10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2014

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 September 30, 2014, there were 180,149,080 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended September 30, 2014

TABLE OF CONTENTS

			Page
PART I. FINANCIAL INFORMATION			2
	ITEM 1.	FINANCIAL STATEMENTS	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2014 AND 2013	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2014 AND 2013	3
		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT SEPTEMBER 30, 2014 AND DECEMBER 31, 2013	4
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2014 AND 2013	5
		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	6
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	30
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	49
	ITEM 4.	CONTROLS AND PROCEDURES	54
PART II. OTHER INFORMATION			54
	ITEM 1.	LEGAL PROCEEDINGS	54
	ITEM 1A.	RISK FACTORS	54
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	56
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	56
	ITEM 4.	MINE SAFETY DISCLOSURES	56
	ITEM 5.	OTHER INFORMATION	56
	ITEM 6.	EXHIBITS	57
SIGNATURES			58

1

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
REVENUES	(in millions, except per share amounts)
Gas sales	$	171.6		$	194.8		$	609.2		$	610.5
Oil sales	393.5			253.8			1,041.0			656.3
NGL sales	51.1			47.7			179.3			144.4
Other revenue	3.4			2.8			5.1			8.7
Purchased gas, oil and NGL sales	290.4			220.4			780.1			644.9
Total Revenues	910.0			719.5			2,614.7			2,064.8
OPERATING EXPENSES
Purchased gas, oil and NGL expense	288.4			219.5			775.5			650.3
Lease operating expense	61.1			43.5			177.0			130.2
Gas, oil and NGL transportation and other handling costs	71.1			58.6			198.5			158.5
Gathering and other expense	1.4			2.1			4.8			6.4
General and administrative	49.4			40.7			147.0			116.8
Production and property taxes	59.4			40.6			160.8			113.7
Depreciation, depletion and amortization	251.4			238.4			712.5			719.3
Exploration expenses	0.8			1.8			4.7			9.5
Impairment	0.1			3.8			3.6			4.0
Total Operating Expenses	783.1			649.0			2,184.4			1,908.7
Net gain (loss) from asset sales	(11.8		)	12.8			(210.3		)	113.4
OPERATING INCOME	115.1			83.3			220.0			269.5
Realized and unrealized gains (losses) on derivative contracts (Note 8)	155.7			(27.8		)	(13.2		)	51.6
Interest and other income	4.2			6.1			7.8			22.7
Income from unconsolidated affiliates	0.1			—			0.2			—
Interest expense	(41.5		)	(41.4		)	(128.4		)	(124.7		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	233.6			20.2			86.4			219.1
Income tax provision	(79.9		)	(8.1		)	(26.1		)	(82.5		)
NET INCOME FROM CONTINUING OPERATIONS	153.7			12.1			60.3			136.6
Net income from discontinued operations, net of income tax	17.4			25.2			58.2			74.8
NET INCOME ATTRIBUTABLE TO QEP	$	171.1		$	37.3		$	118.5		$	211.4
Earnings Per Common Share Attributable to QEP
Basic from continuing operations	$	0.85		$	0.07		$	0.34		$	0.76
Basic from discontinued operations	0.10			0.14			0.32			0.42
Basic total	$	0.95		$	0.21		$	0.66		$	1.18
Diluted from continuing operations	$	0.84		$	0.07		$	0.34		$	0.76
Diluted from discontinued operations	0.10			0.14			0.32			0.42
Diluted total	$	0.94		$	0.21		$	0.66		$	1.18
Weighted-average common shares outstanding
Used in basic calculation	180.1			179.3			180.0			179.2
Used in diluted calculation	180.6			179.5			180.4			179.4
Dividends per common share	$	0.02		$	0.02		$	0.06		$	0.06

See notes accompanying the condensed consolidated financial statements.

2

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2014		2013			2014		2013
	(in millions)
Net income attributable to QEP	$	171.1	$	37.3		$	118.5	$	211.4
Other comprehensive income (loss), net of tax:
Reclassification of previously deferred derivative gains(1)	—		(19.7		)	—		(60.4		)
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss (2)	0.2		0.4			0.4		1.1
Amortization of prior service cost (3)	0.7		0.8			2.4		2.5
Total pension and other postretirement plans adjustments	0.9		1.2			2.8		3.6
Other comprehensive income (loss)	0.9		(18.5		)	2.8		(56.8		)
Comprehensive income attributable to QEP	$	172.0	$	18.8		$	121.3	$	154.6

____________________________

⁽¹⁾  Presented net of income tax benefit of $11.7 million and $35.8 million during the three and nine months ended September 30, 2013, respectively.

⁽²⁾  Presented net of income tax expense of $0.2 million during the nine months ended September 30, 2014 and $0.2 million and $0.7 million during the three and nine months ended September 30, 2013, respectively.

⁽³⁾  Presented net of income tax expense of $0.5 million and $1.5 million during the three and nine months ended September 30, 2014, respectively, and $0.5 million and $1.5 million during the three and nine months ended September 30, 2013, respectively.

See notes accompanying the condensed consolidated financial statements.

3

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2014			December 31, 2013
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	—		$	11.9
Accounts receivable, net	599.4			316.3
Fair value of derivative contracts	32.6			0.2
Gas, oil and NGL inventories, at lower of average cost or market	16.4			13.4
Deferred income taxes - current	—			27.9
Prepaid expenses and other	50.8			45.4
Current assets of discontinued operations held for sale	138.3			122.0
Total Current Assets	837.5			537.1
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	11,723.0			11,571.4
Unproved properties	1,120.5			665.1
Midstream	197.5			197.3
Marketing and resources	95.2			85.5
Material and supplies	55.3			54.3
Total Property, Plant and Equipment	13,191.5			12,573.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	4,915.0			4,930.9
Midstream	34.3			28.1
Marketing and resources	29.8			22.1
Total Accumulated Depreciation, Depletion and Amortization	4,979.1			4,981.1
Net Property, Plant and Equipment	8,212.4			7,592.5
Fair value of derivative contracts	12.7			1.0
Restricted cash	—			50.0
Other noncurrent assets	39.4			46.6
Noncurrent assets of discontinued operations held for sale	1,174.2			1,167.7
TOTAL ASSETS	$	10,276.2		$	9,394.9
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	36.8		$	109.1
Accounts payable and accrued expenses	691.4			361.9
Production and property taxes	73.5			49.4
Interest payable	34.1			37.2
Fair value of derivative contracts	4.5			26.7
Deferred income taxes	2.9			—
Current liabilities of discontinued operations held for sale	161.6			75.3
Total Current Liabilities	1,004.8			659.6
Long-term debt	3,115.5			2,997.5
Deferred income taxes	1,500.8			1,364.9
Asset retirement obligations	162.3			163.3
Fair value of derivative contracts	0.2			—
Other long-term liabilities	90.3			94.5
Noncurrent liabilities of discontinued operations held for sale	402.0			238.3
Commitments and contingencies (Note 11)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized;  180.9 million and 179.7 million shares issued, respectively	1.8			1.8
Treasury stock - 0.8 million and 0.4 million shares, respectively	(25.1		)	(14.9		)
Additional paid-in capital	527.2			498.4
Retained earnings	3,025.4			2,917.8
Accumulated other comprehensive loss	(23.7		)	(26.5		)
Total Common Shareholders' Equity	3,505.6			3,376.6
Noncontrolling interest	494.7			500.2
Total Equity	4,000.3			3,876.8
TOTAL LIABILITIES AND EQUITY	$	10,276.2		$	9,394.9

See notes accompanying the condensed consolidated financial statements.

4

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
	2014			2013
	(in millions)
OPERATING ACTIVITIES
Net income attributable to QEP	$	118.5		$	211.4
Net income attributable to noncontrolling interest	17.6			5.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	755.8			757.1
Deferred income taxes	91.5			39.3
Impairment	3.6			4.0
Equity-based compensation	20.7			20.0
Amortization of debt issuance costs and discounts	5.1			4.7
Net loss (gain) from asset sales	210.3			(113.0		)
Income from unconsolidated affiliates	(4.6		)	(3.7		)
Distributions from unconsolidated affiliates and other	5.1			5.9
Unrealized (gain) loss on derivative contracts	(65.9		)	55.5
Changes in operating assets and liabilities	62.0			(8.1		)
Net Cash Provided by Operating Activities	1,219.7			978.9
INVESTING ACTIVITIES
Property acquisitions	(949.7		)	(39.3		)
Property, plant and equipment, including dry exploratory well expense	(1,270.4		)	(1,089.6		)
Proceeds from disposition of assets	706.2			208.3
Acquisition deposit held in escrow	50.0			—
Other investing activities	3.2			—
Net Cash Used in Investing Activities	(1,460.7		)	(920.6		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(81.1		)	(38.1		)
Long-term debt issued	300.0			—
Long-term debt issuance costs paid	(1.1		)	(3.0		)
Proceeds from credit facility	4,509.0			2,132.5
Repayments of credit facility	(4,461.5		)	(2,457.5		)
Treasury stock repurchases	(6.6		)	(8.7		)
Net proceeds from the issuance of QEP Midstream common units	—			449.6
Other capital contributions	5.1			3.6
Dividends paid	(10.8		)	(10.8		)
Excess tax (provision) benefit on equity-based compensation	(0.6		)	1.3
Distribution to noncontrolling interest	(23.3		)	(4.2		)
Net Cash Provided by Financing Activities	229.1			64.7
Change in cash and cash equivalents	(11.9		)	123.0
Beginning cash and cash equivalents	11.9			—
Ending cash and cash equivalents	$	—		$	123.0
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	128.9		$	120.1
Cash (received) paid for income taxes	(1.1		)	49.4
Non-cash investing activities:
Change in capital expenditure accrual balance	$	66.5		$	53.7

See notes accompanying the condensed consolidated financial statements.

5

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 major 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 a underground gas storage reservoir (QEP Marketing and Other).

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

In December 2013, QEP's Board of Directors authorized the Company to develop a plan to separate its midstream business, QEP Field Services, including the Company's interest in QEP Midstream Partners, LP (“QEP Midstream”), from QEP. Between December 2013 and September 2014, the Company evaluated transaction alternatives, including selling or merging the midstream business or spinning the midstream business off to its shareholders. In June 2014, QEP filed a registration statement on Form 10 with the U.S. Securities and Exchange Commission (SEC) in preparation for a potential spinoff of QEP Field Services as a separate publicly traded company. Concurrently, the Company evaluated selling or merging its midstream business. In September 2014, based on the proposals received, the Company's Board of Directors authorized QEP's management to engage in the negotiation of terms of a definitive transaction with Tesoro Logistics LP ("Tesoro"). In October 2014, the Company announced that its wholly owned subsidiary, 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 to Tesoro in an all cash transaction valued at $2.5 billion, including $230.0 million to refinance debt at QEP Midstream. The transaction is subject to customary closing conditions and regulatory approvals, and is expected to close before year-end 2014. On October 31, 2014, the Federal Trade Commission granted early termination, ending the Hart Scott Rodino waiting period for the transaction. The decision to sell the midstream business is a result of the Company’s ongoing review of strategic alternatives to maximize shareholder value. QEP will retain ownership of QEP Field Services’ Haynesville Gathering System. As a result of the pending transaction, the QEP Field Services reporting segment, excluding the retained ownership of the Haynesville Gathering System, has been classified as assets and liabilities held for sale on the Condensed Consolidated Balance Sheet and 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.

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 for the year ended December 31, 2013.

The preparation of the condensed consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three and nine months ended September 30, 2014, are not necessarily indicative of the results that may be expected for the year ending December 31, 2014.

6

Reclassifications

The 2013 financial information has been recast so that the basis of presentation is consistent with that of the 2014 financial information. This recast reflects the financial condition and results of operations, excluding the Haynesville Gathering System, of QEP Field Services as discontinued operations, for all periods presented. For a summary of discontinued operations see Note 4 - Discontinued Operations.

During the first nine months of 2013, QEP presented certain credit facility payments and borrowings on a net basis on the Condensed Consolidated Statements of Cash Flow. These borrowings and payments were reclassified to be presented on a gross basis on the Condensed Consolidated Statements of Cash Flow in order to conform with the current period presentation. This reclassification is entirely within "Financing Activities" and has no effect on other categories or total cash on the Condensed Consolidated Statements of Cash Flows or net income or earnings per share on the Condensed Consolidated Statements of Operations.

New accounting pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which broadened the reporting of discontinued operations to a component of an entity that has operations and cash flows that can be clearly distinguished from the rest of the entity. Under this guidance, to be a discontinued operation, a component or group of components must represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2014 and early adoption is permitted. The Company has chosen to early adopt ASU 2014-08 and implemented the amendments in the quarter ended September 30, 2014.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments are effective prospectively for reporting periods beginning after December 15, 2016 and early adoption is not permitted. The Company is currently assessing the impact on the Company's consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Topic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This guidance provides additional information to guide management's evaluation of whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. The update is effective for annual periods beginning on or after December 15, 2016. The Company is currently evaluating the impact of this standard on its 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, subject to post-closing purchase price adjustments (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 $114.2 million and net income of $23.1 million were generated from the acquired properties from February 25, 2014, to September 30, 2014, and are included in QEP's Condensed Consolidated Statements of Operations. During the nine months endedSeptember 30, 2014, QEP Energy incurred acquisition-related costs of $0.6 million, which are included in "General and administrative" on the Condensed Consolidated Statement of Operations for the nine months endedSeptember 30, 2014. QEP incurred $1.1 million of debt issuance costs

7

associated with increasing the size of term loan borrowings to fund a portion of the acquisition, which are included in "Other noncurrent assets" on the Condensed Consolidated Balance Sheet as of September 30, 2014.

QEP Energy recorded the Permian Basin Acquisition on its Condensed Consolidated Balance Sheet as of September 30, 2014. The following table presents a summary of the Company's purchase accounting entries:

	As of September 30, 2014
	(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 nine months endedSeptember 30, 2014, and the three and nine months endedSeptember 30, 2013. Pro forma results are not provided for the three months ended September 30, 2014, because the Permian Basin Acquisition occurred during the first quarter of 2014, and therefore there is no pro forma impact on the third quarter of 2014. 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 and nine months ended September 30, 2014 and 2013, 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 preliminary 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				Nine Months Ended
	September 30,				September 30,
	2013		2013		2014		2014		2013		2013
	Actual		Pro forma		Actual		Pro forma		Actual		Pro forma
					(in millions, except per share data)
Revenues	$	719.5	$	776.5	$	2,614.7	$	2,640.8	$	2,064.8	$	2,195.4
Net income (loss) attributable to QEP	37.3		54.2		118.5		125.5		211.4		240.4
Earnings per common share attributable to QEP
Basic	$	0.21	$	0.30	$	0.66	$	0.70	$	1.18	$	1.34
Diluted	0.21		0.30		0.66		0.70		1.18		1.34

Divestitures

In June 2014, QEP Energy sold its interests in certain non-core properties in the Midcontinent area and other non-core assets in the Williston Basin for total cash proceeds of $702.3 million, subject to post-closing purchase price adjustments, and recorded a pre-tax loss of $210.4 million on QEP's Statements of Operations and Condensed Consolidated Statement of Operations in "Net loss from asset sales" for the nine months ended September 30, 2014. An additional $28.7 million of consideration is currently being held in escrow related to unresolved title defects.

8

Note 4 - Discontinued Operations

In December 2013, QEP's Board of Directors authorized the Company to develop a plan to separate its midstream business, QEP Field Services, including the Company's interest in QEP Midstream, from QEP. Between December 2013 and September 2014, the Company evaluated transaction alternatives, including selling or merging the midstream business or spinning the midstream business off to its shareholders. In June 2014, QEP filed a registration statement on Form 10 with the SEC in preparation for a potential spinoff of QEP Field Services as a separate publicly traded company. Concurrently, the Company evaluated selling or merging its midstream business. In September 2014, based on the proposals received, the Company's Board of Directors authorized QEP's management to engage in the negotiation of terms of a definitive transaction with Tesoro. In October 2014, the Company announced that its wholly owned subsidiary, 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 to Tesoro in an all cash transaction valued at $2.5 billion, including $230.0 million to refinance debt at QEP Midstream. The transaction is subject to customary closing conditions and regulatory approvals, and is expected to close before year-end 2014. On October 31, 2014, the Federal Trade Commission granted early termination, ending the Hart Scott Rodino waiting period for the transaction. The decision to sell the midstream business is a result of the Company’s ongoing review of strategic alternatives to maximize shareholder value and represents a significant milestone in the strategic repositioning of the Company. As of September 30, 2014, the operating results and financial position of QEP Field Services, excluding its retained ownership of the Haynesville Gathering System, were classified as discontinued operations as well as assets and liabilities held for sale on its balance sheet. After the transaction closes, QEP will have continuing cash outflows to our discontinued midstream business for gathering, processing and water handling costs in Pinedale, the Uinta Basin and a portion of its Williston Basin operations. These contracts 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 and are now reflected as part of the continuing operations for QEP. For the three months endedSeptember 30, 2014 and 2013, cash outflows for these transactions that are included in continuing operations were $19.0 million and $25.9 million, respectively. For the nine months endedSeptember 30, 2014 and 2013, cash outflows for these transactions that are included in continuing operations were $64.1 million and $67.2 million, respectively.

