ex312.htm
EX-10.2 - EXHIBIT 10.2 - QEP RESOURCES, INC.	qepr-20160930ex102.htm
EX-10.1 - EXHIBIT 10.1 - QEP RESOURCES, INC.	qepr-20160930ex101.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 September 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 September 30, 2016, there were 239,557,986 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended September 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 NINE MONTHS ENDED SEPTEMBER 30, 2016 AND 2015	2

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

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

		UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF EQUITY FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2016	5

		UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 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	40

	ITEM 4.	CONTROLS AND PROCEDURES	45

PART II. OTHER INFORMATION			45

	ITEM 1.	LEGAL PROCEEDINGS	45

	ITEM 1A.	RISK FACTORS	45

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

	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	47

	ITEM 4.	MINE SAFETY DISCLOSURES	47

	ITEM 5.	OTHER INFORMATION	47

	ITEM 6.	EXHIBITS	47

SIGNATURES			49

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
REVENUES	(in millions, except per share amounts)
Gas sales	$	123.2		$	129.4		$	287.5		$	363.3
Oil sales	201.6			211.7			553.1			640.9
NGL sales	19.8			16.5			56.2			61.7
Other revenue	2.5			2.8			4.3			12.4
Purchased gas and oil sales	35.3			147.2			76.3			472.0
Total Revenues	382.4			507.6			977.4			1,550.3
OPERATING EXPENSES
Purchased gas and oil expense	37.1			146.0			80.8			475.1
Lease operating expense	50.7			56.7			163.3			175.6
Gas, oil and NGL transportation and other handling costs	75.8			78.1			218.9			216.2
Gathering and other expense	0.9			1.3			3.8			4.4
General and administrative	67.0			42.0			159.4			140.7
Production and property taxes	26.8			30.2			65.3			90.7
Depreciation, depletion and amortization	217.8			238.1			667.5			649.3
Exploration expenses	0.2			0.8			0.9			2.7
Impairment	5.0			15.0			1,188.2			35.5
Total Operating Expenses	481.3			608.2			2,548.1			1,790.2
Net gain (loss) from asset sales	5.3			12.9			5.0			6.9
OPERATING INCOME (LOSS)	(93.6		)	(87.7		)	(1,565.7		)	(233.0		)
Realized and unrealized gains (losses) on derivative contracts (Note 7)	44.5			153.6			(85.1		)	168.5
Interest and other income (expense)	5.1			0.3			7.1			1.5
Interest expense	(35.9		)	(36.4		)	(109.2		)	(109.4		)
INCOME (LOSS) BEFORE INCOME TAXES	(79.9		)	29.8			(1,752.9		)	(172.4		)
Income tax (provision) benefit	29.0			(8.7		)	641.2			61.6
NET INCOME (LOSS)	$	(50.9	)	$	21.1		$	(1,111.7	)	$	(110.8	)

Earnings (loss) per common share
Basic	$	(0.21	)	$	0.12		$	(5.15	)	$	(0.63	)
Diluted	$	(0.21	)	$	0.12		$	(5.15	)	$	(0.63	)

Weighted-average common shares outstanding
Used in basic calculation	239.6			176.7			215.7			176.5
Used in diluted calculation	239.6			176.7			215.7			176.5
Dividends per common share	$	—		$	0.02		$	—		$	0.06

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2016			2015		2016			2015
	(in millions)
Net income (loss)	$	(50.9	)	$	21.1	$	(1,111.7	)	$	(110.8	)
Other comprehensive income, net of tax:
Pension and other postretirement plans adjustments:
Amortization of prior service costs ⁽¹⁾	0.2			0.3		0.6			0.9
Amortization of actuarial losses ⁽²⁾	0.1			—		0.3			0.2
Other comprehensive income	0.3			0.3		0.9			1.1
Comprehensive income (loss)	$	(50.6	)	$	21.4	$	(1,110.8	)	$	(109.7	)

____________________________


⁽¹⁾	Presented net of income tax expense of $0.1 million and $0.3 million during the three and nine months ended September 30, 2016, respectively. Presented net of income tax expense of $0.1 million and $0.5 million during the three and nine months ended September 30, 2015, respectively.


⁽²⁾	Presented net of income tax expense of $0.1 million and $0.3 million during the three and nine months ended September 30, 2016, respectively. Presented net of income tax expense of $0.2 million for the nine months ended September 30, 2015.

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2016			December 31, 2015
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	1,032.2		$	376.1
Accounts receivable, net	135.6			278.2
Income tax receivable	22.5			87.3
Fair value of derivative contracts	0.5			146.8
Gas, oil and NGL inventories, at lower of average cost or market	10.8			13.3
Prepaid expenses and other	7.4			30.1
Total Current Assets	1,209.0			931.8
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	13,684.0			13,314.9
Unproved properties	658.5			691.0
Gathering and other	300.7			297.9
Materials and supplies	31.7			38.5
Total Property, Plant and Equipment	14,674.9			14,342.3
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	8,604.7			6,870.2
Gathering and other	99.6			87.5
Total Accumulated Depreciation, Depletion and Amortization	8,704.3			6,957.7
Net Property, Plant and Equipment	5,970.6			7,384.6
Fair value of derivative contracts	—			23.2
Other noncurrent assets	95.6			58.6
TOTAL ASSETS	$	7,275.2		$	8,398.2
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	4.3		$	29.8
Accounts payable and accrued expenses	259.3			351.7
Production and property taxes	40.3			46.1
Interest payable	32.8			36.4
Fair value of derivative contracts	34.5			0.8
Current portion of long-term debt	—			176.8
Total Current Liabilities	371.2			641.6
Long-term debt	2,019.3			2,014.7
Deferred income taxes	899.2			1,479.8
Asset retirement obligations	213.1			204.9
Fair value of derivative contracts	19.4			4.0
Other long-term liabilities	117.9			105.3
Commitments and contingencies (Note 10)
EQUITY
Common stock – par value $0.01 per share; 500.0 million shares authorized; 240.7 million and 177.3 million shares issued, respectively	2.4			1.8
Treasury stock – 1.1 million and 0.5 million shares, respectively	(22.2		)	(14.6		)
Additional paid-in capital	1,359.8			554.8
Retained earnings	2,306.6			3,418.3
Accumulated other comprehensive income	(11.5		)	(12.4		)
Total Common Shareholders' Equity	3,635.1			3,947.9
TOTAL LIABILITIES AND EQUITY	$	7,275.2		$	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)	—	—		—		—			—		(1,111.7		)	—			(1,111.7		)
Equity issuance, net of offering costs	61.0	0.6		—		—			781.0		—			—			781.6
Share-based compensation	2.4	—		(0.6	)	(7.6		)	24.0		—			—			16.4
Change in pension and postretirement liability, net of tax	—	—		—		—			—		—			0.9			0.9
Balance at September 30, 2016	240.7	$	2.4	(1.1	)	$	(22.2	)	$	1,359.8	$	2,306.6		$	(11.5	)	$	3,635.1

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended
	September 30,
	2016			2015
	(in millions)
OPERATING ACTIVITIES
Net income (loss)	$	(1,111.7	)	$	(110.8	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	667.5			649.3
Deferred income taxes	(581.1		)	22.7
Impairment	1,188.2			35.5
Bargain purchase gain from acquisition	(4.4		)	—
Share-based compensation	29.0			23.3
Pension curtailment loss	—			11.2
Amortization of debt issuance costs and discounts	4.8			4.7
Net (gain) loss from asset sales	(5.0		)	(6.9		)
Unrealized (gains) losses on marketable securities	(1.2		)	—
Unrealized (gains) losses on derivative contracts	218.6			148.0
Changes in operating assets and liabilities	128.2			(503.1		)
Net Cash Provided by (Used in) Operating Activities	532.9			273.9
INVESTING ACTIVITIES
Property acquisitions	(39.9		)	(23.5		)
Acquisition deposit held in escrow	(30.0		)	—
Property, plant and equipment, including dry exploratory well expense	(411.2		)	(862.6		)
Proceeds from disposition of assets	28.9			5.2
Net Cash Provided by (Used in) Investing Activities	(452.2		)	(880.9		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(25.5		)	(41.9		)
Repayment of senior notes	(176.8		)	—
Treasury stock repurchases	(4.1		)	(2.3		)
Other capital contributions	—			(0.1		)
Dividends paid	—			(10.6		)
Proceeds from issuance of common stock, net	781.6			—
Excess tax (provision) benefit on share-based compensation	0.2			(2.4		)
Net Cash Provided by (Used in) Financing Activities	575.4			(57.3		)
Change in cash and cash equivalents	656.1			(664.3		)
Beginning cash and cash equivalents	376.1			1,160.1
Ending cash and cash equivalents	$	1,032.2		$	495.8

Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	107.0		$	107.4
Cash paid (refund received) for income taxes	$	(123.3	)	$	492.3
Non-cash Investing Activities:
Change in capital expenditure accruals and other non-cash adjustments	$	(20.4	)	$	(68.9	)

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 nine months ended September 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 shares of common stock through a public offering and received net proceeds of approximately $413.0 million. In October, QEP used the net proceeds from this offering to partially fund the 2016 Permian Acquisition (see Note 13 – Subsequent Event).

