SEC Filing | QEP Resources, Inc.

View:

Download DOC

Download PDF

Download XLS

Download XBRL

QEP-2015.03.31-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

For the quarterly period ended March 31, 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 March 31, 2015, there were 176,661,336 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended March 31, 2015

TABLE OF CONTENTS



			Page
PART I. FINANCIAL INFORMATION			2

	ITEM 1.	FINANCIAL STATEMENTS	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCH 31, 2015 AND 2014	2

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE MONTHS ENDED MARCH 31, 2015 AND 2014	3

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

		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE THREE MONTHS ENDED MARCH 31, 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	21

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	38

	ITEM 4.	CONTROLS AND PROCEDURES	43

PART II. OTHER INFORMATION			43

	ITEM 1.	LEGAL PROCEEDINGS	43

	ITEM 1A.	RISK FACTORS	43

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

	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	45

	ITEM 4.	MINE SAFETY DISCLOSURES	45

	ITEM 5.	OTHER INFORMATION	45

	ITEM 6.	EXHIBITS	46

SIGNATURES			47

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three Months Ended
	March 31,
	2015			2014
REVENUES	(in millions, except per share amounts)
Gas sales	$	122.0		$	222.5
Oil sales	178.8			288.7
NGL sales	19.1			63.2
Other revenue	4.4			2.5
Purchased gas and oil sales	167.3			240.6
Total Revenues	491.6			817.5
OPERATING EXPENSES
Purchased gas and oil expense	169.4			237.9
Lease operating expense	61.8			56.4
Gas, oil and NGL transportation and other handling costs	65.1			59.9
Gathering and other expense	1.7			1.6
General and administrative	47.4			45.3
Production and property taxes	27.8			47.9
Depreciation, depletion and amortization	195.4			225.9
Exploration expenses	1.1			2.2
Impairment	20.0			2.0
Total Operating Expenses	589.7			679.1
Net gain (loss) from asset sales	(30.5		)	2.4
OPERATING INCOME (LOSS)	(128.6		)	140.8
Realized and unrealized gains (losses) on derivative contracts (Note 8)	80.9			(80.9		)
Interest and other income (expense)	(2.6		)	2.9
Interest expense	(36.8		)	(41.9		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(87.1		)	20.9
Income tax (provision) benefit	31.5			(8.2		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(55.6		)	12.7
Net income from discontinued operations, net of income tax	—			27.0
NET INCOME (LOSS)	$	(55.6	)	$	39.7

Earnings Per Common Share
Basic from continuing operations	$	(0.32	)	$	0.07
Basic from discontinued operations	—			0.15
Basic total	$	(0.32	)	$	0.22
Diluted from continuing operations	$	(0.32	)	$	0.07
Diluted from discontinued operations	—			0.15
Diluted total	$	(0.32	)	$	0.22
Weighted-average common shares outstanding
Used in basic calculation	176.2			179.7
Used in diluted calculation	176.2			180.0
Dividends per common share	$	0.02		$	0.02

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended
	March 31,
	2015			2014
	(in millions)
Net income (loss)	$	(55.6	)	$	39.7
Other comprehensive income, net of tax:
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss ⁽¹⁾	0.2			0.1
Amortization of prior service cost ⁽²⁾	0.5			0.9
Total pension and other postretirement plans adjustments	0.7			1.0
Other comprehensive income	0.7			1.0
Comprehensive income (loss)	$	(54.9	)	$	40.7

____________________________


⁽¹⁾	Presented net of income tax expense of $0.1 million and $0.1 million during the three months ended March 31, 2015, and 2014, respectively.


⁽²⁾	Presented net of income tax expense of $0.3 million and $0.4 million during the three months ended March 31, 2015, and 2014, respectively.

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	March 31, 2015			December 31, 2014
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	500.4		$	1,160.1
Accounts receivable, net	319.4			441.9
Fair value of derivative contracts	311.7			339.0
Gas, oil and NGL inventories, at lower of average cost or market	7.6			13.7
Prepaid expenses and other	37.8			46.8
Total Current Assets	1,176.9			2,001.5
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	12,558.9			12,278.7
Unproved properties	821.9			825.2
Marketing and other	296.3			293.8
Material and supplies	50.4			54.3
Total Property, Plant and Equipment	13,727.5			13,452.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,357.7			6,153.0
Marketing and other	72.8			67.8
Total Accumulated Depreciation, Depletion and Amortization	6,430.5			6,220.8
Net Property, Plant and Equipment	7,297.0			7,231.2
Fair value of derivative contracts	13.7			9.9
Other noncurrent assets	36.8			44.2
TOTAL ASSETS	$	8,524.4		$	9,286.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	15.8		$	54.7
Accounts payable and accrued expenses	453.5			575.4
Income taxes payable	—			532.1
Production and property taxes	45.9			61.7
Interest payable	33.7			36.4
Deferred income taxes	94.0			84.5
Total Current Liabilities	642.9			1,344.8
Long-term debt	2,218.3			2,218.1
Deferred income taxes	1,348.9			1,362.7
Asset retirement obligations	196.3			193.8
Other long-term liabilities	98.1			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 - 0.3 million and 0.8 million shares, respectively	(11.0		)	(25.4		)
Additional paid-in capital	530.1			535.3
Retained earnings	3,522.6			3,587.9
Accumulated other comprehensive income (loss)	(23.6		)	(24.3		)
Total Common Shareholders' Equity	4,019.9			4,075.3
TOTAL LIABILITIES AND EQUITY	$	8,524.4		$	9,286.8

See Notes accompanying the Condensed Consolidated Financial Statements.

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three Months Ended
	March 31,
	2015			2014
	(in millions)
OPERATING ACTIVITIES
Net income (loss)	$	(55.6	)	$	39.7
Net income attributable to noncontrolling interest	—			5.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	195.4			240.2
Deferred income taxes	(4.8		)	20.7
Impairment	20.0			2.0
Share-based compensation	9.1			7.5
Amortization of debt issuance costs and discounts	1.9			1.7
Net (gain) loss from asset sales	30.5			(2.4		)
Income from unconsolidated affiliates	—			(2.2		)
Distributions from unconsolidated affiliates and other	—			2.7
Unrealized (gains) losses on derivative contracts	23.5			45.5
Changes in operating assets and liabilities	(492.7		)	(38.8		)
Net Cash (Used in) Provided by Operating Activities	(272.7		)	322.4
INVESTING ACTIVITIES
Property acquisitions	—			(946.6		)
Property, plant and equipment, including dry exploratory well expense	(342.1		)	(330.2		)
Proceeds from disposition of assets	1.6			2.9
Acquisition deposit held in escrow	—			50.0
Net Cash Used in Investing Activities	(340.5		)	(1,223.9		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(38.9		)	(12.5		)
Long-term debt issued	—			300.0
Long-term debt issuance costs paid	—			(1.1		)
Proceeds from credit facility	—			1,643.0
Repayments of credit facility	—			(1,021.5		)
Treasury stock repurchases	(1.9		)	(5.5		)
Other capital contributions	(0.4		)	2.9
Dividends paid	(3.5		)	(3.6		)
Excess tax (provision) benefit on share-based compensation	(1.8		)	(0.6		)
Distribution to noncontrolling interest	—			(7.6		)
Net Cash (Used in) Provided by Financing Activities	(46.5		)	893.5
Change in cash and cash equivalents	(659.7		)	(8.0		)
Beginning cash and cash equivalents	1,160.1			11.9
Ending cash and cash equivalents	$	500.4		$	3.9

Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	37.6		$	43.8
Cash paid for income taxes	509.8			—
Non-cash investing activities:
Change in capital expenditure accrual balance	$	(59.2	)	$	11.6