9

Condensed Consolidated Income Statement

The discontinued operations of QEP Field Services (excluding results of the Haynesville Gathering System) are summarized below:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(in millions, except per share amounts)
REVENUES
NGL sales	$	28.8		$	23.6		$	94.6		$	70.6
Other revenue	43.1			44.2			119.9			126.4
Purchased gas, oil and NGL sales(1)	(11.9		)	(14.4		)	(38.5		)	(41.5		)
Total Revenues	60.0			53.4			176.0			155.5
OPERATING EXPENSES
Purchased gas, oil and NGL expense(1)	(12.4		)	(14.4		)	(39.5		)	(41.4		)
Lease operating expense(1)	(1.7		)	(0.8		)	(4.8		)	(2.6		)
Natural gas, oil and NGL transport & other handling costs(1)	(10.6		)	(21.7		)	(40.1		)	(53.0		)
Gathering, processing, and other	22.7			20.3			69.8			60.1
General and administrative	11.1			8.6			34.3			19.4
Production and property taxes	2.1			1.8			6.1			4.0
Depreciation, depletion and amortization	14.3			14.7			43.1			37.8
Total Operating Expenses	25.5			8.5			68.9			24.3
Net loss from asset sales	—			(0.1		)	(0.1		)	(0.5		)
OPERATING INCOME	34.5			44.8			107.0			130.7
Interest income and other loss	—			(2.1		)	—			(13.7		)
Income from unconsolidated affiliates	1.1			0.8			4.4			3.7
Interest expense	(1.5		)	(0.3		)	(2.8		)	2.3
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES (2)	34.1			43.2			108.6			123.0
Income taxes	(9.9		)	(14.2		)	(32.8		)	(42.4		)
NET INCOME FROM DISCONTINUED OPERATIONS	24.2			29.0			75.8			80.6
Net income attributable to noncontrolling interest	(6.8		)	(3.8		)	(17.6		)	(5.8		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	17.4		$	25.2		$	58.2		$	74.8

⁽¹⁾ Includes discontinued intercompany eliminations

⁽²⁾ Includes income from discontinued operations before income taxes attributable to QEP from QEP Midstream (of which QEP owns 57.8%) of $7.9 million and $20.4 million for the three and nine months ended September 30, 2014, respectively, and $7.9 million and $26.2 million for the three and nine months ended September 30, 2013, respectively.

10

Condensed Consolidated Balance Sheet

The current and noncurrent assets and liabilities of QEP Field Services, excluding the retained Haynesville Gathering System, are as follows:

	September 30, 2014			December 31, 2013
Cash and cash equivalents	$	27.1		$	18.1
Accounts receivable, net	71.8			53.9
Income taxes receivable	—			38.4
Deferred income taxes - current	7.0			2.7
Prepaid expenses and other	32.4			8.9
Current assets of discontinued operations held for sale	$	138.3		$	122.0
Property, Plant and Equipment
Midstream field services	$	1,550.5		$	1,500.8
Material and supplies	6.5			4.8
Total Property, Plant and Equipment	1,557.0			1,505.6
Less Accumulated Depreciation, Depletion and Amortization
Midstream field services	(422.2		)	(381.6		)
Net Property, Plant and Equipment	1,134.8			1,124.0
Investment in unconsolidated affiliates	35.9			39.0
Other noncurrent assets	3.5			4.7
Noncurrent assets of discontinued operations held for sale	$	1,174.2		$	1,167.7
Accounts payable and accrued expenses	$	85.6		$	74.1
Accrued income taxes	70.2			—
Production and property taxes	5.4			1.2
Interest payable	0.4			—
Current liabilities of discontinued operations held for sale	$	161.6		$	75.3
Long-term debt	$	230.0		$	—
Deferred income taxes	126.5			195.7
Asset retirement obligations	29.9			28.5
Other long-term liabilities	15.6			14.1
Noncurrent liabilities of discontinued operations held for sale	$	402.0		$	238.3

Condensed Consolidated Statement of Cash Flows

The impact of the QEP Field Services discontinued operations, excluding the Haynesville Gathering System, on the Condensed Consolidated Statement of Cash Flows for "Depreciation, depletion and amortization" contained in "Cash flows from operating activities" was $43.1 million and $37.8 million for the nine months ended September 30, 2014 and 2013, respectively. The impact on cash used for "Property, plant and equipment, including dry exploratory well expense" contained in "Cash flows from investing activities" was $45.6 million and $57.4 million for the nine months ended September 30, 2014 and 2013, respectively.

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Note 5 – Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income attributable to QEP 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 equity-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company’s unvested restricted stock awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company’s unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company’s unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share. During the three and nine months endedSeptember 30, 2014 and 2013, there were no anti-dilutive shares.

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2014	2013	2014	2013
	(in millions)
Weighted-average basic common shares outstanding	180.1	179.3	180.0	179.2
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	0.5	0.2	0.4	0.2
Average diluted common shares outstanding	180.6	179.5	180.4	179.4

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, production facilities, 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 $163.2 million and $165.1 million ARO liability for continuing operations for the periods ended September 30, 2014 and December 31, 2013, $0.9 million and $1.8 million was included, respectively, as a current liability in "Accounts payable and accrued expenses" on the Condensed Consolidated Balance Sheets.

12

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

	Asset Retirement Obligations
	2014
	(in millions)
ARO liability at January 1, (1)	$	165.1
Accretion	4.9
Additions(2)	15.5
Revisions	(0.3		)
Liabilities settled(3)	(22.0		)
ARO liability at September 30,(4)	$	163.2

____________________________

⁽¹⁾ Excludes $28.5 million of ARO classified as liabilities held for sale on the Condensed Consolidated Balance Sheet.

⁽²⁾ Additions include $9.7 million related to the Permian Basin Acquisition (see Note 3 - Acquisitions and Divestitures).

⁽³⁾ Settlements include $20.2 million related to the property sales in the second quarter of 2014 (see Note 3 - Acquisitions and Divestitures).

⁽⁴⁾ Excludes $29.9 million of ARO classified as liabilities held for sale on the Condensed Consolidated Balance Sheet.

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.

In addition, QEP has interest rate swaps that it has determined are Level 2 financial instruments. The fair values of the interest rate swaps are determined using the market standard methodology of discounting the future expected cash flows that would occur under the contractual terms of the swap. The variable interest rates used in the calculation of projected cash flows are based on an expectation of future interest rates derived from observable market interest rate curves. QEP incorporates credit valuation adjustments to reflect both its nonperformance risk and the respective counterparty's nonperformance risk in the fair value measurements. While the credit valuation adjustments are not observable inputs, they are not significant to the overall valuation and the other inputs used to value the interest rate swaps are observable Level 2 inputs.

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The fair value measurements of financial assets and liabilities at September 30, 2014, are shown in the table below:

	Fair Value Measurements
	September 30, 2014
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	36.6	$	—	$	(4.0	)	$	32.6
Commodity derivative instruments - long-term	—		9.6		—		(0.4		)	9.2
Interest rate swaps - long-term	—		3.5		—		—			3.5
Total financial assets	$	—	$	49.7	$	—	$	(4.4	)	$	45.3
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	4.2	$	—	$	(4.0	)	$	0.2
Interest rate swaps - short-term	—		4.3		—		—			4.3
Commodity derivative instruments - long-term	—		0.6		—		(0.4		)	0.2
Total financial liabilities	$	—	$	9.1	$	—	$	(4.4	)	$	4.7

____________________________

⁽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 fair value of financial assets and liabilities at December 31, 2013, is shown in the table below:

	Fair Value Measurements
	December 31, 2013
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	5.5	$	—	$	(5.3	)	$	0.2
Commodity derivative instruments - long-term	—		0.4		—		—			0.4
Interest rate swaps - long-term	—		0.6		—		—			0.6
Total financial assets	$	—	$	6.5	$	—	$	(5.3	)	$	1.2
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	29.4	$	—	$	(5.3	)	$	24.1
Interest rate swaps - short-term	—		2.6		—		—			2.6
Total financial liabilities	$	—	$	32.0	$	—	$	(5.3	)	$	26.7

_______________________

⁽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.

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The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes accompanying the condensed consolidated financial statements in this Quarterly Report on Form 10-Q:

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	September 30, 2014				December 31, 2013
	(in millions)
Financial assets
Cash and cash equivalents	$	—	$	—	$	11.9	$	11.9
Financial liabilities
Checks outstanding in excess of cash balances	$	36.8	$	36.8	$	109.1	$	109.1
Long-term debt	$	3,115.5	$	3,209.3	$	2,997.5	$	3,034.9

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 remaining 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 to realize a known price 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 basis swaps to achieve a fixed price swap for a portion of its oil that it sells at prices that reference ICE Brent and Light Louisiana Sweet (LLS).

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.

Effective January 1, 2012, QEP elected to de-designate all of its gas, oil and NGL derivative contracts that were previously designated as cash flow hedges and discontinue hedge accounting prospectively. As a result of discontinuing hedge accounting, the mark-to-market values at December 31, 2011, were fixed in Accumulated Other Comprehensive Income (AOCI) as of the de-designation date and are being reclassified into the Condensed Consolidated Statements of Operations as the transactions settle and affect earnings. During the nine months endedSeptember 30, 2013, $60.4 million of unrealized gains, after tax, were reclassified from AOCI into the Condensed Consolidated Statements of Operations in "Realized and unrealized losses on derivative contracts" as the transactions settled. All realized and unrealized gains and losses from derivative instruments

15

incurred after January 1, 2012, are presented in the Condensed Consolidated Statements of Operations in "Realized and unrealized losses on derivative contracts" below operating income.

QEP also uses interest rate swaps to mitigate a portion of its exposure to interest rate volatility risk 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%. The average effective interest rate on the $600.0 million term loan when combined with the fixed interest rate swaps for the nine months endedSeptember 30, 2014 was 3.21%. The interest rate swaps settle monthly and will mature in March 2017.

QEP Energy Derivative Contracts

The following table sets forth QEP Energy’s quantities and average prices for its commodity derivative contracts as of September 30, 2014: 

Year	Type of Contract	Index	Total Volumes	Average Swap price per unit
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	NYMEX	7.4	$	4.22
2014	SWAP	IFNPCR	20.2	$	4.08
2015	SWAP	NYMEX	25.6	$	4.14
2015	SWAP	IFNPCR	11.0	$	4.06
Oil sales			(Bbls)
2014	SWAP	NYMEX WTI	3.1	$	93.54
2015	SWAP	NYMEX WTI	7.7	$	90.04
2015	SWAP	BRENT ICE	0.4	$	104.95
2016	SWAP	NYMEX WTI	0.4	$	90.00

The following table sets forth QEP Energy's oil basis swaps as of September 30, 2014:

Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)
Oil basis swaps			(Bbls)
2014	NYMEX WTI	ICE Brent	0.2	$	13.78
2014	NYMEX WTI	LLS	0.2	$	4.03
2015	NYMEX WTI	LLS	0.1	$	4.03

16

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 September 30, 2014:

Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	IFNPCR	1.4	$	4.03
2015	SWAP	IFNPCR	2.5	4.07
Gas purchases			(MMBtu)
2014	SWAP	IFNPCR	0.6	$	3.86

QEP's Derivative Contracts

The following table sets forth QEP’s notional amount and interest rate for its interest rate swaps outstanding as of September 30, 2014:

Notional amount	Type of Contract	Maturity	Fixed Rate Paid	Variable Rate Received
(in millions)
$300.0	Swap	March 2017	1.07%	One-month LIBOR
$300.0	Swap	March 2017	0.86%	One-month LIBOR
$600.0			0.96%

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	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	36.6	$	5.5	$	4.2	$	29.4
Interest rate swaps	Fair value of derivative contracts	—		—		4.3		2.6
Long-term:
Commodity	Fair value of derivative contracts	9.6		0.4		0.6		—
Interest rate swaps	Fair value of derivative contracts	3.5		0.6		—		—
Total derivative instruments		$	49.7	$	6.5	$	9.1	$	32.0

17

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

	Three Months Ended						Nine Months Ended
Derivative instruments not designated as cash flow hedges	September 30,						September 30,
	2014			2013			2014			2013
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	5.5		$	42.5		$	(23.3	)	$	112.0
Oil derivative contracts	(12.2		)	(15.3		)	(50.2		)	(3.7		)
QEP Marketing
Gas derivative contracts	(0.4		)	(0.3		)	(2.4		)	0.7
Total realized gains (losses) on commodity derivative contracts	(7.1		)	26.9			(75.9		)	109.0
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	27.6			(6.6		)	9.5			(9.6		)
Oil derivative contracts	133.2			(46.2		)	54.3			(49.1		)
QEP Marketing
Gas derivative contracts	0.7			0.1			1.0			(0.3		)
Total unrealized gains (losses) on commodity derivative contracts	161.5			(52.7		)	64.8			(59.0		)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	154.4		$	(25.8	)	$	(11.1	)	$	50.0
Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	(1.3	)	$	(0.6	)	$	(3.2	)	$	(1.9	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	2.6			(1.4		)	1.1			3.5
Total realized and unrealized gains (losses) on interest rate swaps	$	1.3		$	(2.0	)	$	(2.1	)	$	1.6
Total net realized gains (losses) on derivative contracts	$	(8.4	)	$	26.3		$	(79.1	)	$	107.1
Total net unrealized gains (losses) on derivative contracts	164.1			(54.1		)	65.9			(55.5		)
Grand Total	$	155.7		$	(27.8	)	$	(13.2	)	$	51.6

Note 9 – Restructuring Costs

In December 2013, QEP announced its plan to pursue a separation of its midstream business, QEP Field Services. In connection with this announcement, 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 occurs, 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 expects to recognize $10.3 million of costs under this retention plan and has $7.9 million accrued since inception as of September 30, 2014. During the three and nine months ended September 30, 2014, $2.3 million and $7.1 million, respectively, was accrued under this retention plan, and are included in "Discontinued operations, net of income tax" on the Condensed Consolidated Statements of Operations.

During 2012, QEP began incurring costs related to the closure of its Oklahoma City office and the subsequent consolidation of its Southern Region operations into a single regional office located in Tulsa. Additionally, during 2012, QEP began incurring additional restructuring and reorganization costs related to consolidating various corporate and accounting functions to the Denver corporate headquarters. The creation of one office for QEP’s Southern Region as well as the consolidation of corporate and accounting functions increased efficiency, team-based collaboration and organizational productivity. As part of the

18

reorganization, QEP incurred costs associated with the severance, retention and relocation of employees, additional pension expenses, exit costs associated with the termination of operating leases arising from office space that will no longer be utilized by the Company and other expenses. All restructuring costs related to the 2012 office consolidations and continued operations were incurred and settled by December 31, 2013.

The following table summarizes, by line of business, each major type of restructuring cost expected to be incurred and the total amounts recorded in "General and administrative" expense on the Condensed Consolidated Statements of Operations for the respective periods indicated:

	Total Restructuring Costs
	Total Expected to be Incurred		Recognized in Income
			Period from Inception to September 30, 2014		Three Months Ended September 30,				Nine Months Ended September 30,
					2014		2013		2014		2013
Continuing Operations:	(in millions)
QEP Energy
One-time termination benefits	$	3.3	$	3.3	$	—	$	0.1	$	—	$	0.4
Retention & relocation expense	3.7		3.7		—		0.1		—		0.3
Lease termination costs	0.6		0.6		—		—		—		—
Total restructuring costs	$	7.6	$	7.6	$	—	$	0.2	—		0.7
QEP Marketing & Other
One-time termination benefits	$	0.3	$	0.3	$	—	$	0.1	$	—	$	0.1
Total restructuring costs	$	0.3	$	0.3	$	—	$	0.1	$	—	$	0.1
Total QEP
One-time termination benefits	$	3.6	$	3.6	$	—	$	0.2	$	—	$	0.5
Retention & relocation expense	3.7		3.7		—		0.1		—		0.3
Lease termination costs	0.6		0.6		—		—		—		—
Total restructuring costs	$	7.9	$	7.9	$	—	$	0.3	$	—	$	0.8

Note 10 – Debt

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

	September 30, 2014			December 31, 2013
	(in millions)
QEP's revolving credit facility due 2016	$	297.5		$	480.0
Term loan due 2017	600.0			300.0
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	3,119.3			3,001.8
Less unamortized discount	(3.8		)	(4.3		)
Total long-term debt outstanding	$	3,115.5		$	2,997.5

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Of the total debt outstanding on September 30, 2014, amounts outstanding under QEP's revolving credit facility due August 25, 2016, QEP's term loan due April 18, 2017, the 6.05% Senior Notes due September 1, 2016, and the 6.80% Senior Notes due April 1, 2018, will mature within the next five years.

Credit Facilities

QEP's Credit Facility

QEP’s unsecured revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit facility also contains an accordion provision that would allow for the amount of the facility to be increased to $2.0 billion and a provision whereby the maturity can be extended for up to two additional one-year periods, with the agreement of the lenders.

During the nine months endedSeptember 30, 2014 and 2013, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.22% and 2.56%, respectively. At September 30, 2014 and December 31, 2013, QEP was in compliance with the covenants under the credit agreement. At September 30, 2014, there was $297.5 million outstanding and $3.8 million of letters of credit issued under the credit facility.