In March 2016, QEP issued 37.95 million 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 nine months ended September 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 nine months ended September 30, 2015.

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



	Three Months Ended							Nine Months Ended
	September 30, 2015							September 30, 2015
	As reported		As revised		Change			As reported		As revised		Change
REVENUES	(in millions)
Purchased gas and oil sales	$	176.3	$	147.2	$	(29.1	)	$	558.6	$	472.0	$	(86.6	)
Total Revenues	536.7		507.6		(29.1		)	1,636.9		1,550.3		(86.6		)
OPERATING EXPENSES
Purchased gas and oil expense	$	175.1	$	146.0	$	(29.1	)	$	561.7	$	475.1	$	(86.6	)
Total Operating Expenses	637.3		608.2		(29.1		)	1,876.8		1,790.2		(86.6		)

Reclassifications

Certain prior period balances on 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 three months ended September 30, 2016, QEP recorded impairment expense of $5.0 million, all of which was related to expiring leaseholds on unproved properties.

During the nine months ended September 30, 2016, QEP recorded impairment expense of $1,188.2 million, of which $1,167.9 million was related to proved properties due to lower future oil and gas prices, $16.6 million was related to expiring leaseholds on unproved properties and $3.7 million was related to an impairment of goodwill. Of the $1,167.9 million impairment on proved properties, $1,164.0 million related to Pinedale properties, $3.5 million related to Other Northern properties and $0.4 million related to Other Southern properties.

New Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 does not expect this ASU to have a material impact 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 does not expect this ASU to have a material impact 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.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of certain cash receipts and cash payments, which intends to reduce the diversity in practice in how certain transactions are classified on the statement of cash flows. This amendment will be effective retrospectively for reporting periods beginning after December 31, 2017, and early adoption is permitted. The Company does not expect this ASU to have a material impact on the Company's Condensed Consolidated Financial Statements.

Note 2 – Acquisitions and Divestitures

Acquisitions

During the three months ended September 30, 2016, QEP acquired various oil and gas properties, primarily proved undeveloped leasehold acreage in the Williston Basin, for an aggregate purchase price of $16.3 million. The Company recorded a $4.4 million bargain purchase gain associated with the acquisition. The bargain purchase gain is reported on the Condensed Consolidated Statements of Operations within "Interest and other income (expense)". During the three months ended September 30, 2015, QEP acquired various oil and gas properties, primarily undeveloped leasehold acreage in the Permian Basin, for an aggregate purchase price of $24.1 million.

During the nine months ended September 30, 2016, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for an aggregate purchase price of $46.1 million, including additional interests in QEP's operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded $3.7 million of goodwill and a $4.4 million bargain purchase gain. During the nine months ended September 30, 2015, QEP acquired various oil and gas properties, primarily undeveloped leasehold acreage in the Permian Basin, for an aggregate purchase price of $23.5 million.

Divestitures

During the three and nine months ended September 30, 2016, QEP received proceeds of $5.2 million and $28.9 million, respectively, and recorded a pre-tax gain on sale of $5.3 million and $5.0 million, respectively, primarily related to the divestiture of certain non-core properties in Other Southern. During the three and nine months ended September 30, 2015, QEP recorded a pre-tax gain on sale of $12.9 million and $6.9 million, respectively, comprised of a gain related to divestitures and post-closing purchase price adjustments of certain non-core properties in Other Southern, partially offset by a loss recognized for post-closing adjustments related to the sale of QEP's midstream business in 2014. These gains and losses are reported on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales".

Note 3 – Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP’s unvested restricted 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 nine months ended September 30, 2016, there were anti-dilutive shares of 0.2 million and 0.1 million, respectively, not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss. During the three and nine months ended September 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		Nine Months Ended
	September 30,		September 30,
	2016	2015	2016	2015
	(in millions)
Weighted-average basic common shares outstanding	239.6	176.7	215.7	176.5
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	239.6	176.7	215.7	176.5

Note 4 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are presented in the table below. The balance at September 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 September 30,	$	13.5

Note 5 – Asset Retirement Obligations

QEP records asset retirement obligations (ARO) associated with the retirement of tangible, long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $217.5 million and $206.8 million ARO liability for the periods ended September 30, 2016 and December 31, 2015, respectively, $4.4 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	6.5
Additions	3.6
Revisions	7.1
Liabilities settled	(6.5		)
ARO liability at September 30,	$	217.5

Note 6 – Fair Value Measurements

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

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

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

The fair value of financial assets and liabilities at September 30, 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⁾
	September 30, 2016
	(in millions)
Financial Assets
Fair value of derivative contracts – short-term	$	—	$	7.6	$	—	$	(7.1	)	$	0.5
Fair value of derivative contracts – long-term	—		—		—		—			—
Total financial assets	$	—	$	7.6	$	—	$	(7.1	)	$	0.5

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	41.6	$	—	$	(7.1	)	$	34.5
Fair value of derivative contracts – long-term	—		19.4		—		—			19.4
Total financial liabilities	$	—	$	61.0	$	—	$	(7.1	)	$	53.9

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

Financial Liabilities
Fair value of derivative contracts – short-term	$	—	$	1.8	$	—	$	(1.0	)	$	0.8
Fair value of derivative contracts – 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
	September 30, 2016				December 31, 2015
	(in millions)
Financial Assets
Cash and cash equivalents	$	1,032.2	$	1,032.2	$	376.1	$	376.1
Financial Liabilities
Checks outstanding in excess of cash balances	$	4.3	$	4.3	$	29.8	$	29.8
Long-term debt	$	2,019.3	$	2,067.9	$	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 nine months ended September 30, 2016 and 2015, the Company recorded impairments on certain proved oil and gas properties of $1,167.9 million and $33.8 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 acquired properties is considered Level 3 within the fair value hierarchy.

Note 7 – Derivative Contracts

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

QEP uses commodity derivative instruments known as fixed-price swaps or 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 gas and oil sales at prices that reference specific regional index prices.

QEP does not currently have any commodity derivative transactions that have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. QEP's commodity derivative contract counterparties are typically financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties 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 presents QEP’s volumes and average prices for its commodity derivative swap contracts as of September 30, 2016:



Year	Index	Total Volumes	Average Swap Price per Unit
		(in millions)
Gas sales		(MMBtu)	($/MMBtu)
2016	NYMEX HH	15.6	$	2.80
2016	IFNPCR	18.4	$	2.53
2017	NYMEX HH	80.3	$	2.78
2017	IFNPCR	32.9	$	2.51
2018	NYMEX HH	29.2	$	2.92
Oil sales		(bbls)	($/bbl)
2016	NYMEX WTI	3.0	$	51.24
2017	NYMEX WTI	11.0	$	50.74
2018	NYMEX WTI	5.1	$	52.73

The following table presents QEP's volumes and average prices for its commodity derivative gas collars as of September 30, 2016:



Year	Index	Total Volumes	Average Price Floor		Average Price Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2016	NYMEX HH	1.8	$	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 presents details of QEP's gas basis swaps as of September 30, 2016:



Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2016	NYMEX HH	IFNPCR	9.2	$	(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 presents QEP’s volumes and average prices for its storage commodity derivative swap contracts as of September 30, 2016:



Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2016	SWAP	IFNPCR	2.0	$	2.78
2017	SWAP	IFNPCR	3.8	$	2.87
Gas purchases
2016	SWAP	IFNPCR	1.5	$	2.57

