QEP RESOURCES, INC. - FORM 10-Q

Attached files

file	filename
EX-31.1 - EXHIBIT 31.1 - QEP RESOURCES, INC.	qepr-201563015ex311.htm
EX-10.2 - EXHIBIT 10.2 - QEP RESOURCES, INC.	qepr-201563015ex102.htm
EX-31.2 - EXHIBIT 31.2 - QEP RESOURCES, INC.	qepr-201563015ex312.htm
EX-10.1 - EXHIBIT 10.1 - QEP RESOURCES, INC.	qepr-201563015ex101.htm
EX-99.1 - EXHIBIT 99.1 - QEP RESOURCES, INC.	qepr-201563015ex991.htm
EX-32.1 - EXHIBIT 32.1 - QEP RESOURCES, INC.	qepr-201563015ex321.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended June 30, 2015



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 o No ý

At June 30, 2015, there were 176,667,217 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended June 30, 2015

TABLE OF CONTENTS



			Page
PART I. FINANCIAL INFORMATION			2

	ITEM 1.	FINANCIAL STATEMENTS	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2015 AND 2014	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2015 AND 2014	3

		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT JUNE 30, 2015 AND DECEMBER 31, 2014	4

		UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30, 2015 AND 2014	5

		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	6

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	27

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	47

	ITEM 4.	CONTROLS AND PROCEDURES	52

PART II. OTHER INFORMATION			52

	ITEM 1.	LEGAL PROCEEDINGS	52

	ITEM 1A.	RISK FACTORS	52

	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	55

	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	55

	ITEM 4.	MINE SAFETY DISCLOSURES	55

	ITEM 5.	OTHER INFORMATION	55

	ITEM 6.	EXHIBITS	56

SIGNATURES			57

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
REVENUES	(in millions, except per share amounts)
Gas sales	$	111.9		$	215.1		$	233.9		$	437.6
Oil sales	250.4			358.8			429.2			647.5
NGL sales	26.1			65.0			45.2			128.2
Other revenue	5.2			(0.8		)	9.6			1.7
Purchased gas and oil sales	215.0			249.1			382.3			489.7
Total Revenues	608.6			887.2			1,100.2			1,704.7
OPERATING EXPENSES
Purchased gas and oil expense	217.2			249.2			386.6			487.1
Lease operating expense	57.1			59.5			118.9			115.9
Gas, oil and NGL transportation and other handling costs	73.0			67.5			138.1			127.4
Gathering and other expense	1.4			1.8			3.1			3.4
General and administrative	51.3			52.3			98.7			97.6
Production and property taxes	32.7			53.5			60.5			101.4
Depreciation, depletion and amortization	215.8			235.2			411.2			461.1
Exploration expenses	0.8			1.7			1.9			3.9
Impairment	0.5			1.5			20.5			3.5
Total Operating Expenses	649.8			722.2			1,239.5			1,401.3
Net gain (loss) from asset sales	24.5			(200.9		)	(6.0		)	(198.5		)
OPERATING INCOME (LOSS)	(16.7		)	(35.9		)	(145.3		)	104.9
Realized and unrealized gains (losses) on derivative contracts (Note 8)	(66.0		)	(88.0		)	14.9			(168.9		)
Interest and other income	3.8			0.8			1.2			3.7
Income from unconsolidated affiliates	—			0.1			—			0.1
Interest expense	(36.2		)	(45.0		)	(73.0		)	(86.9		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(115.1		)	(168.0		)	(202.2		)	(147.1		)
Income tax (provision) benefit	38.8			61.9			70.3			53.7
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(76.3		)	(106.1		)	(131.9		)	(93.4		)
Net income from discontinued operations, net of income tax	—			13.8			—			40.8
NET INCOME (LOSS)	$	(76.3	)	$	(92.3	)	$	(131.9	)	$	(52.6	)

Earnings (Loss) Per Common Share
Basic from continuing operations	$	(0.43	)	$	(0.59	)	$	(0.75	)	$	(0.52	)
Basic from discontinued operations	—			0.08			—			0.23
Basic total	$	(0.43	)	$	(0.51	)	$	(0.75	)	$	(0.29	)
Diluted from continuing operations	$	(0.43	)	$	(0.59	)	$	(0.75	)	$	(0.52	)
Diluted from discontinued operations	—			0.08			—			0.23
Diluted total	$	(0.43	)	$	(0.51	)	$	(0.75	)	$	(0.29	)
Weighted-average common shares outstanding
Used in basic calculation	176.7			180.1			176.4			179.9
Used in diluted calculation	176.7			180.1			176.4			179.9
Dividends per common share	$	0.02		$	0.02		$	0.04		$	0.04

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(in millions)
Net income (loss)	$	(76.3	)	$	(92.3	)	$	(131.9	)	$	(52.6	)
Other comprehensive income, net of tax:
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss ⁽¹⁾	—			0.1			0.2			0.2
Amortization of prior service cost ⁽²⁾	0.1			0.8			0.6			1.7
Other comprehensive income	0.1			0.9			0.8			1.9
Comprehensive income (loss)	$	(76.2	)	$	(91.4	)	$	(131.1	)	$	(50.7	)

____________________________


⁽¹⁾	Presented net of income tax expense of $0.1 million during the six months ended June 30, 2015, and $0.1 million and $0.2 million during the three and six months ended June 30, 2014, respectively.


⁽²⁾	Presented net of income tax expense of $0.1 million and $0.4 million during the three and six months ended June 30, 2015, respectively, and $0.5 million and $1.0 million during the three and six months ended June 30, 2014, respectively.

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	June 30, 2015			December 31, 2014
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	445.6		$	1,160.1
Accounts receivable, net	330.8			441.9
Income taxes receivable	55.7			—
Fair value of derivative contracts	163.6			339.0
Gas, oil and NGL inventories, at lower of average cost or market	10.4			13.7
Prepaid expenses and other	38.0			46.8
Total Current Assets	1,044.1			2,001.5
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	12,686.4			12,278.7
Unproved properties	814.1			825.2
Marketing and other	298.1			293.8
Material and supplies	41.6			54.3
Total Property, Plant and Equipment	13,840.2			13,452.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,415.1			6,153.0
Marketing and other	77.7			67.8
Total Accumulated Depreciation, Depletion and Amortization	6,492.8			6,220.8
Net Property, Plant and Equipment	7,347.4			7,231.2
Fair value of derivative contracts	6.1			9.9
Other noncurrent assets	35.5			44.2
TOTAL ASSETS	$	8,433.1		$	9,286.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	7.4		$	54.7
Accounts payable and accrued expenses	463.3			575.4
Income taxes payable	—			532.1
Production and property taxes	59.3			61.7
Interest payable	36.4			36.4
Fair value of derivative contracts	1.0			—
Deferred income taxes	36.9			84.5
Total Current Liabilities	604.3			1,344.8
Long-term debt	2,218.5			2,218.1
Deferred income taxes	1,381.4			1,362.7
Asset retirement obligations	184.9			193.8
Fair value of derivative contracts	1.6			—
Other long-term liabilities	94.7			92.1
Commitments and contingencies (Note 10)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 177.0 million and 176.2 million shares issued, respectively	1.8			1.8
Treasury stock - 0.4 million and 0.8 million shares, respectively	(11.5		)	(25.4		)
Additional paid-in capital	538.1			535.3
Retained earnings	3,442.8			3,587.9
Accumulated other comprehensive income (loss)	(23.5		)	(24.3		)
Total Common Shareholders' Equity	3,947.7			4,075.3
TOTAL LIABILITIES AND EQUITY	$	8,433.1		$	9,286.8

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six Months Ended
	June 30,
	2015			2014
	(in millions)
OPERATING ACTIVITIES
Net income (loss)	$	(131.9	)	$	(52.6	)
Net income attributable to noncontrolling interest	—			10.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	411.2			489.9
Deferred income taxes	(29.4		)	15.8
Impairment	20.5			3.5
Share-based compensation	15.6			14.6
Pension curtailment loss	11.2			—
Amortization of debt issuance costs and discounts	3.3			3.4
Net (gain) loss from asset sales	6.0			198.6
Income from unconsolidated affiliates	—			(3.4		)
Distributions from unconsolidated affiliates and other	—			6.3
Unrealized (gains) losses on derivative contracts	181.8			98.2
Changes in operating assets and liabilities	(490.9		)	75.2
Net Cash (Used in) Provided by Operating Activities	(2.6		)	860.3
INVESTING ACTIVITIES
Property acquisitions	—			(949.4		)
Property, plant and equipment, including dry exploratory well expense	(651.3		)	(779.0		)
Proceeds from (payments for) disposition of assets	(2.4		)	706.3
Acquisition deposit held in escrow	—			50.0
Net Cash Used in Investing Activities	(653.7		)	(972.1		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(47.3		)	(85.2		)
Long-term debt issued	—			300.0
Long-term debt issuance costs paid	—			(1.1		)
Proceeds from credit facility	—			3,151.0
Repayments of credit facility	—			(2,538.0		)
Treasury stock repurchases	(1.9		)	(5.5		)
Other capital contributions	(0.1		)	4.1
Dividends paid	(7.1		)	(7.3		)
Excess tax (provision) benefit on share-based compensation	(1.8		)	(0.6		)
Distribution to noncontrolling interest	—			(15.2		)
Net Cash (Used in) Provided by Financing Activities	(58.2		)	802.2
Change in cash and cash equivalents	(714.5		)	690.4
Beginning cash and cash equivalents	1,160.1			11.9
Ending cash and cash equivalents	$	445.6		$	702.3

Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	69.7		$	84.9
Cash paid for income taxes	548.5			0.2
Non-cash investing activities:
Change in capital expenditure accrual balance	$	(91.6	)	$	26.3

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 - Nature of Business

QEP Resources, Inc. (QEP or the Company) is a holding company with two principal subsidiaries, QEP Energy Company and QEP Marketing Company, which are engaged in two primary lines of business: (i) oil and gas exploration and production (QEP Energy) and (ii) oil and gas marketing, operation of a gas gathering system and an underground gas storage facility and corporate (QEP Marketing and Other).

QEP's operations are focused in two geographic regions: the Northern Region (primarily in Wyoming, North Dakota and Utah) and the Southern Region (primarily in Texas and Louisiana) of the United States. QEP's corporate headquarters are located in Denver, Colorado.

Shares of QEP’s common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol “QEP”.

Note 2 – Basis of Presentation of Interim 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/A for the year ended December 31, 2014.

The preparation of the Condensed Consolidated Financial Statements and Notes in conformity with GAAP requires that management make estimates and assumptions that affect revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three and six months ended June 30, 2015, are not necessarily indicative of the results that may be expected for the year ending December 31, 2015.

Impairment of Long-Lived Assets

During the six months ended June 30, 2015, QEP Energy recorded impairment charges of $20.5 million, of which $19.4 million was related to proved properties due to lower future prices and $1.1 million was related to expiring leaseholds on unproved properties. Of the $19.4 million impairment on proved properties, $14.5 million related to oil and gas properties in the Southern Region and $4.9 million related to oil and gas properties in the Northern Region.

New Accounting Pronouncements

In May 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) No. 2015-07, Fair Value Measurement (Topic 820), which removes the requirement to categorize investments for which fair values are measured using the net asset value per share practical expedient. It also limits disclosures to investments for which the entity has elected to measure the fair value using the practical expedient. The Company is currently assessing the ASU and does not believe there will be a significant impact on the Company's consolidated financial statements.

In April 2015, the FASB issued ASU No. 2015-05, Intangibles — Goodwill and Other — Internal-Use Software (Subtopic 350-40), which assists entities in evaluating the accounting for fees paid by a customer in a cloud computing arrangement by providing guidance as to whether an arrangement includes the sales or license of software. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not believe there will be a significant impact on the Company's consolidated financial statements.

In April 2015, the FASB issued ASU No. 2015-03, Interest — Imputation of Interest (Subtopic 835-30), which simplifies the presentation of debt issuance costs by requiring that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The amendments will be effective retrospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company plans to implement the ASU effective January 1, 2016 and does not believe there will be a significant impact on the Company's consolidated financial statements.

In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810), which amends the current consolidation guidance. The amendment affects both the variable interest entity and voting interest entity consolidation models. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not believe there will be a significant impact on the Company's consolidated financial statements.

In January 2015, the FASB issued ASU No. 2015-01, Income Statement — Extraordinary and Unusual Items (Subtopic 225-20), which eliminates the concept of extraordinary items from GAAP. The amendment will be effective for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. Additionally, a reporting entity also may apply the amendment retrospectively for all periods presented in the financial statements. The Company is currently assessing the ASU and does not believe there will be a significant impact on the Company's consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. On July 9, 2015, the FASB decided to delay the effective date of the new revenue standard by one year and the amendments are now effective prospectively for reporting periods beginning after December 15, 2017 and early adoption is not permitted. The Company is currently assessing the impact on the Company's Consolidated Financial Statements.

Note 3 - Acquisitions and Divestitures

Permian Basin Acquisition

On February 25, 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $941.8 million (the Permian Basin Acquisition). The acquired properties consisted of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 270 vertical producing wells in the Permian Basin, which created a new core area of operation for QEP Energy. The acquisition was funded with $50.0 million of restricted cash, $300.0 million from the Company's expanded term loan and the remainder was funded from its revolving credit facility.

The Permian Basin Acquisition meets the definition of a business combination under ASC 805, Business Combinations, as it included significant proved properties. QEP allocated the cost of the Permian Basin Acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Revenues of $40.1 million and $69.6 million and net income of $2.4 million and $0.9 million were generated from the acquired properties during the three and six months ended June 30, 2015. Revenues of $61.9 million and net income of $14.0 million were generated from the acquired properties from February 25, 2014, to June 30, 2014, and are included in QEP's Condensed Consolidated Statements of Operations.

The following table presents a summary of the Company's purchase accounting entries (in millions):



Consideration:
Total consideration	$	941.8

Amounts recognized for fair value of assets acquired and liabilities assumed:
Proved properties	$	472.1
Unproved properties	480.6
Asset retirement obligations	(9.7		)
Liabilities assumed	(1.2		)
Total fair value	$	941.8

The following unaudited, pro forma results of operations are provided for the six months ended June 30, 2014. Pro forma results are not provided for the three months ended June 30, 2014, or the three and six months ended June 30, 2015, because the Permian Basin Acquisition occurred during the first quarter of 2014, and therefore there is no pro forma impact on the these periods. These supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the period presented, or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the six months ended June 30, 2014, the acquired properties' historical results of operations, and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.



		Six Months Ended
		June 30, 2014
		Actual			Pro forma
	(in millions, except per share data)
Revenues		$	1,704.7		$	1,730.8
Net income		$	(52.6	)	$	(45.6	)
Earnings per common share
Basic		$	(0.29	)	$	(0.25	)
Diluted		$	(0.29	)	$	(0.25	)

Divestitures

In December 2014, QEP Energy sold its interest in certain non-core properties in southern Oklahoma for aggregate proceeds of $96.3 million, subject to post-closing purchase price adjustments, and recorded a pre-tax gain on sale of $53.3 million for the year ended December 31, 2014. QEP Energy recorded a pre-tax loss on sale of $1.1 million and $2.9 million for the three and six months ended June 30, 2015, respectively, due to post-closing purchase price adjustments.

In June 2014, QEP Energy sold its interest in certain non-core properties in the Midcontinent area and other non-core assets in the Williston Basin for aggregate proceeds of $668.2 million, subject to post-closing purchase price adjustments, and recorded a pre-tax loss of $199.4 million for the year ended December 31, 2014. QEP recorded a pre-tax gain on sale of $0.4 million and a pre-tax loss on sale of $26.4 million for the three and six months ended June 30, 2015, respectively, due to post-closing purchase price adjustments. These gains and losses are reported on the Condensed Consolidated Statements of Operations in "Net gain (loss) from asset sales".