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 the Haynesville 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 months ended March 31, 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 three months ended March 31, 2015, QEP Energy recorded impairment charges of $20.0 million, of which $19.4 million was related to proved properties due to lower future prices and $0.6 million was related to expiring leaseholds on unproved properties. Of the $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 February 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) No. 2015-02, Consolidation (Topic 810), which amends the current consolidation guidance. The amendments affect both the variable interest entity and voting interest entity consolidation models. The amendments 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 standard update 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 amendments 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 amendments retrospectively for all periods presented in the financial statements. The Company is currently assessing the standard update and does not believe there will be a significant 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 consist 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 $29.5 million and a net loss of $1.5 million were generated from the acquired properties during the three months ended March 31, 2015. Revenues of $14.9 million and net income of $3.7 million were generated from the acquired properties from February 25, 2014, to March 31, 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 three months ended March 31, 2014. Pro forma results are not provided for the three months ended March 31, 2015, because the Permian Basin Acquisition occurred during the first quarter of 2014, and therefore there is no pro forma impact on the first quarter of 2015. 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 three months ended March 31, 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.



		Three Months Ended
		March 31,
		2014		2014
		Actual		Pro forma
	(in millions, except per share data)
Revenues		$	817.5	$	843.6
Net income		$	39.7	$	46.7
Earnings per common share
Basic		$	0.22	$	0.26
Diluted		$	0.22	$	0.26

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 $1.8 million for the three months ended March 31, 2015, 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 $692.9 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 loss on sale of $26.8 million for the three months ended March 31, 2015, 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 months ended March 31, 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 three months ended March 31, 2015 and 2014, cash outflows for these transactions that are included in continuing operations were $22.7 million and $34.9 million, respectively.

In connection with the announcement of 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 $2.3 million was included in "Discontinued operations, net of income tax" on the Condensed Consolidated Statements of Operations for the three months ended March 31, 2014.

Condensed Consolidated Statement of Operations

The Discontinued Operations of QEP Field Services are summarized below:



	Three Months Ended
	March 31,
	2014

REVENUES
NGL sales	$	38.0
Other revenue	41.9
Purchased gas and oil sales⁽¹⁾	(13.4		)
Total Revenues	66.5
OPERATING EXPENSES
Purchased gas and oil expense⁽¹⁾	(13.8		)
Lease operating expense⁽¹⁾	(1.1		)
Natural gas, oil and NGL transport and other handling costs⁽¹⁾	(16.4		)
Gathering, processing, and other	24.3
General and administrative	11.3
Production and property taxes	1.5
Depreciation, depletion and amortization	14.3
Total Operating Expenses	20.1
OPERATING INCOME	46.4
Income from unconsolidated affiliates	2.2
Interest expense	(0.6		)
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES ⁽²⁾	48.0
Income taxes	(15.2		)
NET INCOME FROM DISCONTINUED OPERATIONS	32.8
Net income attributable to noncontrolling interest	(5.8		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	27.0


⁽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 $6.8 million for the three months ended March 31, 2014.

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 $14.3 million for the three months ended March 31, 2014. The impact on cash used for "Property, plant and equipment, including dry exploratory well expense" contained in "Cash flows from investing activities" was $12.7 million for the three months ended March 31, 2014.

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 months ended March 31, 2015 and 2014, there were no anti-dilutive shares.

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



	Three Months Ended
	March 31,
	2015	2014
	(in millions)
Weighted-average basic common shares outstanding	176.2	179.7
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	—	0.3
Average diluted common shares outstanding	176.2	180.0

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 $197.2 million and $195.1 million ARO liability for continuing operations for the periods ended March 31, 2015 and December 31, 2014, $0.9 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	2.1
Additions	0.6
Liabilities settled	(0.6		)
ARO liability at March 31,	$	197.2

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 March 31, 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)
	March 31, 2015
Financial Assets
Commodity derivative instruments - short-term	$	—	$	312.5	$	—	$	(0.8	)	$	311.7
Commodity derivative instruments - long-term	—		13.7		—		—			13.7
Total financial assets	$	—	$	326.2	$	—	$	(0.8	)	$	325.4

Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	0.8	$	—	$	(0.8	)	$	—
Total financial liabilities	$	—	$	0.8	$	—	$	(0.8	)	$	—

	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
	March 31, 2015				December 31, 2014
	(in millions)
Financial assets
Cash and cash equivalents	$	500.4	$	500.4	$	1,160.1	$	1,160.1
Financial liabilities
Checks outstanding in excess of cash balances	$	15.8	$	15.8	$	54.7	$	54.7
Long-term debt	$	2,218.3	$	2,248.5	$	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. 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 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 IntercontinentalExchange, 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 contracts as of March 31, 2015:



Year	Type of Contract	Index	Total Volumes	Average Swap price per unit
			(in millions)
Gas sales			(MMBtu)
2015	SWAP	NYMEX HH	52.3	$	3.48
2015	SWAP	IFNPCR	35.8	$	3.55
2016	SWAP	NYMEX HH	14.6	$	3.29
2016	SWAP	IFNPCR	11.0	$	2.97
Oil sales			(bbls)
2015	SWAP	NYMEX WTI	6.6	$	85.89
2015	SWAP	ICE Brent	0.3	$	104.95
2016	SWAP	NYMEX WTI	1.1	$	70.85

The following table sets forth QEP Energy's crude oil collars as of March 31, 2015:

Total Volume

Average Price

Year

Index

Floor

Ceiling

(in millions)

($/bbl)

(bbls)

2015

NYMEX WTI

0.3

50.00

64.35

The following table sets forth QEP Energy's gas basis swaps as of March 31, 2015:



Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)	($/MMBtu)
Gas basis swaps			(MMBtu)
2015	NYMEX HH	IFNPCR	27.5	$	(0.30	)

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 March 31, 2015:



Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2015	SWAP	IFNPCR	1.7	$	3.29
2016	SWAP	IFNPCR	1.4	$	3.34
Gas purchases			(MMBtu)
2015	SWAP	IFNPCR	1.3	$	2.88

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	March 31, 2015		December 31, 2014		March 31, 2015		December 31, 2014
		(in millions)
Current:
Commodity	Fair value of derivative contracts	$	312.5	$	339.3	$	0.8	$	0.3
Long-term:
Commodity	Fair value of derivative contracts	13.7		9.9		—		—
Total derivative instruments		$	326.2	$	349.2	$	0.8	$	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 tables:



	Three Months Ended
Derivative instruments not designated as cash flow hedges	March 31,
Derivative instruments not designated as cash flow hedges	2015			2014
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	17.9		$	(20.4	)
Oil derivative contracts	84.0			(12.9		)
QEP Marketing
Gas derivative contracts	2.5			(1.4		)
Total realized gains (losses) on commodity derivative contracts	104.4			(34.7		)
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	11.4			(24.3		)
Oil derivative contracts	(33.1		)	(20.9		)
QEP Marketing
Gas derivative contracts	(1.8		)	(0.3		)
Total unrealized gains (losses) on commodity derivative contracts	(23.5		)	(45.5		)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	80.9		$	(80.2	)

Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	—		$	(0.7	)
Total realized gains (losses) on interest rate swaps	$	—		$	(0.7	)
Total net realized gains (losses) on derivative contracts	$	104.4		$	(35.4	)
Total net unrealized gains (losses) on derivative contracts	(23.5		)	(45.5		)
Grand Total	$	80.9		$	(80.9	)

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:



	March 31, 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	(3.5		)	(3.7		)
Total long-term debt outstanding	$	2,218.3		$	2,218.1

Of the total debt outstanding on March 31, 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 Facilities

QEP's 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 three months ended March 31, 2014, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.19%. At March 31, 2015 and December 31, 2014, QEP had no borrowings outstanding, 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 March 31, 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 some or all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP’s senior notes contain customary events of default and covenants that may limit QEP’s ability to, among other things, place liens on its property or assets.