QEP Derivative Financial Statement Presentation

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



		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	September 30, 2016		December 31, 2015		September 30, 2016		December 31, 2015
Current:		(in millions)
Commodity	Fair value of derivative contracts	$	7.6	$	147.8	$	41.6	$	1.8
Long-term:
Commodity	Fair value of derivative contracts	—		23.2		19.4		4.0
Total derivative instruments		$	7.6	$	171.0	$	61.0	$	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						Nine Months Ended
Derivative contracts not designated as cash flow hedges	September 30,						September 30,
Derivative contracts not designated as cash flow hedges	2016			2015			2016			2015
Realized gains (losses) on commodity derivative contracts	(in millions)
Production
Gas derivative contracts	$	0.4		$	23.1		$	50.8		$	69.1
Oil derivative contracts	19.1			96.8			79.8			245.3
Storage
Gas derivative contracts	0.1			(0.1		)	2.9			2.1
Total realized gains (losses) on commodity derivative contracts	19.6			119.8			133.5			316.5
Unrealized gains (losses) on commodity derivative contracts
Production
Gas derivative contracts	24.8			3.6			(80.0		)	(19.5		)
Oil derivative contracts	(0.3		)	28.8			(135.9		)	(128.0		)
Storage
Gas derivative contracts	0.4			1.4			(2.7		)	(0.5		)
Total unrealized gains (losses) on commodity derivative contracts	24.9			33.8			(218.6		)	(148.0		)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	44.5		$	153.6		$	(85.1	)	$	168.5

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 total costs related to the 2016 restructuring were approximately $1.9 million and were related to one-time termination benefits. During the three and nine months ended September 30, 2016, restructuring costs of $0.1 million and $1.9 million, respectively, were incurred and paid related to the 2016 restructuring. The Company does not expect to incur additional costs related to the 2016 restructuring.

During 2015, QEP had multiple restructuring events, including the closure of its Tulsa office, which occurred in the third quarter of 2015. The total costs related to the 2015 restructuring events were approximately $8.3 million, of which approximately $5.3 million was related to one-time termination benefits and approximately $3.0 million was related to relocation of certain employees. During the three and nine months ended September 30, 2016, restructuring costs of $0.1 million and $0.6 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 does not expect to incur additional costs related to the closure of its Tulsa office.

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:



	September 30, 2016			December 31, 2015
	(in millions)
Revolving Credit Facility due 2019	$	—		$	—
6.05% Senior Notes due 2016 ⁽¹⁾	—			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	(25.7		)	(30.3		)
Total principal amount of debt (including current portion)	2,019.3			2,191.5
Less: current portion of long-term debt	—			(176.8		)
Total long-term debt outstanding	$	2,019.3		$	2,014.7

_______________________


⁽¹⁾	During the three months ended September 30, 2016, the Company paid $176.8 million for the repayment of the 6.05% Senior Notes, which were due on September 1, 2016.

Of the total debt outstanding on September 30, 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 September 30, 2016, QEP was in compliance with the covenants under the credit agreement.

During the nine months ended September 30, 2016 and 2015, QEP had no borrowings under the credit facility. Additionally, as of September 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 September 30, 2016, the Company had $2,045.0 million principal amount of senior notes outstanding with maturities ranging from April 2018 to May 2023 and coupons ranging from 5.25% to 6.875%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP’s senior notes contain customary events of default and covenants that may limit QEP’s ability to, among other things, place liens on its property or assets.

Note 10 – Commitments and Contingencies

The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. In each reporting period, the Company assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Condensed Consolidated Financial Statements. In

accordance with ASC 450, Contingencies, an accrual is recorded for a material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes.

Legal proceedings are inherently unpredictable, and unfavorable resolutions can occur. Assessing contingencies is highly subjective and requires 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 potential defenses, the procedural status of the matter in question, the presence of complex legal and/or factual issues, the ongoing discovery and/or development of information important to the matter.

Rocky Mountain Resources Lawsuit – Rocky Mountain Resources, LLC (Rocky Mountain) filed a complaint against the Company 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 appealed the verdict to the Wyoming Supreme Court and 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 such amounts become due and payable. These deposits are presented within “Prepaid expenses and other” on the Company’s Condensed Consolidated Balance Sheets. The overriding royalty payments will be subject to the direction of the Court following the conclusion of the appeal.

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.

Arbitration Regarding Gas Purchase Agreement – A midstream service provider 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 service 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 arbitration proceedings are scheduled for the fourth quarter of 2016.

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

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

To the extent that the Company can reasonably estimate losses for contingencies where the risk of a material loss (in excess of accruals, if any) is reasonably possible, the Company estimates such losses could total between zero and approximately $60.0 million.

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 September 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				Nine Months Ended
	September 30,				September 30,
	2016		2015		2016		2015
	(in millions)
Stock options	$	0.6	$	0.7	$	1.8	$	2.2
Restricted share awards	6.0		6.8		18.2		19.5
Performance share units	3.2		0.2		8.8		1.6
Restricted share units	0.1		—		0.2		—
Total share-based compensation expense	$	9.9	$	7.7	$	29.0	$	23.3

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 calculating the value of options not traded on an exchange. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares.

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



	Stock Option Assumptions
Weighted-average grant date fair value of awards granted during the period	$	3.77
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	438,180		10.14
Canceled	(486,999	)	23.77
Outstanding at September 30, 2016	2,151,957		$	25.26	3.92	$	4.1
Options Exercisable at September 30, 2016	1,385,753		$	30.18	2.86	$	0.2
Unvested Options at September 30, 2016	766,204		$	16.38	5.83	$	3.9

During the nine months ended September 30, 2016, there were no exercises of stock options. During the nine months ended September 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 September 30, 2016, $1.7 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 2.02 years.

Restricted Share Awards

Restricted share award grants typically vest in equal installments over a three-year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The total fair value of restricted share awards that vested during the nine months ended September 30, 2016 and 2015, was $24.2 million and $21.0 million, respectively. The weighted-average grant date fair value of restricted share awards was $10.37 per share and $21.02 per share for the nine months ended September 30, 2016 and 2015, respectively. As of September 30, 2016, $22.9 million of unrecognized compensation cost related to restricted share awards granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheet, is expected to be recognized over a weighted-average vesting period of 2.15 years.

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



	Restricted Share Awards Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2015	2,008,210		$	24.18
Granted	2,427,634		10.37
Vested	(966,748	)	25.03
Forfeited	(252,448	)	14.16
Unvested balance at September 30, 2016	3,216,648		$	14.29

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 September 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 $10.16 per share and $21.69 per share for the nine months ended September 30, 2016 and 2015, respectively. As of September 30, 2016, $16.6 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 1.98 years.

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



	Performance Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2015	630,786		$	27.50
Granted	597,185		10.16
Vested and Paid	(178,169	)	30.07
Forfeited	(22,431	)	15.09
Unvested balance at September 30, 2016	1,027,371		$	17.24

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 nine months ended September 30, 2016. As of September 30, 2016, $0.2 million of unrecognized compensation cost, which represents the unvested portion of the fair market value of restricted share units granted, is expected to be recognized over a weighted-average vesting period of 2.59 years.

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



	Restricted Share Units Outstanding		Weighted-Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2015	—		$	—
Granted	21,493		10.12
Vested	(193	)	10.12
Forfeited	(3,266	)	10.12
Unvested balance at September 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 (the SERP), and a postretirement medical plan (the Medical Plan).

The Pension Plan is a closed, qualified, defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. During the nine months ended September 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.

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 required 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 SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. During the nine months ended September 30, 2016, the Company made contributions of $3.5 million to its SERP and expects to contribute an additional $0.1 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 QEP employees. During the nine months ended September 30, 2016, the Company made contributions of $0.2 million to its Medical Plan and expects to contribute an additional $0.1 million to its Medical Plan during the remainder of 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						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.3		$	0.5		$	0.9		$	1.5
Interest cost	1.3			1.3			3.9			3.7
Expected return on plan assets	(1.4		)	(1.5		)	(4.2		)	(4.3		)
Amortization of prior service costs ⁽¹⁾	0.3			0.4			0.9			1.3
Amortization of actuarial losses ⁽¹⁾	0.2			0.1			0.6			0.4
Curtailment loss ⁽²⁾	—			—			—			11.2
Periodic expense	$	0.7		$	0.8		$	2.1		$	13.8

Medical Plan benefits
Interest cost	$	0.1		$	0.1		$	0.2		$	0.2
Amortization of prior service costs ⁽¹⁾	—			—			0.1			0.1
Periodic expense	$	0.1		$	0.1		$	0.3		$	0.3

____________________________


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

Note 13 – Subsequent Event

On October 19, 2016, QEP closed on its previously announced acquisition of oil and gas properties in the Permian Basin for an aggregate purchase price of approximately $590.0 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 existing vertical wells. The 2016 Permian Acquisition was funded with proceeds from the June 2016 equity offering and cash on hand. Final purchase accounting for the transaction was not complete at the time this Form 10-Q was filed with the SEC, and as such, certain disclosures required by ASC Topic 805, Business Combinations, have not been made herein. The Company will include this information in its 2016 Annual Report on Form 10-K.