Note 4 - Discontinued Operations

The operating results of QEP Field Services, excluding the Haynesville Gathering System (the Discontinued Operations of QEP Field Services), have been classified as discontinued operations on the Condensed Consolidated Statements of Operations and Notes accompanying the Condensed Consolidated Financial Statements for the three and six months ended June 30, 2014. QEP will have continuing cash outflows to the entities sold as a part of the Midstream Sale for gathering, processing and water handling costs in Pinedale, the Uinta Basin and a portion of its Williston Basin operations. The contracts related to these cash flows vary in length from month-to-month to over a year and will be reviewed periodically in the normal course of business. Historically, these transactions were eliminated in consolidation, as they represented transactions between two related entities but are now reflected as part of the continuing operations for QEP. For the six months ended June 30, 2015 and 2014, cash outflows for these transactions included in continuing operations were $69.3 million and $74.0 million, respectively.

In connection with QEP's plan to separate its midstream business, the Board of Directors approved an employee retention plan to provide substantially all QEP Field Services' employees as of December 1, 2013, with a one-time lump-sum cash payment on the earlier of December 31, 2014, or whenever the separation of QEP Field Services occurred, conditioned on continued employment with QEP Field Services or a successor through the payment date unless the employee is terminated prior to such date. QEP recognized $10.4 million of costs under this retention plan in 2014, of which $2.6 million and $4.8 million was included in "Discontinued operations, net of income tax" on the Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2014, respectively.

Condensed Consolidated Statement of Operations

The Discontinued Operations of QEP Field Services are summarized below:



	Three Months Ended			Six Months Ended
	June 30, 2014
	(in millions)
REVENUES
NGL sales	$	27.8		$	65.8
Other revenue	34.9			76.8
Purchased gas and oil sales⁽¹⁾	(13.2		)	(26.6		)
Total Revenues	49.5			116.0
OPERATING EXPENSES
Purchased gas and oil expense⁽¹⁾	(13.3		)	(27.1		)
Lease operating expense⁽¹⁾	(2.0		)	(3.1		)
Natural gas, oil and NGL transport and other handling costs⁽¹⁾	(13.1		)	(29.5		)
Gathering, processing, and other	22.8			47.1
General and administrative	11.9			23.2
Production and property taxes	2.5			4.0
Depreciation, depletion and amortization	14.5			28.8
Total Operating Expenses	23.3			43.4
Net loss from asset sales	(0.1		)	(0.1		)
OPERATING INCOME	26.1			72.5
Income from unconsolidated affiliates	1.1			3.3
Interest expense	(0.7		)	(1.3		)
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES ⁽²⁾	26.5			74.5
Income tax provision	(7.7		)	(22.9		)
NET INCOME FROM DISCONTINUED OPERATIONS	18.8			51.6
Net income attributable to noncontrolling interest	(5.0		)	(10.8		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	13.8		$	40.8


⁽¹⁾	Includes discontinued intercompany eliminations.


⁽²⁾	Includes income from discontinued operations before income taxes attributable to QEP from QEP Midstream (of which QEP owned 57.8%) of $5.7 million and $12.5 million for the three and six months ended June 30, 2014, respectively.

Condensed Consolidated Statement of Cash Flows

The impact of the Discontinued Operations of QEP Field Services on the Condensed Consolidated Statement of Cash Flows for "Depreciation, depletion and amortization" contained in "Cash flows from operating activities" was $14.5 million and $28.8 million for the three and six months ended June 30, 2014, respectively. The impact on cash used for "Property, plant and equipment, including dry exploratory well expense" contained in "Cash flows from investing activities" was $24.4 million and $37.1 million for the three and six months ended June 30, 2014, respectively.

Note 5 – 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 receive dividends.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company’s unvested restricted stock awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company’s unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company’s unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share. During the three and six months ended June 30, 2014, 0.4 million and 0.3 million shares, respectively, were not included in diluted common shares outstanding as they were anti-dilutive due to QEP's net loss. During the three and six months ended June 30, 2015, there were no anti-dilutive shares.

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



	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2015	2014	2015	2014
	(in millions)
Weighted-average basic common shares outstanding	176.7	180.1	176.4	179.9
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	176.7	180.1	176.4	179.9

Note 6 – Asset Retirement Obligations

QEP records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible long-lived assets. The Company's ARO liability applies primarily to abandonment costs associated with oil and gas wells and certain other properties. The fair values of such costs are estimated by Company personnel based on abandonment costs of similar assets and depreciated over the life of the related assets. Revisions to the ARO estimates result from changes in expected cash flows or material changes in estimated asset retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Of the $185.9 million and $195.1 million ARO liability for the periods ended June 30, 2015 and December 31, 2014, $1.0 million and $1.3 million were included, respectively, as a current liability in "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
	2015
	(in millions)
ARO liability at January 1,	$	195.1
Accretion	4.3
Additions	1.9
Revisions	0.2
Liabilities related to divestitures	(14.6		)
Liabilities settled	(1.0		)
ARO liability at June 30,	$	185.9

Note 7 – 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 8 - Derivative Contracts) is based on market prices posted on the respective commodity exchange on the last trading day of the reporting period and industry standard discounted cash flow models. QEP primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. QEP considers bid and ask prices for valuing the majority of its assets and liabilities measured and reported at fair value. In addition to using market data, QEP makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique. The Company's policy is to recognize significant transfers between levels at the end of the reporting period.

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

The fair value of financial assets and liabilities at June 30, 2015 and December 31, 2014, 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⁾
	(in millions)
	June 30, 2015
Financial Assets
Commodity derivative instruments - short-term	$	—	$	170.7	$	—	$	(7.1	)	$	163.6
Commodity derivative instruments - long-term	—		7.0		—		(0.9		)	6.1
Total financial assets	$	—	$	177.7	$	—	$	(8.0	)	$	169.7

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	8.1	$	—	$	(7.1	)	$	1.0
Commodity derivative instruments - long-term	—		2.5		—		(0.9		)	1.6
Total financial liabilities	$	—	$	10.6	$	—	$	(8.0	)	$	2.6

	December 31, 2014
Financial Assets
Commodity derivative instruments - short-term	$	—	$	339.3	$	—	$	(0.3	)	$	339.0
Commodity derivative instruments - long-term	—		9.9		—		—			9.9
Total financial assets	$	—	$	349.2	$	—	$	(0.3	)	$	348.9

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	0.3	$	—	$	(0.3	)	$	—
Total financial liabilities	$	—	$	0.3	$	—	$	(0.3	)	$	—

_______________________


⁽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 8 - Derivative Contracts, for additional information regarding the Company's derivative contracts.

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



	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	June 30, 2015				December 31, 2014
	(in millions)
Financial assets
Cash and cash equivalents	$	445.6	$	445.6	$	1,160.1	$	1,160.1
Financial liabilities
Checks outstanding in excess of cash balances	$	7.4	$	7.4	$	54.7	$	54.7
Long-term debt	$	2,218.5	$	2,230.9	$	2,218.1	$	2,171.6

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 6 – Asset Retirement Obligations.

Note 8 – Derivative Contracts

QEP has established policies and procedures for managing commodity price volatility through the use of derivative instruments. In the normal course of business, QEP uses commodity price derivative instruments to reduce the impact of potential downward movements in commodity prices on cash flow, returns on capital investment, and other financial results. However, these instruments typically limit gains from favorable price movements. The volume of production subject to commodity derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may enter into commodity derivative contracts for up to 100% of forecasted production from proved reserves, but generally, QEP intends to enter into commodity derivative contracts for approximately 50% 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 gas sales and purchases for marketing transactions. QEP does not enter into commodity derivative instruments for speculative purposes.

QEP uses commodity derivative instruments known as fixed-price swaps or collars to realize a known price or price range for a specific volume of production delivered into a regional sales point. QEP's commodity derivative instruments do not require the physical delivery of gas, oil, or NGL between the parties at settlement. Swap transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the contract volume, for the settlement period. Gas price derivative instruments are typically structured as fixed-price swaps or collars at regional price indices. Oil price derivative instruments are typically structured as NYMEX fixed-price swaps based at Cushing, Oklahoma or oil price swaps that use Intercontinental Exchange, Inc. (ICE) Brent oil prices as the reference price. QEP also enters into crude oil and natural gas basis swaps to achieve a fixed price swap for a portion of its oil and gas that it sells at prices that reference specific index prices.

QEP enters into commodity derivative transactions that do not have margin requirements or collateral provisions that would require payments prior to the scheduled settlement dates. Commodity derivative contract counterparties are normally financial institutions and energy trading firms with investment-grade credit ratings. QEP routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties and avoids concentration of credit exposure by transacting with multiple counterparties.

During 2014, QEP also used interest rate swaps to mitigate a portion of its exposure to interest rate volatility associated with its $600.0 million term loan. For the $300.0 million term loan issued during 2012, QEP locked in a fixed interest rate of 1.07% in exchange for a variable interest rate indexed to the one-month LIBOR. For the incremental $300.0 million borrowed under the term loan during 2014, QEP locked in a fixed interest rate of 0.86%. These interest rate swaps were terminated in December 2014 in conjunction with the extinguishment of QEP's term loan.

QEP Energy Derivative Contracts

The following table sets forth QEP Energy’s quantities and average prices for its commodity derivative swap contracts as of June 30, 2015:



Year	Index	Total Volumes	Average Swap price per unit
		(in millions)
Gas sales		(MMBtu)
2015	NYMEX HH	35.0	$	3.48
2015	IFNPCR	23.9	$	3.55
2016	NYMEX HH	18.3	$	3.24
2016	IFNPCR	25.6	$	2.92
Oil sales		(bbls)
2015	NYMEX WTI	5.2	$	82.09
2015	ICE Brent	0.2	$	104.95
2016	NYMEX WTI	3.3	$	65.43

The following table sets forth details of QEP Energy's gas collars as of June 30, 2015:

Total Volume

Average Price

Year

Index

Floor

Ceiling

(in millions)

(MMBtu)

($/MMBtu)

2016

NYMEX HH

7.3

2.75

3.89

QEP uses gas basis swaps, combined with NYMEX HH fixed price swaps, to achieve fixed price swaps at the location at which it sells its physical production.

The following table sets forth details of QEP Energy's gas basis swaps as of June 30, 2015:



Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2015	NYMEX HH	IFNPCR	22.1	$	(0.28	)

QEP Marketing Derivative Contracts

QEP Marketing enters into commodity derivative transactions to lock in a margin on gas volumes placed into storage and for marketing transactions in which QEP Marketing sells gas volumes at a fixed price. The following table sets forth QEP Marketing’s volumes and swap prices for its commodity derivative contracts as of June 30, 2015:



Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2015	SWAP	IFNPCR	2.4	$	3.25
2016	SWAP	IFNPCR	1.8	$	3.19
Gas purchases			(MMBtu)
2015	SWAP	IFNPCR	0.9	$	2.80

QEP Derivative Financial Statement Presentation

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



		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	June 30, 2015		December 31, 2014		June 30, 2015		December 31, 2014
		(in millions)
Current:
Commodity	Fair value of derivative contracts	$	170.7	$	339.3	$	8.1	$	0.3
Long-term:
Commodity	Fair value of derivative contracts	7.0		9.9		2.5		—
Total derivative instruments		$	177.7	$	349.2	$	10.6	$	0.3

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



	Three Months Ended						Six Months Ended
Derivative instruments not designated as cash flow hedges	June 30,						June 30,
Derivative instruments not designated as cash flow hedges	2015			2014			2015			2014
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	28.1		$	(8.4	)	$	46.0		$	(28.8	)
Oil derivative contracts	64.5			(25.1		)	148.5			(38.0		)
QEP Marketing
Gas derivative contracts	(0.3		)	(0.6		)	2.2			(2.0		)
Total realized gains (losses) on commodity derivative contracts	92.3			(34.1		)	196.7			(68.8		)
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	(34.5		)	6.2			(23.1		)	(18.1		)
Oil derivative contracts	(123.7		)	(58.0		)	(156.8		)	(78.9		)
QEP Marketing
Gas derivative contracts	(0.1		)	0.7			(1.9		)	0.4
Total unrealized gains (losses) on commodity derivative contracts	(158.3		)	(51.1		)	(181.8		)	(96.6		)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	(66.0	)	$	(85.2	)	$	14.9		$	(165.4	)

Realized gains (losses) on interest rate swaps
Realized gains (losses) on interest rate swaps	$	—		$	(1.2	)	$	—		$	(1.9	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	—			(1.6		)	—			(1.6		)
Total realized gains (losses) on interest rate swaps	$	—		$	(2.8	)	$	—		$	(3.5	)
Total net realized gains (losses) on derivative contracts	$	92.3		$	(35.3	)	$	196.7		$	(70.7	)
Total net unrealized gains (losses) on derivative contracts	(158.3		)	(52.7		)	(181.8		)	(98.2		)
Grand Total	$	(66.0	)	$	(88.0	)	$	14.9		$	(168.9	)

Note 9 – Debt

As of the indicated dates, the principal amount of QEP’s debt, including amounts outstanding under QEP's revolving credit facility and senior notes, consisted of the following:



	June 30, 2015			December 31, 2014
	(in millions)
Revolving Credit Facility due 2019	$	—		$	—
6.05% Senior Notes due 2016	176.8			176.8
6.80% Senior Notes due 2018	134.0			134.0
6.80% Senior Notes due 2020	136.0			136.0
6.875% Senior Notes due 2021	625.0			625.0
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
Total principal amount of debt	2,221.8			2,221.8
Less unamortized discount	(3.3		)	(3.7		)
Total long-term debt outstanding	$	2,218.5		$	2,218.1

Of the total debt outstanding on June 30, 2015, the 6.05% Senior Notes due September 1, 2016, the 6.80% Senior Notes due April 1, 2018 and the 6.80% Senior Notes due March 1, 2020, will mature within the next five years. The revolving credit facility matures on December 2, 2019.

Credit Facility

QEP’s revolving credit facility, which matures in December 2019, provides for loan commitments of $1.8 billion from a group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions.

On December 2, 2014, QEP entered into the Fourth Amendment to its Credit Agreement, which increased the aggregate principal amount of commitments to $1.8 billion, extended the maturity date to December 2, 2019, and made minor adjustments to other provisions and covenants.

During the six months ended June 30, 2014, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.20%. At June 30, 2015 and December 31, 2014, QEP had no borrowings outstanding under the credit facility, had $3.7 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit facility.

Senior Notes

At June 30, 2015, the Company had $2,221.8 million principal amount of senior notes outstanding with maturities ranging from September 2016 to May 2023 and coupons ranging from 5.25% to 6.875%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior obligations. QEP may redeem all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP’s senior notes contain customary events of default and covenants that may limit QEP’s ability to, among other things, place liens on its property or assets.

Note 10 - Contingencies

QEP is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business. QEP assesses these claims in an effort to determine the degree of probability and range of possible loss for potential accrual in its Consolidated Financial Statements. In accordance with ASC 450, Contingencies, an accrual is recorded for a loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable, and unfavorable resolutions can occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, QEP may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, the ongoing discovery and/or development of information important to the matter. QEP is unable to estimate reasonably possible losses (in excess of recorded accruals, if any) for its loss contingencies for the reasons set forth above. QEP believes, however,

that the resolution of pending proceedings (after accruals, insurance coverage, and indemnification arrangements) will not be material to QEP's financial position but could be material to results of operations in a particular quarter or year.

Litigation

Rocky Mountain Resources, LLC v. QEP Energy Company, Wexpro Company, Ultra Resources, Inc. and Lance Oil & Gas Company, Inc., Civil No. 2011-7816, District Court of Sublette County, Wyoming. Rocky Mountain Resources, LLC (Rocky Mountain) filed its complaint on March 30, 2011, seeking determination of the existence of a 4% overriding royalty interest in State of Wyoming oil and gas Lease No. 79-0645 covering Section 16, T32-N R-109-W, Sublette County, Wyoming. QEP and the other defendants are current lessees of Lease 79-0645. Rocky Mountain alleges that the defendants have received benefits from Lease 79-0645 and 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. Rocky Mountain asserts claims for quiet title, declaratory judgment, breach of contract, breach of duty of good faith, conversion, constructive trust and prejudgment interest. On May 7, 2014, the trial court entered its order granting plaintiff's motion for summary judgment on the issue of whether the overriding royalty interest burdens QEP's lease. On June 17, 2014, the Supreme Court of Wyoming denied QEP's Petition for Writ of Review. On August 21, 2014, the trial court denied QEP’s Motion to Certify Questions of Law to the Wyoming Supreme Court. At the conclusion of a trial in February 2015, and after being instructed by the Court that the overriding royalty interest burdened QEP’s lease, a jury rendered a verdict against QEP and awarded Rocky Mountain damages in the amount of $16.7 million, including interest. QEP believes that the Court’s ruling on summary judgment and the resulting jury instructions are in error and will appeal to the Wyoming Supreme Court. On March 27, 2015, defendants filed a Motion for New Trial arguing that the verdict is not sustained by sufficient evidence, is contrary to law and resulted from errors of law occurring at the trial. The Court has taken the motion under advisement. Post-judgment interest accrues at the statutory rate of 10%. QEP estimates that, notwithstanding the verdict, the range of reasonably possible losses is still zero to $20.0 million.