Note 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. While the appeal is pending, 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., 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.

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 March 31, 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's Long Term Incentive Plan) are reflected in "Net income from discontinued operations, net of income tax". During the three months ended March 31, 2015, QEP recognized $9.1 million in total compensation expense related to share-based compensation for continuing operations, compared to $6.4 million during the three months ended March 31, 2014. During the three months ended March 31, 2014, QEP recognized $1.1 million 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 three months ended March 31, 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
Forfeited	(2,817	)	31.31
Canceled	(60,000	)	27.84
Outstanding at March 31, 2015	2,359,275		$	27.37	3.72	$	0.2
Options Exercisable at March 31, 2015	1,673,563		$	28.24	2.63	$	0.2
Unvested Options at March 31, 2015	685,712		$	25.23	6.37	$	—

During the three months ended March 31, 2015, there were no exercises of stock options. The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised during the three months ended March 31, 2014 was $0.2 million. As of March 31, 2015, $4.0 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.57 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 three months ended March 31, 2015 and 2014, was $18.0 million and $15.1 million, respectively. The weighted average grant-date fair value of restricted stock was $21.67 per share and $31.69 per share for the three months ended March 31, 2015 and 2014, respectively. As of March 31, 2015, $39.7 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 2.64 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	1,359,488		21.67
Vested	(584,111	)	30.88
Forfeited	(61,144	)	28.48
Unvested balance at March 31, 2015	2,140,686		$	25.19

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 March 31, 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 $31.69 per share for the three months ended March 31, 2015 and 2014, respectively. As of March 31, 2015, $3.1 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 2.29 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 March 31, 2015	633,225		$	27.52

____________________________


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

Note 12 – Employee Benefits

The Company maintains the QEP Resources, Inc. Retirement Plan, a closed, defined-benefit pension plan (the Pension Plan) and a postretirement medical plan. The Company's postretirement medical plan is unfunded and provides certain health care and life insurance benefits for certain retired employees. The Pension Plan includes a qualified and a nonqualified retirement plan. The nonqualified retirement plan is the Supplemental Executive Retirement Plan (SERP). During the three months ended March 31, 2015, the Company made contributions of $1.0 million to its funded qualified pension plan. Contributions to funded qualified plans increase plan assets. During the three months ended March 31, 2015, the Company made contributions of $0.4 million to its SERP. Payments to the SERP are used to fund current benefit payments. During the remainder of 2015, the Company expects to contribute $3.0 million to its funded qualified pension plan, $4.0 million to its SERP and $0.3 million for retiree health care and life insurance benefits. During the three months ended March 31, 2015, for continuing operations, QEP recognized $1.7 million in recurring employee benefit expense, compared to $2.0 million during the three months ended March 31, 2014. During the three months ended March 31, 2014, for discontinued operations, QEP recognized $0.5 million in recurring employee benefit expense.

The following table sets forth the Company’s pension and postretirement benefits net periodic benefit costs:



	Pension
	Three Months Ended
	March 31,
	2015			2014
	(in millions)
Service cost	$	0.6		$	0.7
Interest cost	1.3			1.4
Expected return on plan assets	(1.4		)	(1.2		)
Amortization of prior service costs ⁽¹⁾	0.8			1.2
Amortization of actuarial losses ⁽¹⁾	0.3			0.2
Periodic expense	$	1.6		$	2.3

____________________________


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



	Postretirement Benefits
	Three Months Ended
	March 31,
	2015		2014
	(in millions)
Interest cost	$	0.1	$	0.1
Amortization of prior service costs ⁽¹⁾	—		0.1
Periodic expense	$	0.1	$	0.2

____________________________


⁽¹⁾	Amortization of prior service costs out of AOCI are recognized in the Condensed Consolidated Statements of Operations in "General and administrative."

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 months ended March 31, 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 March 31, 2015, by line of business:



	QEP Energy			QEP Marketing and Other			Eliminations			QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	353.3		$	138.3		$	—		$	491.6
From affiliated customers	—			207.5			(207.5		)	—
Total Revenues	353.3			345.8			(207.5		)	491.6
OPERATING EXPENSES
Purchased gas and oil expense	31.2			342.8			(204.6		)	169.4
Lease operating expense	61.8			—			—			61.8
Gas, oil and NGL transportation and other handling costs	67.4			—			(2.3		)	65.1
Gathering and other expense	—			1.7			—			1.7
General and administrative	46.2			1.8			(0.6		)	47.4
Production and property taxes	27.5			0.3			—			27.8
Depreciation, depletion and amortization	192.7			2.7			—			195.4
Impairment and exploration expense	21.1			—			—			21.1
Total Operating Expenses	447.9			349.3			(207.5		)	589.7
Net gain (loss) from asset sales	(27.8		)	(2.7		)	—			(30.5		)
OPERATING INCOME (LOSS)	(122.4		)	(6.2		)	—			(128.6		)
Realized and unrealized gains (losses) on derivative contracts	80.2			0.7			—			80.9
Interest and other income (expense)	(3.5		)	48.0			(47.1		)	(2.6		)
Interest expense	(47.2		)	(36.7		)	47.1			(36.8		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(92.9		)	5.8			—			(87.1		)
Income tax (provision) benefit	33.6			(2.1		)	—			31.5
NET INCOME (LOSS)	$	(59.3	)	$	3.7		$	—		$	(55.6	)

The following table is a summary of operating results for the three months ended March 31, 2014, by line of business:



	QEP Energy			QEP Marketing and Other			Eliminations			Discontinued Operations		QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	613.2		$	204.3		$	—		$	—	$	817.5
From affiliated customers	—			303.5			(303.5		)	—		—
Total Revenues	613.2			507.8			(303.5		)	—		817.5
OPERATING EXPENSES
Purchased gas and oil expense	38.0			497.9			(298.0		)	—		237.9
Lease operating expense	56.4			—			—			—		56.4
Gas, oil and NGL transportation and other handling costs	64.5			—			(4.6		)	—		59.9
Gathering and other expense	—			1.6			—			—		1.6
General and administrative	45.0			1.2			(0.9		)	—		45.3
Production and property taxes	47.4			0.5			—			—		47.9
Depreciation, depletion and amortization	223.4			2.5			—			—		225.9
Impairment and exploration expense	4.2			—			—			—		4.2
Total Operating Expenses	478.9			503.7			(303.5		)	—		679.1
Net gain (loss) from assets sales	2.4			—			—			—		2.4
OPERATING INCOME (LOSS)	136.7			4.1			—			—		140.8
Realized and unrealized gains (losses) on derivative contracts	(78.5		)	(2.4		)	—			—		(80.9		)
Interest and other income (expense)	2.9			48.8			(48.8		)	—		2.9
Interest expense	(48.9		)	(41.8		)	48.8			—		(41.9		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	12.2			8.7			—			—		20.9
Income tax (provision) benefit	(7.1		)	(1.1		)	—			—		(8.2		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	5.1			7.6			—			—		12.7
Net income from discontinued operations, net of income tax	—			—			—			27.0		27.0
NET INCOME (LOSS)	$	5.1		$	7.6		$	—		$	27.0	$	39.7
Identifiable total assets	$	9,004.1		$	225.3		$	—		1,306.2		$	10,535.6

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 months ended March 31, 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, while locking 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.