Term Loan

QEP's $600.0 million unsecured term loan facility provides for borrowings at short-term interest rates and contains covenants, restrictions, and interest rates that are substantially the same as QEP’s revolving credit facility. The term loan matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. In conjunction with the Permian Basin Acquisition, QEP borrowed an incremental $300.0 million available under the facility and increased total borrowings under the term loan to $600.0 million. There were no changes to the maturity date, pricing or covenants in the credit agreement. QEP incurred $1.1 million of debt issuance costs associated with the new term loan issuance.

During the nine months endedSeptember 30, 2014 and 2013, QEP’s weighted-average interest rate on borrowings from the term loan was 2.26% and 2.23%, respectively. At September 30, 2014 and December 31, 2013, QEP was in compliance with the covenants under the term loan credit agreement.

Senior Notes

At September 30, 2014, 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 11 - 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 can be reasonably estimated 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 could 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, and/or the ongoing discovery and development of information important to the matter. QEP's litigation loss contingencies are discussed below. Except for the Rocky Mountain Resources, the Questar Gas Company, and the XTO Energy Inc. matters discussed below, QEP is unable to estimate reasonably possible losses (in excess of recorded accruals, if any) for these 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.

Environmental Claims

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In October 2009, QEP received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from unpermitted work resulting in the discharge of dredged and/or fill material into waters of the United States at three sites located in Caddo and Red River Parishes, Louisiana. Region 6 of the U.S. Environmental Protection Agency (EPA) has assumed lead responsibility for enforcement of the cease and desist order and any possible future orders for the removal of unauthorized fills and/or civil penalties under the Clean Water Act. On June 28, 2013, the EPA issued to QEP an Administrative Complaint for the alleged violations. QEP and the EPA reached an agreement to settle the alleged violations through an Administrative Order, under the terms of which QEP paid an administrative penalty of $0.2 million. The Administrative Order is final. In 2012, QEP completed a field audit, which identified 112 additional instances affecting approximately 90 acres where work may have been conducted in violation of the Clean Water Act. QEP has disclosed each of these instances to the EPA under the EPA's Audit Policy (to reduce penalties) and to the COE. QEP is working with the EPA and the COE to resolve these matters, which will require the Company to undertake certain mitigation and permitting activities, and may require QEP to pay a monetary penalty.

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.

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 attaches to 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. On October 8, 2014, Rocky Mountain, Ultra Resources, Inc. (Ultra) and Lance Oil and Gas Company (Lance) reached a confidential agreement resolving the application of the 4% override as to production by Ultra and Lance and filed a stipulation to dismiss the lawsuit with respect to Ultra and Lance. The stipulation has no effect on the claims asserted against QEP or Wexpro.There are several affirmative defenses that remain to be tried and QEP continues to vigorously defend the case. A trial date is scheduled for February 2015. QEP estimates, based in part on damages asserted by the plaintiff, that the range of reasonably possible outcomes is no loss to a loss of approximately $20.0 million.

Gatti et al v. State of Louisiana et al, 589,350, 19th JDC, Parish of East Baton Rouge, Louisiana. In this putative class action arising out of the unitization practices and orders of the Louisiana Commissioner of Conservation (Commissioner), plaintiffs seek to represent a class of all Haynesville Shale mineral owners (alleged to be over 50,000 in number) against the Commissioner and all Haynesville Shale unit operators. Plaintiffs filed their complaint on April 8, 2010, and claim that the Commissioner exceeded his statutory authority in creating and perpetuating units larger than the area that can be efficiently and economically drained by a single well. They seek declaratory relief that would nullify all such improper orders, along with an unspecified amount of monetary damages from the unit operators sufficient to compensate the putative class members for the alleged dilution of their true interest in unit production as a result of "oversized" units and the "cloud on title" caused by having excessive and improperly sized units purport to hold their mineral leases via unit operations. All defendants filed exceptions to the plaintiffs' petition on the primary ground that plaintiffs had failed to comply with the exclusive statutory judicial review procedure (Louisiana Revised Statutes 30:12), which the trial court granted, dismissing the action in its entirety. On January 15, 2014, the Louisiana First Circuit Court of Appeal reversed and reinstated plaintiffs' claims. Defendants asked for review by the Louisiana Supreme Court and on August 25, 2014, the Supreme Court reversed the Court of Appeals and dismissed the plaintiffs’ claim without prejudice as originally ordered by the District Court.

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. The plaintiffs contend that QEP,

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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 are ongoing.

Litigation related to discontinued operations:

In accordance with the terms of the Membership Interest Purchase Agreement, dated as of October 19, 2014, by and between QEP Field Services and Tesoro, Tesoro has agreed to indemnify QEP Field Services and its affiliates for any liabilities or claims associated with Questar Gas Company and XTO Energy litigation. Therefore, following the closing of the Tesoro transaction, QEP believes it will have no significant exposure to liability for the following litigation matters.

Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services' former affiliate, Questar Gas Company (QGC), filed this complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the 1993 Agreement) executed when the parties were affiliates. Specific monetary damages are not asserted. Under the 1993 Agreement, certain of QEP Field Services' systems provide gathering services to QGC charging an annual gathering rate which is based on the cost of service. QGC is disputing the annual calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. At the closing of the QEP Midstream initial public offering (IPO), the assets and agreement discussed above were assigned to QEP Midstream. QGC amended its complaint to add QEP Midstream as a defendant in the litigation. QEP agreed to indemnify QEP Midstream for costs, expenses and other losses incurred by QEP Midstream in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement entered into between QEP Midstream and QEP in connection with the IPO. QGC netted the disputed amount from its monthly payments of the gathering fees to QEP Field Services and has continued to net such amounts from its monthly payment to QEP Midstream. As of September 30, 2014, QEP Midstream has deferred revenue of $13.2 million, which was included in "Current liabilities of discontinued operations held for sale" on the Condensed Consolidated Balance Sheet, related to the QGC disputed amount. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement.

XTO Energy Inc. v. QEP Field Services Company, Civil No. 140900709, Third Judicial District Court, State of Utah. XTO Energy Inc. (XTO), filed this complaint in Utah state court on January 30, 2014, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, unjust enrichment and an accounting related to a 2010 gas processing agreement (the Agreement). QEP Field Services processes XTO’s natural gas on a firm basis under the Agreement. The Agreement requires QEP Field Services to transport, fractionate and market XTO’s natural gas liquids derived from XTO’s processed gas. XTO is seeking monetary damages related to QEP Field Services allocation of charges related to XTO’s share of natural gas liquid transportation, fractionation and marketing costs associated with shortfalls in contractual firm processing volumes.

Note 12 – Equity-Based Compensation

QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and awards performance-based share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP recognizes expense over time as the stock options, restricted shares, and performance-based share units vest. Deferred equity-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 10.9 million shares available for future grants under the LTSIP at September 30, 2014. Equity-based compensation expense related to continuing operations is recognized in “General and administrative” on the Condensed Consolidated Statements of Operations, and expenses related to discontinued operations (including compensation expense related to the QEP Midstream Long Term Incentive Plan) are reflected in "Discontinued operations, net of income tax". During the three and nine months ended September 30, 2014 for continuing operations, QEP recognized $6.4 million and $17.7 million in total compensation expense related to equity-based compensation compared to $5.5 million and $17.9 million during the three and nine months ended September 30, 2013, respectively. During the three and nine months ended September 30, 2014 for discontinued operations, QEP recognized $0.9 million and $3.0 million in total compensation expense related to equity-based compensation compared to $1.3 million and $2.1 million during the three and nine months ended September 30, 2013, respectively.

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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:

	Stock Option Assumptions
	Nine Months Ended
	September 30, 2014
Weighted-average grant-date fair value of awards granted during the period	$	10.11
Weighted-average risk-free interest rate	1.31		%
Weighted-average expected price volatility	37.1		%
Expected dividend yield	0.25		%
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, 2013	1,794,187		$	27.90
Granted	282,236		31.67
Exercised	(65,366	)	22.24
Forfeited	(14,842	)	30.53
Outstanding at September 30, 2014	1,996,215		$	28.60	3.43	$	6.3
Options Exercisable at September 30, 2014	1,452,138		$	27.71	2.56	$	6.2
Unvested Options at September 30, 2014	544,077		$	30.97	5.75	$	0.2

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.6 million and $4.2 million during the nine months endedSeptember 30, 2014 and 2013, respectively. As of September 30, 2014, $2.7 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.05 years. During the nine months endedSeptember 30, 2014, QEP received $1.5 million in cash upon the exercise of stock options during 2014.

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 nine months endedSeptember 30, 2014 and 2013 was $20.2 million and $18.4 million, respectively. The weighted average grant-date fair value of restricted stock was $31.82 per share and $30.03 per share for the nine months endedSeptember 30, 2014 and 2013, respectively. As of September 30, 2014, $18.2 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 2.26 years.

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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, 2013	1,388,953		$	30.96
Granted	968,118		31.82
Vested	(637,677	)	31.63
Forfeited	(116,238	)	30.96
Unvested balance at September 30, 2014	1,603,156		$	31.22

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 delivered in cash at the end of the performance period. The weighted average grant-date fair value of the performance share units was $31.71 per share and $30.12 per share for the nine months endedSeptember 30, 2014 and 2013, respectively. As of September 30, 2014, $3.2 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 2.07 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, 2013	480,660		$	32.33
Granted	252,161		31.71
Vested and paid out	(55,659	)	39.07
Canceled (1)	(51,361	)	39.07
Forfeited	(22,416	)	30.47
Unvested balance at September 30, 2014	603,385		$	30.92

____________________________

⁽¹⁾  Represents units that were not paid out due to not meeting performance targets. Payout of the performance share units is dependent upon the Company’s total shareholder return compared to a group of its peers over a three-year period.

Note 13 – Employee Benefits

The Company maintains closed, defined-benefit pension and postretirement medical plans. QEP's pension plans include a qualified and a nonqualified retirement plan. The Company's postretirement medical plan is unfunded and provides certain health care and life insurance benefits for certain retired employees. During the nine months endedSeptember 30, 2014, the Company made contributions of $8.1 million to its funded qualified pension plan and $4.4 million to its unfunded nonqualified retirement plan. Contributions to funded qualified plans increase plan assets while contributions to unfunded nonqualified plans are used to fund current benefit payments. During the remainder of 2014, the Company expects to contribute $0.6 million to its unfunded nonqualified pension plans and $0.1 million for retiree health care and life insurance benefits. No additional funding in 2014 is expected for its funded qualified pension plan. During the three and nine months ended September 30, 2014 for continuing operations, QEP recognized $1.4 million and $5.5 million, respectively, in recurring employee benefit expense compared to $2.3 million and $7.6 million, respectively, during the three and nine months ended September 30, 2013. During the three and nine months ended September 30, 2014 for discontinued operations, QEP recognized $0.4 million and $1.4 million, respectively, in recurring employee benefit expense compared to $0.7 million and $1.9 million, respectively, during the three and nine months ended September 30, 2013.

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During the nine months endedSeptember 30, 2014, the Company recognized a $2.4 million expense on curtailment and a $0.3 million expense for special termination benefits in connection with the second quarter 2014 property sales in the Midcontinent area (see Note 3 - Acquisitions and Divestitures). A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for present employees' future services. These expenses are included within “Net gain (loss) from asset sales” on the Condensed Consolidated Statement of Operations for the nine months endedSeptember 30, 2014.

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

	Pension
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(in millions)
Service cost	$	0.6		$	0.7		$	2.0		$	2.6
Interest cost	1.2			1.2			4.0			3.7
Expected return on plan assets	(1.4		)	(0.9		)	(3.8		)	(2.9		)
Amortization of prior service costs (1)	1.1			1.2			3.6			3.7
Amortization of actuarial losses (1)	0.2			0.5			0.6			1.7
Curtailment cost	—			—			2.0			—
Special termination benefits	—			—			0.3			—
Periodic expense	$	1.7		$	2.7		$	8.7		$	8.8

____________________________

⁽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				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
	(in millions)
Service cost	$	—	$	0.1	$	—	$	0.1
Interest cost	—		—		0.2		0.2
Amortization of prior service costs (1)	0.1		0.1		0.3		0.3
Recognized net actuarial loss	—		0.1		—		0.1
Curtailment cost	—				0.4		—
Periodic expense	$	0.1	$	0.3	$	0.9	$	0.7

____________________________

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

Note 14 – Operations by Line of Business

QEP’s lines of business include oil and gas exploration and production (QEP Energy); and marketing, the Haynesville Gathering System, an underground storage reservoir, and corporate (QEP Marketing & 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.

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

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	652.9		$	257.1		$	—		$	910.0
From affiliated customers	—			417.8			(417.8		)	—
Total revenues	652.9			674.9			(417.8		)	910.0
Operating expenses
Purchased gas, oil and NGL expense	32.8			668.3			(412.7		)	288.4
Lease operating expense	61.1			—			—			61.1
Gas, oil and NGL transportation and other handling costs	75.2			—			(4.1		)	71.1
Gathering and other expense	—			1.4			—			1.4
General and administrative	44.3			6.1			(1.0		)	49.4
Production and property taxes	59.3			0.1			—			59.4
Depreciation, depletion and amortization	249.0			2.4			—			251.4
Impairment and exploration expense	0.9			—			—			0.9
Total operating expenses	522.6			678.3			(417.8		)	783.1
Net (loss) gain from asset sales	(11.9		)	0.1						(11.8		)
Operating income (loss)	118.4			(3.3		)	—			115.1
Realized and unrealized gains on derivative contracts	154.1			1.6			—			155.7
Interest and other income	3.9			56.6			(56.3		)	4.2
Income from unconsolidated affiliates	0.1			—			—			0.1
Interest expense	(57.0		)	(40.8		)	56.3			(41.5		)
Income before income taxes	219.5			14.1			—			233.6
Income tax provision	(72.7		)	(7.2		)	—			(79.9		)
Income from continuing operations	146.8			6.9			—			153.7
Net income from discontinued operations, net of income tax	—			—			—			17.4
Net income attributable to QEP	$	146.8		$	6.9		$	—		$	171.1

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The following table is a summary of operating results for the three months endedSeptember 30, 2013, by line of business:

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	538.5		$	181.0		$	—		$	719.5
From affiliated customers	—			265.6			(265.6		)	—
Total revenues	538.5			446.6			(265.6		)	719.5
Operating expenses
Purchased gas, oil and NGL expense	39.2			438.2			(257.9		)	219.5
Lease operating expense	43.5			—			—			43.5
Gas, oil and NGL transportation and other handling costs	65.1			—			(6.5		)	58.6
Gathering and other expense	—			2.1			—			2.1
General and administrative	33.5			8.4			(1.2		)	40.7
Production and property taxes	40.4			0.2			—			40.6
Depreciation, depletion and amortization	236.0			2.4			—			238.4
Impairment and exploration expense	5.6						—			5.6
Total operating expenses	463.3			451.3			(265.6		)	649.0
Net gain from assets sales	12.8			—			—			12.8
Operating income (loss)	88.0			(4.7		)	—			83.3
Realized and unrealized losses on derivative contracts	(25.6		)	(2.2		)	—			(27.8		)
Interest and other income	2.6			52.2			(48.7		)	6.1
Income from unconsolidated affiliates	—			—			—			—
Interest expense	(49.2		)	(40.9		)	48.7			(41.4		)
Income before income taxes	15.8			4.4			—			20.2
Income tax (provision) benefit	(6.2		)	(1.9		)	—			(8.1		)
Income from continuing operations	9.6			2.5			—			12.1
Net income from discontinued operations, net of income tax	—			—			—			25.2
Net income attributable to QEP	$	9.6		$	2.5		$	—		$	37.3

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The following table is a summary of operating results for the nine months endedSeptember 30, 2014, by line of business:

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	1,953.3		$	661.4		$	—		$	2,614.7
From affiliated customers	—			1,132.9			(1,132.9		)	—
Total revenues	1,953.3			1,794.3			(1,132.9		)	2,614.7
Operating expenses
Purchased gas, oil and NGL expense	120.9			1,771.6			(1,117.0		)	775.5
Lease operating expense	177.0			—			—			177.0
Gas, oil and NGL transportation and other handling costs	211.8			—			(13.3		)	198.5
Gathering and other expense	—			4.8			—			4.8
General and administrative	132.0			17.6			(2.6		)	147.0
Production and property taxes	159.8			1.0			—			160.8
Depreciation, depletion and amortization	704.7			7.8			—			712.5
Impairment and exploration expense	8.3			—			—			8.3
Total operating expenses	1,514.5			1,802.8			(1,132.9		)	2,184.4
Net loss from asset sales	(210.3		)	—			—			(210.3		)
Operating income (loss)	228.5			(8.5		)	—			220.0
Realized and unrealized losses on derivative contracts	(9.7		)	(3.5		)	—			(13.2		)
Interest and other income	7.4			162.0			(161.6		)	7.8
Income from unconsolidated affiliates	0.2			—			—			0.2
Interest expense	(162.5		)	(127.5		)	161.6			(128.4		)
Income before income taxes	63.9			22.5			—			86.4
Income tax provision	(14.6		)	(11.5		)	—			(26.1		)
Income from continuing operations	49.3			11.0			—			60.3
Net income from discontinued operations, net of income tax	—			—			—			58.2
Net income attributable to QEP	$	49.3		$	11.0		$	—		$	118.5

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The following table is a summary of operating results for the nine months endedSeptember 30, 2013, by line of business:

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	1,575.2		$	489.6		$	—		$	2,064.8
From affiliated customers	—			686.0			(686.0		)	—
Total revenues	1,575.2			1,175.6			(686.0		)	2,064.8
Operating expenses
Purchased gas, oil and NGL expense	159.8			1,150.5			(660.0		)	650.3
Lease operating expense	130.2			—			—			130.2
Gas, oil and NGL transportation and other handling costs	180.8			—			(22.3		)	158.5
Gathering and other expense	—			6.4			—			6.4
General and administrative	100.2			20.3			(3.7		)	116.8
Production and property taxes	112.7			1.0			—			113.7
Depreciation, depletion and amortization	712.1			7.2			—			719.3
Impairment and exploration expense	13.5			—			—			13.5
Total operating expenses	1,409.3			1,185.4			(686.0		)	1,908.7
Net gain from asset sales	113.4			—			—			113.4
Operating income (loss)	279.3			(9.8		)	—			269.5
Realized and unrealized gains on derivative contracts	49.6			2.0			—			51.6
Interest and other income	7.5			158.4			(143.2		)	22.7
Interest expense	(143.4		)	(124.5		)	143.2			(124.7		)
Income before income taxes	193.0			26.1			—			219.1
Income tax provision	(71.1		)	(11.4		)	—			(82.5		)
Income for continuing operations	121.9			14.7			—			136.6
Net income from discontinued operations, net of income tax	—			—			—			74.8
Net income attributable to QEP	$	121.9		$	14.7		$	—		$	211.4

Note 15 - Subsequent Events

On October 19, 2014, QEP announced that its wholly owned subsidiary, QEP Field Services, had entered into a definitive agreement to sell its midstream business, including its ownership interest in QEP Midstream, to Tesoro in an all cash transaction valued at $2.5 billion, including $230.0 million to refinance debt at QEP Midstream. QEP will retain ownership of QEP Field Services’ Haynesville Gathering System. The transaction is subject to customary closing conditions and regulatory approvals and is expected to close in the fourth quarter of 2014.