Yannick Gagné and others similarly situated v. QEP Resources, Inc., et al., No. 480-06-1-132, Superior Court, Province of Quebec, Canada. Plaintiffs seek to represent a class of all persons who sustained damages as a result of the July 6, 2013 train derailment in Lac-Mégantic, Quebec, which resulted in substantial loss of life and property. The fourth amended motion to authorize the bringing of a class action was filed on February 19, 2014, and names numerous defendants, including the rail company that transported the crude oil (which filed for bankruptcy protection in August 2013). The plaintiffs contend that QEP, and other producer defendants, sold Bakken crude oil to third-party purchasers in North Dakota, who resold the oil and transported it on the derailed train. Plaintiffs alleged that QEP and the producer defendants, among other things, failed to ensure that the oil was adequately processed to remove volatile gases and vapors, knowingly added volatile light end petroleum liquids and/or vapors or blended the crude with condensate, failed to conduct adequate well site testing to determine the proper hazard classification of the oil, failed to properly classify the shipping requirements for the oil, failed to take reasonable care to ensure that the oil was properly labeled and shipped, failed to identify the risk of the train derailment and take action to prevent it, and failed to adopt, implement and enforce rules and procedures pertaining to the safe shipment of the oil. The plaintiffs seek damages, but specific monetary damages are not asserted. Class certification hearings took place in June 2014, and a court order regarding class certification is pending. Many of the defendants, including QEP, and their insurers have reached an agreement with Trustees in both Canadian and U.S. Bankruptcy Courts to resolve all of these claims. The terms of the agreement are confidential and are contingent upon the approval of the courts. In addition, on July 15, 2015, QEP was served with a complaint entitled Samuel Audet, et al. vs. Devlar Energy Marketing, LLC, et al., No. DC-15-06428, District Court of Dallas County, Texas, 95^th Judicial District. The plaintiffs, defendants, allegations, and damages sought are materially similar to those in the Yannick Gagné case, and plaintiffs state that this lawsuit is filed to preserve claims under the applicable two-year statute of limitations. Plaintiffs also filed a motion to stay proceedings in this case for 90 days pending the outcome of the global settlement discussions described above in the Yannick Gagné case. The court's order on this request for a stay is pending.

Note 11 – Share-Based Compensation

QEP issues stock options and restricted shares 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 expense over the vesting periods for the stock options, restricted shares, and performance share units. Deferred share-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 9.2 million shares available for future grants under the LTSIP at June 30, 2015. Share-based compensation expense related to continuing operations is recognized in “General and administrative” on the Condensed Consolidated Statements of Operations, and expenses related to discontinued operations (including compensation expense related to the QEP Midstream Long Term Incentive Plan) are reflected in "Net income from discontinued operations, net of income tax". During the three and six months ended June 30, 2015, QEP recognized $6.5 million and $15.6 million, respectively, in total compensation expense related to share-based compensation for continuing operations, compared to $5.9 million and $12.3 million, respectively, during the three and six months ended June 30, 2014. During the three and six months ended June 30, 2014, QEP recognized $1.2 million and $2.3 million, respectively, in total compensation expense related to share-based compensation for discontinued operations.

Stock Options

QEP uses the Black-Scholes-Merton mathematical model to estimate the fair value of stock option awards at the date of the grant. Fair-value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model is intended for measuring the value of options traded on an exchange. The Company utilizes the "simplified" method to estimate the expected term of the stock options granted as there is limited historical exercise data available in estimating the expected term of the stock options. QEP uses a historical volatility method to estimate the fair value of stock options awards and the risk-free interest rate is based on the yield on U.S. Treasury strips with maturities similar to those of the expected term of the stock options. The stock options typically vest in equal installments over a three-year period from the grant date and are exercisable immediately upon vesting through the seventh anniversary of the grant date. To fulfill options exercised, QEP either reissues treasury stock or issues new shares.

The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below for the six months ended June 30, 2015:



	Stock Option Assumptions
Weighted-average grant-date fair value of awards granted during the period	$	6.82
Weighted-average risk-free interest rate	1.38		%
Weighted-average expected price volatility	36.8		%
Expected dividend yield	0.37		%
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, 2014	1,996,215		$	28.60
Granted	425,877		21.69
Exercised	(15,000	)	19.37
Forfeited	(2,817	)	31.31
Canceled	(60,000	)	27.84
Outstanding at June 30, 2015	2,344,275		$	27.42	3.48	$	—
Options Exercisable at June 30, 2015	1,658,563		$	28.32	2.40	$	—
Unvested Options at June 30, 2015	685,712		$	25.23	6.12	$	—

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 and $0.5 million during the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015, $3.3 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.34 years.

Restricted Shares

Restricted share grants typically vest in equal installments over a three-year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The total fair value of restricted stock that vested during the six months ended June 30, 2015 and 2014, was $18.1 million and $15.2 million, respectively. The weighted average grant-date fair value of restricted stock was $21.66 per share and $31.63 per share for the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015, $33.0 million of unrecognized compensation cost related to restricted shares granted under the LTSIP is expected to be recognized over a weighted-average vesting period of 2.42 years.

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



	Restricted Shares Outstanding		Weighted- Average Grant-Date Fair Value
			(per share)
Unvested balance at December 31, 2014	1,426,453		$	31.02
Granted	1,373,300		21.66
Vested	(585,611	)	30.88
Forfeited	(83,590	)	27.54
Unvested balance at June 30, 2015	2,130,552		$	25.16

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 but have historically been delivered in cash at the end of the performance period. Beginning with awards granted in 2015, the Company has the option to settle earned awards in cash or shares of common stock under the Company's LTSIP; however, as of June 30, 2015, the Company expects to settle all awards in cash. The weighted average grant-date fair value of the performance share units was $21.69 per share and $31.67 per share for the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015, $2.5 million of unrecognized compensation cost, representing the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 2.09 years.

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



	Performance Share Units Outstanding		Weighted- Average Grant-Date Fair Value
Unvested balance at December 31, 2014	552,209		$	30.85
Granted	234,085		21.69
Vested and paid out	(131,665	)	30.77
Canceled ⁽¹⁾	(14,612	)	30.77
Forfeited	(6,792	)	28.29
Unvested balance at June 30, 2015	633,225		$	27.52

____________________________


⁽¹⁾	Represents units that were not paid out due to performance under the plan.

Note 12 – Employee Benefits

Pension and other postretirement benefits

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

The Pension Plan is a qualified, closed, defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. During the six months ended June 30, 2015, the Company made contributions of $2.0 million to the Pension Plan and does not expect to make additional contributions to the Pension Plan during 2015. Contributions to the Pension Plan increase plan assets.

As a result of the Company's 2014 divestitures and expected retirements in 2015, the number of participants in the Pension Plan is expected to fall below 50 employees by December 31, 2015, which is below the minimum number of participants for a plan to be qualified under the Internal Revenue Services' participation rules. In order to prevent disqualification, the Pension Plan was amended in June 2015 and will be frozen effective January 1, 2016, such that employees do not earn additional defined benefits for future services. This change resulted in a non-cash curtailment loss of $11.2 million recognized on the Condensed Consolidated Statements of Operations within "General and administrative" expense during the three and six months ended June 30, 2015.

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. During the six months ended June 30, 2015, the Company made contributions of $1.8 million to its SERP and expects to contribute an additional $2.6 million to its SERP during the remainder of 2015. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and will be closed to new participants effective, January 1, 2016.

The Medical Plan is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired employees. During the six months ended June 30, 2015, the Company made contributions of $0.2 million to its Medical Plan and expects to contribute an additional $0.2 million to its Medical Plan during the remainder of 2015. Contributions to the Medical Plan are used to fund current benefit payments.

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
	(in millions)
Pension Plan and SERP benefits
Service cost	$	0.4		$	0.7		$	1.0		$	1.4
Interest cost	1.1			1.4			2.4			2.8
Expected return on plan assets	(1.4		)	(1.2		)	(2.8		)	(2.4		)
Amortization of prior service costs ⁽¹⁾	0.1			1.2			0.9			2.5
Amortization of actuarial losses ⁽¹⁾	—			0.2			0.3			0.4
Curtailment loss ⁽²⁾	11.2			2.0			11.2			2.0
Special termination benefits ⁽³⁾	—			0.3			—			0.3
Periodic expense	$	11.4		$	4.6		$	13.0		$	7.0

Medical Plan benefits
Interest cost	$	—		$	0.1		$	0.1		$	0.2
Amortization of prior service costs ⁽¹⁾	0.1			0.1			0.1			0.2
Curtailment loss ⁽²⁾	—			0.4			—			0.4
Periodic expense	$	0.1		$	0.6		$	0.2		$	0.8

____________________________


⁽¹⁾	Amortization of prior service costs and actuarial losses out of accumulated other comprehensive income are recognized in the Condensed Consolidated Statements of Operations in "General and administrative."

⁽²⁾

A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. These expenses are included on the Condensed Consolidated Statements of Operations within "General and administrative" expense for the three and six months ended June 30, 2015, as the expenses incurred in that period related to the Pension Plan amendment (see above), and within "Net gain (loss) from asset sales" for the three and six months ended June 30, 2014, as the expenses incurred in that period related to the Midcontinent property sales (see Note 3 - Acquisitions and Divestitures).


⁽³⁾	During the three and six months ended June 30, 2014, the Company recognized special termination benefits on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales" as the expense related to the Midcontinent property sales (see Note 3 - Acquisitions and Divestitures).

During the three and six months ended June 30, 2015, for continuing operations, QEP recognized $11.5 million and $13.2 million, respectively, in employee benefit expense, compared to $4.1 million and $6.1 million, respectively, during the three and six months ended June 30, 2014. During the three and six months ended June 30, 2014, for discontinued operations, QEP recognized $1.1 million and $1.7 million, respectively, in employee benefit expense.

Note 13 – Operations by Line of Business

QEP’s lines of business include oil and gas exploration and production (QEP Energy); and oil and gas marketing, operation of the Haynesville Gathering System and an underground storage facility, and corporate (QEP Marketing and Other). The lines of business are managed separately and therefore the financial information is presented separately due to the distinct differences in the nature of operations of each line of business, among other factors.

Our financial results for the three and six months ended June 30, 2014, have been revised, in accordance with GAAP, to reflect the impact of the Midstream Sale. See Note 4 - Discontinued Operations for detailed information on the Midstream Sale.

The following table is a summary of operating results for the three months ended June 30, 2015, by line of business:



	QEP Energy			QEP Marketing and Other			Eliminations			QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	407.9		$	200.7		$	—		$	608.6
From affiliated customers	—			248.1			(248.1		)	—
Total Revenues	407.9			448.8			(248.1		)	608.6
OPERATING EXPENSES
Purchased gas and oil expense	16.8			445.4			(245.0		)	217.2
Lease operating expense	57.1			—			—			57.1
Gas, oil and NGL transportation and other handling costs	75.5			—			(2.5		)	73.0
Gathering and other expense	—			1.4			—			1.4
General and administrative	50.0			1.9			(0.6		)	51.3
Production and property taxes	31.2			1.5			—			32.7
Depreciation, depletion and amortization	213.2			2.6			—			215.8
Impairment and exploration expense	1.3			—			—			1.3
Total Operating Expenses	445.1			452.8			(248.1		)	649.8
Net gain (loss) from asset sales	26.5			(2.0		)	—			24.5
OPERATING INCOME (LOSS)	(10.7		)	(6.0		)	—			(16.7		)
Realized and unrealized gains (losses) on derivative contracts	(65.6		)	(0.4		)	—			(66.0		)
Interest and other income	3.1			53.1			(52.4		)	3.8
Interest expense	(52.6		)	(36.0		)	52.4			(36.2		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(125.8		)	10.7			—			(115.1		)
Income tax (provision) benefit	42.4			(3.6		)	—			38.8
NET INCOME (LOSS)	$	(83.4	)	$	7.1		$	—		$	(76.3	)

The following table is a summary of operating results for the three months ended June 30, 2014, by line of business:



	QEP Energy			QEP Marketing and Other			Eliminations			Discontinued Operations		QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	687.2		$	200.0		$	—		$	—	$	887.2
From affiliated customers	—			411.6			(411.6		)	—		—
Total Revenues	687.2			611.6			(411.6		)	—		887.2
OPERATING EXPENSES
Purchased gas and oil expense	50.1			605.4			(406.3		)	—		249.2
Lease operating expense	59.5			—			—			—		59.5
Gas, oil and NGL transportation and other handling costs	72.1			—			(4.6		)	—		67.5
Gathering and other expense	—			1.8			—			—		1.8
General and administrative	52.5			0.5			(0.7		)	—		52.3
Production and property taxes	53.1			0.4			—			—		53.5
Depreciation, depletion and amortization	232.3			2.9			—			—		235.2
Impairment and exploration expense	3.2			—			—			—		3.2
Total Operating Expenses	522.8			611.0			(411.6		)	—		722.2
Net gain (loss) from assets sales	(200.8		)	(0.1		)	—			—		(200.9		)
OPERATING INCOME (LOSS)	(36.4		)	0.5			—			—		(35.9		)
Realized and unrealized gains (losses) on derivative contracts	(85.3		)	(2.7		)	—			—		(88.0		)
Interest and other income	0.6			56.7			(56.5		)	—		0.8
Income from unconsolidated affiliates	0.1			—			—			—		0.1
Interest expense	(56.6		)	(44.9		)	56.5			—		(45.0		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(177.6		)	9.6			—			—		(168.0		)
Income tax (provision) benefit	67.2			(5.3		)	—			—		61.9
INCOME (LOSS) FROM CONTINUING OPERATIONS	(110.4		)	4.3			—			—		(106.1		)
Net income from discontinued operations, net of income tax	—			—			—			13.8		13.8
NET INCOME (LOSS)	$	(110.4	)	$	4.3		$	—		$	13.8	$	(92.3	)

The following table is a summary of operating results for the six months ended June 30, 2015, by line of business:



	QEP Energy			QEP Marketing and Other			Eliminations			QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	761.2		$	339.0		$	—		$	1,100.2
From affiliated customers	—			455.6			(455.6		)	—
Total Revenues	761.2			794.6			(455.6		)	1,100.2
OPERATING EXPENSES
Purchased gas and oil expense	48.0			788.2			(449.6		)	386.6
Lease operating expense	118.9			—			—			118.9
Gas, oil and NGL transportation and other handling costs	142.9			—			(4.8		)	138.1
Gathering and other expense	—			3.1			—			3.1
General and administrative	96.2			3.7			(1.2		)	98.7
Production and property taxes	58.7			1.8			—			60.5
Depreciation, depletion and amortization	405.9			5.3			—			411.2
Impairment and exploration expense	22.4			—			—			22.4
Total Operating Expenses	893.0			802.1			(455.6		)	1,239.5
Net gain (loss) from asset sales	(1.3		)	(4.7		)	—			(6.0		)
OPERATING INCOME (LOSS)	(133.1		)	(12.2		)	—			(145.3		)
Realized and unrealized gains (losses) on derivative contracts	14.6			0.3			—			14.9
Interest and other income (expense)	(0.4		)	101.1			(99.5		)	1.2
Interest expense	(99.8		)	(72.7		)	99.5			(73.0		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(218.7		)	16.5			—			(202.2		)
Income tax (provision) benefit	76.0			(5.7		)	—			70.3
NET INCOME (LOSS)	$	(142.7	)	$	10.8		$	—		$	(131.9	)

The following table is a summary of operating results for the six months ended June 30, 2014, by line of business:



	QEP Energy			QEP Marketing and Other			Eliminations			Discontinued Operations		QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	1,300.4		$	404.3		$	—		—		$	1,704.7
From affiliated customers	—			715.1			(715.1		)	—		$	—
Total Revenues	1,300.4			1,119.4			(715.1		)	—		1,704.7
OPERATING EXPENSES
Purchased gas and oil expense	88.1			1,103.3			(704.3		)	—		487.1
Lease operating expense	115.9			—			—			—		115.9
Gas, oil and NGL transportation and other handling costs	136.6			—			(9.2		)	—		127.4
Gathering and other expense	—			3.4			—			—		3.4
General and administrative	97.5			1.7			(1.6		)	—		97.6
Production and property taxes	100.5			0.9			—			—		101.4
Depreciation, depletion and amortization	455.7			5.4			—			—		461.1
Impairment and exploration expense	7.4			—			—			—		7.4
Total Operating Expenses	1,001.7			1,114.7			(715.1		)	—		1,401.3
Net gain (loss) from assets sales	(198.4		)	(0.1		)	—			—		(198.5		)
OPERATING INCOME (LOSS)	100.3			4.6			—			—		104.9
Realized and unrealized gains (losses) on derivative contracts	(163.8		)	(5.1		)	—			—		(168.9		)
Interest and other income	3.5			105.5			(105.3		)	—		3.7
Income from unconsolidated affiliates	0.1			—			—			—		0.1
Interest expense	(105.5		)	(86.7		)	105.3			—		(86.9		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(165.4		)	18.3			—			—		(147.1		)
Income tax (provision) benefit	60.1			(6.4		)	—			—		53.7
INCOME (LOSS) FROM CONTINUING OPERATIONS	(105.3		)	11.9			—			—		(93.4		)
Net income from discontinued operations, net of income tax	—			—			—			40.8		40.8
NET INCOME (LOSS)	$	(105.3	)	$	11.9		$	—		$	40.8	$	(52.6	)

Note 14 - Subsequent Events

On July 30, 2015, QEP Resources announced the closing of its regional office in Tulsa, Oklahoma. Closing the Tulsa office will result in all of the Company’s technical and commercial teams being located at QEP’s headquarters in Denver, Colorado. Restructuring costs are estimated to be approximately $6.0 million to $10.0 million, the majority of which are expected to be incurred during the year ended December 31, 2015. Although management believes this range of estimated cost is reasonable, actual results could differ depending on final results of the restructuring and potential lease termination costs.