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.

In response to the current commodity price environment, we are reducing drilling and completion activities, slowing production growth, and preserving liquidity. During the first quarter of 2015, we reduced QEP operated drilling rigs from 21 during 2014 to 11 at the end of the first quarter of 2015. We have reduced our capital expenditure budget for 2015 to approximately $975.0 million from $2,726.4 million in 2014 (which included $941.8 million for the Permian Basin Acquisition). We are highly focused on driving improved operating performance by optimizing reservoir development, enhancing well completion designs and aggressively pursuing cost reductions.

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

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 consist 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 creates 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 from QEP's revolving credit facility.

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 may periodically divest select non-core portfolio assets to redirect capital towards higher-return projects. 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 $692.9 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 months ended March 31, 2015, no shares were repurchased under this plan.

Financial and Operating Results

QEP Energy reported total equivalent production of 75.2 Bcfe during the first quarter of 2015, an increase of 2% compared to the first quarter of 2014. Oil production increased 1,169.4 Mbbls in the first quarter of 2015, an increase of 35% from the first quarter of 2014. Contributing to this increase was continuing development of properties in the Williston Basin, which contributed oil production of 3,431.5 Mbbls in the first quarter of 2015 compared to 2,520.2 Mbbls in the first quarter of 2014. Additionally, QEP Energy completed the Permian Basin Acquisition on February 25, 2014, which contributed 571.8 Mbbls of oil production during the first quarter of 2015, compared to 140.0 Mbbls of oil production during the period from February 25, 2014 to March 31, 2014. These increases were partially offset by a decrease in gas production to 42.6 Bcf in the first quarter of 2015, a decrease of 4% from the first quarter of 2014, and a decrease in NGL production to 947.4 Mbbls in the first quarter of 2015, a decrease of 40% from the first quarter of 2014. 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 quarter of 2015 compared to ethane recovery in the first quarter of 2014. Average realized prices (including the impact of settled commodity derivatives) decreased 24% to $5.61 per Mcfe during the first quarter of 2015 due primarily to decreases in commodity index pricing when compared to the first quarter of 2014.

Factors Affecting Results of Operations

Oil, Gas, and NGL Prices

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 Marcellus Shale region, have resulted in downward pressure on U.S. natural gas prices and a high degree of pricing variability among different 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 and adequate storage levels led to natural gas price declines later in the year and into 2015. Similarly, growth in U.S. oil production in excess of 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 that have continued into 2015. NGL prices have also been affected by increased U.S. hydrocarbon production. Prices of heavier NGL components are typically correlated to crude oil prices, while ethane and propane prices have decreased as a result of oversupply. In addition, QEP's NGL prices are affected by ethane recovery. When ethane is recovered as an NGL instead of being sold as part of the natural gas stream, the average NGL barrel sales price 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 quarter of 2015 and expects to continue to reject ethane throughout 2015 due to the recent decline in ethane and propane 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.

During 2014, the NYMEX-WTI oil monthly average spot price ranged from a high of $105.79 per bbl in June to a low of $59.29 per bbl in December, while the NYMEX-HH natural gas one-month future price ranged from a high of $5.15 per MMBtu in February to a low of $3.65 per MMBtu in November. 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 $2.58 per MMBtu in February 2015. Due to increased uncertainty around the global economic outlook and the volatility of commodity prices, QEP has built a strong liquidity position to ensure financial flexibility. In response to significantly lower commodity prices, QEP 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 March 31, 2015, assuming forecasted 2015 annual production of 301 Bcfe, QEP Energy had approximately 56% of its forecasted gas equivalent production covered with fixed-price swaps, including 65% of its forecasted gas production and 53% 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 outlook of the global economy, including Europe's economic outlook; political unrest in Eastern Europe, the Middle East, and Africa; slowing growth in Asia; the United States' federal budget deficit; changes in regulatory oversight policy; commodity price volatility; 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 throughout 2013 and 2014, 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 last half of 2013 and into 2014. Natural gas prices weakened in the second half of 2014 and through the first quarter of 2015 due to more typical

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. QEP expects that ethane prices will continue to be range-bound until new ethylene crackers and export facilities are built. 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 EIA, U.S. oil production has increased by more than three million barrels per day, or more than 50%, since 2011. International oil supply disruptions in recent years have prevented oversupply and a corresponding negative price impact, but reduced supply disruptions in recent months 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 oil 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. The Company recorded $20.0 million of impairment expense during the first quarter of 2015, of which $19.4 million was related to proved properties due to lower future prices and $0.6 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 first quarter of 2015 of $55.6 million, or $0.32 per diluted share, compared to net income from continuing operations of $12.7 million, or $0.07 per diluted share, in the first quarter of 2014. The decrease in the first quarter of 2015 was due to a $64.4 million decrease in QEP Energy’s net income and a $3.9 million decrease in QEP Marketing and Other's net income. QEP Energy's net income decrease was primarily due to decreases in average field-level prices for gas, oil and NGL. These decreases were partially offset by realized derivative instrument gains in the first quarter of 2015 compared to realized losses in the first quarter of 2014 and lower operating expenses in the first quarter of 2015 compared to the first quarter of 2014. QEP Marketing and Other's net income decreased in the first quarter of 2015 primarily due to a lower resale margin and a net loss from asset sales of $2.7 million during the first quarter of 2015 related to purchase price adjustments for the Midstream Sale.

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



	Three Months Ended March 31,
	2015			2014		Change
	(in millions, except per share amounts)
QEP Energy	$	(59.3	)	$	5.1	$	(64.4	)
QEP Marketing and Other	3.7			7.6		(3.9		)
Net income (loss) from continuing operations	(55.6		)	12.7		(68.3		)
Net income from discontinued operations, net of income tax	—			27.0		(27.0		)
Net income (loss)	$	(55.6	)	$	39.7	$	(95.3	)
Diluted earnings per share from continuing operations	$	(0.32	)	$	0.07	$	(0.39	)
Diluted earnings per share from discontinued operations	—			0.15		(0.15		)
Diluted earnings per share	$	(0.32	)	$	0.22	$	(0.54	)
Average diluted shares	176.2			180.0		(3.8		)

Adjusted EBITDA

Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure of the Company's cash flow, liquidity, and ability to incur and service debt, fund capital expenditures and return capital to shareholders. The use of this measure 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 March 31,
	2015		2014		Change
	(in millions)
QEP Energy	$	221.1	$	328.6	$	(107.5	)
QEP Marketing and Other	1.7		4.5		(2.8		)
Adjusted EBITDA from continuing operations	222.8		333.1		(110.3		)
Adjusted EBITDA from discontinued operations	—		53.2		(53.2		)
Adjusted EBITDA	$	222.8	$	386.3	$	(163.5	)

Adjusted EBITDA from continuing operations decreased to $222.8 million in the first quarter of 2015 from $333.1 million in the first quarter of 2014, due to a 24% decrease in average net realized equivalent gas, oil and NGL prices as well as a 4% decrease in gas production and a 40% decrease in NGL production. These decreases were partially offset by a 35% increase in oil production and lower production and property taxes.