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

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

The following information updates the discussion of QEP's financial condition provided in its 2015 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three and nine months ended September 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 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., which provide a solid base for growth in organic production and reserves.

Outlook

In response to the commodity price environment in the first three quarters of 2016, we have reduced drilling and completion activities from 2015 and focused on reducing costs and preserving our liquidity, and plan 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 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 (excluding acquisitions) for 2016 are expected to be approximately $538.0 million, a decrease of approximately 50% from 2015 capital expenditures. With this capital program, we expect total equivalent production to be slightly higher than in 2015, excluding production from the 2016 Permian Acquisition (defined below). We plan to continuously evaluate our level of drilling and completion activity in light of both commodity prices and changes in our operating and development costs and will 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

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

During the nine months ended September 30, 2016, QEP acquired various oil and gas properties, primarily in the Williston and Permian basins, for an aggregate purchase price of $46.1 million, including interests in QEP's operated wells and additional undeveloped leasehold acreage. In conjunction with the acquisitions, the Company recorded $3.7 million of goodwill and a $4.4 million bargain purchase gain. During the nine months ended September 30, 2015, QEP acquired various oil and gas properties, primarily undeveloped leasehold acreage in the Permian Basin, for an aggregate purchase price of $23.5 million.

During the nine months ended September 30, 2016, QEP received proceeds of $28.9 million and recorded a pre-tax gain on sale of $5.0 million primarily related to the divestiture of certain non-core properties in Other Southern. During the nine months ended September 30, 2015, QEP recorded a pre-tax gain on sale of $6.9 million comprised of a gain related to divestitures and post-closing purchase price adjustments of certain non-core properties in Other Southern, partially offset by a loss recognized for post-closing adjustments related to the sale of QEP's midstream business in 2014.

While QEP believes its extensive inventory of identified drilling locations provides a solid base for growth in production and reserves, the Company continues to evaluate 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 September 30, 2016, QEP:


•	Maintained flat natural gas equivalent production of 86.6 Bcfe, compared to 86.7 Bcfe during the third quarter of 2015;


•	Reported oil production in the Permian Basin of 989.9 Mbbls, a 33% increase over the third quarter of 2015;


•	Reduced lease operating expense by $0.07 per Mcfe from the third quarter of 2015 to $0.58 per Mcfe;


•	Generated a net loss of $50.9 million, or $0.21 per diluted share;


•	Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $168.7 million; and


•	Maintained $1,032.2 million in cash and cash equivalents and had no borrowings under its credit facility.

During the nine months ended September 30, 2016, QEP:


•	Reported natural gas equivalent production of 252.6 Bcfe, a 4% increase over the same period in 2015;


•	Reported oil production of 15,411.0 Mbbls, a 6% increase over the first three quarters of 2015, including higher production in the Permian and Williston basins;


•	Reduced lease operating expense by $0.07 per Mcfe from the first three quarters of 2015 to $0.65 per Mcfe;


•	Generated a net loss of $1,111.7 million, or $5.15 per diluted share;


•	Reported Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $452.1 million;


•	Incurred impairment expense of $1,188.2 million, primarily due to lower future commodity prices; and


•	Issued 60.95 million 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 their Impact on Oil and Gas Prices

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

Changes in the market prices for 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 $110.62 per barrel in September 2013. The Henry Hub spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. If prices of oil and gas decline to early 2016 levels or further, our operations, financial condition and level of expenditures for the development of our oil and gas reserves may be materially and adversely affected.

NGL prices have also been affected by increased U.S. hydrocarbon production and insufficient domestic demand and export capacity. Prices of heavier NGL components, typically correlated to oil prices, have declined in concert with weakening oil prices. Concurrently, the lighter NGL components, ethane and propane, have experienced declines as a result of growing North American oversupply. In addition to commodity price movements, QEP's composite NGL prices are affected by ethane recovery or rejection. When ethane is recovered as a discrete NGL component instead of being sold as part of the natural gas stream, the average sales price of a NGL barrel decreases as the ethane price is generally lower than the prices of the remaining NGL components. As permitted in some of its processing agreements, QEP recovers ethane when gas processing economics support the recovery of ethane from the natural gas stream. When gas processing economics do not support ethane recovery, and processing agreements permit it to do so, QEP elects to reject ethane from the NGL stream. In instances where QEP can make an election, QEP rejected ethane during the nine months ended September 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 impact of 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 gas, 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. 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 September 30, 2016, assuming forecasted 2016 annual production of approximately 337 Bcfe, QEP had approximately 74% of its forecasted gas production and 46% 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

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 Environmental Protection Agency (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 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 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.

In October 2016, the Department of Interior’s Bureau of Land Management (BLM) finalized Onshore Orders No. 3 (Site Security), No. 4 (Measurement of Oil), and No. 5 (Measurement of Gas). The finalized versions of the new Orders are substantially different from the draft versions originally circulated by the BLM for public comment in 2015. QEP is currently reviewing the new regulations to determine the overall impact to the Company.

Potential for Future Asset Impairments

The carrying value of the Company's properties is sensitive to declines in gas, oil and NGL prices. The value of these assets are at risk of impairment if future gas, 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 nine months ended September 30, 2016, the Company recorded impairments of $1,188.2 million, of which $1,167.9 million was related to impairments of proved properties due to lower future prices, primarily in Pinedale, $16.6 million was related to expiring leaseholds on unproved properties and $3.7 million was related to an impairment of goodwill. During the nine months ended September 30, 2015, impairments totaled $35.5 million, of which $33.8 million was related to proved properties due to lower future prices and $1.7 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. Due to this dispute, completion activities and production volumes were negatively impacted during the third quarter of 2016, and the pace at which the Company is able to complete additional drilled and uncompleted wells during the fourth quarter of 2016 at South Antelope in the Williston Basin will be impacted. QEP initiated arbitration

proceedings in May 2016 to enforce the terms of the existing agreement. The arbitration proceedings are scheduled for the fourth quarter of 2016.

Uncertainties related to Claims

QEP is currently subject to claims that could adversely impact QEP’s liquidity, operating results and capital expenditures for a particular reporting period, including, but not limited to, claims of former limited partners regarding distributions, a Department of Interior Investigation regarding timely payment of Indian royalties, and claims regarding potential noncompliance associated with air emissions in the Williston Basin, each of which is described more fully in Note 10 – Commitments and Contingencies, in Item 1 of Part I of this Quarterly Report on Form 10-Q. Given the uncertainties involved in these matters, QEP is unable to predict the ultimate outcomes.

Critical Accounting Estimates

QEP's significant accounting policies are described in Item 7 of Part II of its 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 nine months ended September 30, 2016:



	Operated Completions				Non-operated Completions
	Three Months Ended		Nine Months Ended		Three Months Ended		Nine Months Ended
	September 30, 2016		September 30, 2016		September 30, 2016		September 30, 2016
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	34	18.4	38	21.8	—	—	—	—
Williston Basin	9	7.8	27	25.6	16	1.0	23	1.0
Uinta Basin	—	—	8	8.0	—	—	2	0.0
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	—	—	9	1.8
Permian Basin	5	5.0	18	17.7	—	—	—	—
Other Southern	—	—	—	—	—	—	—	—

The following table presents operated and non-operated wells drilling or waiting on completion at September 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	4.5	6	2.6	—	—	—	—
Williston Basin	4	3.7	23	19.1	4	0.1	12	1.3
Uinta Basin	—	—	—	—	—	—	1	0.0
Other Northern	1	1.0	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	4	0.6	11	1.1
Permian Basin	5	5.0	2	1.8	—	—	—	—
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 31 gross operated wells waiting on completion as of September 30, 2016.