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

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

The following information updates the discussion of QEP’s financial condition provided in its 2014 Annual Report on Form 10-K/A filing and analyzes the changes in the results of operations between the three and six months ended June 30, 2015 and 2014. For definitions of commonly used oil and gas terms found in this Quarterly Report on Form 10-Q, please refer to the “Glossary of Commonly Used Terms” provided in QEP’s 2014 Annual Report on Form 10-K/A.

Our MD&A focuses on our continuing operations. Discontinued operations are excluded from our MD&A except as indicated otherwise.

OVERVIEW

Strategies

We seek to create value for our shareholders through returns-focused growth, superior execution and a low-cost structure. To achieve these objectives we strive to:


•	operate in a safe and environmentally responsible manner;


•	allocate capital to those projects that generate the highest returns;


•	acquire businesses and assets that complement or expand our current business;


•	maintain a sustainable, diverse inventory of low-cost, high-margin resource plays;


•	be in the highest-potential areas of the resource plays in which we operate;


•	build contiguous acreage positions that drive operating efficiencies;


•	be the operator of our assets, whenever possible;


•	be the low-cost driller and producer in each area where we operate;


•	actively market our production to maximize value;


•	utilize derivative contracts to mitigate the impact of gas, oil or NGL price volatility and fluctuating interest rates and to lock in acceptable cash flows required to support future capital expenditures;


•	attract and retain the best people; and


•	maintain a capital structure that allows us the necessary financial flexibility with which to invest in organic growth and potential acquisition opportunities, as they may arise.

In response to the current commodity price environment, we are reducing drilling and completion activities, slowing production growth, and preserving liquidity. We have reduced QEP operated drilling rigs to eight rigs at the end of the second quarter of 2015 compared to a high of 21 during 2014. We have reduced our annual capital expenditure budget for 2015 to approximately $975.0 million from $2.7 billion in 2014 (which included $941.8 million for the Permian Basin Acquisition (defined below)). We are highly focused on driving improved operating performance by optimizing reservoir development, enhancing well completion designs and aggressively pursuing cost reductions.

On December 2, 2014, QEP completed the sale of its midstream business; see "Discontinued Operations" below. QEP believes this transaction represents a significant milestone in the strategic repositioning of the Company, as it will be better positioned to deliver continued growth by focusing on its exploration and production assets.

Discontinued Operations

In October 2014, the Company announced that its wholly owned subsidiary, QEP Field Services Company (QEP Field Services), had entered into a definitive agreement to sell substantially all of its midstream business, including the Company's ownership interest in QEP Midstream Partners, LP (QEP Midstream), to Tesoro Logistics LP (Tesoro). On December 2, 2014, QEP closed the sale of its midstream business to Tesoro (Midstream Sale) for total cash proceeds of approximately $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, subject to post-closing adjustments, and QEP recorded a pre-tax gain of approximately $1.8 billion for the year ended December 31, 2014. QEP Marketing retained ownership of the Haynesville Gathering System. As a result of the Midstream Sale, the QEP Field Services reporting segment, excluding the retained ownership of the Haynesville Gathering System, has been classified as a discontinued operation on the Condensed Consolidated Statement of Operations and the Notes accompanying the Condensed Consolidated Financial Statements. For reporting purposes, the retained Haynesville Gathering System has been combined with QEP Marketing and Other.

Acquisitions

While QEP believes that it can grow production and reserves from its extensive inventory of identified drilling locations, 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 its low-cost operating model and financial strength, enhance its ability to pursue acquisition opportunities.

Divestitures

The Company periodically divests select non-core portfolio assets. In December 2014, QEP sold its interest in certain non-core properties in southern Oklahoma for aggregate proceeds of approximately $96.3 million, subject to post-closing purchase price adjustments. In June 2014, QEP sold its interests in certain non-core properties in the Midcontinent area and other non-core assets in the Williston Basin for aggregate proceeds of approximately $668.2 million, subject to post-closing purchase price adjustments. The Company used the proceeds to repay borrowings on its revolving credit facility incurred to fund the Permian Basin Acquisition.

Outlook

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 has a large inventory of lower-risk, predictable development drilling locations across its acreage holdings in the onshore United States that provide a solid base for growth in organic production and reserves.

In January 2014, QEP's Board of Directors authorized the repurchase of up to $500.0 million of the Company's outstanding shares of common stock. This program was extended through December 2015. The timing and amount of any QEP share repurchases will depend upon a number of factors, including general market conditions, the Company’s financial position and the estimated intrinsic value of the Company’s shares. The repurchase plan does not obligate QEP to acquire any specific number of shares and may be discontinued at any time. During the three and six months ended June 30, 2015, no shares were repurchased under this plan.

Financial and Operating Results

QEP Energy reported total equivalent production of 80.9 Bcfe during the second quarter of 2015 and 156.1 Bcfe during the first half of 2015, decreases of 4% and 1%, respectively, compared to the same periods of 2014. Gas production decreased to 44.5 Bcf and 87.1 Bcf in the second quarter and first half of 2015, respectively, decreases of 8% and 6% from the second quarter and first half of 2014, respectively. Additionally, NGL production decreased to 1,198.0 Mbbls and 2,145.4 Mbbls in the second quarter and first half of 2015, respectively, decreases of 36% and 38% from the second quarter and first half of 2014, respectively. These decreases were primarily driven by decreased production in the Midcontinent due to the divestitures of non-core properties during the second and fourth quarters of 2014. Additionally, Pinedale and Uinta NGL volumes decreased due to ethane rejection in the first half of 2015 compared to ethane recovery in the first half of 2014. These decreases were partially offset by an increase in oil production to 4,875.9 Mbbls in the second quarter of 2015 and 9,357.3 Mbbls during the first half of 2015, increases of 22% and 28%, respectively, compared to the same periods of 2014. Continuing development of properties in the Williston Basin contributed oil production of 3,769.2 Mbbls and 7,200.7 Mbbls in the second quarter and first half of 2015, respectively, compared to 2,831.5 Mbbls and 5,351.7 Mbbls in the second quarter and first half of 2014, respectively. Additionally, QEP Energy completed the Permian Basin Acquisition on February 25, 2014, which contributed 628.1 Mbbls and 1,199.9 Mbbls of oil production in the second quarter and first half of 2015, respectively, compared to 418.2 Mbbls and 558.2 Mbbls of oil production during the second quarter and first half of 2014, respectively, due to development of the area and because production results included six months of production in 2015 compared to four months of production in 2014. Average realized prices (including the impact of settled commodity derivatives) decreased 18% to $5.94 per Mcfe during the second quarter of 2015 and 20% to $5.79 during the first half of 2015 due primarily to decreases in gas, oil and NGL prices compared to the second quarter and first half of 2014.

Factors Affecting Results of Operations

Oil, Gas, and NGL Prices

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 activity and related capital expenditures, liquidity, rate of growth, costs of goods and services required to drill and complete wells, and the carrying value of its oil and natural gas properties. Historically, field-level prices received for QEP's gas, oil and NGL production have been volatile and unpredictable, and that volatility is expected to continue. In recent years, domestic crude oil and natural gas supplies have grown dramatically, driven by advances in drilling and completion technologies, including horizontal drilling and multi-stage hydraulic fracturing. These changes have allowed producers to extract increased quantities of hydrocarbons from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supplies, particularly in the eastern portion of the country, have resulted in downward pressure on U.S. natural gas prices and a high degree of pricing variability among different regional natural gas pricing hubs. High natural gas demand in 2014, driven primarily by unusually cold winter weather, resulted in improved natural gas prices in the first half of 2014, but continued growth in production, a more normal winter during 2014 and 2015, and adequate storage levels led to natural gas price declines later in the year and into 2015. Similarly, growth in U.S. oil production combined with global crude oil supplies that exceed global demand and other factors, such as a strong U.S. dollar, have led to a dramatic weakening of global oil prices starting in late 2014, which has continued into 2015. NGL prices have also been affected by increased U.S. hydrocarbon production and insufficient export capacity. Prices of heavier NGL components, typically correlated to crude oil prices, have declined consistently with weakening oil prices, while ethane and propane prices have decreased as a result of growing North American oversupply. In addition, QEP's NGL prices are affected by ethane recovery and rejection. When ethane is recovered as a discrete NGL component instead of being sold as part of the natural gas stream, the average sales price of an NGL barrel decreases as the ethane price is generally lower than the prices of the remaining NGL components. QEP recovered ethane for the majority of 2014 but rejected ethane in the first half of 2015 and expects to continue to reject ethane throughout 2015 as gas processing economics do not support recovery of ethane from the natural gas stream.

During 2014, the NYMEX-WTI oil monthly average spot price ranged from a high of $105.79 per bbl in June 2014 to a low of $59.29 per bbl in December 2014, while the NYMEX-HH natural gas one-month future price ranged from a high of $5.15 per MMBtu in February 2014 to a low of $3.65 per MMBtu in November 2014. Prices continue to be volatile in 2015 as the NYMEX-WTI oil monthly average spot price fell to a low of $43.39 per bbl in March 2015 and the NYMEX-HH natural gas

one-month future price fell to a low of $2.49 per MMBtu in April 2015. 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 decreased 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% of its forecasted annual production by the end of the first quarter of each fiscal year. At June 30, 2015, assuming forecasted 2015 annual production of 306 Bcfe, QEP Energy had approximately 57% of its forecasted gas equivalent production for the remainder of 2015 covered with fixed-price swaps, including 65% of its forecasted gas production and 56% of its forecasted oil production. See Part 1, Item 3 “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk Management” for further details concerning QEP’s commodity derivatives transactions. QEP Energy has allocated approximately 96% of its forecasted 2015 drilling and completion capital expenditure budget to oil and liquids-rich gas projects in its portfolio.

Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the global economy, including Europe's economic outlook; political unrest in Eastern Europe, the Middle East, and Africa; slowing growth in Asia, particularly in China; the United States' federal budget deficit; changes in regulatory oversight policy; commodity price volatility; the potential impact of rising 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 and prices, 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.

Supply, Demand and Other Market Risk Factors

During the last five years, the U.S. natural gas directed drilling rig count has decreased as producers reduced drilling activity for dry natural gas in response to lower natural gas prices and directed investment toward oil and liquid-rich projects. Over the same period of time, U.S. natural gas production has continued to grow, particularly in the Marcellus Shale region, as efficiency gains have allowed more wells to be drilled and completed per operating rig, higher per-well natural gas production from horizontal wells as a result of investment focused on more prolific resources, and increased amounts of natural gas produced in association with crude oil. As a result, U.S. natural gas production continued to increase into 2015, despite the gradually decreasing rig-count. Strong natural gas demand from electric power generation, cold winter weather during the 2013-2014 heating season, and other demand sources caused a general firming of natural gas prices during the second half of 2013 and into 2014. Natural gas prices weakened in the second half of 2014 and through the first half of 2015 due to more typical winter season demand levels and continued increases in supply. QEP expects U.S. natural gas prices to remain range-bound over the near term. Relatively low natural gas prices in recent years have caused U.S. E&P companies, including QEP, to shift capital investments away from predominantly dry gas areas toward plays that produce crude oil, condensate and liquids-rich gas. This shift in focus has caused domestic NGL production to increase dramatically. Increased NGL production and price dislocations from infrastructure bottlenecks in certain regions have all contributed to a weakening of domestic NGL prices, particularly ethane and, more recently, propane. QEP expects that ethane prices will continue to be range-bound until new ethylene crackers and export facilities are built. Propane prices have declined as a result of abnormally high inventory levels. An increase in exports and typical seasonal demand is expected to draw down propane inventories to more normal levels over the coming year. The prices of heavier components of the NGL barrel have weakened as a result of the decline in crude oil prices.

Increased oil production in the U.S. combined with various other factors has led to weaker oil prices. According to data from the Energy Information Agency, U.S. oil production has increased by more than four million barrels per day, or more than 70%, since 2011. International oil supply disruptions in recent years have prevented oversupply and a corresponding negative price impact, but reduced supply disruptions over the last year combined with softening global demand, a stronger U.S. dollar, and other factors have led to substantially lower oil prices starting in late 2014 that have continued into 2015. As a result, many oil producers around the world are dramatically reducing activity. QEP anticipates global oil prices will improve in the coming years as supply growth moderates due to lower level of investment and modest demand increases. Disruption to the global oil supply system, political and/or economic instability, fluctuations in currency values, and/or other factors could trigger additional volatility in oil prices. In addition, transportation, refining, or other infrastructure constraints could introduce significant price differentials between regional markets where QEP sells its production and national (NYMEX HH at Henry Hub or NYMEX WTI at Cushing) and global (ICE Brent) markets. Because of the global and regional price volatility and the uncertainty around the natural gas, oil and NGL price environments, QEP continues to manage its capital spending program and liquidity accordingly and has scaled back its capital expenditure budget and drilling and completion activities for 2015.

Potential for Future Asset Impairments

The carrying value of the Company's properties is sensitive to declines in gas, oil and NGL prices. These assets are at risk of impairment if future prices for gas, oil 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 oil, gas and NGL production, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward gas, oil or NGL prices alone could result in an impairment of properties. During the year ended December 31, 2014, the Company recorded impairments of $1.1 billion primarily due to impairments of proved property in the Southern Region associated with lower future prices as of December 31, 2014. Additionally, the Company recorded $20.5 million of impairment expense during the first half of 2015, of which $19.4 million was related to proved properties due to lower future prices and $1.1 million was related to expiring leaseholds on unproved properties. If commodity prices decline further during 2015, 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 completed and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the commencement of production, which may cause volatility in QEP’s quarterly operating results.

Critical Accounting Estimates

QEP’s significant accounting policies are described in Item 8 of Part II of its 2014 Annual Report on Form 10-K/A. 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 oil and gas properties, asset retirement obligations, accounting for derivative contracts, revenue recognition, environmental obligations, litigation and other contingencies, benefit plan obligations, 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.

RESULTS OF OPERATIONS

Our financial results for 2014 and for prior periods have been revised, in accordance with GAAP, to reflect the impact of the Midstream Sale. See Note 4 - Discontinued Operations, in Item I of Part I of this Quarterly Report on Form 10-Q for detailed information on the Midstream Sale.