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 March 31, 2015	(in millions)
Net income (loss)	$	(59.3	)	$	3.7		$	(55.6	)	$	—	$	(55.6	)
Unrealized (gains) losses on derivative contracts	21.7			1.8			23.5			—		23.5
Net (gain) loss from asset sales	27.8			2.7			30.5			—		30.5
Interest and other (income) expense	3.5			(0.9		)	2.6			—		2.6
Income tax provision (benefit)	(33.6		)	2.1			(31.5		)	—		(31.5		)
Interest expense (income)	47.2			(10.4		)	36.8			—		36.8
Depreciation, depletion and amortization	192.7			2.7			195.4			—		195.4
Impairment	20.0			—			20.0			—		20.0
Exploration expenses	1.1			—			1.1			—		1.1
Adjusted EBITDA	$	221.1		$	1.7		$	222.8		$	—	$	222.8

Three Months Ended March 31, 2014
Net income (loss)	$	5.1		$	7.6		$	12.7		27.0		$	39.7
Unrealized (gains) losses on derivative contracts	45.2			0.3			45.5			—		45.5
Net (gain) loss from asset sales	(2.4		)	—			(2.4		)	—		(2.4		)
Interest and other (income) expense	(2.9		)	—			(2.9		)	—		(2.9		)
Income tax provision (benefit)	7.1			1.1			8.2			15.2		23.4
Interest expense (income) ⁽²⁾	48.9			(7.0		)	41.9			0.4		42.3
Depreciation, depletion and amortization ⁽³⁾	223.4			2.5			225.9			10.6		236.5
Impairment	2.0			—			2.0			—		2.0
Exploration expenses	2.2			—			2.2			—		2.2
Adjusted EBITDA	$	328.6		$	4.5		$	333.1		$	53.2	$	386.3

__________________________

⁽¹⁾ Includes intercompany eliminations.

⁽²⁾ Excludes noncontrolling interest's share of $0.2 million during the three months ended March 31, 2014, of interest expense attributable to QEP Midstream.

⁽³⁾Excludes noncontrolling interest's share of $3.7 million during the three months ended March 31, 2014, 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 March 31,
	2015			2014			Change
REVENUES	(in millions)
Gas sales	$	122.0		$	222.5		$	(100.5	)
Oil sales	178.8			288.7			(109.9		)
NGL sales	19.0			63.1			(44.1		)
Purchased gas sales	31.5			37.1			(5.6		)
Other	2.0			1.8			0.2
Total Revenues	353.3			613.2			(259.9		)
OPERATING EXPENSES
Purchased gas expense	31.2			38.0			(6.8		)
Lease operating expense	61.8			56.4			5.4
Gas, oil and NGL transportation and other handling costs	67.4			64.5			2.9
General and administrative	46.2			45.0			1.2
Production and property taxes	27.5			47.4			(19.9		)
Depreciation, depletion and amortization	192.7			223.4			(30.7		)
Exploration expenses	1.1			2.2			(1.1		)
Impairment	20.0			2.0			18.0
Total Operating Expenses	447.9			478.9			(31.0		)
Net gain (loss) from asset sales	(27.8		)	2.4			(30.2		)
OPERATING INCOME (LOSS)	(122.4		)	136.7			(259.1		)
Realized gains (losses) on derivative instruments	101.9			(33.3		)	135.2
Unrealized gains (losses) on derivative instruments	(21.7		)	(45.2		)	23.5
Interest and other income (expense)	(3.5		)	2.9			(6.4		)
Interest expense	(47.2		)	(48.9		)	1.7
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(92.9		)	12.2			(105.1		)
Income tax (provision) benefit	33.6			(7.1		)	40.7
NET INCOME (LOSS)	$	(59.3	)	$	5.1		$	(64.4	)

Production volumes (Bcfe)
Northern Region
Pinedale	21.8			20.9			0.9
Williston Basin	25.4			16.8			8.6
Uinta Basin	6.9			6.2			0.7
Other Northern	2.7			2.5			0.2
Southern Region
Haynesville/Cotton Valley	11.7			14.4			(2.7		)
Permian Basin	4.9			1.2			3.7
Midcontinent	1.8			11.7			(9.9		)
Total production	75.2			73.7			1.5
Total equivalent prices (per Mcfe)
Average equivalent field-level price	$	4.25		$	7.79		$	(3.54	)
Commodity derivative impact	1.36			(0.45		)	1.81
Net realized equivalent price	$	5.61		$	7.34		$	(1.73	)

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 months ended March 31, 2015, compared to the three months ended March 31, 2014:



	Gas			Oil			NGL			Total
	(in millions)
QEP Energy Production Revenues
Three months ended March 31, 2014 Revenues	$	222.5		$	288.7		$	63.1		$	574.3
Changes associated with volumes ⁽¹⁾	(9.5		)	101.9			(25.0		)	67.4
Changes associated with prices ⁽²⁾	(91.0		)	(211.8		)	(19.1		)	(321.9		)
Three months ended March 31, 2015 Revenues	$	122.0		$	178.8		$	19.0		$	319.8

____________________________


⁽¹⁾	The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three months ended March 31, 2015, as compared to the three months ended March 31, 2014, by the average field-level price for the three months ended March 31, 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 months ended March 31, 2015, as compared to the three months ended March 31, 2014, by volumes for the three months ended March 31, 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 March 31,
	2015		2014			Change
Gas production volumes (Bcf)
Northern Region
Pinedale	19.0		15.9			3.1
Williston Basin	2.7		0.7			2.0
Uinta Basin	4.9		4.1			0.8
Other Northern	2.4		2.2			0.2
Southern Region
Haynesville/Cotton Valley	11.6		14.3			(2.7		)
Permian Basin	0.7		0.2			0.5
Midcontinent	1.3		7.1			(5.8		)
Total production	42.6		44.5			(1.9		)
Gas prices (per Mcf)
Northern Region	$	2.85	$	5.12		$	(2.27	)
Southern Region	2.89		4.89			(2.00		)
Average field-level price	2.87		5.00			(2.13		)
Commodity derivative impact	0.42		(0.46		)	0.88
Net realized price	$	3.29	$	4.54		$	(1.25	)

Gas revenues decreased $100.5 million, or 45%, in the first quarter of 2015 when compared to the first quarter of 2014 due to lower field-level prices and lower gas production. Average field-level gas prices decreased 43% in the first quarter of 2015 compared to the first quarter of 2014 driven by a decrease in average NYMEX-HH natural gas prices for the comparable periods. The decrease in production was primarily driven by the divestitures of non-core Midcontinent properties in the second and fourth quarters of 2014 and the production decrease in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program. These production decreases were partially offset by a production increase in Pinedale due to additional 2014 net well completions, and a production increase in the Williston Basin due to 2014 development.

Oil Volumes and Prices



	Three Months Ended March 31,
	2015		2014			Change
Oil production volumes (Mbbls)
Northern Region
Pinedale	145.5		133.1			12.4
Williston Basin	3,431.5		2,520.2			911.3
Uinta Basin	221.6		212.4			9.2
Other Northern	45.1		49.1			(4.0		)
Southern Region
Haynesville/Cotton Valley	7.8		9.2			(1.4		)
Permian Basin	571.8		140.0			431.8
Midcontinent	58.1		248.0			(189.9		)
Total production	4,481.4		3,312.0			1,169.4
Oil prices (per bbl)
Northern Region	$	38.75	$	86.53		$	(47.78	)
Southern Region	46.76		91.80			(45.04		)
Average field-level price	39.89		87.16			(47.27		)
Commodity derivative impact	18.75		(3.91		)	22.66
Net realized price	$	58.64	$	83.25		$	(24.61	)