RESULTS OF OPERATIONS

Net Income

QEP generated a net loss during the third quarter of 2016 of $50.9 million, or $0.21 per diluted share, compared to net income of $21.1 million, or $0.12 per diluted share, in the third quarter of 2015. QEP's net loss was primarily due to a 24% decrease in average realized prices and a 60% increase in general and administrative expenses. These changes were partially offset by a 9% decrease in depreciation, depletion and amortization and an 11% decrease in lease operating expense in the third quarter of 2016 compared to the third quarter of 2015.

QEP generated a net loss during the first three quarters of 2016 of $1,111.7 million, or $5.15 per diluted share, compared to a net loss of $110.8 million, or $0.63 per diluted share, in the first three quarters of 2015. QEP's increased net loss was primarily due to an increase in impairment expense of $1,152.7 million, a 28% decrease in average realized prices, a 48% increase in unrealized derivative losses and a 13% increase in general and administrative expenses. These changes were partially offset by a 4% increase in natural gas equivalent production, a 28% decrease in production and property tax expense and a 7% decrease in lease operating expense in the first three quarters of 2016 compared to the first three quarters 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 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 September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
	(in millions)
Net income (loss)	$	(50.9	)	$	21.1		$	(1,111.7	)	$	(110.8	)
Interest expense	35.9			36.4			109.2			109.4
Interest and other (income) expense	(5.1		)	(0.3		)	(7.1		)	(1.5		)
Income tax provision (benefit)	(29.0		)	8.7			(641.2		)	(61.6		)
Depreciation, depletion and amortization	217.8			238.1			667.5			649.3
Unrealized (gains) losses on derivative contracts	(24.9		)	(33.8		)	218.6			148.0
Exploration expenses	0.2			0.8			0.9			2.7
Net (gain) loss from asset sales	(5.3		)	(12.9		)	(5.0		)	(6.9		)
Impairment	5.0			15.0			1,188.2			35.5
Other ⁽¹⁾	25.0			—			32.7			11.2
Adjusted EBITDA	$	168.7		$	273.1		$	452.1		$	775.3

____________________________

⁽¹⁾

Reflects legal expenses and loss contingencies incurred during the three and nine months ended September 30, 2016, and a non-cash pension curtailment loss that was incurred during the nine months ended September 30, 2015, due to changes in the Company's pension plan (see Note 12 – Employee Benefits for additional information). The Company believes that these losses 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 $168.7 million in the third quarter of 2016 from $273.1 million in the third quarter of 2015, due to a 24% decrease in average realized prices, partially offset by an 11% decrease in lease operating expense in the third quarter of 2016 compared to the third quarter of 2015.

Adjusted EBITDA decreased to $452.1 million in the first three quarters of 2016 from $775.3 million in the first three quarters of 2015, due to a 28% decrease in the average realized prices, partially offset by a 4% increase in natural gas equivalent production, a 28% decrease in production and property tax expense and a 7% decrease in lease operating expense in the first three quarters of 2016 compared to the first three quarters 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 nine months ended September 30, 2016, compared to the three and nine months ended September 30, 2015:



	Gas			Oil			NGL			Total
	(in millions)
Production revenues
Three months ended September 30, 2015 revenues	$	129.4		$	211.7		$	16.5		$	357.6
Changes associated with volumes ⁽¹⁾	(3.2		)	(5.6		)	4.3			(4.5		)
Changes associated with prices ⁽²⁾	(3.0		)	(4.5		)	(1.0		)	(8.5		)
Three months ended September 30, 2016 revenues	$	123.2		$	201.6		$	19.8		$	344.6

Production revenues
Nine months ended September 30, 2015 revenues	$	363.3		$	640.9		$	61.7		$	1,065.9
Changes associated with volumes ⁽¹⁾	(5.4		)	39.3			19.1			53.0
Changes associated with prices ⁽²⁾	(70.4		)	(127.1		)	(24.6		)	(222.1		)
Nine months ended September 30, 2016 revenues	$	287.5		$	553.1		$	56.2		$	896.8

____________________________


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

⁽²⁾

The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level price from the three and nine months ended September 30, 2016, as compared to the three and nine months ended September 30, 2015, by volumes for the three and nine months ended September 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 September 30,							Nine Months Ended September 30,
	2016		2015		Change			2016		2015		Change
Production volumes (Bcfe)
Northern Region
Pinedale	24.0		26.3		(2.3		)	72.0		73.0		(1.0		)
Williston Basin	31.5		29.8		1.7			92.5		83.8		8.7
Uinta Basin	7.3		8.8		(1.5		)	22.5		23.0		(0.5		)
Other Northern	2.5		2.7		(0.2		)	6.9		7.8		(0.9		)
Southern Region
Haynesville/Cotton Valley	12.2		11.2		1.0			30.5		33.3		(2.8		)
Permian Basin	9.0		7.3		1.7			27.6		18.4		9.2
Other Southern	0.1		0.6		(0.5		)	0.6		3.5		(2.9		)
Total production	86.6		86.7		(0.1		)	252.6		242.8		9.8
Total equivalent prices (per Mcfe)
Average equivalent field-level price	$	3.98	$	4.12	$	(0.14	)	$	3.55	$	4.39	$	(0.84	)
Commodity derivative impact	0.22		1.38		(1.16		)	0.52		1.29		(0.77		)
Net realized equivalent price	$	4.20	$	5.50	$	(1.30	)	$	4.07	$	5.68	$	(1.61	)

Gas Volumes and Prices



	Three Months Ended September 30,							Nine Months Ended September 30,
	2016		2015		Change			2016		2015		Change
Gas production volumes (Bcf)
Northern Region
Pinedale	21.1		23.0		(1.9		)	62.7		63.5		(0.8		)
Williston Basin	4.3		2.8		1.5			11.5		8.5		3.0
Uinta Basin	5.7		7.0		(1.3		)	17.9		17.6		0.3
Other Northern	2.1		2.4		(0.3		)	6.1		6.9		(0.8		)
Southern Region
Haynesville/Cotton Valley	12.1		11.1		1.0			30.2		33.0		(2.8		)
Permian Basin	1.3		1.3		—			4.3		3.2		1.1
Other Southern	0.2		0.4		(0.2		)	0.4		2.4		(2.0		)
Total production	46.8		48.0		(1.2		)	133.1		135.1		(2.0		)
Gas prices (per Mcf)
Northern Region	$	2.62	$	2.71	$	(0.09	)	$	2.14	$	2.68	$	(0.54	)
Southern Region	$	2.65	$	2.64	$	0.01		$	2.22	$	2.71	$	(0.49	)

Average field-level price	$	2.63	$	2.69	$	(0.06	)	$	2.16	$	2.69	$	(0.53	)
Commodity derivative impact	0.01		0.48		(0.47		)	0.38		0.51		(0.13		)
Net realized price	$	2.64	$	3.17	$	(0.53	)	$	2.54	$	3.20	$	(0.66	)

Gas revenues decreased $6.2 million, or 5%, in the third quarter of 2016 compared to the third quarter of 2015, due to lower field-level prices and lower gas production. Average field-level gas prices decreased 2% in the third quarter of 2016 compared to the third quarter of 2015, which is primarily driven by our Williston Basin production having a lower MMbtu content during the third quarter of 2016 compared to the third quarter of 2015. The lower MMbtu content is a result of a midstream provider in the Williston Basin electing to operate its gas processing plant in ethane recovery and recovering an increased amount of ethane from QEP's gas in the third quarter of 2016 compared to the third quarter of 2015. The 3% decrease in production volumes was primarily driven by a production decrease in Pinedale and the Uinta Basin due to decreased well completions in 2016 compared to 2015. These decreases were partially offset by production increases in the Williston Basin due to continued development drilling and higher gas recovery on 2016 well completions and increases in Haynesville/Cotton Valley due to recent well workovers, changes in working interest as a result of resolution of certain title issues, non-operated well completions and other production related adjustments.

Gas revenues decreased $75.8 million, or 21%, in the first three quarters of 2016 compared to the first three quarters of 2015, due to lower field-level prices and lower gas production. Average field-level gas prices decreased 20% in the first three quarters of 2016 compared to the first three quarters 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 the Williston and Permian basins due to continued development drilling.