Net Income

QEP generated a net loss from continuing operations during the second quarter of 2015 of $76.3 million, or $0.43 per diluted share, compared to a net loss from continuing operations of $106.1 million, or $0.59 per diluted share, in the second quarter of 2014. The change in the second quarter of 2015 compared to the second quarter of 2014 was due to a $27.0 million decrease in QEP Energy’s net loss and a $2.8 million increase in QEP Marketing and Other's net income. QEP Energy's net loss decrease was primarily due to a $200.8 million net loss from asset sales in the second quarter of 2014 compared to a $26.5 million net gain from asset sales in the second quarter of 2015. Additionally, QEP recognized realized derivative instrument gains in the second quarter of 2015 compared to realized losses in the second quarter of 2014, as well as increased oil production and lower operating expenses in the second quarter of 2015 compared to the second quarter of 2014. These increases were partially offset by decreases in average field-level prices for gas, oil and NGL, decreased gas and NGL production and larger unrealized derivative losses. QEP Marketing and Other's net income increased in the second quarter of 2015 primarily due to a lower interest expense in the second quarter of 2015 compared to the second quarter of 2014 due to lower average debt levels, partially offset by a net loss from asset sales of $2.0 million in the second quarter of 2015 related to purchase price adjustments for the Midstream Sale and a lower resale margin in the second quarter of 2015 compared to the second quarter of 2014.

QEP generated a net loss from continuing operations during the first half of 2015 of $131.9 million, or $0.75 per diluted share, compared to a net loss from continuing operations of $93.4 million, or $0.52 per diluted share, in the first half of 2014. The change in the first half of 2015 compared to the first half of 2014 was due to a $37.4 million increase in QEP Energy’s net loss and a $1.1 million decrease in QEP Marketing and Other's net income. QEP Energy's net loss increase was primarily due to decreases in average field-level prices for gas, oil and NGL and decreased gas and NGL production. These decreases were partially offset by realized derivative instrument gains in the first half of 2015 compared to realized losses in the first half of 2014, a $198.4 million net loss from asset sales in the first half of 2014 compared to a net loss from asset sales of $1.3 million in the first half of 2015, as well as increased oil production and lower operating expenses in the first half of 2015 compared to the first half of 2014. QEP Marketing and Other's net income decreased in the first half of 2015 primarily due to a lower resale margin and a net loss from asset sales of $4.7 million during the first half of 2015 related to purchase price adjustments for the Midstream Sale, partially offset by lower interest expense due to lower average debt levels during the first half of 2015.

The following table provides a summary of net income (loss) by line of business:



	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Change			2015			2014			Change
	(in millions, except per share amounts)
QEP Energy	$	(83.4	)	$	(110.4	)	$	27.0		$	(142.7	)	$	(105.3	)	$	(37.4	)
QEP Marketing and Other	7.1			4.3			2.8			10.8			11.9			(1.1		)
Net income (loss) from continuing operations	(76.3		)	(106.1		)	29.8			(131.9		)	(93.4		)	(38.5		)
Net income from discontinued operations, net of income tax	—			13.8			(13.8		)	—			40.8			(40.8		)
Net income (loss)	$	(76.3	)	$	(92.3	)	$	16.0		$	(131.9	)	$	(52.6	)	$	(79.3	)
Diluted earnings per share from continuing operations	$	(0.43	)	$	(0.59	)	$	0.16		$	(0.75	)	$	(0.52	)	$	(0.23	)
Diluted earnings per share from discontinued operations	—			0.08			(0.08		)	—			0.23			(0.23		)
Diluted earnings per share	$	(0.43	)	$	(0.51	)	$	0.08		$	(0.75	)	$	(0.29	)	$	(0.46	)
Average diluted shares	176.7			180.1			(3.4		)	176.4			179.9			(3.5		)

Adjusted EBITDA

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. Management defines Adjusted EBITDA as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment, and certain other non-cash and/or non-recurring items.

The following table provides a summary of Adjusted EBITDA by line of business:



	Three Months Ended June 30,								Six Months Ended June 30,
	2015			2014		Change			2015		2014		Change
	(in millions)
QEP Energy	$	280.9		$	366.5	$	(85.6	)	$	502.0	$	695.1	$	(193.1	)
QEP Marketing and Other	(1.5		)	1.7		(3.2		)	0.2		6.2		(6.0		)
Adjusted EBITDA from continuing operations	279.4			368.2		(88.8		)	502.2		701.3		(199.1		)
Adjusted EBITDA from discontinued operations	—			32.6		(32.6		)	—		85.8		(85.8		)
Adjusted EBITDA	$	279.4		$	400.8	$	(121.4	)	$	502.2	$	787.1	$	(284.9	)

Adjusted EBITDA from continuing operations decreased to $279.4 million in the second quarter of 2015 from $368.2 million in the second quarter of 2014, due to a 37% decrease in the average equivalent field-level price as well as an 8% decrease in gas production and a 36% decrease in NGL production, partially offset by a 22% increase in oil production and higher realized gains on derivative contracts.

Adjusted EBITDA from continuing operations decreased to $502.2 million in the first half of 2015 from $701.3 million in the first half of 2014, due to a 41% decrease in the average equivalent field-level price as well as a 6% decrease in gas production

and a 38% decrease in NGL production, partially offset by a 28% increase in oil production and higher realized gains on derivative contracts.

The following tables are reconciliations of Adjusted EBITDA to net income, the most comparable GAAP financial measures:



	QEP Energy			QEP Marketing and Other⁽¹⁾			Continuing Operations			Discontinued Operations		QEP Consolidated
Three Months Ended June 30, 2015	(in millions)
Net income (loss)	$	(83.4	)	$	7.1		$	(76.3	)	$	—	$	(76.3	)
Unrealized (gains) losses on derivative contracts	158.2			0.1			158.3			—		158.3
Net (gain) loss from asset sales	(26.5		)	2.0			(24.5		)	—		(24.5		)
Interest and other (income) expense	(3.1		)	(0.7		)	(3.8		)	—		(3.8		)
Income tax provision (benefit)	(42.4		)	3.6			(38.8		)	—		(38.8		)
Interest expense (income)	52.6			(16.4		)	36.2			—		36.2
Pension curtailment loss ⁽²⁾	11.0			0.2			11.2			—		11.2
Depreciation, depletion and amortization	213.2			2.6			215.8			—		215.8
Impairment	0.5			—			0.5			—		0.5
Exploration expenses	0.8			—			0.8			—		0.8
Adjusted EBITDA	$	280.9		$	(1.5	)	$	279.4		$	—	$	279.4

Three Months Ended June 30, 2014
Net income (loss)	$	(110.4	)	$	4.3		$	(106.1	)	13.8		$	(92.3	)
Unrealized (gains) losses on derivative contracts	51.8			0.9			52.7			—		52.7
Net (gain) loss from asset sales	200.8			0.1			200.9			0.1		201.0
Interest and other (income) expense	(0.6		)	(0.2		)	(0.8		)	—		(0.8		)
Income tax provision (benefit)	(67.2		)	5.3			(61.9		)	7.7		(54.2		)
Interest expense (income) ⁽³⁾	56.6			(11.6		)	45.0			0.5		45.5
Depreciation, depletion and amortization ⁽⁴⁾	232.3			2.9			235.2			10.5		245.7
Impairment	1.5			—			1.5			—		1.5
Exploration expenses	1.7			—			1.7			—		1.7
Adjusted EBITDA	$	366.5		$	1.7		$	368.2		$	32.6	$	400.8

Six Months Ended June 30, 2015
Net income (loss)	$	(142.7	)	$	10.8		$	(131.9	)	$	—	$	(131.9	)
Unrealized (gains) losses on derivative contracts	179.9			1.9			181.8			—		181.8
Net loss from asset sales	1.3			4.7			6.0			—		6.0
Interest and other (income) expense	0.4			(1.6		)	(1.2		)	—		(1.2		)
Income tax provision (benefit)	(76.0		)	5.7			(70.3		)	—		(70.3		)
Interest expense (income)	99.8			(26.8		)	73.0			—		73.0
Pension curtailment loss ⁽²⁾	11.0			0.2			11.2			—		11.2
Depreciation, depletion and amortization	405.9			5.3			411.2			—		411.2
Impairment	20.5			—			20.5			—		20.5
Exploration expenses	1.9			—			1.9			—		1.9
Adjusted EBITDA	$	502.0		$	0.2		$	502.2		$	—	$	502.2



	QEP Energy			QEP Marketing and Other⁽¹⁾			Continuing Operations			Discontinued Operations		QEP Consolidated
Six Months Ended June 30, 2014
Net income (loss)	$	(105.3	)	$	11.9		$	(93.4	)	40.8		$	(52.6	)
Unrealized (gains) losses on derivative contracts	97.0			1.2			98.2			—		98.2
Net (gain) loss from asset sales	198.4			0.1			198.5			0.1		198.6
Interest and other (income) expense	(3.5		)	(0.2		)	(3.7		)	—		(3.7		)
Income tax provision (benefit)	(60.1		)	6.4			(53.7		)	22.9		(30.8		)
Interest expense (income) ⁽³⁾	105.5			(18.6		)	86.9			0.9		87.8
Depreciation, depletion and amortization ⁽⁴⁾	455.7			5.4			461.1			21.1		482.2
Impairment	3.5			—			3.5			—		3.5
Exploration expenses	3.9			—			3.9			—		3.9
Adjusted EBITDA	$	695.1		$	6.2		$	701.3		$	85.8	$	787.1

____________________________


⁽¹⁾	Includes intercompany eliminations.

⁽²⁾

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


⁽³⁾	Excludes noncontrolling interest's share of $0.2 million and $0.4 million during the three and six months ended June 30, 2014, respectively, of interest expense attributable to QEP Midstream.


⁽⁴⁾	Excludes noncontrolling interest's share of $4.0 million and $7.7 million during the three and six months ended June 30, 2014, respectively, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C and QEP Midstream.

QEP ENERGY

The following table provides a summary of QEP Energy’s financial and operating results:



	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Change			2015			2014			Change
REVENUES	(in millions)
Gas sales	$	112.0		$	215.1		$	(103.1	)	$	234.0		$	437.6		$	(203.6	)
Oil sales	250.3			358.5			(108.2		)	429.1			647.2			(218.1		)
NGL sales	26.0			64.8			(38.8		)	45.0			127.9			(82.9		)
Purchased gas sales	16.3			49.8			(33.5		)	47.8			86.9			(39.1		)
Other	3.3			(1.0		)	4.3			5.3			0.8			4.5
Total Revenues	407.9			687.2			(279.3		)	761.2			1,300.4			(539.2		)
OPERATING EXPENSES
Purchased gas expense	16.8			50.1			(33.3		)	48.0			88.1			(40.1		)
Lease operating expense	57.1			59.5			(2.4		)	118.9			115.9			3.0
Gas, oil and NGL transportation and other handling costs	75.5			72.1			3.4			142.9			136.6			6.3
General and administrative	50.0			52.5			(2.5		)	96.2			97.5			(1.3		)
Production and property taxes	31.2			53.1			(21.9		)	58.7			100.5			(41.8		)
Depreciation, depletion and amortization	213.2			232.3			(19.1		)	405.9			455.7			(49.8		)
Exploration expenses	0.8			1.7			(0.9		)	1.9			3.9			(2.0		)
Impairment	0.5			1.5			(1.0		)	20.5			3.5			17.0
Total Operating Expenses	445.1			522.8			(77.7		)	893.0			1,001.7			(108.7		)
Net gain (loss) from asset sales	26.5			(200.8		)	227.3			(1.3		)	(198.4		)	197.1
OPERATING INCOME (LOSS)	(10.7		)	(36.4		)	25.7			(133.1		)	100.3			(233.4		)
Realized gains (losses) on derivative instruments	92.6			(33.5		)	126.1			194.5			(66.8		)	261.3
Unrealized gains (losses) on derivative instruments	(158.2		)	(51.8		)	(106.4		)	(179.9		)	(97.0		)	(82.9		)
Interest and other income (expense)	3.1			0.6			2.5			(0.4		)	3.5			(3.9		)
Income from unconsolidated affiliates	—			0.1			(0.1		)	—			0.1			(0.1		)
Interest expense	(52.6		)	(56.6		)	4.0			(99.8		)	(105.5		)	5.7
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(125.8		)	(177.6		)	51.8			(218.7		)	(165.4		)	(53.3		)
Income tax (provision) benefit	42.4			67.2			(24.8		)	76.0			60.1			15.9
NET INCOME (LOSS)	$	(83.4	)	$	(110.4	)	$	27.0		$	(142.7	)	$	(105.3	)	$	(37.4	)

Production volumes (Bcfe)
Northern Region
Pinedale	24.9			25.3			(0.4		)	46.7			46.2			0.5
Williston Basin	28.6			19.4			9.2			54.0			36.2			17.8
Uinta Basin	7.3			6.8			0.5			14.2			13.0			1.2
Other Northern	2.4			3.5			(1.1		)	5.1			6.0			(0.9		)
Southern Region
Haynesville/Cotton Valley	10.4			13.1			(2.7		)	22.1			27.5			(5.4		)
Permian Basin	6.2			4.2			2.0			11.1			5.4			5.7
Midcontinent	1.1			11.6			(10.5		)	2.9			23.3			(20.4		)
Total production	80.9			83.9			(3.0		)	156.1			157.6			(1.5		)
Total equivalent prices (per Mcfe)
Average equivalent field-level price	$	4.80		$	7.62		$	(2.82	)	$	4.54		$	7.70		$	(3.16	)
Commodity derivative impact	1.14			(0.40		)	1.54			1.25			(0.42		)	1.67
Net realized equivalent price	$	5.94		$	7.22		$	(1.28	)	$	5.79		$	7.28		$	(1.49	)

Revenue, Volume and Price Variance Analysis

The following table shows volume and price related changes for each of QEP Energy’s major revenue categories for the three and six months ended June 30, 2015, compared to the three and six months ended June 30, 2014:



	Gas			Oil			NGL			Total
	(in millions)
QEP Energy Production Revenues
Three months ended June 30, 2014 Revenues	$	215.1		$	358.5		$	64.8		$	638.4
Changes associated with volumes ⁽¹⁾	(18.0		)	80.6			(23.6		)	39.0
Changes associated with prices ⁽²⁾	(85.1		)	(188.8		)	(15.2		)	(289.1		)
Three months ended June 30, 2015 Revenues	$	112.0		$	250.3		$	26.0		$	388.3

QEP Energy Production Revenues
Six months ended June 30, 2014 Revenues	$	437.6		$	647.2		$	127.9		$	1,212.7
Changes associated with volumes ⁽¹⁾	(28.4		)	183.2			(48.5		)	106.3
Changes associated with prices ⁽²⁾	(175.2		)	(401.3		)	(34.4		)	(610.9		)
Six months ended June 30, 2015 Revenues	$	234.0		$	429.1		$	45.0		$	708.1

____________________________


⁽¹⁾	The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three and six months ended June 30, 2015, as compared to the three and six months ended June 30, 2014, by the average field-level price for the three and six months ended June 30, 2014.

⁽²⁾

The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level prices from the three and six months ended June 30, 2015, as compared to the three and six months ended June 30, 2014, by volumes for the three and six months ended June 30, 2015. Pricing changes are driven by changes in commodity field-level prices, excluding the impact from commodity derivatives.