Oil revenues decreased $109.9 million, or 38%, in the first quarter of 2015 when compared to the first quarter of 2014, due to lower average field-level prices partially offset by higher volumes. Average field-level oil prices decreased 54% in the first quarter of 2015 compared to the first quarter of 2014, driven by a 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 Basin due to continued development during 2014. The Company also had an increase in production of 431.8 Mbbls from the Permian Basin due to continued development combined with a full quarter of production in 2015 compared to one month of production in the first quarter of 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 March 31,
	2015		2014		Change
NGL production volumes (Mbbls)
Northern Region
Pinedale	313.0		714.8		(401.8		)
Williston Basin	358.8		160.9		197.9
Uinta Basin	109.4		139.4		(30.0		)
Other Northern	2.7		2.0		0.7
Southern Region
Haynesville/Cotton Valley	7.1		7.8		(0.7		)
Permian Basin	119.8		33.0		86.8
Midcontinent	36.6		510.4		(473.8		)
Total production	947.4		1,568.3		(620.9		)
NGL prices (per bbl)
Northern Region	$	21.25	$	39.74	$	(18.49	)
Southern Region	14.53		41.24		(26.71		)
Average field-level price	20.09		40.26		(20.17		)
Commodity derivative impact	—		—		—
Net realized price	$	20.09	$	40.26	$	(20.17	)

NGL revenues decreased $44.1 million, or 70%, during the first quarter of 2015 when compared to the first 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 due to ethane rejection in the first quarter of 2015 compared to ethane recovery in the first quarter of 2014. These decreases were partially offset by increases in NGL volumes in the Williston Basin as a result of increased development drilling and well completions. Additionally, the Permian Basin Acquisition contributed to the increased NGL production due to a full quarter of production in 2015 compared to one month of production in the first quarter of 2014. NGL prices decreased 50% during the first quarter of 2015 compared to the first quarter of 2014 driven by a decrease in index pricing for the NGL components.

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 March 31,
	2015			2014			Change
Resale Margin	(in millions)
Purchased gas sales	$	31.5		$	37.1		$	(5.6	)
Purchased gas expense	(31.2		)	(38.0		)	6.8
Resale margin	$	0.3		$	(0.9	)	$	1.2

During the first quarter of 2015, QEP Energy recorded income on resale margin of $0.3 million compared to a $0.9 million loss in the first quarter of 2014 as a 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 months ended March 31, 2015:



	Operated Completions		Non-operated Completions
	Gross	Net	Gross	Net
Northern Region
Pinedale	20	14.5	—	—
Williston Basin	16	12.8	22	1.7
Uinta Basin	1	1.0	—	—
Other Northern	1	1.0	—	—
Southern Region
Haynesville/Cotton Valley	—	—	9	0.4
Permian Basin⁽¹⁾	11	10.1	1	0.3
Midcontinent	—	—	3	0.1

____________________________


⁽¹⁾	Operated completions includes seven gross, 6.4 net, vertical wells.

The following table presents operated and non-operated wells drilling or waiting on completion, at March 31, 2015:



	Operated				Non-operated
	Drilling		Waiting on completion		Drilling		Waiting on completion
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale⁽¹⁾	17	11.2	46	28.0	—	—	—	—
Williston Basin	7	4.6	40	30.0	7	0.2	17	0.9
Uinta Basin	3	3.0	5	5.0	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	2	0.2	19	2.9
Permian Basin⁽²⁾	4	3.7	6	3.9	—	—	1	0.6
Midcontinent	—	—	—	—	1	—	1	—

________________________


⁽¹⁾	QEP suspends Pinedale completions during the coldest months of the winter, usually from December to mid-March.


⁽²⁾	Operated drilling includes one net vertical well.

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 97 gross operated wells waiting on completion as of March 31, 2015.

Operating expenses

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



	Three Months Ended March 31,
	2015		2014		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	2.56	$	3.03	$	(0.47	)
Lease operating expense	0.82		0.76		0.06
Gas, oil and NGL transportation and other handling costs	0.90		0.88		0.02
Production and property taxes	0.37		0.65		(0.28		)
Operating Expenses	$	4.65	$	5.32	$	(0.67	)

Depreciation, depletion and amortization (DD&A). DD&A expense decreased $30.7 million, or $0.47 per Mcfe, in the first quarter of 2015 compared to the first quarter of 2014, due to decreases in the Haynesville/Cotton Valley and Midcontinent, partially offset by increases in the Permian and Williston basins. 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 an impairment at year-end 2014. The increases in the Permian and Williston basins' DD&A expense relates to increased production and Permian Basin operating for a full quarter in 2015 compared to a partial quarter of production in 2014.

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 March 31,
	2015		2014		Change
	(per Mcfe)
Northern Region	$	0.71	$	0.77	$	(0.06	)
Southern Region	1.17		0.75		0.42
Average lease operating expense	0.82		0.76		0.06

QEP Energy’s LOE increased $5.4 million, or $0.06 per Mcfe, during the first quarter of 2015 compared to the first quarter of 2014. The increase in the Southern Region's LOE during the first quarter 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 in the Southern Region, and an increase on a per Mcfe basis in QEP's remaining Midcontinent properties that carry higher operating costs than the properties that were divested in 2014. The Northern Region per Mcfe decrease was driven primarily by new high-rate wells and cost reductions in the Williston Basin, offset by declining production on older wells in the Northern Region.

Gas, oil and NGL transportation and other handling costs. Gas, oil and NGL transportation and other handling costs increased $2.9 million, or $0.02 per Mcfe, in the first quarter of 2015 when compared to the first quarter of 2014. The per Mcfe expense increase was primarily attributable to additional expenses incurred in the Permian Basin, partially offset by a decrease in the Williston Basin due to a reduction in the NGL processing and transportation costs.

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 $19.9 million, or $0.28 per Mcfe, during the first quarter 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 $1.1 million during the first quarter of 2015 compared to the first quarter of 2014. These decreases primarily related to lower exploration-related labor expenses.

Impairment expense. Impairment expense was $20.0 million during the first quarter of 2015, of which $19.4 million was related to proved properties due to lower future prices and $0.6 million was related to expiring leaseholds on unproved properties. Of the $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 $2.0 million in the first quarter 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 retained interest in the Haynesville Gathering System, 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 March 31,
	2015			2014			Change
	(in millions)
REVENUES
Purchased gas and oil sales	$	340.5		$	501.5		$	(161.0	)
Other	5.3			6.3			(1.0		)
Total Revenues	345.8			507.8			(162.0		)
OPERATING EXPENSES
Purchased gas and oil expense	342.8			497.9			(155.1		)
Gathering and other expense	1.7			1.6			0.1
General and administrative	1.8			1.2			0.6
Production and property taxes	0.3			0.5			(0.2		)
Depreciation, depletion and amortization	2.7			2.5			0.2
Total Operating Expenses	349.3			503.7			(154.4		)
Net gain (loss) from asset sales	(2.7		)	—			(2.7		)
OPERATING INCOME (LOSS)	(6.2		)	4.1			(10.3		)
Realized gains (losses) on derivative instruments	2.5			(2.1		)	4.6
Unrealized gains (losses) on derivative instruments	(1.8		)	(0.3		)	(1.5		)
Interest and other income (expense)	48.0			48.8			(0.8		)
Interest expense	(36.7		)	(41.8		)	5.1
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	5.8			8.7			(2.9		)
Income tax (provision) benefit	(2.1		)	(1.1		)	(1.0		)
NET INCOME (LOSS)	$	3.7		$	7.6		$	(3.9	)

Resale Margin

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



	Three Months Ended March 31,
	2015			2014			Change
Resale Margin	(in millions)
Purchased gas and oil sales	$	340.5		$	501.5		$	(161.0	)
Purchased gas and oil expense	(342.8		)	(497.9		)	155.1
Realized gains (losses) on derivative instruments	2.5			(2.1		)	4.6
Resale margin	$	0.2		$	1.5		$	(1.3	)

Purchased gas and oil sales decreased by $161.0 million, or 32%, during the first quarter of 2015 compared to the first quarter of 2014, due to a $84.4 million decrease in resale oil sales and a $76.6 million decrease in resale gas sales. Resale oil sales decreased due to a 55% decrease in resale price, partially offset by a 62% increase in resale volumes. Resale gas sales decreased due to a 45% decrease in resale price, partially offset by a 4% increase in resale volumes.