Oil Volumes and Prices



	Three Months Ended September 30,							Nine Months Ended September 30,
	2016		2015		Change			2016		2015		Change
Oil production volumes (Mbbl)
Northern Region
Pinedale	161.1		190.4		(29.3		)	486.9		511.9		(25.0		)
Williston Basin	3,625.5		3,915.8		(290.3		)	11,142.8		11,116.5		26.3
Uinta Basin	190.0		242.4		(52.4		)	596.6		666.0		(69.4		)
Other Northern	44.1		43.5		0.6			114.6		132.9		(18.3		)
Southern Region
Haynesville/Cotton Valley	6.3		9.4		(3.1		)	20.2		26.1		(5.9		)
Permian Basin	989.9		742.7		247.2			3,018.0		1,942.6		1,075.4
Other Southern	8.2		17.9		(9.7		)	31.9		123.4		(91.5		)
Total production	5,025.1		5,162.1		(137.0		)	15,411.0		14,519.4		891.6
Oil prices (per bbl)
Northern Region	$	39.21	$	40.05	$	(0.84	)	$	34.90	$	43.21	$	(8.31	)
Southern Region	$	43.76	$	46.50	$	(2.74	)	$	39.86	$	49.64	$	(9.78	)

Average field-level price	$	40.12	$	41.01	$	(0.89	)	$	35.89	$	44.13	$	(8.24	)
Commodity derivative impact	3.81		18.75		(14.94		)	5.18		16.90		(11.72		)
Net realized price	$	43.93	$	59.76	$	(15.83	)	$	41.07	$	61.03	$	(19.96	)

Oil revenues decreased $10.1 million, or 5%, in the third quarter of 2016 compared to the third quarter of 2015, due to lower average field-level prices and lower volumes. Average field-level oil prices decreased 2% in the third quarter of 2016 compared to the third quarter of 2015 driven by a decrease in average NYMEX-WTI and ICE Brent oil prices for the comparable periods. The 3% decrease in production volumes was driven by decreases in the Williston and Uinta basins and in Pinedale due to decreased completions. These decreases were partially offset by a production increase in the Permian Basin due to continued development drilling.

Oil revenues decreased $87.8 million, or 14%, in the first three quarters of 2016 compared to the first three quarters of 2015, due to lower average field-level prices, partially offset by higher volumes. Average field-level oil prices decreased 19% in the first three quarters of 2016 compared to the first three quarters of 2015 driven by a decrease in average NYMEX-WTI and ICE Brent oil prices for the comparable periods. The 6% 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 and a production decrease in the Uinta Basin due to decreased completions.

NGL Volumes and Prices



	Three Months Ended September 30,							Nine Months Ended September 30,
	2016		2015		Change			2016		2015		Change
NGL production volumes (Mbbl)
Northern Region
Pinedale	333.8		350.7		(16.9		)	1,069.9		1,067.5		2.4
Williston Basin	920.8		588.7		332.1			2,362.7		1,430.3		932.4
Uinta Basin	56.0		59.1		(3.1		)	157.6		238.8		(81.2		)
Other Northern	7.6		4.9		2.7			17.3		14.1		3.2
Southern Region
Haynesville/Cotton Valley	6.0		6.2		(0.2		)	20.6		20.1		0.5
Permian Basin	288.6		268.0		20.6			860.9		596.8		264.1
Other Southern	3.7		9.3		(5.6		)	13.8		64.7		(50.9		)
Total production	1,616.5		1,286.9		329.6			4,502.8		3,432.3		1,070.5
NGL prices (per bbl)
Northern Region	$	12.43	$	13.26	$	(0.83	)	$	12.87	$	19.09	$	(6.22	)
Southern Region	$	11.52	$	11.41	$	0.11		$	10.95	$	13.25	$	(2.30	)

Average field-level price	$	12.26	$	12.85	$	(0.59	)	$	12.49	$	17.93	$	(5.44	)
Commodity derivative impact	—		—		—			—		—		—
Net realized price	$	12.26	$	12.85	$	(0.59	)	$	12.49	$	17.93	$	(5.44	)

NGL revenues increased $3.3 million, or 20%, during the third quarter of 2016 compared to the third quarter of 2015, due to higher production volumes, partially offset by lower average field-level prices. NGL prices decreased 5% during the third quarter of 2016 compared to the third 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 third quarter of 2016 compared to the third quarter of 2015. The increased percentage of ethane is a result of a midstream provider electing to operate its gas processing plant in ethane recovery. The 26% increase in 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 decreased well completions in 2016 compared to 2015.

NGL revenues decreased $5.5 million, or 9%, during the first three quarters of 2016 compared to the first three quarters of 2015, due to lower average field-level prices, partially offset by higher production volumes. NGL prices decreased 30% during the first three quarters of 2016 compared to the first three quarters of 2015, which was primarily driven lower component index pricing and by receiving an increased percentage of ethane from a midstream provider on our Williston Basin production during the first three quarters of 2016 compared to the first three quarters 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 31% 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 three quarters of 2016 compared to cryogenic processing during a portion of the first three quarters of 2015 as well as decreased well completions in 2016 compared to 2015 and a production decrease in Other Southern due to the continued divestitures of non-core properties.

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 following table is a summary of QEP's financial results from its resale activities.



	Three Months Ended September 30,									Nine Months Ended September 30,
	2016			2015			Change			2016			2015			Change
	(in millions)
Purchased gas and oil sales	$	35.3		$	147.2		$	(111.9	)	$	76.3		$	472.0		$	(395.7	)
Purchased gas and oil expense	(37.1		)	(146.0		)	108.9			(80.8		)	(475.1		)	394.3
Realized gains (losses) on storage derivative contracts	0.1			(0.1		)	0.2			2.9			2.1			0.8
Resale margin	$	(1.7	)	$	1.1		$	(2.8	)	$	(1.6	)	$	(1.0	)	$	(0.6	)

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 reported lower resale revenue and expenses in the first three quarters 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 September 30,							Nine Months Ended September 30,
	2016		2015		Change			2016		2015		Change
	(per Mcfe)
Lease operating expense	$	0.58	$	0.65	$	(0.07	)	$	0.65	$	0.72	$	(0.07	)
Gas, oil and NGL transportation and other handling costs	0.87		0.90		(0.03		)	0.87		0.89		(0.02		)
Production and property taxes	0.31		0.35		(0.04		)	0.26		0.37		(0.11		)
Total production costs	$	1.76	$	1.90	$	(0.14	)	$	1.78	$	1.98	$	(0.20	)

Lease operating expense (LOE). QEP’s LOE was $50.7 million, a decrease of $6.0 million, or $0.07 per Mcfe, during the third quarter of 2016 compared to the third quarter of 2015. The decrease was driven by a decrease in the Uinta Basin due to lower maintenance and repair expenses and a decrease in the Permian Basin as a result of lower workover and produced water disposal expenses. Partially offsetting the decrease was an increase in Haynesville/Cotton Valley due to increased workover expenses.

QEP’s LOE was $163.3 million, a decrease of $12.3 million, or $0.07 per Mcfe, during the first three quarters of 2016 compared to the first three quarters of 2015. The decrease was driven by a decrease in the Permian Basin as a result of lower workover and chemical 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 $75.8 million, a decrease of $2.3 million, or $0.03 per Mcfe, during the third quarter of 2016 compared to the third quarter of 2015. The $2.3 million decrease in expense was primarily attributable to additional fees recognized during the third quarter of 2015 in Haynesville/Cotton Valley related to historical unutilized gathering and transportation capacity, which were charged to QEP by the operator of wells in which QEP has a working interest. QEP is disputing these charges and has filed a legal claim against the operator. This decrease was partially offset by an increase in the Williston Basin due to production increases and 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 $218.9 million, an increase of $2.7 million, during the first three quarters of 2016 compared to the first three quarters of 2015, primarily attributable to production increases in the Permian and Williston basins and higher rates in Pinedale. These increases are partially offset by a decrease in Haynesville/Cotton Valley as a result of decreased production and additional fees recognized during the third quarter of 2015 related to historical unutilized

gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP has a working interest. QEP is disputing these charges and has filed a legal claim against the operator.

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 $26.8 million, a decrease of $3.4 million, or $0.04 per Mcfe, during the third quarter of 2016 compared to the third quarter of 2015, primarily as a result of decreased gas and oil revenues from lower field-level prices and decreased production, and production tax refunds.