Gas Volumes and Prices



	Three Months Ended June 30,								Six Months Ended June 30,
	2015		2014			Change			2015		2014			Change
Gas production volumes (Bcf)
Northern Region
Pinedale	21.5		19.1			2.4			40.5		35.0			5.5
Williston Basin	3.0		1.2			1.8			5.7		1.9			3.8
Uinta Basin	5.7		4.3			1.4			10.6		8.4			2.2
Other Northern	2.1		2.9			(0.8		)	4.5		5.1			(0.6		)
Southern Region
Haynesville/Cotton Valley	10.3		13.0			(2.7		)	21.9		27.3			(5.4		)
Permian Basin	1.2		0.9			0.3			1.9		1.1			0.8
Midcontinent	0.7		7.2			(6.5		)	2.0		14.3			(12.3		)
Total production	44.5		48.6			(4.1		)	87.1		93.1			(6.0		)
Gas prices (per Mcf)
Northern Region	$	2.49	$	4.44		$	(1.95	)	$	2.66	$	4.75		$	(2.09	)
Southern Region	2.59		4.40			(1.81		)	2.75		4.65			(1.90		)
Average field-level price	$	2.52	$	4.42		$	(1.90	)	$	2.69	$	4.70		$	(2.01	)
Commodity derivative impact	0.63		(0.17		)	0.80			0.53		(0.31		)	0.84
Net realized price	$	3.15	$	4.25		$	(1.10	)	$	3.22	$	4.39		$	(1.17	)

Gas revenues decreased $103.1 million, or 48%, in the second quarter of 2015 when compared to the second quarter of 2014 due to lower field-level prices and lower gas production. Average field-level gas prices decreased 43% in the second quarter of 2015 compared to the second quarter of 2014 driven by a decrease in average NYMEX-HH natural gas prices for the comparable period. The decrease in production was primarily driven by the divestitures of non-core Midcontinent properties in

the second and fourth quarters of 2014 and a production decrease in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program. These production decreases were partially offset by production increases in Pinedale due to additional 2014 net well completions in which QEP had higher net revenue interest, in the Williston Basin due to continued development and in the Uinta Basin due to higher performing well completions.

Gas revenues decreased $203.6 million, or 47%, in the first half of 2015 when compared to the first half of 2014 due to lower field-level prices and lower gas production. Average field-level gas prices decreased 43% in the first half of 2015 compared to the first half of 2014 driven by a decrease in average NYMEX-HH natural gas prices for the comparable period. The decrease in production was primarily driven by the divestitures of non-core Midcontinent properties in the second and fourth quarters of 2014 and a production decrease in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program. These production decreases were partially offset by production increases in Pinedale due to additional 2014 net well completions in which QEP had higher net revenue interest, in the Williston Basin due to continued development, and in the Uinta Basin due to higher performing well completions.

Oil Volumes and Prices



	Three Months Ended June 30,								Six Months Ended June 30,
	2015		2014			Change			2015		2014			Change
Oil production volumes (Mbbls)
Northern Region
Pinedale	176.0		159.7			16.3			321.5		292.8			28.7
Williston Basin	3,769.2		2,831.5			937.7			7,200.7		5,351.7			1,849.0
Uinta Basin	202.0		229.9			(27.9		)	423.6		442.3			(18.7		)
Other Northern	44.3		92.0			(47.7		)	89.4		141.1			(51.7		)
Southern Region
Haynesville/Cotton Valley	8.9		11.4			(2.5		)	16.7		20.6			(3.9		)
Permian Basin	628.1		418.2			209.9			1,199.9		558.2			641.7
Midcontinent	47.4		237.9			(190.5		)	105.5		485.9			(380.4		)
Total production	4,875.9		3,980.6			895.3			9,357.3		7,292.6			2,064.7
Oil prices (per bbl)
Northern Region	$	50.60	$	88.93		$	(38.33	)	$	44.93	$	87.81		$	(42.88	)
Southern Region	55.85		95.68			(39.83		)	51.47		94.23			(42.76		)
Average field-level price	$	51.34	$	90.06		$	(38.72	)	$	45.86	$	88.74		$	(42.88	)
Commodity derivative impact	13.24		(6.29		)	19.53			15.88		(5.21		)	21.09
Net realized price	$	64.58	$	83.77		$	(19.19	)	$	61.74	$	83.53		$	(21.79	)

Oil revenues decreased $108.2 million, or 30%, in the second quarter of 2015 when compared to the second quarter of 2014, due to lower average field-level prices partially offset by higher volumes. Average field-level oil prices decreased 43% in the second quarter of 2015 compared to the second quarter of 2014 driven by a substantial decrease in average NYMEX-WTI and ICE Brent oil prices between the comparable periods. The increase in production volumes was primarily driven by increases in the Williston and Permian basins due to continued development drilling and well completions. These production increases were partially offset by a production decrease in the Midcontinent due to the divestitures of non-core properties in the second and fourth quarters of 2014.

Oil revenues decreased $218.1 million, or 34%, in the first half of 2015 when compared to the first half of 2014, due to lower average field-level prices partially offset by higher volumes. Average field-level oil prices decreased 48% in the first half of 2015 compared to the first half of 2014, driven by a substantial decrease in average NYMEX-WTI and ICE Brent oil prices between the comparable periods. The increase in production volumes was primarily driven by an increase in the Williston Basin due to continued development drilling and well completions. The Company also had an increase in production of 641.7 Mbbls from the Permian Basin due to development of the area combined with six months of production in 2015 compared to four months of production in 2014. These production increases were partially offset by a production decrease in the Midcontinent due to the divestitures of non-core properties in the second and fourth quarters of 2014.

NGL Volumes and Prices



	Three Months Ended June 30,							Six Months Ended June 30,
	2015		2014		Change			2015		2014		Change
NGL production volumes (Mbbls)
Northern Region
Pinedale	403.8		854.0		(450.2		)	716.8		1,568.8		(852.0		)
Williston Basin	482.8		204.4		278.4			841.6		365.3		476.3
Uinta Basin	70.3		177.4		(107.1		)	179.7		316.8		(137.1		)
Other Northern	6.5		3.3		3.2			9.2		5.3		3.9
Southern Region
Haynesville/Cotton Valley	6.8		11.0		(4.2		)	13.9		18.8		(4.9		)
Permian Basin	209.0		130.4		78.6			328.8		163.4		165.4
Midcontinent	18.8		505.5		(486.7		)	55.4		1,015.9		(960.5		)
Total production	1,198.0		1,886.0		(688.0		)	2,145.4		3,454.3		(1,308.9		)
NGL prices (per bbl)
Northern Region	$	23.41	$	35.55	$	(12.14	)	$	22.44	$	37.44	$	(15.00	)
Southern Region	14.59		32.02		(17.43		)	14.57		36.26		(21.69		)
Average field-level price	21.68		34.34		(12.66		)	$	20.98	$	37.03	$	(16.05	)
Commodity derivative impact	—		—		—			—		—		—
Net realized price	$	21.68	$	34.34	$	(12.66	)	$	20.98	$	37.03	$	(16.05	)

NGL revenues decreased $38.8 million, or 60%, during the second quarter of 2015 when compared to the second quarter of 2014 due to decreased production volumes and a decreased average price per barrel. Midcontinent NGL volumes decreased due to divestitures of non-core properties in the second and fourth quarters of 2014. Additionally, Pinedale and Uinta Basin NGL volumes decreased primarily due to ethane rejection in the second quarter of 2015 compared to ethane recovery in the second quarter of 2014. These decreases were partially offset by increases in NGL volumes in the Williston and Permian basins as a result of increased development drilling and well completions. NGL prices decreased 37% during the second quarter of 2015 compared to the second quarter of 2014 driven by a significant decrease in the pricing of the NGL components, particularly the heavier components, which have weakened as a result of the decline in crude oil prices.

NGL revenues decreased $82.9 million, or 65%, during the first half of 2015 when compared to the first half of 2014 due to decreased production volumes and a decreased average price per barrel. Midcontinent NGL volumes decreased due to divestitures of non-core properties in the second and fourth quarters of 2014. Additionally, Pinedale and Uinta Basin NGL volumes decreased primarily due to ethane rejection in the first half of 2015 compared to ethane recovery in the first half of 2014. These decreases were partially offset by increases in NGL volumes in the Williston and Permian basins as a result of increased development drilling and well completions combined with six months of production from the Permian Basin in 2015 compared to four months of production in 2014. NGL prices decreased 43% during the first half of 2015 compared to the first half of 2014 driven by a significant in the pricing of the NGL components, particularly the heavier components, which have weakened as a result of the decline in crude oil prices.

QEP Energy Resale Margin

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



	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Change			2015			2014			Change
Resale Margin	(in millions)
Purchased gas sales	$	16.3		$	49.8		$	(33.5	)	$	47.8		$	86.9		$	(39.1	)
Purchased gas expense	(16.8		)	(50.1		)	33.3			(48.0		)	(88.1		)	40.1
Resale margin	$	(0.5	)	$	(0.3	)	$	(0.2	)	$	(0.2	)	$	(1.2	)	$	1.0

During the second quarter of 2015, QEP Energy recorded a loss on resale margin of $0.5 million compared to a loss of $0.3 million in the second quarter of 2014. During the first half of 2015, QEP Energy recorded a loss on resale margin of $0.2 million compared to a loss of $1.2 million in the first half of 2014. These losses were the result of its activities to utilize pipeline transportation commitments in Louisiana.

QEP Energy Drilling Activity

The following table presents operated and non-operated well completions for the three and six months ended June 30, 2015:



	Operated Completions				Non-operated Completions
	Three Months Ended		Six Months Ended		Three Months Ended		Six Months Ended
	June 30, 2015		June 30, 2015		June 30, 2015		June 30, 2015
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale ⁽¹⁾	35	21.3	55	35.8	—	—	—	—
Williston Basin	20	14.4	36	27.2	11	1.0	33	2.7
Uinta Basin	8	8.0	9	9.0	4	—	17	0.1
Other Northern	—	—	1	1.0	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	4	1.1	13	1.5
Permian Basin ⁽²⁾	13	10.4	24	20.5	—	—	1	0.3
Midcontinent	—	—	—	—	1	—	4	0.1

____________________________


⁽¹⁾	Gross completions include seven wells for the three months ended June 30, 2015, and eight wells for the six months ended June 30, 2015, in which QEP only owns a small overriding royalty interest.


⁽²⁾	Operated completions includes one gross, one net, vertical well for the three months ended June 30, 2015, and eight gross, 7.4 net, vertical wells for the six months ended June 30, 2015.

The following table presents operated and non-operated wells drilling or waiting on completion at June 30, 2015:



	Operated				Non-operated
	Drilling		Waiting on completion		Drilling		Waiting on completion
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	25	17.7	34	21.5	—	—	—	—
Williston Basin	3	3.0	34	29.1	—	—	44	1.8
Uinta Basin	1	1.0	—	—	—	—	1	0.1
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	2	0.4	8	0.7
Permian Basin	4	3.8	1	0.9	—	—	1	0.6
Midcontinent	—	—	—	—	—	—	4	0.3

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 utilizes multi-well pad drilling where practical. In certain of our producing areas, 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. As a result, QEP had 69 gross operated wells waiting on completion as of June 30, 2015.

Operating expenses

The following table presents certain QEP Energy operating expenses on a per unit of production basis:



	Three Months Ended June 30,							Six Months Ended June 30,
	2015		2014		Change			2015		2014		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	2.64	$	2.77	$	(0.13	)	$	2.60	$	2.89	$	(0.29	)
Lease operating expense	0.71		0.71		—			0.76		0.74		0.02
Gas, oil and NGL transportation and other handling costs	0.93		0.86		0.07			0.91		0.87		0.04
Production and property taxes	0.38		0.63		(0.25		)	0.38		0.64		(0.26		)
Operating Expenses	$	4.66	$	4.97	$	(0.31	)	$	4.65	$	5.14	$	(0.49	)

Depreciation, depletion and amortization (DD&A). DD&A expense decreased $19.1 million, or $0.13 per Mcfe, in the second quarter of 2015 compared to the second quarter of 2014, due to decreases in the Haynesville/Cotton Valley and Midcontinent, partially offset by an increase in the Williston Basin. The decrease in the Midcontinent was a result of the second and fourth quarter 2014 property sales, while the decrease at Haynesville/Cotton Valley was a result of declining production and a rate decrease due to an impairment at year-end 2014. The increase in the Williston Basin DD&A expense primarily relates to increased production.

DD&A expense decreased $49.8 million, or $0.29 per Mcfe, in the first half of 2015 compared to the first half of 2014, due to decreases in the Haynesville/Cotton Valley and Midcontinent, partially offset by an increase in the Williston Basin. The decrease in the Midcontinent was a result of the second and fourth quarter 2014 property sales, while the decrease at Haynesville/Cotton Valley was a result of declining production and a rate decrease due to an impairment at year-end 2014. The increase in the Williston Basin DD&A expense primarily relates to increased production.

Lease operating expense. The following table presents lease operating expenses (LOE) for QEP Energy by region on a unit of production basis:



	Three Months Ended June 30,						Six Months Ended June 30,
	2015		2014		Change		2015		2014		Change
	(per Mcfe)
Northern Region	$	0.59	$	0.58	$	0.01	$	0.65	$	0.67	$	(0.02	)
Southern Region	1.09		0.89		0.20		1.13		0.82		0.31
Average lease operating expense	0.71		0.71		—		0.76		0.74		0.02

QEP Energy’s LOE decreased $2.4 million during the second quarter of 2015 compared to the second quarter of 2014, and remained flat on a per Mcfe basis. The decrease was driven by a decrease in the Southern Region during the second quarter of 2015, which was primarily due to a decrease in the Midcontinent as a result of the second and fourth quarter 2014 property sales, partially offset by an increase in the Permian Basin. Partially offsetting the decrease was an increase in the Northern Region, primarily due to increased production in the Williston Basin. On a per Mcfe basis, the increase in the Southern Region was primarily due to Midcontinent production declining at a faster rate than LOE due to QEP's remaining Midcontinent properties that carry higher operating costs than the properties that were divested in 2014.

QEP Energy’s LOE increased $3.0 million, or $0.02 per Mcfe, during the first half of 2015 compared to the first half of 2014. The increase in the Southern Region's LOE during the first half of 2015 was primarily driven by the Permian Basin Acquisition late in the first quarter of 2014, which are oil properties that have higher operating costs than the historical gas properties that were divested in 2014 in the Southern Region. The Northern Region per Mcfe decrease was driven primarily by higher performing well completions in the Uinta and Williston basins.

Gas, oil and NGL transportation and other handling costs. Gas, oil and NGL transportation and other handling costs increased $3.4 million, or $0.07 per Mcfe, in the second quarter of 2015 when compared to the second quarter of 2014. The per Mcfe expense increase was primarily attributable to additional expenses incurred in Pinedale due to deficiency payments on NGL volume commitments as a result of lower ethane volumes in 2015, in Haynesville/Cotton Valley due to deficiency fees on unutilized firm transportation commitments and in the Permian Basin due to higher contractual rates. These increases were

partially offset by a decrease in the Midcontinent due to divestitures of non-core properties in the second and fourth quarters of 2014.

Gas, oil and NGL transportation and other handling costs increased $6.3 million, or $0.04 per Mcfe, in the first half of 2015 when compared to the first half of 2014. The per Mcfe expense increase was primarily attributable to additional expenses incurred in Pinedale due to deficiency payments on NGL volume commitments as a result of lower ethane volumes in 2015, in Haynesville/Cotton Valley due to deficiency fees on unutilized firm transportation commitments and in the Permian Basin due to higher contractual rates. These increases were partially offset by decreases in the Williston Basin due to a reduction in the NGL processing and transportation costs and in the Midcontinent due to divestitures of non-core properties in the second and fourth quarters of 2014.

Production and property taxes. In most states in which QEP Energy operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Production taxes decreased $21.9 million, or $0.25 per Mcfe, during the second quarter of 2015 as a result of decreased gas, oil and NGL revenues due to decreased prices and lower gas and NGL production.

Production taxes decreased $41.8 million, or $0.26 per Mcfe, during the first half of 2015 as a result of decreased gas, oil and NGL revenues due to decreased prices and lower gas and NGL production.

Exploration expense. Exploration expenses decreased $0.9 million during the second quarter of 2015 and $2.0 million during the first half of 2015 compared to the 2014 equivalent periods. These decreases primarily related to lower exploration-related labor expenses.

Impairment expense. Impairment expense was $20.5 million during the first half of 2015, of which $19.4 million was related to proved properties due to lower future prices and $1.1 million was related to expiring leaseholds on unproved properties. Of the $19.4 million impairment on proved properties, $14.5 million related to impairments on QEP's remaining Midcontinent properties and $4.9 million related to impairments in the Other Northern properties. Impairment expense was $3.5 million in the first half of 2014 due to unproved property impairments resulting from changes in drilling plans.