On October 31, 2014, QEP entered into two purchase and sale agreements to divest non-core properties in southern Oklahoma for an aggregate sale price of $108 million, subject to customary purchase price adjustments. The aggregate net book value of the properties being sold is approximately $37 million as of September 30, 2014. Any gain or loss on the sale recorded by the Company will be determined based upon the final purchase price, which is subject to customary purchase price adjustments. The Company expects to close the transactions by year end.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide 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 2013 Annual Report on Form 10-K filing and analyzes the changes in the results of operations between the three and nine months endedSeptember 30, 2014 and 2013. 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 2013 Annual Report on Form 10-K.

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

OVERVIEW

QEP Resources, Inc. (QEP or the Company) is a holding company with two major 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 a underground gas storage reservoir (QEP Marketing and Other).

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

Strategies

We 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;

• manage our asset portfolio by divesting of non-core assets and midstream 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.

In October 2014, QEP entered into an agreement to sell its midstream business. See "Discontinued Operations" below. QEP believes this decision represents a significant milestone in the strategic repositioning of the Company, as it will be better positioned to deliver continued growth by focusing on its exploration and production assets.

Discontinued Operations

In December 2013, QEP's Board of Directors authorized the Company to develop a plan to separate its midstream business, QEP Field Services, including the Company's interest in QEP Midstream Partners, LP (“QEP Midstream”), from QEP. Between December 2013 and September 2014, the Company evaluated transaction alternatives, including selling or merging the

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midstream business or spinning the midstream business off to its shareholders. In June 2014, QEP filed a registration statement on Form 10 with the U.S. Securities and Exchange Commission (SEC) in preparation for a potential spinoff of QEP Field Services as a separate publicly traded company. Concurrently, the Company evaluated selling or merging its midstream business. In September 2014, based on the proposals received, the Company's Board of Directors authorized QEP's management to engage in the negotiation of terms of a definitive transaction with Tesoro Logistics LP ("Tesoro"). In October 2014, the Company announced that its wholly owned subsidiary, 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 to Tesoro in an all cash transaction valued at $2.5 billion, including $230.0 million to refinance debt at QEP Midstream. The decision to sell the midstream business is a result of the Company’s ongoing review of strategic alternatives to maximize shareholder value. QEP will retain ownership of QEP Field Services’ Haynesville Gathering System. As a result of the pending transaction, the QEP Field Services reporting segment, excluding the retained ownership of the Haynesville Gathering System, has been classified as assets and liabilities held for sale on the Condensed Consolidated Balance Sheet, as a discontinued operation on the Condensed Consolidated Statement of Operations and the notes accompanying the Condensed Consolidated Financial Statements, and in Management's Discussion and Analysis of Financial Condition and Results of Operations. 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.

Other Divestitures

The Company will periodically divest select non-core portfolio assets to redirect capital towards higher-return projects. 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 an aggregate sales price of approximately $702.3 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. On October 31, 2014, QEP entered into two purchase and sale agreements to divest non-core properties in southern Oklahoma for an aggregate sale price of $108 million, subject to customary purchase price adjustments. The aggregate net book value of the properties being sold is approximately $37 million as of September 30, 2014. Any gain or loss on the sale recorded by the Company will be determined based upon the final purchase price, which is subject to customary purchase price adjustments. In 2013, QEP divested of certain non-core properties resulting in total cash proceeds of $205.8 million.

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 consistent growth in organic production and reserves. QEP believes that it has one of the lowest cash operating structures among its E&P company peers. However, in certain of its resource plays, QEP, along with its peers, has experienced increased drilling and completion costs, which could impact near term drilling plans.

While historically a natural gas producer, the Company has increased its focus on growing the relative proportion of oil and NGL production in its E&P business. During the first three quarters of 2014, which includes seven months of results from the Permian Basin Acquisition, QEP Energy increased its oil and NGL production by 61% compared to the first three quarters of

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2013. Additionally, oil and NGL revenue represented 72% and 67% of QEP Energy's field-level revenue during the three and nine months endedSeptember 30, 2014, respectively, up from 61% and 57% during the three and nine months endedSeptember 30, 2013, respectively.

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 authorization was effective until January 2015, however QEP's Board of Directors has extended the program 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 authorization does not obligate QEP to acquire any specific number or value of shares, may be discontinued at any time and is governed by the Company's various restrictions on trading activity. During the three and nine months ended September 30, 2014, no shares were repurchased under this plan.

Financial and Operating Results

QEP Energy reported total equivalent production of 79.2 Bcfe during the third quarter of 2014 and 236.8 Bcfe in the first three quarters of 2014, an increase of 2% and 1%, respectively, compared to the same periods in 2013. Oil and NGL production increased to 6,235.9 Mbbls and to 16,982.8 Mbbls in the three and nine months ended September 30, 2014, increases of 64% and 61%, respectively, from the comparable periods in 2013. These increases were partially offset by a decrease in gas production to 41.8 Bcf in the third quarter of 2014 and to 134.9 Bcf in the first three quarters of 2014, decreases of 24% and 21%, respectively, from the comparable periods of 2013. The Company's 2012 Williston Basin acquisition contributed oil and NGL production of 2,857.6 Mbbls and 6,288.6 Mbbls in the three and nine months ended September 30, 2014, respectively. Additionally, QEP Energy completed the Permian Basin Acquisition on February 25, 2014, which contributed 1,375.6 Mbbls of oil and NGL production, $114.2 million of revenue and $23.1 million of net income during the period from February 25, 2014 to September 30, 2014. Properties in the Midcontinent contributed 25.6 Bcfe of total production in the nine months endedSeptember 30, 2014 which declined from 44.9 Bcfe in the nine months endedSeptember 30, 2013 due to the divestitures of non-core properties. QEP Energy benefited from higher average realized prices (including the impact of settled commodity derivatives) which increased 15% to $7.69 per Mcfe during the third quarter of 2014 and 14% to $7.41 per Mcfe during the nine months endedSeptember 30, 2014 compared to the nine months endedSeptember 30, 2013.

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 natural gas supply has grown faster than natural gas demand, 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 natural gas from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supplies have resulted in downward pressure on natural gas prices. Recently, increased oil production in the United States combined with softening global demand, a stronger US dollar, and other factors have led to weaker oil prices. Additionally, 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 lower than the remaining NGL components. QEP operated in ethane recovery for the majority of the first three quarters of 2014 and expects to continue in ethane recovery for the reminder of 2014. 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, and costs of goods and services required to drill and complete wells, and may impact the carrying value of its oil and natural gas properties.

QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production and to 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 September 30, 2014, assuming forecasted 2014 annual production of 318 Bcfe, QEP Energy had approximately 56% of its forecasted gas equivalent production covered with fixed-price swaps, including 60% of its forecasted gas production and 73% of its forecasted oil production covered with fixed-price swaps. 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 2014 drilling and completion capital expenditure budget to oil and liquids-rich gas projects in its portfolio.

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Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the outlook of the global economy, including political unrest in Eastern Europe, the Middle East, and Africa; a slowing of growth in Asia; the United States federal budget deficit; the potential for future shut-downs of federal government offices including the Department of Interior (including the Bureau of Land Management (BLM) and Bureau of Indian Affairs (BIA), which process permits to drill and rights-of-way for construction of gathering lines and other midstream infrastructure on federal (BLM) and Native American (BIA and BLM) minerals and surface); 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

Since 2008, 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. A reduction in natural gas production has lagged the downturn in the natural gas rig count because efficiency gains have allowed more wells to be drilled and completed per operating rig, higher per-well natural gas production from horizontal wells 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 the first three quarters of 2014 despite the decreased rig-count. However, strong natural gas demand from electric power generation, cold winter weather during the 2013-2014 heating season, and other demand sources have caused a general firming of natural gas prices during the last half of 2013 and into 2014. Despite recent increases in natural gas prices, QEP expects U.S. natural gas prices to remain range-bound over the near term. Relatively low natural gas prices have caused U.S. E&P companies, including QEP, to shift capital investments away from predominantly dry gas areas toward plays that are known to have liquids-rich oil and 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; however, the prices of heavier components of the NGL barrel have strengthened as a result of recent weather conditions combined with newly commissioned export facilities. Recently, increased oil production in the United States combined with softening global demand, a stronger US dollar, and other factors have led to weaker oil prices. QEP anticipates global oil prices will remain near current levels, assuming the global economy and socio-political backdrops remain relatively stable. Disruption to the global oil supply system, political and/or economic instability, 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 or Cushing) and global (Brent or U.S. Gulf Coast) 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.

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 $3.6 million in impairments of unproved properties and no impairment of proved properties during the first three quarters of 2014.

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. Because 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, 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 7 of Part II of its 2013 Annual Report on Form 10-K. The Company’s condensed consolidated financial statements are prepared in accordance with GAAP. The preparation of the Company’s condensed consolidated financial statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP’s accounting policies on oil and gas reserves, successful efforts accounting for oil and gas operations, impairment of oil and gas properties, asset retirement obligations, accounting for derivative contracts, revenue recognition, environmental obligations, litigation and other contingencies, benefit plan

33

obligations, equity-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

Net Income

QEP generated net income from continuing operations during the third quarter of 2014 of $153.7 million, or $0.84 per diluted share, compared to net income from continuing operations of $12.1 million, or $0.07 per diluted share, in the third quarter of 2013. The increase in the third quarter of 2014 was due to a $137.2 millionincrease in QEP Energy’s net income and a $4.4 millionincrease in QEP Marketing and Other's net income. QEP Energy's net income increase was primarily due to unrealized gains on derivative instruments compared to an unrealized loss in the third quarter of 2013 and increased oil production. These increases were offset by realized derivative instrument losses in the third quarter of 2014 compared to realized gains in the third quarter of 2013, higher operating expenses and a net loss on asset sales compared to a net gain in the third quarter of 2013. QEP Marketing and Other's net income increased in the third quarter of 2014 primarily due to realized and unrealized losses on derivative instruments and higher interest income compared to the third quarter of 2013.

QEP generated net income from continuing operations during the first three quarters of 2014 of $60.3 million, or $0.34 per diluted share, compared to a net income from continuing operations of $136.6 million, or $0.76 per diluted share in the first three quarters of 2013. The decrease in the first three quarters of 2014 is due to a $72.6 million decrease in QEP Energy's net income and a $3.7 million decrease in QEP Marketing and Other's net income. QEP Energy's net income decreased because of the loss on the disposal of the non-core properties of $210.4 million and higher operating expenses which were partially offset by higher oil and NGL production and greater unrealized gains on derivative instruments in the first three quarters of 2014 compared to losses in the first three quarters of 2013. QEP Marketing and Other's net income decreased in the first three quarters of 2014 primarily due to unrealized losses on derivative instruments compared to a gain in the first three quarters of 2013, partially offset by higher margins on purchased gas, oil and NGL sales.

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Change			2014		2013		Change
	(in millions)
QEP Energy	$	146.8	$	9.6	$	137.2		$	49.3	$	121.9	$	(72.6	)
QEP Marketing & Other	6.9		2.5		4.4			11.0		14.7		(3.7		)
Net income from continuing operations	153.7		12.1		141.6			60.3		136.6		(76.3		)
Net income from discontinued operations	17.4		25.2		(7.8		)	58.2		74.8		(16.6		)
Net income	$	171.1	$	37.3	$	133.8		$	118.5	$	211.4	$	(92.9	)
Diluted earnings per share from continuing operations	$	0.84	$	0.07	$	0.77		$	0.34	$	0.76	$	(0.42	)
Diluted earnings per share from discontinued operations	0.10		0.14		(0.04		)	0.32		0.42		(0.10		)
Diluted earnings per share	$	0.94	$	0.21	$	0.73		$	0.66	$	1.18	$	(0.52	)
Average diluted shares	180.6		179.5		1.1			180.4		179.4		1.0

Adjusted EBITDA

Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure for comparing the Company’s financial performance to other oil and gas producing companies. 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.

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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
	(in millions)
QEP Energy	$	373.6		$	344.0		$	29.6		$	1,078.5		$	999.8		$	78.7
QEP Marketing & Other	(2.7		)	(3.2		)	0.5			(6.3		)	(3.8		)	(2.5		)
Adjusted EBITDA from continuing operations	370.9			340.8			30.1			1,072.2			996.0			76.2
Discontinued Operations	38.4			54.3			(15.9		)	124.2			163.6			(39.4		)
Adjusted EBITDA	$	409.3		$	395.1		$	14.2		$	1,196.4		$	1,159.6		$	36.8

Adjusted EBITDA from continuing operations increased to $370.9 million in the third quarter of 2014 from $340.8 million in the third quarter of 2013, due to a 77% increase in oil production and a 35% increase in NGL production, partially offset by a 24% decrease in gas production, decreases of 10% and 21%, respectively, in average net realized equivalent oil and NGL prices and higher operating expenses.

Adjusted EBITDA from continuing operations increased to $1,072.2 million in the first three quarters of 2014 from $996.0 million in the first three quarters of 2013, due to a 67% increase in oil production and a 49% increase in NGL production, partially offset by a 21% decrease in gas production, decreases of 9% and 17%, respectively, in average net realized equivalent oil and NGL prices and higher operating expenses

The following tables are reconciliations of Adjusted EBITDA to net income from continuing operations and discontinued operations, net of tax, the most comparable GAAP financial measures:

	QEP Energy			QEP Marketing & Other(1)			Continuing Operations			Discontinued Operations
Three Months Ended September 30, 2014	(in millions)
Net income attributable to QEP	$	146.8		$	6.9		$	153.7		$	17.4
Unrealized gains on derivative contracts	(160.8		)	(3.3		)	(164.1		)	—
Net loss (gain) from asset sales	11.9			(0.1		)	11.8			—
Interest and other income	(3.9		)	(0.3		)	(4.2		)	—
Income tax provision	72.7			7.2			79.9			9.9
Interest expense (income) (2)	57.0			(15.5		)	41.5			0.8
Depreciation, depletion and amortization (3)	249.0			2.4			251.4			10.3
Impairment	0.1			—			0.1			—
Exploration expenses	0.8			—			0.8			—
Adjusted EBITDA	$	373.6		$	(2.7	)	$	370.9		$	38.4
Three Months Ended September 30, 2013
Net income attributable to QEP	$	9.6		$	2.5		$	12.1		$	25.2
Unrealized losses on derivative contracts	52.8			1.3			54.1			—
Net (gain) loss from asset sales	(12.8		)	—			(12.8		)	0.1
Interest and other (income) loss	(2.6		)	(3.5		)	(6.1		)	2.1
Income tax provision	6.2			1.9			8.1			14.2
Interest expense (income) (2)	49.2			(7.8		)	41.4			0.2
Depreciation, depletion and amortization (3)	236.0			2.4			238.4			12.5
Impairment	3.8			—			3.8			—
Exploration expenses	1.8			—			1.8			—
Adjusted EBITDA	$	344.0		$	(3.2	)	$	340.8		$	54.3

35

	QEP Energy			QEP Marketing & Other(1)			Continuing Operations			Discontinued Operations
Nine Months Ended September 30, 2014
Net income attributable to QEP	$	49.3		$	11.0		$	60.3		$	58.2
Unrealized gain on derivative contracts	(63.8		)	(2.1		)	(65.9		)	—
Net loss from asset sales	210.3			—			210.3			0.1
Interest and other income	(7.4		)	(0.4		)	(7.8		)	—
Income tax provision	14.6			11.5			26.1			32.8
Interest expense (income) (2)	162.5			(34.1		)	128.4			1.7
Depreciation, depletion and amortization (3)	704.7			7.8			712.5			31.4
Impairment	3.6			—			3.6			—
Exploration expenses	4.7			—			4.7			—
Adjusted EBITDA	$	1,078.5		$	(6.3	)	$	1,072.2		$	124.2
Nine Months Ended September 30, 2013
Net income attributable to QEP	$	121.9		$	14.7		$	136.6		$	74.8
Unrealized (gains) losses on derivative contracts	58.7			(3.2		)	55.5			—
Net (gain) loss from asset sales	(113.4		)	—			(113.4		)	0.5
Interest and other (income) loss	(7.5		)	(15.2		)	(22.7		)	13.7
Income tax provision	71.1			11.4			82.5			42.4
Interest expense (income) (2)	143.4			(18.7		)	124.7			(2.4		)
Depreciation, depletion and amortization (3)	712.1			7.2			719.3			34.6
Impairment	4.0			—			4.0			—
Exploration expenses	9.5			—			9.5			—
Adjusted EBITDA	$	999.8		$	(3.8	)	$	996.0		$	163.6

__________________________

⁽¹⁾ Includes intercompany eliminations.