Purchased gas and oil expense, which includes transportation expense, decreased by $155.1 million, or 31%, in the first quarter of 2015 compared to the first quarter of 2014, due to an $83.8 million decrease in resale oil purchases and a $71.3 million decrease in resale gas purchases. Resale oil purchases expense decreased due to a 56% decrease in resale purchase price,

partially offset by a 68% increase in resale purchase volumes. Resale gas purchases expense decreased due to a 34% decrease in the resale purchase price and a 5% decrease in resale purchase volumes.

QEP Resources

Other Consolidated Expenses and Income from Continuing and Discontinued Operations

General and administrative expense. During the first quarter of 2015, general and administrative (G&A) expense increased $2.1 million, or 5%, compared to the first quarter of 2014, primarily due to the following: $5.3 million increase in labor and benefits costs associated with an increase in the average number of employees and severance payments related to workforce reduction efforts in the first quarter of 2015 and $3.3 million increase in stock compensation related to grants made in 2015 and changes in QEP's stock price that impacted the mark-to-market value of the Deferred Compensation Wrap Plan and Cash Incentive Plan. These increases were partially offset by a $6.3 million decrease in professional and outside services mainly related to the 2014 Enterprise Resource Planning (ERP) system implementation and additional decreases in other employee expenses.

Net gain (loss) from asset sales. QEP recognized a loss on sale of assets of $30.5 million during the first quarter of 2015 compared to a gain on sale of $2.4 million in the first quarter of 2014. The loss on sale of assets recognized during the first quarter of 2015 was primarily due to $28.6 million in post-closing adjustments related to QEP Energy's sale of its interest in non-core oil and gas properties in the Midcontinent area in 2014. The gain on sale recognized during the first quarter of 2014 related to QEP Energy's sale of its interest in other non-core oil and gas properties for a pre-tax gain on sale of $2.4 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 first quarter of 2015, gains on commodity derivative instruments were $80.9 million, of which $104.4 million were realized gains, partially offset by $23.5 million of unrealized losses. During the first quarter of 2014, losses on commodity derivative instruments were $80.2 million, of which $34.7 million were realized and $45.5 million were unrealized. Additionally, during the first quarter of 2014, losses from interest rate swaps were $0.7 million, all of which were realized. All of QEP's interest rate swaps were settled in the fourth quarter of 2014.

Interest expense. Interest expense decreased $5.1 million, or 12%, during the three months ended March 31, 2015, compared to the three months ended March 31, 2014. The decrease was attributable to average debt levels in the first quarter of 2015 that were $1,240.1 million, or 36%, lower than average debt levels in the first 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.

Income taxes. Income tax benefit was $31.5 million during the first quarter of 2015 compared to an income tax provision of $8.2 million during the first quarter of 2014. The income tax rate was 36.2% during the first quarter of 2015 compared to a rate of 39.2% during the first quarter of 2014. The decrease in the effective tax rate is due primarily to a lower state tax rate and the incremental impact of permanent items.

Discontinued operations. Discontinued operations represent results of operations from QEP Field Services, excluding QEP’s retained Haynesville Gathering System. During the first quarter of 2014, net income from discontinued operations was $27.0 million, primarily attributable to NGL sales revenue of $38.0 million and other revenue of $41.9 million, which primarily consists of gathering and processing revenue, partially offset by gathering, processing and other expense of $24.3 million, DD&A of $14.3 million and G&A of $11.3 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:



	March 31, 2015			December 31, 2014
	(in millions, except %)
Cash and cash equivalents	$	500.4		$	1,160.1
Amount available under the QEP credit facility ⁽¹⁾	1,796.3			1,796.3
Total liquidity	$	2,296.7		$	2,956.4
Total debt	$	2,218.3		$	2,218.1
Total common shareholders' equity	$	4,019.9		$	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 March 31, 2015 and December 31, 2014, respectively.


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

QEP's Credit Facility

Senior Notes

The Company’s senior notes outstanding as of March 31, 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 $595.1 million during the first quarter of 2015 compared to the first quarter of 2014, due to a decrease in changes in operating assets and liabilities, lower non-cash adjustments to net income and a net loss incurred during the first quarter of 2015. Changes in operating activities decreased $453.9 million, which was mainly due to a decrease in income taxes payable from the gain on the Midstream Sale, which were paid in the first quarter of 2015. Net cash from operating activities is presented below:



	Three Months Ended March 31,
	2015			2014			Change
	(in millions)
Net income (loss)	$	(55.6	)	$	39.7		$	(95.3	)
Net income attributable to noncontrolling interest	—			5.8			(5.8		)
Noncash adjustments to net income	275.6			315.7			(40.1		)
Changes in operating assets and liabilities	(492.7		)	(38.8		)	(453.9		)
Net cash (used in) provided by operating activities	$	(272.7	)	$	322.4		$	(595.1	)

Cash Flow from Investing Activities

In the first quarter of 2015, net cash used in investing activities was $340.5 million, compared to $1,223.9 million in the first quarter of 2014. This decrease in investing activities was due to a 73% 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 quarter of 2015 and 2014 and a forecast for calendar year 2015 are presented in the table below:



	Three Months Ended								Current Forecast Twelve Months Ended		Prior Forecast Twelve Months Ended ⁽¹⁾
	March 31,								Current Forecast Twelve Months Ended		Prior Forecast Twelve Months Ended ⁽¹⁾
	2015		2014			Change			December 31, 2015		December 31, 2015
	(in millions)
QEP Energy	$	280.2	$	1,263.2		$	(983.0	)	$	960.0	$	960.0
QEP Marketing and Other	2.7		4.1			(1.4		)	15.0		15.0
Continuing Operations	282.9		1,267.3			(984.4		)	975.0		975.0
Discontinued Operations	—		21.1			(21.1		)	—		—
Total accrued capital expenditures	282.9		1,288.4			(1,005.5		)	975.0		975.0
Change in accruals	59.2		(11.6		)	70.8			—		—
Total cash capital expenditures	$	342.1	$	1,276.8		$	(934.7	)	$	975.0	$	975.0

____________________________


⁽¹⁾	Forecast as reported in the December 31, 2014, Form 10-K/A, filed on February 25, 2015.

In the first quarter of 2015, QEP Energy's capital expenditures, on an accrual basis, decreased $983.0 million over the first quarter of 2014 to a total of $280.2 million, which was primarily driven by the Permian Basin Acquisition. In addition, capital expenditures decreased $51.0 million in the Williston Basin and $23.4 million in Pinedale due to reductions in QEP's capital expenditures in response to the current pricing environment and $24.4 million in the Midcontinent due to 2014 divestitures. These decreases were partially offset by increases of $41.6 million in the Permian Basin and $13.8 million in Haynesville/Cotton Valley.

At March 31, 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, 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 quarter of 2015, net cash used in financing activities was $46.5 million compared to net cash provided by financing activities of $893.5 million in the first quarter of 2014. During the first quarter of 2015, QEP had checks outstanding in excess of cash balances of $38.9 million and $3.5 million of regular quarterly dividend payments. During the first quarter of 2014, QEP had borrowings from the credit facility of $1,643.0 million offset by repayments on the credit facility of $1,021.5 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 lower checks outstanding in excess of cash balances of $12.5 million and $3.6 million of regular quarterly dividends payment during the first quarter of 2014.