Production and property taxes were $65.3 million, a decrease of $25.4 million, or $0.11 per Mcfe, during the first three quarters of 2016 compared to the first three quarters 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 $217.8 million, a decrease of $20.3 million in the third quarter of 2016 compared to the third 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 rate decrease from the first quarter 2016 impairment and a decrease in production. 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 $667.5 million, an increase of $18.2 million in the first three quarters of 2016 compared to the first three quarters 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 in the Permian Basin. The decrease in Pinedale is primarily the result of a rate decrease due to a first quarter 2016 impairment, combined with decreased production, 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 $5.0 million for the third quarter of 2016, which was related to expiring leaseholds on unproved properties. Impairment expense was $15.0 million for the third quarter of 2015, of which $14.4 million was related to proved properties due to lower future prices and $0.6 million was related to expiring leaseholds on unproved properties. Of the $14.4 million impairment on proved properties, $13.1 million related to Other Northern properties, $1.0 million related to Other Southern properties and $0.3 million related to Permian Basin properties.

Impairment expense was $1,188.2 million for the first three quarters of 2016, of which $1,167.9 million was related to proved properties due to lower future prices, $16.6 million was related to expiring leaseholds on unproved properties and $3.7 million 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 $35.5 million for the first three quarters of 2015, of which $33.8 million was related to proved properties due to lower future prices and $1.7 million was related to expiring leaseholds on unproved properties. Of the $33.8 million impairment on proved properties, $18.0 million related to Other Northern properties, $15.5 million related to Other Southern properties and $0.3 million related to Permian Basin properties.

General and administrative expense (G&A). During the third quarter of 2016, G&A expense was $67.0 million, an increase of $25.0 million, or 60%, compared to the third quarter of 2015, primarily due to a $25.0 million increase in loss contingencies and a $5.9 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). These increases were partially offset by a $3.9 million decrease in severance payments and restructuring costs related to the Tulsa office closure in the third quarter of 2015 (See Note 8 – Restructuring Costs in Part 1, Item 1 of this Quarterly Report on Form 10-Q for additional information), a $2.0 million decrease in labor, benefits and employee expenses and a $1.7 million decrease in professional and outside services expenses.

During the first three quarters of 2016, G&A expense was $159.4 million, an increase of $18.7 million, or 13%, compared to the first three quarters of 2015, primarily due to a $32.7 million increase in loss contingencies and legal expenses and a $13.4 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). These increases were partially offset by 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 $6.1 million decrease in labor, benefits and employee expenses, a $5.0 million decrease in severance payments and restructuring costs related to the 2015 restructuring events (see Note 8 – Restructuring Costs, in Item 1 of Part I of this Quarterly Report on Form 10-Q), a $3.2 million decrease in professional and outside services expenses and a $1.9 million decrease in bad debt expense.

Net gain (loss) from asset sales. QEP recognized a gain on the sale of assets of $5.3 million during the third quarter of 2016 compared to a gain on sale of $12.9 million in the third quarter of 2015. The gain on sale of assets in the third quarter of 2016 was primarily related to continued divestitures of non-core Other Southern properties. The gain on sale of assets of $12.9 million recognized during the third quarter of 2015 was primarily due to a gain recognized for post-closing adjustments related to divestitures of certain non-core properties in Other Southern, partially offset by a loss recognized for post-closing adjustments related to the sale of QEP's midstream business in 2014.

QEP recognized a gain on the sale of assets of $5.0 million during the first three quarters of 2016 compared to a gain on the sale of assets of $6.9 million in the first three quarters of 2015. The gain on sale of assets in the first three quarters of 2016 was primarily related to continued divestitures of non-core Other Southern properties. The gain on sale of assets of $6.9 million recognized during the first three quarters of 2015 was primarily due to a gain recognized for post-closing adjustments related to divestitures of certain non-core properties in Other Southern, partially offset by a loss recognized for post-closing adjustments related to the sale of QEP's midstream business in 2014.

Non-operating Expenses

Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative contracts are comprised of both realized and unrealized gains and losses on QEP’s commodity derivative contracts, which are marked-to-market each quarter. During the third quarter of 2016, gains on commodity derivative contracts were $44.5 million, of which $24.9 million were unrealized gains and $19.6 million were realized gains. During the third quarter of 2015, gains on commodity derivative contracts were $153.6 million, of which $33.8 million were unrealized gains and $119.8 million were realized gains.

During the first three quarters of 2016, losses on commodity derivative contracts were $85.1 million, of which $218.6 million were unrealized losses, partially offset by $133.5 million of realized gains. During the first three quarters of 2015, gains on commodity derivative contracts were $168.5 million, of which $316.5 million were realized gains, partially offset by $148.0 million of unrealized losses.

Interest expense. Interest expense was $35.9 million during the third quarter of 2016 compared to $36.4 million during the third quarter of 2015. The decrease of $0.5 million primarily related to the repayment of senior notes on September 1, 2016.

Interest expense was $109.2 million during the first three quarters of 2016 compared to $109.4 million during the first three quarters of 2015. The decrease of $0.2 million primarily related to the repayment of senior notes on September 1, 2016.

Income tax (provision) benefit. Income tax benefit was $29.0 million during the third quarter of 2016 compared to $8.7 million of expense during the third quarter of 2015. The income tax rate was 36.3% during the third quarter of 2016 compared to a rate of 29.2% during the third quarter of 2015. The increase in income tax rate was primarily the result of being subject to a lower state tax rate in 2015 due to a change in the composition of income between subsidiaries and the states in which the subsidiaries are taxed.

Income tax benefit was $641.2 million during the first three quarters of 2016 compared to $61.6 million of benefit during the first three quarters of 2015. The income tax rate was 36.6% during the first three quarters of 2016 compared to a rate of 35.7% during the first three quarters of 2015. The increase in income tax rate was primarily the result of being subject to 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 three quarters 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 used to fund the 2016 Permian Acquisition. 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 operations, planned capital expenditures and working capital requirements during the next 12 months and the foreseeable future.

The Company estimates that, as of September 30, 2016, it could incur additional indebtedness of approximately $1.3 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 in the fourth quarter 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 September 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 October 21, 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 September 30, 2016, totaled $2,045.0 million principal amount and are comprised of five issuances as follows:


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


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


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


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


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

During the three months ended September 30, 2016, the Company paid $176.8 million for the repayment of the 6.05% Senior Notes, which were due on September 1, 2016.

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:



	Nine Months Ended September 30,
	2016			2015			Change
	(in millions)
Net income (loss)	$	(1,111.7	)	$	(110.8	)	$	(1,000.9	)
Non-cash adjustments to net income (loss)	1,516.4			887.8			628.6
Changes in operating assets and liabilities	128.2			(503.1		)	631.3
Net cash provided by (used in) operating activities	$	532.9		$	273.9		$	259.0

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

Net cash provided by operating activities was $273.9 million during the first three quarters of 2015, which included a $110.8 million net loss, $887.8 million of non-cash adjustments to the net loss and a $503.1 million decrease in operating assets and liabilities. Non-cash adjustments to the net loss primarily included DD&A expense of $649.3 million, unrealized losses on derivative contracts of $148.0 million, impairment expense of $35.5 million and an increase in deferred income taxes of $22.7 million. The decrease in cash from operating assets and liabilities primarily included a decrease in accounts payable and accrued expenses of $97.4 million and a decrease in income taxes payable of $574.0 million, primarily related to income taxes payable from the gain on the sale of substantially all of QEP's midstream business, which was paid during the first three quarters of 2015. These changes were partially offset by a decrease in accounts receivable of $159.1 million.

Cash Flow from Investing Activities

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



	Nine Months Ended September 30,
	2016		2015		Change
	(in millions)
Property acquisitions and acquisition deposit held in escrow	$	76.1	$	23.5	$	52.6
Property, plant and equipment capital expenditures	384.6		793.7		(409.1		)
Total accrued capital expenditures	460.7		817.2		(356.5		)
Change in accruals and other non-cash adjustments	20.4		68.9		(48.5		)
Total cash capital expenditures	$	481.1	$	886.1	$	(405.0	)

In the first three quarters of 2016, on an accrual basis, the Company invested $384.6 million in property, plant and equipment capital expenditures, a decrease of $409.1 million compared to the first three quarters of 2015. In the first three quarters of 2016, QEP's capital expenditures were $184.0 million in the Williston Basin, $102.0 million in the Permian Basin, $44.9 million in Pinedale, $38.1 million in Haynesville/Cotton Valley and $10.4 million in the Uinta Basin. In addition, in the first three quarters of 2016, QEP acquired various oil and gas properties in the Williston and Permian basins, including additional interests in QEP's operated wells and additional undeveloped leasehold acreage, for a total purchase price of $46.1 million, of

which $39.9 million was cash and $6.2 million was non-cash related to the settlement of an accounts receivable balance. Lastly, QEP paid a deposit of $30.0 million into escrow for the 2016 Permian Acquisition, which closed in October 2016.