⁽²⁾ Excludes noncontrolling interest's share of $0.7 million and $0.1 million during the three months endedSeptember 30,2014 and 2013, respectively, and $1.1 million and $0.1 million during the nine months ended months ended September 30,2014 and 2013, respectively, of interest expense attributable to QEP Midstream.

⁽³⁾ Excludes noncontrolling interest's share of $4.0 million and $2.2 million during the three months endedSeptember 30,2014 and 2013, respectively, and $11.7 million and $3.2 million during the nine months endedSeptember 30,2014 and 2013, respectively, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C and QEP Midstream.

36

QEP ENERGY

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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
Revenues	(in millions)
Gas sales	$	171.7		$	194.8		$	(23.1	)	$	609.3		$	610.5		$	(1.2	)
Oil sales	393.4			253.8			139.6			1,040.6			656.3			384.3
NGL sales	51.1			47.7			3.4			179.0			144.4			34.6
Purchased gas, oil and NGL sales	33.3			39.3			(6.0		)	120.2			156.6			(36.4		)
Other	3.4			2.9			0.5			4.2			7.4			(3.2		)
Total revenues	652.9			538.5			114.4			1,953.3			1,575.2			378.1
Operating expenses
Purchased gas, oil and NGL expense	32.8			39.2			(6.4		)	120.9			159.8			(38.9		)
Lease operating expense	61.1			43.5			17.6			177.0			130.2			46.8
Gas, oil and NGL transportation and other handling costs	75.2			65.1			10.1			211.8			180.8			31.0
General and administrative	44.3			33.5			10.8			132.0			100.2			31.8
Production and property taxes	59.3			40.4			18.9			159.8			112.7			47.1
Depreciation, depletion and amortization	249.0			236.0			13.0			704.7			712.1			(7.4		)
Exploration expenses	0.8			1.8			(1.0		)	4.7			9.5			(4.8		)
Impairment	0.1			3.8			(3.7		)	3.6			4.0			(0.4		)
Total operating expenses	522.6			463.3			59.3			1,514.5			1,409.3			105.2
Net gain (loss) from asset sales	(11.9		)	12.8			(24.7		)	(210.3		)	113.4			(323.7		)
Operating income (loss)	118.4			88.0			30.4			228.5			279.3			(50.8		)
Realized gains (losses) on derivative instruments	(6.7		)	27.2			(33.9		)	(73.5		)	108.3			(181.8		)
Unrealized gains (losses) on derivative instruments	160.8			(52.8		)	213.6			63.8			(58.7		)	122.5
Interest and other income	3.9			2.6			1.3			7.4			7.5			(0.1		)
Income from unconsolidated affiliates	0.1			—			0.1			0.2			—			0.2
Interest expense	(57.0		)	(49.2		)	(7.8		)	(162.5		)	(143.4		)	(19.1		)
Income from continuing operations before income taxes	219.5			15.8			203.7			63.9			193.0			(129.1		)
Income tax provision	(72.7		)	(6.2		)	(66.5		)	(14.6		)	(71.1		)	56.5
Net income attributable to QEP Energy	$	146.8		$	9.6		$	137.2		$	49.3		$	121.9		$	(72.6	)
Production volumes (Bcfe)
Northern Region
Pinedale	26.4			25.2			1.2			72.6			70.1			2.5
Williston Basin	25.4			11.8			13.6			61.6			31.9			29.7
Uinta Basin	6.8			7.3			(0.5		)	19.8			20.1			(0.3		)
Other Northern	1.9			2.6			(0.7		)	7.9			9.6			(1.7		)
Southern Region
Haynesville/Cotton Valley	11.4			16.2			(4.8		)	38.9			57.3			(18.4		)
Permian Basin	5.0			—			5.0			10.4			—			10.4
Midcontinent	2.3			14.9			(12.6		)	25.6			44.9			(19.3		)
Total production	79.2			78.0			1.2			236.8			233.9			2.9
Total equivalent prices (per Mcfe)
Average equivalent field-level price	$	7.77		$	6.36		$	1.41		$	7.72		$	6.03		$	1.69
Commodity derivative impact	(0.08		)	0.35			(0.43		)	(0.31		)	0.47			(0.78		)
Net realized equivalent price	$	7.69		$	6.71		$	0.98		$	7.41		$	6.50		$	0.91

37

Revenue, Volume and Price Variance Analysis

The following table shows volume and price related changes for each of QEP Energy’s major revenue categories for the three and nine months ended September 30, 2014, compared to the three and nine months ended September 30, 2013:

	Gas			Oil			NGL			Total
	(in millions)
QEP Energy Production Revenues
Three months ended September 30, 2013 Revenues	$	194.8		$	253.8		$	47.7		$	496.3
Changes associated with volumes (1)	(47.2		)	194.7			16.9			164.4
Changes associated with prices (2)	24.1			(55.1		)	(13.5		)	(44.5		)
Three months ended September 30, 2014 Revenues	$	171.7		$	393.4		$	51.1		$	616.2
QEP Energy Production Revenues
Nine months ended September 30, 2013 Revenues	$	610.5		$	656.3		$	144.4		$	1,411.2
Changes associated with volumes (1)	(127.9		)	439.2			70.1			381.4
Changes associated with prices (2)	126.7			(54.9		)	(35.5		)	36.3
Nine months ended September 30, 2014 Revenues	$	609.3		$	1,040.6		$	179.0		$	1,828.9

____________________________

⁽¹⁾  The revenue variance attributed to the change in volume is calculated by multiplying the change in volumes from the three and nine months ended September 30, 2014, as compared to the three and nine months ended September 30, 2013, by the average field-level price for the three and nine months ended September 30, 2013.

⁽²⁾  The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level prices from the three and nine months ended September 30, 2014, as compared to the three and nine months ended September 30, 2013, by volumes for the three and nine months ended September 30, 2014.

Gas Volumes and Prices

	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Change			2014			2013		Change
Gas production volumes (Bcf)
Northern Region
Pinedale	19.9		22.0		(2.1		)	54.9			61.1		(6.2		)
Williston Basin	1.8		0.6		1.2			3.7			2.1		1.6
Uinta Basin	4.5		5.1		(0.6		)	12.9			14.1		(1.2		)
Other Northern	1.7		2.2		(0.5		)	6.8			8.2		(1.4		)
Southern Region
Haynesville/Cotton Valley	11.3		16.1		(4.8		)	38.6			57.0		(18.4		)
Permian Basin	1.1		—		1.1			2.2			—		2.2
Midcontinent	1.5		9.2		(7.7		)	15.8			28.1		(12.3		)
Total production	41.8		55.2		(13.4		)	134.9			170.6		(35.7		)
Gas prices (per Mcf)
Northern Region	$	4.07	$	3.48	$	0.59		$	4.50		$	3.59	$	0.91
Southern Region	4.17		3.57		0.60			4.53			3.56		0.97
Average field-level price	$	4.10	$	3.52	$	0.58		$	4.52		$	3.58	$	0.94
Commodity derivative impact	0.13		0.77		(0.64		)	(0.18		)	0.65		(0.83		)
Net realized price	$	4.23	$	4.29	$	(0.06	)	$	4.34		$	4.23	$	0.11

Gas revenues decreased$23.1 million, or 12%, in the third quarter of 2014 when compared to the third quarter of 2013, due to lower gas production partially offset by higher field-level prices. The decrease in production was primarily driven by the divestiture of non-core Midcontinent properties in the third quarter 2013 and second quarter 2014 and a production decrease in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program. Additionally, gas production

38

decreased in QEP's Pinedale field due to ethane recovery in the third quarter of 2014, in which ethane is extracted from the gas stream and sold as an NGL, compared to ethane rejection in 2013, in which ethane is sold in the gas stream.

Gas revenues decreased$1.2 million in the first three quarters of 2014 when compared to the first three quarters of 2013, due to lower gas production partially offset by higher field-level prices. The decrease in production volumes was primarily driven by the continued suspension of QEP's Haynesville/Cotton Valley operated drilling program and a production decrease in the Midcontinent due to the divestitures of non-core properties in the Midcontinent in the third quarter of 2013 and second quarter 2014 and fewer net well completions in the second half of 2013 and in 2014. Additionally, production decreased in QEP's Pinedale field due to partial ethane recovery in the first three quarters of 2014, compared to ethane rejection in 2013, as well as completions of wells in late 2013 in which QEP had no working interest.

Oil Volumes and Prices

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
Oil production volumes (Mbbl)
Northern Region
Pinedale	172.1			180.7			(8.6		)	464.9			490.6			(25.7		)
Williston Basin	3,692.0			1,799.1			1,892.9			9,043.7			4,641.9			4,401.8
Uinta Basin	230.3			265.7			(35.4		)	672.6			717.3			(44.7		)
Other Northern	24.9			48.5			(23.6		)	166.0			200.5			(34.5		)
Southern Region
Haynesville/Cotton Valley	10.8			11.5			(0.7		)	31.4			33.9			(2.5		)
Permian Basin	474.1			—			474.1			1,032.3			—			1,032.3
Midcontinent	68.2			339.2			(271.0		)	554.1			1,084.6			(530.5		)
Total production	4,672.4			2,644.7			2,027.7			11,965.0			7,168.8			4,796.2
Oil prices (per bbl)
Northern Region	$	83.74		$	95.05		$	(11.31	)	$	86.19		$	91.32		$	(5.13	)
Southern Region	87.74			102.06			(14.32		)	92.02			92.80			(0.78		)
Average field-level price	$	84.21		$	95.98		$	(11.77	)	$	86.98		$	91.55		$	(4.57	)
Commodity derivative impact	(2.60		)	(5.79		)	3.19			(4.20		)	(0.52		)	(3.68		)
Net realized price	$	81.61		$	90.19		$	(8.58	)	$	82.78		$	91.03		$	(8.25	)

Oil revenues increased$139.6 million, or 55%, in the third quarter of 2014 when compared to the third quarter of 2013 due to higher volumes partially offset by lower average field-level prices. The increase in production volumes was primarily driven by increases in the Williston Basin due to the continued development of the properties acquired in 2012. The Company also had an additional 474.1 Mbbls of production in the third quarter of 2014 from its Permian Basin Acquisition. These production increases were partially offset by a decrease in the Midcontinent due to the divestitures of non-core properties in the third quarter 2013 and second quarter 2014 and fewer well completions. Field-level oil prices decreased 12% in the third quarter of 2014.

Oil revenues increased$384.3 million, or 59%, in the first three quarters of 2014 when compared to the first three quarters of 2013 due to higher volumes, slightly offset by lower average field-level prices. The increase in production volumes was primarily driven by increases in the Williston Basin due to the continued development of the properties acquired in 2012. The Company also had an additional 1,032.3 Mbbls of production in the first three quarters of 2014 from its Permian Basin Acquisition. These increases were partially offset by a decrease in the Midcontinent due to divestitures of non-core properties in the third quarter of 2013 and second quarter 2014 and decreased well completions. Field-level oil prices decreased in the first three quarters of 2014 by 5%.

39

NGL Volumes and Prices

	Three Months Ended September 30,							Nine Months Ended September 30,
	2014		2013		Change			2014		2013		Change
NGL production volumes (Mbbl)
Northern Region
Pinedale	915.3		355.8		559.5			2,484.1		1,005.4		1,478.7
Williston Basin	239.7		66.8		172.9			605.0		321.8		283.2
Uinta Basin	161.5		111.0		50.5			478.3		283.1		195.2
Other Northern	6.4		12.9		(6.5		)	11.7		43.8		(32.1		)
Southern Region
Haynesville/Cotton Valley	9.7		3.6		6.1			28.5		12.9		15.6
Permian Basin	179.9		—		179.9			343.3		—		343.3
Midcontinent	51.0		603.8		(552.8		)	1,066.9		1,710.4		(643.5		)
Total production	1,563.5		1,153.9		409.6			5,017.8		3,377.4		1,640.4
NGL prices (per bbl)
Northern Region	$	34.19	$	54.91	$	(20.72	)	$	36.24	$	55.22	$	(18.98	)
Southern Region	24.35		29.18		(4.83		)	34.27		30.79		3.48
Average field-level price	$	32.68	$	41.36	$	(8.68	)	$	35.68	$	42.75	$	(7.07	)
Commodity derivative impact	—		—		—			—		—		—
Net realized price	$	32.68	$	41.36	$	(8.68	)	$	35.68	$	42.75	$	(7.07	)

NGL revenues increased$3.4 million, or 7%, during the third quarter of 2014, when compared to the third quarter of 2013, due to increased production volumes partially offset by a decreased average price per barrel. Pinedale and Uinta NGL volumes increased due to ethane recovery in the third quarter of 2014 compared to ethane rejection in the third quarter of 2013, while the Williston Basin volumes grew as a result of increased development drilling. Additionally, the Permian Basin Acquisition contributed to the increased NGL production. These increases were partially offset by a decrease in the Midcontinent due to divestitures of non-core properties in the third quarter of 2013 and the second quarter of 2014 and decreased well completions. NGL prices decreased 21% during the third quarter of 2014 primarily as a result of recovering ethane from the wet gas production stream in Pinedale and Uinta during the third quarter of 2014, compared to no recovery in the third quarter of 2013. When ethane is recovered as an NGL instead of being sold as part of the gas stream, the average NGL barrel sales price decreases as the ethane price is lower than the remaining NGL components.

NGL revenues increased$34.6 million, or 24%, during the first three quarters of 2014, when compared to the first three quarters of 2013, due to increased production volumes partially offset by a decreased average price per barrel. Pinedale and Uinta NGL volumes increased due to partial ethane recovery in the first three quarters of 2014 compared to ethane rejection in the first three quarters of 2013, while the Williston Basin NGL volumes grew as a result of increased development drilling. Additionally, the Permian Basin Acquisition contributed to the increased NGL production. These increases were partially offset by a decrease in the Midcontinent due to divestitures of non-core properties in the third quarter of 2013 and second quarter 2014 and decreased well completions. NGL prices decreased 17% during the first three quarters of 2014 primarily as a result of partially recovering ethane from the gas stream in Pinedale and Uinta during the first three quarters of 2014, compared to no recovery in the first three quarters of 2013.

40

QEP Energy Resale Margin

QEP Energy purchases and resells gas, oil and NGL products in order to fulfill firm transportation contract commitments and mitigate potential losses. The difference between the price of the products purchased and sold 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, oil and NGL resale activities:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
Resale Margin	(in millions)
Purchased gas, oil and NGL sales	$	33.3		$	39.3		$	(6.0	)	$	120.2		$	156.6		$	(36.4	)
Purchased gas, oil and NGL expense	(32.8		)	(39.2		)	6.4			(120.9		)	(159.8		)	38.9
Resale margin	$	0.5		$	0.1		$	0.4		$	(0.7	)	$	(3.2	)	$	2.5

During the third quarter of 2014, QEP Energy recorded income on resale margin of $0.5 million compared to $0.1 million of income in the third quarter of 2013 as a result of its activities to utilize pipeline transportation commitments in Louisiana.

During the first three quarters of 2014, QEP Energy recorded a loss on resale margin of $0.7 million compared to a loss of $3.2 million in the first three quarters of 2013 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, excluding divested wells, for the three and nine months ended September 30, 2014:

	Operated Completions				Non-operated Completions
	Three Months Ended		Nine Months Ended		Three Months Ended		Nine Months Ended
	September 30, 2014		September 30, 2014		September 30, 2014		September 30, 2014
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	38	29.0	95	73.6	—	—	—	—
Williston Basin	28	23.0	73	60.5	28	2.7	55	4.3
Uinta Basin	4	4.0	5	5.0	50	0.1	162	0.4
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	8	0.1	26	1.6
Permian Basin	25	22.7	44	40.1	1	0.3	1	0.3
Midcontinent	—	—	1	0.9	13	0.4	28	1.2

41

The following table presents operated and non-operated wells being drilled or waiting on completion, excluding divested wells, at September 30, 2014:

	Operated				Non-operated
	Being drilled		Waiting on completion		Being drilled		Waiting on completion
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	16	7.6	40	22.9	—	—	—	—
Williston Basin	20	15.8	20	16.5	8	0.5	36	1.4
Uinta Basin	1	1.0	1	1.0	—	—	—	—
Other Northern	1	1.0	3	3.0	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	14	1.4	17	2.0
Permian Basin	7	6.3	9	8.4	—	—	—	—
Midcontinent	—	—	—	—	4	0.1	6	0.2

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. 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 73 gross operated wells waiting on completion as of September 30, 2014.