At March 31, 2015, the Company did not have any borrowings outstanding under the credit facility and $2,221.8 million in senior notes (excluding $3.5 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 March 31, 2015, QEP held commodity price derivative contracts totaling 145.5 million MMBtu of gas and 8.3 million barrels of oil.

The following table presents QEP's derivative positions as of April 24, 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 March 31, 2015.

QEP Energy Commodity Derivative Positions

Year	Type of Contract	Index	Total Volumes	Average Swap price per unit
			(in millions)
Gas sales			(MMBtu)
2015	SWAP	NYMEX HH	46.6	$	3.48
2015	SWAP	IFNPCR	31.9	$	3.55
2016	SWAP	NYMEX HH	18.3	$	3.24
2016	SWAP	IFNPCR	14.6	$	2.91
Oil Sales			(bbls)
2015	SWAP	NYMEX WTI	7.1	$	83.93
2015	SWAP	ICE Brent	0.3	$	104.95
2016	SWAP	NYMEX WTI	2.2	$	66.06

QEP Energy Crude Oil Collars

Total Volume

Average Price

Year

Index

Floor

Ceiling

(in millions)

($/bbl)

(bbls)

2015

NYMEX WTI

0.3

50.00

64.35

QEP Energy Gas Basis Swaps

Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)	($/MMBtu)
Gas basis swaps			(MMBtu)
2015	NYMEX HH	IFNPCR	24.5	$	(0.30	)

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	1.7	$	3.29
2016	SWAP	IFNPCR	1.7	$	3.20
Gas purchases			(MMBtu)
2015	SWAP	IFNPCR	1.6	$	2.77

Changes in the fair value of derivative contracts from December 31, 2014 to March 31, 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	(104.4		)
Change in oil and gas prices on futures markets	62.5
Contracts added	18.4
Net fair value of oil and gas derivative contracts outstanding at March 31, 2015	$	325.4

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



	March 31, 2015
	(in millions)
Net fair value - asset (liability)	$	325.4
Fair value if market prices of oil and gas and basis differentials decline by 10%	398.9
Fair value if market prices of oil and gas and basis differentials increase by 10%	250.9

Utilizing the actual derivative volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $74.5 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $73.5 million as of March 31, 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 March 31, 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:


•	impact of sale of our midstream business;


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


•	ability to pursue acquisition opportunities;


•	our growth strategies;


•	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;


•	factors impacting oil, gas and NGL prices;


•	impact of global geopolitical and macroeconomic events;


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


•	pro forma results for acquired properties;


•	plans to divest 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 pension plans;


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


•	delays caused by transportation and refining capacity issues;


•	fair value and critical accounting estimates;


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


•	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 March 31, 2015. Based on such evaluation, such officers have concluded that, as of March 31, 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 March 31, 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

In 2012, QEP completed a field audit of its operations in Northwest Louisiana, which identified 112 instances affecting approximately 90 acres where work may have discharged dredged or fill material into waters of the United States in violation of the Clean Water Act. QEP self-reported each of these instances to the Environmental Protection Agency (EPA) under the EPA's Audit Policy and to the U.S. Army Corps of Engineers (COE). In April 2015, QEP and the EPA executed Consent Agreements and Final Orders, under the terms of which QEP agreed to pay $0.2 million in civil penalties to resolve all violations. All of the impacts have been mitigated and permitted with COE.

In July 2010, QEP received a Notice of Potential Penalty (NOPP) from the Louisiana Department of Environmental Quality (LDEQ) regarding the assumption of ownership and operatorship of a single facility in Louisiana prior to transferring the facility's air quality permit. In 2011, QEP completed an internal audit, which identified 424 facilities in Louisiana for which QEP both failed to submit a complete permit application and to receive approval from the department prior to construction, modification, or operation. QEP has corrected and disclosed all instances of non-compliance to the LDEQ and is working with the department to resolve the NOPP. The LDEQ has assumed lead responsibility for enforcement of the NOPP, and may require the Company to pay a monetary penalty.

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 three months ended March 31, 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 SDWA 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, the BLM proposed in May 2012, 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. 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.

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 issued a progress report regarding the study in December 2012, which described generally the continuing focus of the study, but did not provide any data, findings, or conclusions regarding the safety of hydraulic fracturing operations. The EPA intends to issue a final draft report for peer review and comment at the completion of the study. The results of this study, which is still ongoing, 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 EPCRA's Toxics Release Inventory (TRI) program.

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
January 1, 2015 - January 31, 2015	—	$	—	—	$	400.3
February 1, 2015 - February 28, 2015	3,741	22.78		—	400.3
March 1, 2015 - March 31, 2015	200,359	21.66		—	400.3

____________________________

⁽¹⁾

All of the 204,100 shares purchased during the three-month period ended March 31, 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.

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
10.1		Form of Performance Share Unit Award Agreement under the QEP Resources, Inc. Cash Incentive Plan, for awards to executive officers after 2014 (incorporated by reference to Exhibit 10.42 to the Company's Annual Report on Form 10-K for the year ended December 31, 2014, filed with the Securities and Exchange Commission on February 24, 2015.)
10.2		QEP Resources, Inc. Deferred Compensation Plan for Directors, Amended and Restated, effective as of August 1, 2014 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2014, filed with the Securities and Exchange Commission on August 6, 2014), as amended and restated by the QEP Resources, Inc. Deferred Compensation Plan for Directors, Amended and Restated, effective as of February 23, 2015 (incorporated by reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year ended December 31, 2014, filed with the Securities and Exchange Commission on February 24, 2015.)
10.3		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 1, 2013). As amended and restated by the QEP Resources, Inc. Amended Deferred Compensation Wrap Plan, effective as of February 23, 2015 (incorporated by reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K for the year ended December 31, 2014, filed with the Securities and Exchange Commission on February 24, 2015.)
31.1		Certification signed by Charles B. Stanley, QEP Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2		Certification signed by Richard J. Doleshek, QEP Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1		Certification signed by Charles B. Stanley and Richard J. Doleshek, QEP Resources, Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS		XBRL Instance Document
101.SCH		XBRL Schema Document
101.CAL		XBRL Calculation Linkbase Document
101.LAB		XBRL Label Linkbase Document
101.PRE		XBRL Presentation Linkbase Document
101.DEF		XBRL Definition Linkbase Document

SIGNATURES

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



	QEP RESOURCES, INC.
	(Registrant)

April 29, 2015	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer

April 29, 2015	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

QEPR-2015 3.31.15 EX31.1

Exhibit 31.1

CERTIFICATION

I, Charles B. Stanley, certify that:


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


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


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


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


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


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


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


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


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


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


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

April 29, 2015

/s/ Charles B. Stanley

Charles B. Stanley

Chairman, President and Chief Executive Officer

QEPR-2015 3.31.15 EX31.2

Exhibit 31.2

CERTIFICATION

I, Richard J. Doleshek, certify that:


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


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


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


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


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


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


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


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


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


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


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

April 29, 2015

/s/ Richard J. Doleshek

Richard J. Doleshek

Executive Vice President and Chief Financial Officer

QEPR-2015 3.31.15 EX32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of QEP Resources, Inc. (the Company) on Form 10-Q for the period ended March 31, 2015, as filed with the Securities and Exchange Commission on the date hereof (the Report), Charles B. Stanley, Chairman, President and Chief Executive Officer of the Company, and Richard J. Doleshek, Executive Vice President and Chief Financial Officer, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:


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


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



	QEP RESOURCES, INC.

April 29, 2015

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

April 29, 2015

	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President and Chief Financial Officer