QEP MARKETING AND OTHER

QEP Marketing and Other includes the results of operations from QEP Marketing Company, including the operation of a gas gathering system and an underground storage facility, and corporate. The following table provides a summary of QEP Marketing and Other's financial and operating results:



	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Change			2015			2014			Change
	(in millions)
REVENUES
Purchased gas and oil sales	$	443.6		$	605.6		$	(162.0	)	$	784.1		$	1,107.1		$	(323.0	)
Other	5.2			6.0			(0.8		)	10.5			12.3			(1.8		)
Total Revenues	448.8			611.6			(162.8		)	794.6			1,119.4			(324.8		)
OPERATING EXPENSES
Purchased gas and oil expense	445.4			605.4			(160.0		)	788.2			1,103.3			(315.1		)
Gathering and other expense	1.4			1.8			(0.4		)	3.1			3.4			(0.3		)
General and administrative	1.9			0.5			1.4			3.7			1.7			2.0
Production and property taxes	1.5			0.4			1.1			1.8			0.9			0.9
Depreciation, depletion and amortization	2.6			2.9			(0.3		)	5.3			5.4			(0.1		)
Total Operating Expenses	452.8			611.0			(158.2		)	802.1			1,114.7			(312.6		)
Net gain (loss) from asset sales	(2.0		)	(0.1		)	(1.9		)	(4.7		)	(0.1		)	(4.6		)
OPERATING INCOME (LOSS)	(6.0		)	0.5			(6.5		)	(12.2		)	4.6			(16.8		)
Realized gains (losses) on derivative instruments	(0.3		)	(1.8		)	1.5			2.2			(3.9		)	6.1
Unrealized gains (losses) on derivative instruments	(0.1		)	(0.9		)	0.8			(1.9		)	(1.2		)	(0.7		)
Interest and other income	53.1			56.7			(3.6		)	101.1			105.5			(4.4		)
Interest expense	(36.0		)	(44.9		)	8.9			(72.7		)	(86.7		)	14.0
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	10.7			9.6			1.1			16.5			18.3			(1.8		)
Income tax (provision) benefit	(3.6		)	(5.3		)	1.7			(5.7		)	(6.4		)	0.7
NET INCOME (LOSS)	$	7.1		$	4.3		$	2.8		$	10.8		$	11.9		$	(1.1	)

Resale Margin

The following table is a summary of QEP Marketing’s financial results from resale activities:



	Three Months Ended June 30,									Six Months Ended June 30,
	2015			2014			Change			2015			2014			Change
Resale Margin	(in millions)
Purchased gas and oil sales	$	443.6		$	605.6		$	(162.0	)	$	784.1		$	1,107.1		$	(323.0	)
Purchased gas and oil expense	(445.4		)	(605.4		)	160.0			(788.2		)	(1,103.3		)	315.1
Realized gains (losses) on derivative instruments	(0.3		)	(1.8		)	1.5			2.2			(3.9		)	6.1
Resale margin	$	(2.1	)	$	(1.6	)	$	(0.5	)	$	(1.9	)	$	(0.1	)	$	(1.8	)

Purchased gas and oil sales decreased by $162.0 million, or 27%, during the second quarter of 2015 compared to the second quarter of 2014, due to a $96.7 million decrease in resale oil sales and a $64.3 million decrease in resale gas sales. Resale oil sales decreased due to a 44% decrease in resale price, partially offset by a 39% increase in resale volumes. Resale gas sales decreased due to a 45% decrease in resale price, partially offset by a 7% increase in resale volumes.

Purchased gas and oil sales decreased by $323.0 million, or 29%, during the first half of 2015 compared to the first half of 2014, due to a $181.1 million decrease in resale oil sales and a $141.9 million decrease in resale gas sales. Resale oil sales

decreased due to a 50% decrease in resale price, partially offset by a 52% increase in resale volumes. Resale gas sales decreased due to a 54% decrease in resale price, partially offset by a 27% increase in resale volumes.

Purchased gas and oil expense, which includes transportation expense, decreased by $160.0 million, or 26%, in the second quarter of 2015 compared to the second quarter of 2014, due to a $97.5 million decrease in resale oil purchases and a $62.5 million decrease in resale gas purchases. Resale oil purchases expense decreased due to a 42% decrease in resale purchase price, partially offset by a 34% increase in resale purchase volumes. Resale gas purchases expense decreased due to a 42% decrease in the resale purchase price, partially offset by a 5% increase in resale purchase volumes.

Purchased gas and oil expense, which includes transportation expense, decreased by $315.1 million, or 29%, in the first half of 2015 compared to the first half of 2014, due to a $179.8 million decrease in resale oil purchases and a $135.3 million decrease in resale gas purchases. Resale oil purchases expense decreased due to a 49% decrease in resale purchase price, partially offset by a 48% increase in resale purchase volumes. Resale gas purchases expense decreased due to a 48% decrease in the resale purchase price, partially offset by an 8% increase in resale purchase volumes.

QEP Resources

Other Consolidated Expenses and Income from Continuing and Discontinued Operations

General and administrative expense. During the second quarter of 2015, general and administrative (G&A) expense decreased $1.0 million, or 2%, compared to the second quarter of 2014, primarily due to a $5.6 million decrease in professional and outside services and compensation expense mainly related to the 2014 Enterprise Resource Planning (ERP) system implementation and other 2014 transactions, a $4.2 million decrease in the mark-to-market value of the Deferred Compensation Wrap Plan and Cash Incentive Plan (CIP) due to a decrease in QEP's stock price and a $3.5 million decrease in labor, benefits and other employee expenses. These decreases were partially offset by an $11.2 million pension curtailment loss recognized in the second quarter of 2015 related to changes in the Company's pension plan (see Note 12 - Employee Benefits for additional information).

During the first half of 2015, G&A expense increased $1.1 million, or 1%, compared to the first half of 2014, primarily due to an $11.2 million pension curtailment loss recognized in the second quarter of 2015 related to changes in the Company's pension plan (see Note 12 - Employee Benefits for additional information) and a $4.0 million increase in labor and benefits costs primarily related to severance payments related to workforce reduction efforts in the first quarter of 2015. These increases were partially offset by a $12.8 million decrease in professional and outside services and compensation expense mainly related to the 2014 ERP system implementation and other 2014 transactions and a $1.8 million decrease in other employee expenses.

Net gain (loss) from asset sales. QEP recognized a gain on sale of assets of $24.5 million during the second quarter of 2015 compared to a loss on sale of $200.9 million in the second quarter of 2014. The gain on sale of assets recognized during the second quarter of 2015 was primarily due to a $26.6 million gain recognized on the sale of non-core properties in QEP Energy's Midcontinent area during the second quarter of 2015, partially offset by losses related to post-closing adjustments on QEP Energy's 2014 Midcontinent property sales. The loss on sale recognized during the second quarter of 2014 related to QEP Energy's sale of its interest in non-core oil and gas properties in the Midcontinent area for a pre-tax loss on sale of $200.9 million.

QEP recognized a loss on sale of assets of $6.0 million during the first half of 2015 compared to a loss on sale of assets of $198.5 million in the first half of 2014. The loss on sale of assets recognized during the first half of 2015 was primarily due to $29.3 million in post-closing adjustments related to QEP Energy's 2014 Midcontinent property sales and $4.3 million in post-closing adjustments related to the Midstream Sale in 2014, partially offset by a $26.6 million gain recognized on the sale of non-core properties in QEP Energy's Midcontinent area during the second quarter of 2015. The loss on sale recognized during the first half of 2014 primarily related to QEP Energy's sale of its interest in non-core oil and gas properties in the Midcontinent area for a pre-tax loss on sale of $200.9 million.

Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative instruments are comprised of both realized and unrealized gains and losses on QEP’s commodity derivative contracts and interest rate swaps, which are marked-to-market each quarter. During the second quarter of 2015, losses on commodity derivative instruments were $66.0 million, of which $158.3 million of unrealized losses, partially offset by $92.3 million of realized gains. During the second quarter of 2014, losses on commodity derivative instruments were $85.2 million, of which $34.1 million were realized and $51.1 million were unrealized. Additionally, during the second quarter of 2014, losses from interest rate swaps were $2.8 million, of which $1.2 million were realized and $1.6 million were unrealized. All of QEP's interest rate swaps were settled in the fourth quarter of 2014.

During the first half of 2015, gains on commodity derivative instruments were $14.9 million, of which $196.7 million were realized gains, partially offset by $181.8 million of unrealized losses. During the first half of 2014, losses on commodity derivative instruments were $165.4 million, of which $68.8 million were realized and $96.6 million were unrealized. Additionally, during the first half of 2014, losses from interest rate swaps were $3.5 million, of which $1.9 million were realized and $1.6 million were unrealized.

Interest expense. Interest expense decreased $8.8 million, or 20%, during the three months ended June 30, 2015, compared to the three months ended June 30, 2014. The decrease was attributable to average debt levels in the second quarter of 2015 that were $1,240.1 million, or 36%, lower than average debt levels in the second quarter of 2014. The decrease in average debt levels is primarily related to repaying all outstanding borrowings under the revolving credit facility and repaying the $600.0 million term loan from the proceeds of the Midstream Sale in December 2014.

Interest expense decreased $13.9 million, or 16%, during the six months ended June 30, 2015, compared to the six months ended June 30, 2014. The decrease was attributable to average debt levels in the first half of 2015 that were $1,235.9 million, or 36%, lower than average debt levels in the first half of 2014. The decrease in average debt levels is primarily related to repaying all outstanding borrowings under the revolving credit facility and repaying the $600.0 million term loan from the proceeds of the Midstream Sale in December 2014.

Income taxes. Income tax benefit was $38.8 million during the second quarter of 2015 compared $61.9 million during the second quarter of 2014. The income tax rate was 33.7% during the second quarter of 2015 compared to a rate of 36.8% during the second quarter of 2014. The income tax benefits recognized in 2015 and 2014 were primarily the result of losses before income taxes for the second quarters of 2015 and 2014. The decrease in income tax rate was primarily the result of a change in the composition of income between subsidiaries.

Income tax benefit was $70.3 million during the first half of 2015 compared to $53.7 million during the first half of 2014. The income tax rate was 34.8% during the first half of 2015 compared to a rate of 36.5% during the first half of 2014. The income tax benefits recognized in 2015 and 2014 were primarily the result of losses before income taxes for the first half of 2015 and 2014. The decrease in income tax rate was primarily the result of a change in the composition of income between subsidiaries.

Discontinued operations. Discontinued operations represent results of operations from QEP Field Services, excluding QEP’s retained Haynesville Gathering System. During the second quarter of 2014, net income from discontinued operations was $13.8 million, primarily attributable to other revenue of $34.9 million, which primarily consists of gathering and processing revenue, and NGL sales revenue of $27.8 million, partially offset by gathering, processing and other expense of $22.8 million, DD&A of $14.5 million and G&A of $11.9 million.

During the first half of 2014, net income from discontinued operations was $40.8 million, primarily attributable to other revenue of $76.8 million, which primarily consists of gathering and processing revenue, and NGL sales revenue of $65.8 million, partially offset by gathering, processing and other expense of $47.1 million, DD&A of $28.8 million and G&A of $23.2 million.

LIQUIDITY AND CAPITAL RESOURCES

QEP seeks to fund its development projects by employing a capital structure and financing strategy to provide sufficient liquidity to withstand commodity price volatility. QEP maintains a commodity price derivative strategy to reduce commodity price volatility and to provide some certainty to cash flows. QEP funds its operations, capital expenditures and working capital requirements with cash flow from its operating activities and borrowings under its credit facilities. Periodically, QEP accesses debt and equity capital markets and sells assets to provide additional liquidity. The Company believes cash flow from operations, cash-on-hand and availability under its credit facility will be sufficient to fund the Company’s planned capital expenditures and operating expenses during the next 12 months and the foreseeable future. To the extent actual operating results or actual commodity prices differ from the Company’s assumptions, QEP's liquidity could be adversely affected.

The following table provides QEP’s available liquidity and debt to equity ratio compared to the previous period:



	June 30, 2015			December 31, 2014
	(in millions, except %)
Cash and cash equivalents	$	445.6		$	1,160.1
Amount available under the QEP credit facility ⁽¹⁾	1,796.3			1,796.3
Total liquidity	$	2,241.9		$	2,956.4
Total debt	$	2,218.5		$	2,218.1
Total common shareholders' equity	$	3,947.7		$	4,075.3
Ratio of debt to total capital ⁽²⁾	36		%	35		%

____________________________


⁽¹⁾	See discussion of revolving credit facility below. Availability under QEP's credit facility is reduced by outstanding letters of credit of $3.7 million as of June 30, 2015 and December 31, 2014, respectively.


⁽²⁾	Defined as total debt divided by the sum of total debt plus common shareholders’ equity.

Credit Facility

Senior Notes

The Company’s senior notes outstanding as of June 30, 2015, totaled $2,221.8 million principal amount and are comprised of six issuances as follows:


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


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


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


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


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


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

Cash Flow from Operating Activities

Cash flows from operations are primarily affected by gas, oil and NGL production volumes and commodity prices (including the effects of settlements of the Company’s derivative contracts) and by changes in working capital. QEP 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 24 months.

Net cash from operating activities decreased $862.9 million during the first half of 2015 compared to the first half of 2014, due to a decrease in changes in operating assets and liabilities, lower non-cash adjustments to net income and a higher net loss incurred during the first half of 2015 compared to the first half of 2014. Changes in operating assets and liabilities decreased $566.1 million, which was mainly due to a decrease in income taxes payable of $587.8 million, primarily from the gain on the Midstream Sale, which was paid in the first half of 2015. Net cash from operating activities is presented below:



	Six Months Ended June 30,
	2015			2014			Change
	(in millions)
Net income (loss)	$	(131.9	)	$	(52.6	)	$	(79.3	)
Net income attributable to noncontrolling interest	—			10.8			(10.8		)
Non-cash adjustments to net income	620.2			826.9			(206.7		)
Changes in operating assets and liabilities	(490.9		)	75.2			(566.1		)
Net cash (used in) provided by operating activities	$	(2.6	)	$	860.3		$	(862.9	)

Cash Flow from Investing Activities

In the first half of 2015, net cash used in investing activities was $653.7 million, compared to $972.1 million in the first half of 2014. This decrease in investing activities was due to a 62% decrease in capital expenditures on a cash basis. Capital expenditures decreased primarily because of the Permian Basin Acquisition, which closed in the first quarter of 2014 for a total purchase price of $941.8 million, as well as a reduction in capital activity due to the current price environment. A comparison of capital expenditures for the first half of 2015 and 2014 and a forecast for calendar year 2015 are presented in the table below:



	Six Months Ended								Current Forecast Twelve Months Ended		Prior Forecast Twelve Months Ended ⁽¹⁾
	June 30,								Current Forecast Twelve Months Ended		Prior Forecast Twelve Months Ended ⁽¹⁾
	2015		2014			Change			December 31, 2015		December 31, 2015
	(in millions)
QEP Energy	$	554.8	$	1,710.5		$	(1,155.7	)	$	960.0	$	960.0
QEP Marketing and Other	4.9		6.9			(2.0		)	15.0		15.0
Continuing Operations	559.7		1,717.4			(1,157.7		)	975.0		975.0
Discontinued Operations	—		37.3			(37.3		)	—		—
Total accrued capital expenditures	559.7		1,754.7			(1,195.0		)	975.0		975.0
Change in accruals	91.6		(26.3		)	117.9			—		—
Total cash capital expenditures	$	651.3	$	1,728.4		$	(1,077.1	)	$	975.0	$	975.0

____________________________


⁽¹⁾	Forecast as reported in the March 31, 2015, Form 10-Q, filed on April 29, 2015.

In the first half of 2015, QEP Energy's capital expenditures, on an accrual basis, decreased $1,155.7 million over the first half of 2014 to a total of $554.8 million, which was primarily driven by the Permian Basin Acquisition which occurred in 2014. In addition, capital expenditures decreased $148.8 million in the Williston Basin, $62.6 million in Pinedale and $17.8 million in the Other Northern properties due to reductions in QEP's capital expenditures in response to the current pricing environment and $29.0 million in the Midcontinent due to 2014 divestitures. These decreases were partially offset by increases of $31.1 million in the Permian Basin due to additional horizontal well completions during the first half of 2015 compared to the first half of 2014, and $15.5 million in Haynesville/Cotton Valley.