Operating expenses

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014		2013		Change		2014		2013		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	3.14	$	3.02	$	0.12	$	2.98	$	3.04	$	(0.06	)
Lease operating expense	0.77		0.56		0.21		0.75		0.56		0.19
Gas, oil and NGL transportation and other handling costs	0.95		0.84		0.11		0.89		0.77		0.12
Production taxes	0.75		0.51		0.24		0.67		0.48		0.19
Operating Expenses	$	5.61	$	4.93	$	0.68	$	5.29	$	4.85	$	0.44

Depreciation, depletion and amortization (DD&A). DD&A expense increased $13.0 million, or $0.12 per Mcfe, in the third quarter of 2014 compared to the third quarter of 2013 due to an increase in the Williston Basin expense and additional expenses related to the Permian Basin Acquisition expense partially offset by decreases in the Midcontinent and Haynesville/Cotton Valley. The increase in the Williston Basin expense relates to increased production partially offset by a reduction in the DD&A expense related to the retirement of properties sold in the Williston Basin during the second quarter of 2014 and a lower rate due to additional proved reserves added at the end of the 2013. The decrease in the Midcontinent DD&A expense was a result of the second quarter 2014 property sales (see Note 3 - Acquisitions and Divestitures). Upon entering into purchase and sale agreements during the second quarter of 2014, the divested Midcontinent properties were characterized as held for sale resulting in no further depletion on the fields. The decrease in expense at Haynesville/Cotton Valley was a result of declining production.

During the first three quarters of 2014, DD&A expense decreased $7.4 million, or $0.06 per Mcfe, due to expense decreases in the Midcontinent and Haynesville/Cotton Valley partially offset by an increase in the Williston Basin expense and additional expenses related to the Permian Basin Acquisition. The decrease in the Midcontinent DD&A expense was a result of the second quarter 2014 property sales (see Note 3 - Acquisitions and Divestitures). Upon entering into purchase and sale agreements during the second quarter of 2014, the divested Midcontinent properties were characterized as held for sale resulting in no further depletion on the fields. The decrease in expense in Haynesville/Cotton Valley relates to decreased production. The increase in the Williston Basin expense relates to increased production partially offset by a reduction in the DD&A expense

42

related to the retirement of properties sold in the Williston Basin during the second quarter of 2014 and a lower rate due to additional proved reserves added at the end of the 2013.

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 September 30,						Nine Months Ended September 30,
	2014		2013		Change		2014		2013		Change
	(per Mcfe)
Northern Region	$	0.58	$	0.51	$	0.07	$	0.64	$	0.59	$	0.05
Southern Region	1.02		0.62		0.40		0.87		0.51		0.36
Average lease operating expense	0.77		0.56		0.21		0.75		0.56		0.19

QEP Energy’s LOE increased $17.6 million, or $0.21 per Mcfe, during the third quarter of 2014 compared to the third quarter of 2013. The Southern Region's LOE per Mcfe increase during the third quarter of 2014 was driven primarily by the Permian Basin Acquisition oil wells in the first quarter of 2014 as well as a per Mcfe increase in Haynesville/Cotton Valley and Midcontinent. The Haynesville increase is due to declining production volume but relatively flat labor costs, fixed operating expenses due to the consistent well count and increased workover costs. The Midcontinent increase was due to the divestiture of non-core properties in the second quarter of 2014 with the remaining wells in the area having higher per Mcfe LOE costs. QEP also incurred repair expenses in the Permian Basin of $1.9 million in the third quarter of 2014. The Northern Region increase was driven primarily by increased well count and greater production from the Williston Basin oil wells which have higher operating costs compared to the other properties, which are primarily lower cost gas wells.

QEP Energy’s LOE increased $46.8 million, or $0.19 per Mcfe, during the first three quarters of 2014 compared to the first three quarters of 2013. The Southern Region's LOE per Mcfe increase during the first three quarters of 2014 was driven primarily by the Permian Basin Acquisition oil wells in the first quarter of 2014 as well as a per Mcfe increase in Haynesville/Cotton Valley. The Haynesville increase is due to declining production volume but relatively flat labor costs, and other fixed operating expenses due to the consistent well count and increased workover costs. QEP also incurred repair expenses in the Permian Basin of $4.2 million in the first three quarters of 2014. The Northern Region increase was driven primarily by increased well count and greater production from the Williston Basin oil wells which have higher operating costs compared to the other properties, which are primarily lower cost gas wells.

Gas, oil and NGL transportation and other handling costs. Gas, oil and NGL transportation and other handling costs increased $10.1 million, or $0.11 per Mcfe, in the third quarter of 2014 when compared to the third quarter of 2013. The expense increase was primarily attributable to the Williston Basin increased production as well as additional expenses incurred for the Permian Basin Acquisition.

Gas, oil and NGL transportation and other handling costs increased $31.0 million, or $0.12 per Mcfe, in the first three quarters of 2014 when compared to the first three quarters of 2013. The expense increase was primarily due to an increase in the Williston Basin increased production and additional expenses incurred for the Permian Basin Acquisition.

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 increased $18.9 million, or $0.24 per Mcfe, during the third quarter of 2014 and $47.1 million, or $0.19 per Mcfe, during the first three quarters of 2014, as a result of increased oil and NGL revenues due to higher oil and NGL production.

Exploration expense. Exploration expenses decreased $1.0 million during the third quarter of 2014 and $4.8 million in the first three quarters of 2014 compared to the equivalent 2013 periods. These decreases primarily related to lower exploration-related labor.

Impairment expense. Impairment expense was $0.1 million during the third quarter of 2014 and $3.6 million during the first three quarters of 2014 related to unproved property impairments due to expiring leases and changes in drilling plans.

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QEP MARKETING AND OTHER

QEP Marketing and Other includes the results of operations from QEP Marketing, the retained interest in the Haynesville Gathering System and Corporate. The following table provides a summary of QEP Marketing and Other's financial and operating results:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
	(in millions)
Revenues
Purchased gas, oil and NGL sales	$	669.9		$	439.1		$	230.8		$	1,777.0		$	1,148.6		$	628.4
Other	5.0			7.5			(2.5		)	17.3			27.0			(9.7		)
Total revenues	674.9			446.6			228.3			1,794.3			1,175.6			618.7
Operating expenses
Purchased gas, oil and NGL expense	668.3			438.2			230.1			1,771.6			1,150.5			621.1
Gathering and other expense	1.4			2.1			(0.7		)	4.8			6.4			(1.6		)
General and administrative	6.1			8.4			(2.3		)	17.6			20.3			(2.7		)
Production and property taxes	0.1			0.2			(0.1		)	1.0			1.0			—
Depreciation, depletion and amortization	2.4			2.4			—			7.8			7.2			0.6
Total operating expenses	678.3			451.3			227.0			1,802.8			1,185.4			617.4
Net gain from asset sales	0.1			—			0.1			—			—			—
Operating income (loss)	(3.3		)	(4.7		)	1.4			(8.5		)	(9.8		)	1.3
Realized losses on derivative instruments	(1.7		)	(0.9		)	(0.8		)	(5.6		)	(1.2		)	(4.4		)
Unrealized gains (losses) on derivative instruments	3.3			(1.3		)	4.6			2.1			3.2			(1.1		)
Interest and other income	56.6			52.2			4.4			162.0			158.4			3.6
Interest expense	(40.8		)	(40.9		)	0.1			(127.5		)	(124.5		)	(3.0		)
Income before income taxes	14.1			4.4			9.7			22.5			26.1			(3.6		)
Income tax provision	(7.2		)	(1.9		)	(5.3		)	(11.5		)	(11.4		)	(0.1		)
Net income	$	6.9		$	2.5		$	4.4		$	11.0		$	14.7		$	(3.7	)

Resale Margin

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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Change			2014			2013			Change
Resale Margin	(in millions)
Purchased gas, oil and NGL sales	$	669.9		$	439.1		$	230.8		$	1,777.0		$	1,148.6		$	628.4
Purchased gas, oil and NGL expense	(668.3		)	(438.2		)	(230.1		)	(1,771.6		)	(1,150.5		)	(621.1		)
Realized losses on derivative instruments	(1.7		)	(0.9		)	(0.8		)	(5.6		)	(1.2		)	(4.4		)
Resale margin	$	(0.1	)	$	—		$	(0.1	)	$	(0.2	)	$	(3.1	)	$	2.9

Purchased gas, oil and NGL sales increased by $230.8 million, or 53%, during the third quarter of 2014, compared to the third quarter of 2013, due to a $248.0 million increase in resale oil and NGL sales, partially offset by a $17.2 million decrease in resale gas sales. Resale oil and NGL sales increased due to a 132% increase in resale volumes and a 19% decrease in resale price. Resale gas sales decreased due to a 24% decrease in resale volumes, partially offset by a 17% increase in resale price.

Purchased gas, oil and NGL expense, which includes transportation expense, increased 53% in the third quarter of 2014, compared to the third quarter of 2013, due to a $248.3 million increase in resale oil and NGL purchases, partially offset by a $18.2 million decrease in resale gas purchases. Resale oil and NGL sales increased due to a 136% increase in resale purchase

44

volumes, partially offset by a 20% decrease in resale purchase price. Resale gas purchased expense decreased due to a 5% decrease in the resale volumes and a 8% decrease in resale purchase price.

Purchased gas, oil and NGL sales increased by $628.4 million, or 55%, during the first three quarters of 2014, compared to the first three quarters of 2013, due to a $626.1 million increase in resale oil and NGL sales and a $2.4 million increase in resale gas sales. Resale oil and NGL sales increased due to a 114% increase in resale volumes, partially offset by a 10% decrease in resale oil and NGL price. Resale gas sales increased due to a 26% increase in resale price, partially offset by a 13% decrease in resale volumes.

Purchased gas, oil and NGL expense, which includes transportation expense, increased 54% in the first three quarters of 2014, compared to the first three quarters of 2013, due to a $624.8 million increase in resale oil and NGL purchases offset by a $3.8 million decrease in resale gas purchases. Resale oil and NGL sales increased due to a 117% increase in resale purchase volumes, partially offset by a 11% decrease in resale purchase price. Resale gas purchased expense decreased due to a 13% decrease in resale purchase volumes partially offset by a 14% increase in resale purchase price.

OTHER CONSOLIDATED EXPENSES AND INCOME FROM CONTINUING OPERATIONS

General and administrative expense. During the third quarter of 2014, general and administrative (G&A) expense increased $8.7 million, or 21% compared to the third quarter of 2013 primarily due to the following: a $3.5 million increase in labor and benefits costs associated with an increase in the number of employees and the Company's annual compensation program and a $2.8 million increase in professional and outside services and compensation expense mainly related to the Enterprise Resource Planning (ERP) system implementation. These increases were partially offset by a $0.7 million decrease in legal costs.

During the first three quarters of 2014, G&A expense increased $30.2 million, or 26% compared to the first three quarters of 2013. The increase in G&A in 2014 was primarily due to the following: a $13.7 million increase in labor and benefits costs due to the increased number of employees and the Company's annual compensation program; a $10.2 million increase in professional and outside services and compensation expenses mainly related to the ERP system implementation; and a $4.8 million increase in the mark-to-market value of the deferred compensation wrap plan and the cash incentive plan due to an increase in our stock price.

Net gain (loss) from asset sales. QEP recognized a loss on sale of assets of $210.3 million during the first three quarters of 2014 compared to a gain on sale of $113.4 million in the first three quarters of 2013. The loss on sale of assets recognized during the first three quarters of 2014 primarily related to QEP Energy's sale of its interest in non-core oil and gas properties in the Midcontinent area for a pre-tax loss on sale of $210.4 million. The gain on sale recognized during the first three quarters of 2013 related to QEP Energy's sale of its interest in non-core oil and gas properties located in both the Northern and Southern Regions for a pre-tax gain on sale of $114.9 million.

Realized and unrealized gains (losses) on derivative contracts. Gains and losses on derivative instruments are comprised of both realized and unrealized gains and losses on QEP’s commodity derivative contracts and interest rate swaps, which are marked-to-market each quarter. During the third quarter of 2014, gains on commodity derivative instruments were $154.4 million, of which 161.5 million were unrealized gains partially offset by $7.1 million of realized losses. During the third quarter of 2013, losses on commodity derivative instruments were $25.8 million, of which $52.7 million were unrealized losses partially offset by $26.9 million of realized gains. Additionally, during the third quarter of 2014, gains from interest rate swaps were $1.3 million, of which $2.6 million were unrealized gains partially offset by $1.3 million of realized losses, compared to losses of $2.0 million during the third quarter of 2013, of which $0.6 million were realized losses and $1.4 million were unrealized losses.

During the first three quarters of 2014, losses on commodity derivative instruments were $11.1 million, of which $76.0 million were realized losses partially offset by $64.9 million of unrealized gains. During the first three quarters of 2013, gains on commodity derivative instruments were $50.0 million, of which $109.0 million were realized gains partially offset by $59.0 million of unrealized losses. Additionally, during the first three quarters of 2014, losses from interest rate swaps were $2.1 million, of which $3.2 million were realized losses partially offset by $1.1 million of unrealized gains, compared to gains of $1.6 million during the first three quarters of 2013, of which $3.5 million of unrealized gains partially offset by $1.9 million of realized losses.

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Interest expense. Interest expense was relatively flat during the three and nine months ended September 30, 2014, compared to the three and nine months ended September 30, 2013.

Income taxes. Income tax provision was $79.9 million during the third quarter of 2014 compared to an income tax provision of $8.1 million during the third quarter of 2013. The income tax rate was 34.2% during the third quarter of 2014 compared to a rate of 40.1% during the third quarter of 2013. The decrease in the effective rate was largely driven by miscellaneous tax adjustments recorded in the third quarter 2013, which were magnified due to the smaller net income during the period.

Income tax provision was $26.1 million during the first three quarters of 2014 compared to an income tax provision of $82.5 million during the first three quarters of 2013. The income tax rate was 30.2% during the first three quarters of 2014 compared to a rate of 37.7% during the first three quarters of 2013. The decrease in the income tax rate is primarily a result of a reduction in the state income tax blended rate and a valuation allowance recorded in the second quarter of 2014 related to Oklahoma net operating loss carryforwards. The state income tax rate reduction and the valuation allowance were driven by changes in the Company's asset mix due to acquisitions and divestitures in the nine months ended September 30, 2014.

DISCONTINUED OPERATIONS

Discontinued operations represent results of operations from QEP Field Services, excluding QEP’s retention of the Haynesville Gathering System. During the third quarter of 2014 and 2013, net income from discontinued operations was $17.4 million and $25.2 million, respectively. The decrease in net income was primarily due to decreased gathering revenue and increased income attributable to non-controlling interest due to the QEP Midstream offering in August 2013. During the first three quarters of 2014 and 2013, net income from discontinued operations was $58.2 million and $74.8 million, respectively. The decrease in net income from discontinued operations is due to decreased gathering revenue, higher transportation and shrink expense, and increased income attributable to non-controlling interest due to the QEP Midstream initial public offering in August 2013.

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 swings. QEP maintains a commodity price derivative strategy to reduce commodity price volatility and to provide 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 differ from the Company’s estimates, 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:

	September 30, 2014			December 31, 2013
	(in millions, except %)
Cash and cash equivalents	$	—		$	11.9
Amount available under the QEP credit facility (1)	1,198.7			1,016.2
Total liquidity	$	1,198.7		$	1,028.1
Total debt	$	3,115.5		$	2,997.5
Total common shareholders' equity	$	3,505.6		$	3,376.6
Ratio of debt to total capital (2)	47		%	47		%

____________________________

⁽¹⁾  See discussion of revolving credit facility below. Availability under QEP's credit facility is reduced by outstanding letters of credit of $3.8 million as of September 30, 2014, and December 31, 2013.

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

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QEP's Credit Facility

QEP’s unsecured revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit facility also contains an accordion provision that would allow for the amount of the facility to be increased to $2.0 billion and a provision whereby the maturity can be extended for up to two additional one-year periods, with the agreement of the lenders. QEP’s weighted-average interest rate on borrowings from its credit facility was 2.22% during the nine months endedSeptember 30, 2014. At September 30, 2014, QEP was in compliance with the debt covenants under the credit agreement. QEP's borrowings under its credit facility were increased to $361.5 million as of

October 31, 2014.

Term Loan

QEP's $600.0 million unsecured term loan facility provides for borrowings at short-term interest rates and contains covenants, restrictions and interest rates that are substantially the same as QEP’s revolving credit facility. The term loan matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. In conjunction with the Permian Basin Acquisition, QEP borrowed the incremental $300.0 million available under the facility and increased total borrowings under the term loan to $600.0 million. There were no changes to the maturity date, pricing or covenants in the credit agreement. QEP incurred $1.1 million of debt issuance costs associated with the new term loan issuance.