In the first three quarters of 2015, on an accrual basis, the Company invested $793.7 million in property, plant and equipment capital expenditures, which included $395.4 million in the Williston Basin, $166.6 million in the Permian Basin, $137.0 million in Pinedale, $52.4 million in the Uinta Basin and $32.3 million in Haynesville/Cotton Valley. In addition, during the nine months ended September 30, 2015, QEP acquired various oil and gas properties, primarily undeveloped leasehold acreage in the Permian Basin, for an aggregate purchase price of $23.5 million.

QEP has significantly reduced its 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 slightly higher than in 2015, excluding any production from the 2016 Permian Acquisition. The mid-point of our forecasted capital expenditures (excluding acquisitions) for 2016 is $538.0 million. 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 three quarters of 2016, net cash provided by financing activities was $575.4 million compared to net cash used in financing activities of $57.3 million in the first three quarters of 2015. During the first three quarters of 2016, QEP had net proceeds from the March and June 2016 equity offerings of approximately $781.6 million, a repayment of senior notes of $176.8 million and a decrease in checks outstanding in excess of cash balances of $25.5 million. During the first three quarters of 2015, QEP had a decrease in checks outstanding in excess of cash balances of $41.9 million and paid $10.6 million of quarterly dividend payments.

As of September 30, 2016, the Company did not have any borrowings outstanding under the credit facility and had $2,045.0 million in senior notes outstanding (excluding $25.7 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 derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price and basis swaps and collars. The volume of commodity derivative instruments utilized by the Company may vary from year to year based on QEP's forecasted production. The Company's current derivative instruments do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of September 30, 2016, QEP held commodity price derivative contracts totaling 264.1 million MMBtu of gas and 19.1 million barrels of oil.

The following tables present QEP's volumes and average prices for its derivative positions as of October 21, 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 September 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	12.8	$	2.90
2016	IFNPCR	12.2	$	2.53
2017	NYMEX HH	87.6	$	2.83
2017	IFNPCR	32.9	$	2.51
2018	NYMEX HH	40.2	$	2.94
Oil sales		(bbls)	($/bbl)
2016	NYMEX WTI	3.4	$	51.21
2017	NYMEX WTI	11.7	$	50.88
2018	NYMEX WTI	6.6	$	53.14



Production Gas Collars
Year	Index	Total Volumes	Average Price Floor		Average Price Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2016	NYMEX HH	1.2	$	2.75	$	3.89
2017	NYMEX HH	11.0	$	2.50	$	3.50



Production Basis Swaps
Year	Index Less Differential	Index	Total Volumes	Weighted-Average Differential
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2016	NYMEX HH	IFNPCR	6.1	$	(0.16	)
2017	NYMEX HH	IFNPCR	51.1	$	(0.18	)
2018	NYMEX HH	IFNPCR	7.3	$	(0.16	)
Oil sales			(bbls)	($/bbl)
2017	NYMEX WTI	Argus WTI Midland ⁽¹⁾	0.7	$	(0.75	)
2018	NYMEX WTI	Argus WTI Midland ⁽¹⁾	0.7	$	(0.95	)

__________________________


⁽¹⁾	Argus WTI Midland is an index price reflecting the weighted average price of WTI at the pipeline and storage hub at Midland, Texas.



Storage Commodity Derivative Positions
Year	Type of Contract	Index	Total Volumes	Average Swap Price per Unit
			(in millions)
Gas sales			(MMBtu)	($/MMBtu)
2016	SWAP	IFNPCR	1.8	$	2.85
2017	SWAP	IFNPCR	4.0	$	2.88
Gas purchases
2016	SWAP	IFNPCR	0.9	$	2.58

Changes in the fair value of derivative contracts from December 31, 2015 to September 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	(133.5		)
Change in gas and oil prices on futures markets	(80.5		)
Contracts added	(4.6		)
Net fair value of gas and oil derivative contracts outstanding at September 30, 2016	$	(53.4	)

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:



	September 30, 2016
	(in millions)
Net fair value – asset (liability)	$	(53.4	)
Fair value if market prices of gas and oil and basis differentials decline by 10%	$	(48.0	)
Fair value if market prices of gas and oil and basis differentials increase by 10%	$	(58.7	)

Utilizing the actual derivative volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $5.3 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $5.4 million as of September 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 September 30, 2016, the Company did not have any borrowings outstanding under its credit facility.

The remaining $2,045.0 million of the Company’s debt is senior notes with fixed interest rates; therefore, it is not affected by interest rate movements. For additional information regarding the Company’s debt instruments, see Note 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 our operations, planned capital expenditures and working capital requirements;


•	plans and ability to pursue acquisition opportunities;


•	our inventory of drilling locations;


•	drilling and completion plans;


•	focus on improving operating performance by optimizing reservoir development, enhancing well completion designs and 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 under our credit facility;


•	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;


•	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 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;


•	outcome and impact of various claims;


•	ability to meet delivery and sales commitments;


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


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

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 September 30, 2016. Based on such evaluation, such officers have concluded that, as of September 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 over Financial Reporting

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

In July 2015, QEP received an information request from the Environmental Protection Agency (EPA) pursuant to Section 114(a) of the Clean Air Act. The information request sought facts and data about certain tank batteries in QEP’s Williston Basin operations. QEP timely responded to the information requests. In August 2016, the EPA requested a conference to review this matter. In addition, since February 2016, the North Dakota Department of Health (NDDH) has engaged with the oil and gas production industry in North Dakota to address potential noncompliance associated with emissions from tank batteries. QEP has participated in these discussions. While no formal federal or state enforcement action has been commenced in connection with the tank batteries to date, QEP anticipates that resolution of these matters will likely result in penalties in excess of $100,000 and require QEP to incur additional capital expenditures to correct noncompliance issues.

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 nine months ended September 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 completion of or production from its wells. Disputes over termination or changes to such agreements 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. 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
July 1, 2016 - July 31, 2016	—	$	—	—	$	—
August 1, 2016 - August 31, 2016	—	$	—	—	$	—
September 1, 2016 - September 30, 2016	46,240	$	19.40	—	$	—

____________________________


⁽¹⁾	All of the 46,240 shares purchased during the three-month period ended September 30, 2016, were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting of restricted share grants.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

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



Exhibit No.		Exhibits
3.1		Certificate of Incorporation, dated May 18, 2010 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, filed with the Securities and Exchange Commission on May 24, 2010)
3.2		Amended and Restated Bylaws, effective February 22, 2016 (incorporated by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission on February 24, 2016)
10.1+		Amendment to Restricted Stock Agreements under the QEP Resources, Inc. Long-Term Stock Incentive Plan Granted to Austin Murr, dated effective as of September 30, 2016, by and between the Company and Austin Murr.
10.2		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 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q, filed with the Securities and Exchange Commission on July 27, 2016), as amended by the First Amendment to Purchase and Sale Agreement, dated as of September 7, 2016 (filed herewith), and the Second Amendment to Purchase and Sale Agreement, dated September 14, 2016 (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 September 19, 2016)
31.1		Certification signed by Charles B. Stanley, QEP Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification signed by Richard J. Doleshek, QEP Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification signed by Charles B. Stanley and Richard J. Doleshek, QEP Resources, Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*		XBRL Instance Document
101.SCH*		XBRL Schema Document
101.CAL*		XBRL Calculation Linkbase Document
101.LAB*		XBRL Label Linkbase Document
101.PRE*		XBRL Presentation Linkbase Document
101.DEF*		XBRL Definition Linkbase Document

____________________________


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


+	Indicates a management contract or compensatory plan or arrangement.

SIGNATURES

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



	QEP RESOURCES, INC.
	(Registrant)

October 26, 2016	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer

October 26, 2016	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

QEP RESOURCES, INC. - FORM 10-Q - October 26, 2016

Attached files

QEP RESOURCES, INC. Reports