At June 30, 2015, the midpoint of our forecasted capital investment for 2015 is $975.0 million, comprised of $960.0 million allocated to QEP Energy and $15.0 million between QEP Marketing and Other. QEP intends to fund capital expenditures with cash flow from operating activities, cash on hand and, if needed, borrowings under its revolving credit facility. As a result of the decline in oil and gas prices, forecasted capital investment in 2015 is expected to be significantly lower than in 2014. QEP

plans minimal capital expenditures for the Haynesville Shale and other dry-gas development areas in 2015 and plans to focus investment during 2015 on higher return projects, including oil-directed horizontal drilling in the Williston Basin and the Permian Basin. QEP Energy has allocated approximately 96% of its forecasted 2015 drilling and completion capital expenditure budget to oil and liquids-rich gas plays. QEP plans to invest approximately $15.0 million in capital expenditures related to corporate activities. The aggregate levels of capital expenditures for 2015 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, gas, oil and NGL prices, industry conditions, the extent to which properties or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management’s business assessments as to where QEP’s capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP’s estimates.

Cash Flow from Financing Activities

In the first half of 2015, net cash used in financing activities was $58.2 million compared to net cash provided by financing activities of $802.2 million in the first half of 2014. During the first half of 2015, QEP had checks outstanding in excess of cash balances of $47.3 million and $7.1 million of regular quarterly dividend payments. During the first half of 2014, QEP had borrowings from the credit facility of $3,151.0 million offset by repayments on the credit facility of $2,538.0 million as well as an additional issuance of $300.0 million under its term loan which were used to fund the Permian Basin Acquisition. These borrowings were offset by checks outstanding in excess of cash balances of $85.2 million, $15.2 million of distributions to noncontrolling interest, and $7.3 million of regular quarterly dividends payment during the first half of 2014.

At June 30, 2015, the Company did not have any borrowings outstanding under the credit facility and $2,221.8 million in senior notes (excluding $3.3 million of net original issue discount).

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP’s primary market risk exposures 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 Energy and QEP Marketing also have long-term contracts for pipeline capacity, and are obligated to pay for transportation services with no guarantee that QEP will be able to fully utilize the contractual capacity of these transportation commitments. In addition, a non-cash write-down of the Company’s oil and gas properties may be required if future oil and gas commodity prices experience a sustained, significant decline. Furthermore, the Company’s credit facility has a floating interest rate, which expose QEP to interest rate risk. To manage the Company’s exposure to these risks, QEP enters into commodity derivative contracts in the form of fixed-price swaps to manage commodity price risk and periodically interest rate swaps to manage interest rate risk.

Commodity Price Risk Management

QEP uses commodity price derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price swaps or collars. The volume of commodity derivative instruments utilized by the Company may vary from year-to-year based on QEP's forecasted production. The derivative instruments utilized by the Company do not have margin requirements or collateral provisions that would require payments prior to the scheduled cash settlement dates. As of June 30, 2015, QEP held commodity price derivative contracts totaling 137.3 million MMBtu of gas and 8.7 million barrels of oil.

The following table presents QEP's derivative positions as of July 29, 2015. See Note 8 - Derivative Contracts, under Part 1, Item 1 of this Quarterly Report on Form 10-Q for open derivative positions as of June 30, 2015.

QEP Energy Commodity Derivative Swap Positions

Year	Index	Total Volumes	Average Swap price per unit
		(in millions)
Gas sales		(MMBtu)
2015	NYMEX HH	35.0	$	3.48
2015	IFNPCR	23.9	$	3.55
2016	NYMEX HH	18.3	$	3.24
2016	IFNPCR	32.9	$	2.92
Oil Sales		(bbls)
2015	NYMEX WTI	5.2	$	82.09
2015	ICE Brent	0.2	$	104.95
2016	NYMEX WTI	3.3	$	65.43

QEP Energy Gas Collars

Total Volume

Average Price

Year

Index

Floor

Ceiling

(in millions)

(MMBtu)

($/MMBtu)

2016

NYMEX HH

7.3

2.75

3.89

QEP Energy Gas Basis Swaps

Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2015	NYMEX HH	IFNPCR	22.1	$	(0.28	)

QEP Marketing Commodity Derivative Positions

Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2015	SWAP	IFNPCR	2.4	$	3.25
2016	SWAP	IFNPCR	2.0	$	3.17
Gas purchases			(MMBtu)
2015	SWAP	IFNPCR	1.1	$	2.77

Changes in the fair value of derivative contracts from December 31, 2014 to June 30, 2015, are presented below:



	Commodity derivative contracts
	(in millions)
Net fair value of oil and gas derivative contracts outstanding at December 31, 2014	$	348.9
Contracts settled	(196.7		)
Change in oil and gas prices on futures markets	17.3
Contracts added	(2.4		)
Net fair value of oil and gas derivative contracts outstanding at June 30, 2015	$	167.1

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 NGL and basis differentials:



	June 30, 2015
	(in millions)
Net fair value - asset (liability)	$	167.1
Fair value if market prices of oil and gas and basis differentials decline by 10%	250.7
Fair value if market prices of oil and gas and basis differentials increase by 10%	83.2

Utilizing the actual derivative volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $83.9 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $83.6 million as of June 30, 2015. 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 8 – Derivative Contracts under 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 as described in the risk factors in Item 1A of Part I of the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2014. The Company’s credit facility has a floating interest rate, which exposes QEP to interest rate risk. At June 30, 2015, the Company did not have any borrowings outstanding under its revolving credit facility.

The remaining $2,221.8 million of the Company’s debt is Senior Notes with fixed interest rates; therefore, it is not affected by interest rate movements. For additional information regarding the Company’s debt instruments, see Note 9 – Debt, in Item I of Part I of this Quarterly Report on Form 10-Q.

Forward-Looking Statements

This 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, 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;


•	ability to deliver continued growth by focusing on exploration and production assets;


•	ability to pursue acquisition opportunities;


•	inventory of drilling locations;


•	strong liquidity position providing financial flexibility;


•	our liquidity and sufficiency of cash flow from operations, cash-on-hand and availability under our credit facility to fund our planned capital expenditures and operating expenses;


•	drilling plans;


•	focus on improving well design and reducing costs;


•	results from planned drilling operations and production operations;


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


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


•	anticipated oil, gas and NGL prices and factors impacting such prices;


•	impact of global geopolitical and macroeconomic events;


•	plans to enter into derivative contracts and manage counterparty risk;


•	pro forma results for acquired properties;


•	divestitures of non-core assets;


•	expected gain or loss on sale of assets;


•	amount and allocation of forecasted capital expenditures and plans for funding capital expenditures and operating expenses;


•	timing and impact of proposed environmental legislation and studies;


•	compliance with governmental regulations;


•	the outcome of contingencies such as legal proceedings;


•	assumptions regarding equity compensation;


•	recognition of compensation costs related to equity compensation grants;


•	expected contributions to our employee benefit plans;


•	employee benefit plan 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 value and critical accounting estimates, including estimated asset retirement obligations;


•	impact of new accounting pronouncements;


•	impact of shutting in wells;


•	factors impacting our ability to transport oil and gas;


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


•	impact of sale of our midstream business;


•	the timing and estimated costs of, and benefits from, the closing of our Tulsa office; and


•	factors impacting the timing and amount of share repurchases.

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/A for the year ended December 31, 2014;


•	changes in gas, oil and NGL prices;


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


•	drilling 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;


•	permitting delays;


•	operating risks such as unexpected drilling conditions;


•	weather conditions;


•	the availability and cost of debt and equity financing;


•	changes in laws or regulations;


•	legislation regarding climate change and other initiatives related to drilling and completion techniques, including hydraulic fracturing and water use;


•	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;


•	regulatory approvals and compliance with contractual obligations;


•	actions, or inaction, by federal, state, local or tribal governments;


•	lack of, or disruptions in, adequate and reliable transportation for our production;


•	competitive conditions;


•	production levels;


•	reserve levels; and


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

We undertake 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 website to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, the Exchange Act) as of June 30, 2015. Based on such evaluation, such officers have concluded that, as of June 30, 2015, the Company’s disclosure controls and procedures are designed and effective to ensure that information required to be disclosed in the Company’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms and that information is accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure.

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

Changes in Internal Controls.

There were no changes in the Company's internal controls over financial reporting that occurred during the quarter ended June 30, 2015, 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

ITEM 1A. RISK FACTORS

Risk factors relating to the Company are set forth in its Annual Report on Form 10-K/A for the year ended December 31, 2014. Below are material changes to such risk factors that have occurred during the six months ended June 30, 2015.

QEP's ability to produce oil and gas economically and in commercial quantities could be impaired if it is unable to acquire adequate supplies of water for its drilling and completion operations or is unable to dispose of or recycle the water or other waste at a reasonable cost and in accordance with applicable environmental rules. The hydraulic fracture stimulation process on which QEP depends to produce commercial quantities of oil and gas requires the use and disposal of significant quantities of water. The availability of disposal wells with sufficient capacity to receive all of the water produced from QEP’s wells may affect QEP’s production. In some cases, QEP may need to obtain water from new sources and transport it to drilling sites, resulting in increased costs. QEP's inability to secure sufficient amounts of water, or to dispose of or recycle the water used in its operations, could adversely impact its operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on QEP's ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of gas. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase QEP's operating costs or may cause QEP to delay, curtail or discontinue its exploration and development plans, which could have a material adverse effect on its business, financial condition, results of operations and cash flows. In addition, concerns have been raised about the potential for induced seismicity to occur from the use of underground injection wells, a predominant method for disposing of waste water (including hydraulic fracturing flowback water) from oil and gas activities. QEP operates injection wells and utilizes injection wells owned by third parties to dispose of waste water associated with its operations. New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others. Further, lawsuits against other companies have been filed by plaintiffs alleging they suffered damages from seismicity caused by injection of waste water into disposal wells, which may make it more expensive or difficult to conduct water disposal activities and to obtain insurance for such activities.

Federal and state hydraulic fracturing legislation or regulatory initiatives could increase QEP's costs and restrict its access to oil and gas reserves. Currently, well construction activities, including hydraulic fracture stimulation, are regulated by state agencies that review and approve all aspects of oil and gas well design and operation. The EPA recently asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the federal Safe Drinking Water Act and issued guidance related to this newly asserted regulatory authority. The EPA appears to be considering its existing regulatory authorities for possible avenues to further regulate hydraulic fracturing fluids and/or the components of those fluids. Additionally, in May 2012, the BLM proposed new regulations regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing, on federal and tribal lands and proposed further revision to those regulations in May 2013. The BLM finalized those regulations in March 2015, to become effective in June 2015; however, due to pending litigation (discussed below), the effective date of the rule has been postponed. The new regulations have the potential to increase the cost of drilling and completing any well requiring federal permits, and could result in further delays in getting such permits to authorize drilling and completion activities on federal and tribal lands. Several states, including some in which the Company operates, have filed suit against the Department of Interior over the final BLM hydraulic fracturing regulations, which could contribute to increased uncertainty regarding the Company’s compliance obligations on federal and tribal lands and has caused the effective date of the regulations to be postponed.

Legislation has also been introduced before Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process, notwithstanding the proposed and ongoing rulemaking proceedings noted above. At the state level, some states have adopted and other states are considering adopting regulations that could restrict hydraulic fracturing in certain circumstances. In the event that new or more stringent federal, state or local regulations, restrictions or moratoria are adopted in areas where QEP operates, QEP could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling or stimulating wells in some areas.

The EPA is also considering other potential regulation of hydraulic fracturing activities. For example, the EPA is considering regulation of wastewater discharges from hydraulic fracturing and other natural gas production under the federal Clean Water Act. The EPA is also collecting information as part of a nationwide study into the effects of hydraulic fracturing on drinking water. The EPA released a draft assessment of the potential impacts to drinking water resources from hydraulic fracturing for public comment and peer review. The results of this study, which has not been finalized, could result in additional regulations, which could lead to operational burdens similar to those described above. The EPA has also issued an advance notice of proposed rulemaking and initiated a public participation process under the Toxic Substances Control Act (TSCA) to seek

comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanisms for obtaining this information. Additionally, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that the EPA add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals" under the Toxics Release Inventory (TRI) program of the Emergency Planning and Community Right-to-Know Act.

Lack of availability of refining, gas processing, storage or transportation capacity will likely impact results of operations. The lack of availability of satisfactory oil, gas and NGL transportation, including trucks, railways and pipelines, gas processing, storage or refining capacity may hinder QEP's access to oil, NGL and gas markets or delay production from its wells. QEP's ability to market its production depends in substantial part on the availability and capacity of transportation, gas processing facilities, storage or refineries owned and operated by third parties. Although QEP has some contractual control over the transportation of its production through firm transportation arrangements, third-party systems may be temporarily unavailable due to market conditions, mechanical failures, accidents or other reasons. If transportation, gas processing or storage facilities do not exist near producing wells, if transportation, gas processing, storage or refining capacity is limited or if transportation, gas processing or refining capacity is unexpectedly disrupted, completion activity could be delayed, sales could be reduced, or production shut in each of which could reduce profitability. Furthermore, if QEP were required to shut in wells, it might also be obligated to pay certain demand charges for gathering and processing services, firm transportation charges on interstate pipelines as well as shut-in royalties to certain mineral interest owners in order to maintain its leases; or depending on the specific lease provisions, some leases could terminate. In addition, rail accidents involving crude oil carriers have resulted in regulations, and may result in additional regulations, on transportation of oil by railway. If transportation quality requirements change, QEP might be required to install or contract for additional treating or processing equipment, which could increase costs. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand, transportation pressures, damage to or destruction of transportation facilities and general economic conditions could also adversely affect QEP's ability to transport oil and gas.

Requirements to reduce gas flaring could have an adverse effect on our operations. Wells in the Bakken and Three Forks formations in North Dakota, where QEP has significant operations, produce natural gas as well as crude oil. Constraints in the current gas gathering and processing network in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. In June 2014, the North Dakota Industrial Commission, North Dakota's chief energy regulator, adopted a policy to reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations. The Commission is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals. The Bureau of Land Management (BLM) has also indicated its intent to pursue a rulemaking related to further controls on the venting and flaring of natural gas on BLM land. These capture requirements, and any similar future obligations in North Dakota or our other locations, may increase our operational costs or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

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 stock awards withheld for

taxes.



Period	Total shares purchased ⁽¹⁾	Weighted-average price paid per share		Total shares purchased as part of publicly announced plans or programs	Remaining dollar amount that may be purchased under the plans or programs
April 1, 2015 - April 30, 2015	—	$	—	—	$	400.3
May 1, 2015 - May 31, 2015	—	—		—	400.3
June 1, 2015 - June 30, 2015	1,500	18.56		—	400.3

____________________________

⁽¹⁾

All of the 1,500 shares purchased during the three-month period ended June 30, 2015, were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common stock. Stock options that are net settled do not involve the acquisition of any shares.

In January 2014, QEP's Board of Directors authorized the repurchase of up to $500.0 million of the Company's outstanding shares of common stock. This program was extended through December 2015. The timing and amount of any QEP share repurchases will depend upon a number of factors, including general market conditions, the Company’s financial position and the estimated intrinsic value of the Company’s shares. The repurchase plan does not obligate QEP to acquire any specific number of shares and may be discontinued at any time. During the six months ended June 30, 2015, no shares were repurchased under this plan.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

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, deemed effective October 27, 2014. (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on October 29, 2014.)
10.1†		QEP Resources, Inc. Supplemental Executive Retirement Plan adopted June 12, 2010 (Incorporated by reference to Exhibit 10.12 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on June 16, 2010), as amended and restated by the QEP Resources, Inc. Amended Supplemental Executive Retirement Plan, effective as of January 1, 2016.
10.2†		QEP Resources, Inc. Amended Deferred Compensation Wrap Plan adopted January 28, 2013 (Incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on January 31, 2013), as amended and restated by the QEP Resources, Inc. Amended Deferred Compensation Wrap Plan, effective as of January 1, 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.
99.1		Notice of Stipulation and Order, dated June 25, 2015 (Stipulation), dismissing Plumbers Local 98 Defined Benefit Fund v. Rattie, C.A. No. 10405-VCN, a shareholder derivative lawsuit (filed pursuant to the terms of the Stipulation).
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)

August 3, 2015	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer

August 3, 2015	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

QEP RESOURCES, INC. - FORM 10-Q - August 3, 2015

Attached files

QEP RESOURCES, INC. Reports