During the nine months endedSeptember 30, 2014, QEP’s weighted-average interest rate on borrowings under the term loan was 2.26%. In conjunction with the term loan, QEP entered into interest rate swap contracts with a combined notional principal amount of $600.0 million which will mature in March 2017. Under the aggregated swap contracts, QEP pays 0.96% for the life of the swaps and receives one-month LIBOR. The interest rate at September 30, 2014, under the term loan is one-month LIBOR, plus 2.00% (the Applicable Margin) which, when combined with the fixed interest rate swaps, results in an effective rate of 3.21% for borrowings under the term loan. To the extent that the Applicable Margin under the term loan changes, the effective fixed rate paid for borrowings under the term loan will change.

Senior Notes

The Company’s senior notes outstanding as of September 30, 2014, 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

• $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 provided by operating activities during the first three quarters of 2014 increased $240.8 million compared to the first three quarters of 2013, due to higher non-cash adjustments to net income and an increase in changes in operating assets and liabilities partially offset by a net loss incurred during the nine months endedSeptember 30, 2014. Non-cash adjustments to net income increased in the first three quarters of 2014 compared to the first three quarters of 2013 due to the loss on asset sales in the third quarter of 2014. Changes in operating assets and liabilities provided $62.0 million of cash in the first three quarters of 2014, mainly due to an increase of accounts payable and accrued expenses offset by an increase in accounts receivable. Changes in operating assets and liabilities used $8.1 million of cash in the first three quarters of 2013 primarily due to a decrease in accounts payable and accrued expenses due to the $115.0 million Chieftain settlement payment in the first quarter of 2013 and an increase in accounts receivable. Net cash provided by operating activities is presented below:

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	Nine Months Ended September 30,
	2014		2013			Change
	(in millions)
Net income	$	136.1	$	217.2		$	(81.1	)
Noncash adjustments to net income	1,021.6		769.8			251.8
Changes in operating assets and liabilities	62.0		(8.1		)	70.1
Net cash provided by operating activities	$	1,219.7	$	978.9		$	240.8

Cash Flow from Investing Activities

In the first three quarters of 2014, net cash used in investing activities was $1,460.7 million, compared to $920.6 million in the first three quarters of 2013. This increase in investing activities was largely due to the Permian Basin Acquisition, which closed in the first quarter of 2014 for a total purchase price of $941.8 million. A comparison of capital expenditures for the first three quarters of 2014 and 2013 and a forecast for calendar year 2014 are presented in the table below:

	Nine Months Ended									Current Forecast Twelve Months Ended (1)		Prior Forecast Twelve Months Ended (2)
	September 30,
	2014			2013			Change			December 31, 2014		December 31, 2014
	(in millions)
QEP Energy	$	2,225.9		$	1,108.9		$	1,117.0		$	1,744.0	$	1,775.0
QEP Marketing	0.7			0.8			(0.1		)	0.5		0.5
QEP Corporate	9.4			17.4			(8.0		)	14.5		14.5
Continuing Operations	2,236.0			1,127.1			1,108.9			1,759.0		1,790.0
Discontinued Operations	50.6			55.5			(4.9		)	75.0		75.0
Total accrued capital expenditures	2,286.6			1,182.6			1,104.0			1,834.0		1,865.0
Change in accruals and purchase adjustments	(66.5		)	(53.7		)	(12.8		)	—		—
Total cash capital expenditures	$	2,220.1		$	1,128.9		$	1,091.2		$	1,834.0	$	1,865.0

____________________________

⁽¹⁾  Represents the mid-point of the most recent guidance and excludes approximately $941.8 million for the Permian Basin Acquisition.

⁽²⁾  Forecast as reported in the June 30, 2014 Form 10-Q, filed on August 6, 2014.

During the first three quarters of 2014, capital expenditures on a cash basis increased 97% to $2,220.1 million, compared to $1,128.9 million during the first three quarters of 2013. The increase of $1,091.2 million in cash capital expenditures during the first three quarters of 2014 was primarily the result of QEP Energy's increased capital expenditures related to the Permian Basin Acquisition.

In the first three quarters of 2014, QEP Energy's capital expenditures, on an accrual basis, increased $1,117.0 million over the first three quarters of 2013 to a total of $2,225.9 million. This increase was primarily due to the Permian Basin Acquisition, which closed in the first three quarters of 2014 for a total purchase price of $941.8 million. In addition, capital expenditures increased $78.8 million in the Williston Basin, $215.4 million in the Permian Basin, $17.9 million in Pinedale, and $14.0 in Haynesville/Cotton Valley due to additional drilling activity and operations in these areas. These increases were partially offset by decreases of $128.7 million in the Midcontinent following decreased drilling and operations due to divestitures of non-core properties and $31.7 million in the Uinta Basin due to a decreased rig count.

In the first three quarters of 2014, compared to the first three quarters of 2013, capital expenditures for QEP Field Services, (the operations of which are classified as discontinued operations throughout this Quarterly Report Form 10-Q), decreased $4.9 million to $50.6 million on an accrual basis. Capital expenditures during the first three quarters of 2014 primarily related to $13.8 million for expansion of the Uinta Basin Gathering system, $8.7 million for expansion of the Vermillion Processing Plant and $5.8 million of expansions related to other minor projects on various plants and gathering systems. The remaining expenditures related to maintenance capital expenditures.

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At September 30, 2014, forecasted capital investments for 2014, excluding acquisitions, are expected to be approximately $1,834.0 million, comprised of $1,744.0 million for QEP Energy, $75.0 million for discontinued operations, and $15.0 million for QEP Marketing and Other. For the remainder of 2014, QEP intends to fund capital expenditures with cash flow from operating activities, and, if needed, borrowings under its revolving credit facility. QEP plans minimal capital expenditures for the Haynesville Shale and other dry-gas development areas and plans to direct the majority of its capital expenditures for higher return projects, including oil-directed horizontal drilling in the Williston Basin and the Permian Basin, the latter of which was acquired in the first quarter of 2014. Approximately 96% of QEP's forecasted 2014 drilling and completion capital expenditure budget is directed to oil and liquids-rich gas plays. QEP plans to invest a total of approximately $75.0 million in capital expenditures during 2014 in its discontinued midstream business (including QEP Midstream), including an expansion of the Vermillion processing plant as well as additional gathering facilities in the Uinta Basin. QEP plans to invest approximately $15.0 million in capital expenditures related to corporate activities, primarily the implementation of a new ERP system and building improvements. The aggregate levels of capital expenditures for 2014, 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 investment can generate the best return. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP’s estimates.

In the first three quarters of 2014, QEP had proceeds from disposition of assets of $706.2 million primarily related to QEP Energy's sale of its interest in non-core oil and gas properties in the Midcontinent area and other non-core assets in the Williston Basin. In the first three quarters of 2013, QEP had proceeds from disposition of assets of $208.3 million due to QEP Energy's sale of its interest in non-core oil and gas properties located in both the Northern and Southern Regions.

Cash Flow from Financing Activities

In the first three quarters of 2014, net cash proceeds from financing activities were $229.1 million compared to $64.7 million in the first three quarters of 2013. Included in the 2014 amount is $230.0 million of borrowings on QEP Midstream's credit facility, which was offset by payments of the same amount on QEP's credit facility. During the first three quarters of 2014, QEP had net borrowings from the QEP credit facility of $47.5 million and issued an additional $300.0 million under its term loan. These increased borrowings were offset by decreased checks outstanding in excess of cash balances of $81.1 million, distributions to noncontrolling interest of $23.3 million and $10.8 million of regular quarterly dividend payments during the nine months endedSeptember 30, 2014. During the first three quarters of 2013, QEP received proceeds of $449.6 million from the QEP Midstream initial public offering, which was offset by net repayments on the credit facility of $325.0 million, a decrease in checks outstanding in excess of cash balances of $38.1 million, and regular quarterly dividend payments of $10.8 million.

At September 30, 2014, long-term debt consisted of $297.5 million outstanding under the credit facility, $600.0 million under the term loan and $2,221.8 million in senior notes (including $3.8 million of net original issue discount). The Company used the $300.0 million increase in the term loan during the first nine months of 2014 to fund part of the Permian Basin Acquisition. The $182.5 million decrease in borrowings under the credit facility was due to repayments with the proceeds of the Midcontinent divestitures, offset by borrowings used to fund the Permian Basin Acquisition.

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, QEP Field Services, 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 and term loan agreement have floating interest rates, 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 interest rate swaps to manage interest rate risk.

49

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 same arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price swaps. 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 September 30, 2014, QEP held commodity price derivative contracts totaling 68.7 million MMBtu of gas and 12.1 million barrels of oil. At December 31, 2013, the QEP derivative contracts covered 139.4 million MMBtu of gas and 6.9 million barrels of oil.

The following table presents open 2014 derivative positions as of October 31, 2014. See Note 8 - Derivative Contracts, under Part 1, Item 1 of this Quarterly Report on Form 10-Q for open derivative positions as of September 30, 2014.

QEP Energy Commodity Derivative Positions
Year	Type of Contract	Index	Total Volumes	Average Swap price per unit
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	NYMEX	7.4	$	4.22
2014	SWAP	IFNPCR	20.2	$	4.08
2015	SWAP	NYMEX	25.6	$	4.14
2015	SWAP	IFNPCR	11.0	$	4.06
Oil Sales			(Bbls)
2014	SWAP	NYMEX WTI	3.1	$	93.54
2015	SWAP	NYMEX WTI	7.7	$	90.04
2015	SWAP	BRENT ICE	0.4	$	104.95
2016	SWAP	NYMEX WTI	0.4	$	90.00

QEP Energy Oil Basis Swaps
Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)
Oil basis swaps			(Bbls)
2014	NYMEX WTI	ICE Brent	0.2	$	13.78
2014	NYMEX WTI	LLS	0.2	$	4.03
2015	NYMEX WTI	LLS	0.1	$	4.03

50

QEP Marketing Commodity Derivative Positions
Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	IFNPCR	1.4	$	4.03
2015	SWAP	IFNPCR	2.5	$	4.07
2016	SWAP	IFNPCR	0.3	$	3.87
Gas purchases			(MMBtu)
2014	SWAP	IFNPCR	0.6	$	3.86
2015	SWAP	IFNPCR	0.3	$	3.27

Changes in the fair value of derivative contracts from December 31, 2013 to September 30, 2014, are presented below:

	Commodity derivative contracts
	(in millions)
Net fair value of oil and gas derivative contracts outstanding at December 31, 2013	$	(23.5	)
Contracts settled	76.0
Change in oil and gas prices on futures markets	(39.7		)
Contracts added	28.6
Net fair value of oil and gas derivative contracts outstanding at September 30, 2014	$	41.4

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

	September 30, 2014
	(in millions)
Net fair value - asset (liability)	$	41.4
Fair value if market prices of oil and gas and basis differentials decline by 10%	170.2
Fair value if market prices of oil and gas and basis differentials increase by 10%	(87.4		)

Utilizing the actual derivative volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $128.8 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $128.8 million as of September 30, 2014. 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 Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2013. The Company’s credit facility has a floating interest rate, which exposes QEP to interest rate risk. At September 30, 2014, the Company had $297.5 million outstanding under its revolving credit facility. If interest rates were to increase or decrease 10% over the nine months ended September 30, 2014, at our average level of borrowing for those same periods, our interest expense would increase or decrease by $1.2 million for the nine months endedSeptember 30, 2014.

The Company’s term loan has a floating interest rate, which also exposes QEP to interest rate risk. QEP uses interest rate swaps to mitigate a portion of its exposure to interest rate volatility risk associated with its $600.0 million term loan. For the $300.0

51

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 $300.0 million term loan issued during 2014, QEP locked in a fixed interest rate of 0.86%. The interest rate swaps settle monthly and will mature in March 2017. At September 30, 2014, the fair value of the interest rate swaps was a derivative liability balance of $0.8 million. A 50 basis point decrease would cause the fair value of the interest rate swaps to decrease by $7.2 million while a 50 basis point increase would cause the fair value of the interest rate swaps to increase by $7.1 million.

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 10 – Debt under Part I, Item 1 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. They 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:

• timing and benefits of the sale of QEP Field Services' midstream business;

• fair value and critical accounting estimates;

• plans to operate in ethane recovery mode;

• timing of the closing of sales of non-core assets;

• QEP’s growth strategies;

• future gas, oil and NGL prices, their impact on operations and factors affecting the volatility of such prices;

• plans to drill or participate in wells;

• results from planned drilling operations and production operations;

• pro forma results for acquired properties;

• ability to pursue acquisition opportunities;

• expected restructuring costs;

• having one of the lowest cash operating cost structures;

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

• plans to divest of non-core assets and use of proceeds from such divestitures;

• impact of refinery and pipeline and other infrastructure constraints on oil prices;

• assumptions regarding equity-based compensation;

• recognition of compensation costs related to equity compensation grants;

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

• estimated accrual for loss contingencies and other items;

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

• impact of global geopolitical and macroeconomic events;

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

• the outcome of contingencies such as legal proceedings;

• expected contributions to the Company’s pension plans and returns from plan assets;

• the importance of Adjusted EBITDA as a measure of performance;

• potential for future asset impairments;

• factors impacting the timing and amount of share repurchases;

• enhancements from the new ERP system and controls maintained during implementation; and

• compliance with new internal controls framework.

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:

52

• the risk factors discussed in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2013;

• 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 capacity;

• QEP's ability to successfully integrate acquired assets or divest of non-core assets;

• the outcome of contingencies such as legal proceedings;

• QEP's success in closing the sale of QEP Field Services' midstream business

• permitting delays;

• operating risks such as unexpected drilling conditions;

• weather conditions;

• changes in maintenance and construction costs, including possible inflationary pressures;

• 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;

• substantial liabilities from legal proceedings and environmental claims;

• failure of internal controls and procedures;

• failure of QEP's 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;

• fluctuations in processing margins;

• unexpected changes in costs for constructing, modifying or operating midstream facilities;

• lack of, or disruptions in, adequate and reliable transportation for QEP's products; and

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

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

53

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 Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, the Exchange Act) as of September 30, 2014. Based on such evaluation, such officers have concluded that, as of September 30, 2014, 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.

The Company maintains a system of internal controls over financial reporting that is designed to provide reasonable assurance that its books and records accurately reflect transactions and that established policies and procedures are followed. During the quarter ended June 30, 2014, the Company completed the implementation of a new ERP system. The ERP system was implemented by QEP to improve standardization and automation, and not in response to a deficiency in internal control over financial reporting. The Company believes the implementation of the ERP system and related changes to internal controls will enhance its internal controls over financial reporting while providing the ability to scale its business in the future. The Company believes it has taken the necessary steps to monitor and maintain appropriate internal control over financial reporting during this period of change and will continue to evaluate the operating effectiveness of related key controls during subsequent periods.

On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) issued an updated version of its Internal Control - Integrated Framework (the 2013 Framework). Originally issued in 1992 (the 1992 Framework), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. QEP believes it will meet the required implementation date for the 2013 Framework of December 15, 2014.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information regarding legal proceedings is set forth in Note 11 - Contingencies to the Company's condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report on Form 10-Q and is incorporated herein by reference.

ITEM 1A. RISK FACTORS

Risk factors relating to the Company are set forth in its Annual Report on Form 10-K for the year ended December 31, 2013. Below are material changes to such risk factors that have occurred during the nine months ended September 30, 2014.

Requirements to reduce gas flaring could have an adverse effect on our operations.

Wells in the Bakken and Three Forks formations in North Dakota, where we have significant operations, produce natural gas as well as crude oil. Constraints in the current gas gathering network in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. The North Dakota Industrial Commission, the State's chief energy regulator, recently issued an order to reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations. In addition, the Commission is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties

54

will be imposed on certain wells that cannot meet the capture goals. These capture requirements, and any similar future obligations in North Dakota or our other locations, may increase our operational costs or restrict our production, which could materially and adversely affect our financial condition, results of operations and cash flows.

Crude oil from the Bakken and Three Forks formations may pose unique hazards that may have an adverse effect on our operations.

The U.S. Department of Transportation has started rulemaking to develop new requirements for shipping crude oil by rail. Any new regulations that significantly affect transportation of crude oil production could materially and adversely affect our financial condition, results of operations and cash flows.

QEP is subject to complex federal and other laws and regulations that could adversely affect its cost of doing business and recording of proved reserves.

Current federal regulations restrict activities during certain times of the year on significant portions of QEP Energy leasehold due to wildlife activity and/or habitat. QEP Energy has worked with federal and state officials in Wyoming to obtain authorization for limited winter-drilling activities on the Pinedale Anticline and has developed measures, such as drilling multiple wells from a single pad location, to minimize the impact of its activities on wildlife and wildlife habitat in its operations on federal lands. Various wildlife species inhabit certain of QEP Energy's leaseholds. The presence of wildlife or plants, including species that are protected under the federal Endangered Species Act, could limit access to leases held by QEP Energy on public and other lands. Many of QEP's operations are subject to the requirements of the National Environmental Policy Act (NEPA), and are therefore evaluated under NEPA for their direct, indirect and cumulative environmental impacts. This is done in Environmental Assessments or Environmental Impact Statements prepared for a lead agency under Council on Environmental Quality and other agency regulations, usually for the BLM in the areas where QEP operates currently. In September 2008, the BLM issued a Record of Decision (ROD) on the Final Supplemental Environmental Impact Statement (FSEIS) for long-term development of gas resources in the Pinedale Anticline Project Area (PAPA). Under the ROD, QEP Energy is allowed to drill and complete wells year-round in one of five Concentrated Development Areas.

55

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	Maximum number of shares that may yet be purchased under the plans or programs
July 1, 2014 - July 31, 2014	1,740	$	33.90	—	—
August 1, 2014 - August 31, 2014	—	—		—	—
September 1, 2014 - September 30, 2014	36,780	34.02		—	—

____________________________

⁽¹⁾  All of the 38,520 shares purchased during the three-month period ended September 30, 2014 were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common stock. Stock options that are net settled do not involve the acquisition of any shares.

In January 2014, QEP's Board of Directors authorized the repurchase of up to $500.0 million of the Company's outstanding shares of common stock. This authorization was effective until January 2015, however QEP's Board of Directors has extended the program 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 nine months endedSeptember 30, 2014, no shares were repurchased.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

56

ITEM 6. EXHIBITS

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

Exhibit No.	Exhibits
10.1	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.)
10.2	Membership Interest Purchase Agreement, dated as of October 19, 2014, by and between QEP Field Services Company, as seller, and Tesoro Logistics LP, as purchaser (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 October 20, 2014.)
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

57

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)
November 5, 2014	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer
November 5, 2014	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

58

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Charles B. Stanley, certify that:

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

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

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

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

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

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

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

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

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

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

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

November 5, 2014

/s/ Charles B. Stanley

Charles B. Stanley

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Richard J. Doleshek, certify that:

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

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

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

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

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

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

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

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

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

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

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

November 5, 2014

/s/ Richard J. Doleshek

Richard J. Doleshek

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this report of QEP Resources, Inc. (the Company) on Form 10-Q for the period ended September 30, 2014, 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.
November 5, 2014
	/s/ Charles B. Stanley
	Charles B. Stanley
	Chairman, President and Chief Executive Officer
November 5, 2014
	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President and Chief Financial Officer

XML

Discontinued Operations (Narrative) (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Value of midstream business sold	$ 2,500,000,000		$ 2,500,000,000
Debt refinancing included in sale of midstream business	230,000,000		230,000,000
Continuing cash flows related to midstream business held for sale	19,000,000	25,900,000	64,100,000	67,200,000
Depreciation, depletion and amortization	251,400,000	238,400,000	712,500,000	719,300,000
Midstream Business Held For Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Depreciation, depletion and amortization	14,300,000	14,700,000	43,100,000	37,800,000
Property, plant and equipment, including dry exploratory well expense			$ 45,600,000	$ 57,400,000

XML

Debt Schedule of Debt Instruments (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 3,119.3	$ 3,001.8
Less unamortized discount	(3.8)	(4.3)
Long-term Debt	3,115.5	2,997.5
Line of Credit [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	297.5	480.0
Term Loan due 2017 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	600.0	300.0
Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	176.8	176.8
Senior Notes Due 2018 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	134.0	134.0
Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	136.0	136.0
Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	625.0	625.0
Senior Notes Due 2022 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	500.0	500.0
5.25% Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 650.0	$ 650.0

XML

Derivative Contracts Schedule of Interest Rate Contracts (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Maturity Date	Mar. 31, 2017
Derivative, Fixed Interest Rate	0.96%
First Term Loan Tranche [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Notional amount	$ 300.0
Derivative, Fixed Interest Rate	1.07%
Derivative, Description of Terms	One-month LIBOR
Second Term Loan Tranche [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Notional amount	300.0
Derivative, Fixed Interest Rate	0.86%
Derivative, Description of Terms	One-month LIBOR
Term Loan due 2017 [Member]
Derivative [Line Items]
Notional amount	$ 600.0

XML

Contingencies (Narrative) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2014
Loss Contingencies [Line Items]
Deferred Revenue		$ 13.2
Administrative penalty	0.2
Loss Contingency, Range of Possible Loss, Maximum		$ 20.0

XML

Derivative Contracts (Narrative) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013		Dec. 31, 2013
Derivative [Line Items]
Maximum Forecasted Production Covered By Derivatives					100.00%
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	$ 0	[1]	$ 19.7	[1]	$ 0	[1]	$ 60.4	[1]
Long-term Debt, Gross	3,119.3				3,119.3				3,001.8
Term Loan due 2017 [Member]
Derivative [Line Items]
Long-term Debt, Gross	600.0				600.0				300.0
Effective interest Rate Before Impact of Derivatives	3.21%				3.21%
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Fixed Interest Rate	0.96%				0.96%
Derivative, Maturity Date					Mar. 31, 2017
First Term Loan Tranche [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative Liability, Notional Amount	300.0				300.0
Derivative, Fixed Interest Rate	1.07%				1.07%
Second Term Loan Tranche [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative Liability, Notional Amount	$ 300.0				$ 300.0
Derivative, Fixed Interest Rate	0.86%				0.86%

[1] Presented net of income tax benefit of $11.7 million and $35.8 million during the three and nine months ended September 30, 2013

XML

Employee Benefits (Tables)

9 Months Ended

Sep. 30, 2014

Compensation and Retirement Disclosure [Abstract]

Pension and Other Postretirement Benefit Costs

	Pension
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(in millions)
Service cost	$	0.6		$	0.7		$	2.0		$	2.6
Interest cost	1.2			1.2			4.0			3.7
Expected return on plan assets	(1.4		)	(0.9		)	(3.8		)	(2.9		)
Amortization of prior service costs (1)	1.1			1.2			3.6			3.7
Amortization of actuarial losses (1)	0.2			0.5			0.6			1.7
Curtailment cost	—			—			2.0			—
Special termination benefits	—			—			0.3			—
Periodic expense	$	1.7		$	2.7		$	8.7		$	8.8

____________________________

⁽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				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
	(in millions)
Service cost	$	—	$	0.1	$	—	$	0.1
Interest cost	—		—		0.2		0.2
Amortization of prior service costs (1)	0.1		0.1		0.3		0.3
Recognized net actuarial loss	—		0.1		—		0.1
Curtailment cost	—				0.4		—
Periodic expense	$	0.1	$	0.3	$	0.9	$	0.7

____________________________

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

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Equity-Based Compensation Schedule of Major Assumptions Used in Valuation Model (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 3.2
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 2.7
Fair value of options at grant date	$ 10.11
Risk-free interest rate (in hundredths)	1.31%
Expected price volatility (in hundredths)	37.10%
Expected dividend yield (in hundredths)	0.25%
Expected life in years	4 years 6 months

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Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2014

Discontinued Operations and Disposal Groups [Abstract]

Income Statement Impact Of Discontinued Operations [Table Text Block]

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(in millions, except per share amounts)
REVENUES
NGL sales	$	28.8		$	23.6		$	94.6		$	70.6
Other revenue	43.1			44.2			119.9			126.4
Purchased gas, oil and NGL sales(1)	(11.9		)	(14.4		)	(38.5		)	(41.5		)
Total Revenues	60.0			53.4			176.0			155.5
OPERATING EXPENSES
Purchased gas, oil and NGL expense(1)	(12.4		)	(14.4		)	(39.5		)	(41.4		)
Lease operating expense(1)	(1.7		)	(0.8		)	(4.8		)	(2.6		)
Natural gas, oil and NGL transport & other handling costs(1)	(10.6		)	(21.7		)	(40.1		)	(53.0		)
Gathering, processing, and other	22.7			20.3			69.8			60.1
General and administrative	11.1			8.6			34.3			19.4
Production and property taxes	2.1			1.8			6.1			4.0
Depreciation, depletion and amortization	14.3			14.7			43.1			37.8
Total Operating Expenses	25.5			8.5			68.9			24.3
Net loss from asset sales	—			(0.1		)	(0.1		)	(0.5		)
OPERATING INCOME	34.5			44.8			107.0			130.7
Interest income and other loss	—			(2.1		)	—			(13.7		)
Income from unconsolidated affiliates	1.1			0.8			4.4			3.7
Interest expense	(1.5		)	(0.3		)	(2.8		)	2.3
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES (2)	34.1			43.2			108.6			123.0
Income taxes	(9.9		)	(14.2		)	(32.8		)	(42.4		)
NET INCOME FROM DISCONTINUED OPERATIONS	24.2			29.0			75.8			80.6
Net income attributable to noncontrolling interest	(6.8		)	(3.8		)	(17.6		)	(5.8		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	17.4		$	25.2		$	58.2		$	74.8

Assets And Liabilities Of Discontinued Operations [Table Text Block]

	September 30, 2014			December 31, 2013
Cash and cash equivalents	$	27.1		$	18.1
Accounts receivable, net	71.8			53.9
Income taxes receivable	—			38.4
Deferred income taxes - current	7.0			2.7
Prepaid expenses and other	32.4			8.9
Current assets of discontinued operations held for sale	$	138.3		$	122.0
Property, Plant and Equipment
Midstream field services	$	1,550.5		$	1,500.8
Material and supplies	6.5			4.8
Total Property, Plant and Equipment	1,557.0			1,505.6
Less Accumulated Depreciation, Depletion and Amortization
Midstream field services	(422.2		)	(381.6		)
Net Property, Plant and Equipment	1,134.8			1,124.0
Investment in unconsolidated affiliates	35.9			39.0
Other noncurrent assets	3.5			4.7
Noncurrent assets of discontinued operations held for sale	$	1,174.2		$	1,167.7
Accounts payable and accrued expenses	$	85.6		$	74.1
Accrued income taxes	70.2			—
Production and property taxes	5.4			1.2
Interest payable	0.4			—
Current liabilities of discontinued operations held for sale	$	161.6		$	75.3
Long-term debt	$	230.0		$	—
Deferred income taxes	126.5			195.7
Asset retirement obligations	29.9			28.5
Other long-term liabilities	15.6			14.1
Noncurrent liabilities of discontinued operations held for sale	$	402.0		$	238.3

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Gain (Loss) in Statement of Financial Performance (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) derivative contracts not designated as hedging instruments	$ (8.4)	$ 26.3	$ (79.1)	$ 107.1
Unrealized gain (loss) derivative contracts not designated as hedging instruments	164.1	(54.1)	65.9	(55.5)
Total gain (loss) on commodity derivative instruments	155.7	(27.8)	(13.2)	51.6
Realized and unrealized gains on commodity derivative instruments [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(7.1)	26.9	(75.9)	109.0
Unrealized gain (loss) on commodity derivative contracts	161.5	(52.7)	64.8	(59.0)
Total gain (loss) on commodity derivative instruments	154.4	(25.8)	(11.1)	50.0
Natural gas derivative contracts [Member] | QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	5.5	42.5	(23.3)	112.0
Unrealized gain (loss) on commodity derivative contracts	27.6	(6.6)	9.5	(9.6)
Natural gas derivative contracts [Member] | QEP Marketing [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(0.4)	(0.3)	(2.4)	0.7
Unrealized gain (loss) on commodity derivative contracts	0.7	0.1	1.0	(0.3)
Oil derivative contracts [Member] | QEP Energy [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(12.2)	(15.3)	(50.2)	(3.7)
Unrealized gain (loss) on commodity derivative contracts	133.2	(46.2)	54.3	(49.1)
Interest Rate Swap [Member]
Derivative Instruments Not Designated as Hedging Instruments [Abstract]
Realized gain (loss) on commodity derivative contracts	(1.3)	(0.6)	(3.2)	(1.9)
Unrealized gain (loss) on commodity derivative contracts	2.6	(1.4)	1.1	3.5
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	$ 1.3	$ (2.0)	$ (2.1)	$ 1.6

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Earnings Per Share (Details) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Earnings Per Share [Abstract]
Weighted-average basic common shares outstanding (in shares)	180.1	179.3	180.0	179.2
Potential number of shares issuable upon excerise of in-the-money stock options under the Long-term Stock Incentive Plan	0.5	0.2	0.4	0.2
Average diluted common shares outstanding (in shares)	180.6	179.5	180.4	179.4

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Acquisitions & Divestitures (Schedule Of Purchase Accounting Entries) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014
Significant Acquisitions and Disposals [Line Items]
Payments to Acquire Businesses Net		$ 941.8
Liabilities incurred		(15.5)	[1]
Fair value of assets acquired (liabilities assumed)	941.8	941.8
Proved Property [Member]
Significant Acquisitions and Disposals [Line Items]
Fair value of assets acquired (liabilities assumed)	472.1	472.1
Unproved Property [Member]
Significant Acquisitions and Disposals [Line Items]
Fair value of assets acquired (liabilities assumed)	480.6	480.6
Other Liabilities [Member]
Significant Acquisitions and Disposals [Line Items]
Fair value of assets acquired (liabilities assumed)	(1.2)	(1.2)
Permian Basin [Member]
Significant Acquisitions and Disposals [Line Items]
Payments to Acquire Businesses, Gross	941.8
Liabilities incurred		$ (9.7)

[1] Additions include $9.7 million related to the Permian Basin Acquisition (see Note 3 - Acquisitions and Divestitures).

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Restructuring Costs - Summary of Restructuring Costs (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred from inception to reporting date			$ 7.9
Restructuring Charges	0	0.3	0	0.8
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred from inception to reporting date			3.6
Restructuring Charges	0	0.2	0	0.5
Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred from inception to reporting date			3.7
Restructuring Charges	0	0.1	0	0.3
Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred from inception to reporting date			0.6
Restructuring Charges	0	0	0	0
QEP Energy [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred from inception to reporting date			7.6
Restructuring Charges	0	0.2	0	0.7
QEP Energy [Member] | One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred from inception to reporting date			3.3
Restructuring Charges	0	0.1	0	0.4
QEP Energy [Member] | Employee Relocation [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred from inception to reporting date			3.7
Restructuring Charges	0	0.1	0	0.3
QEP Energy [Member] | Termination of Lease [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred from inception to reporting date			0.6
Restructuring Charges	0	0	0	0
QEP Marketing [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred from inception to reporting date			0.3
Restructuring Charges	0	0.1	0	0.1
QEP Marketing [Member] | One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring costs incurred from inception to reporting date			0.3
Restructuring Charges	$ 0	$ 0.1	$ 0	$ 0.1

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Schedule of Commodity Derivative Contracts (Details) (USD $) In Millions, unless otherwise specified			9 Months Ended																9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 QEP Marketing [Member] 2014 [Member] Swap [Member] IFNPCR [Member] Purchased Gas and Oil Expense [Member] Btu	Sep. 30, 2014 QEP Energy [Member] 2014 [Member] Swap [Member] NYMEX WTI less ICE Brent Differential [Member] Oil Sales [Member] bbl	Sep. 30, 2014 QEP Energy [Member] 2014 [Member] Swap [Member] NYMEX WTI less LLS Differential [Member] Oil Sales [Member] bbl	Sep. 30, 2014 QEP Energy [Member] 2015 [Member] Swap [Member] NYMEX WTI less LLS Differential [Member] Oil Sales [Member] bbl	Sep. 30, 2014 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 2 [Member]	Dec. 31, 2013 Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 2 [Member]	Sep. 30, 2014 Long-term [Member] Interest Rate Swap [Member]	Dec. 31, 2013 Long-term [Member] Interest Rate Swap [Member]	Dec. 31, 2013 Long-term [Member] Commodity Contract [Member]	Sep. 30, 2014 Long-term [Member] Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 2 [Member] Commodity Contract [Member]	Dec. 31, 2013 Short-term [Member] Interest Rate Swap [Member]	Dec. 31, 2013 Short-term [Member] Commodity Contract [Member]	Sep. 30, 2014 Short-term [Member] Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 2 [Member] Interest Rate Swap [Member]	Dec. 31, 2013 Short-term [Member] Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 2 [Member] Interest Rate Swap [Member]	Sep. 30, 2014 Short-term [Member] Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 2 [Member] Commodity Contract [Member]	Dec. 31, 2013 Short-term [Member] Fair Value, Measurements, Recurring [Member] Fair Value, Inputs, Level 2 [Member] Commodity Contract [Member]	Sep. 30, 2014 Oil Sales [Member] QEP Energy [Member] 2014 [Member] Swap [Member] NYMEX WTI [Member] bbl	Sep. 30, 2014 Oil Sales [Member] QEP Energy [Member] 2015 [Member] Swap [Member] NYMEX WTI [Member] bbl	Sep. 30, 2014 Oil Sales [Member] QEP Energy [Member] 2015 [Member] Swap [Member] BRENT ICE [Member] bbl	Sep. 30, 2014 Oil Sales [Member] QEP Energy [Member] Year2016 [Member] Swap [Member] NYMEX WTI [Member] bbl	Sep. 30, 2014 Natural Gas Sales [Member] QEP Marketing [Member] 2014 [Member] Swap [Member] IFNPCR [Member] Btu	Sep. 30, 2014 Natural Gas Sales [Member] QEP Marketing [Member] 2015 [Member] Swap [Member] IFNPCR [Member] Btu	Sep. 30, 2014 Natural Gas Sales [Member] QEP Energy [Member] 2014 [Member] Swap [Member] NYMEX [Member] MMBTU	Sep. 30, 2014 Natural Gas Sales [Member] QEP Energy [Member] 2014 [Member] Swap [Member] IFNPCR [Member] MMBTU	Sep. 30, 2014 Natural Gas Sales [Member] QEP Energy [Member] 2015 [Member] Swap [Member] NYMEX [Member] MMBTU	Sep. 30, 2014 Natural Gas Sales [Member] QEP Energy [Member] 2015 [Member] Swap [Member] IFNPCR [Member] MMBTU
Derivatives, Fair Value [Line Items]
Year			2014	2014	2014	2015													2014	2015	2015	2016	2014	2015	2014	2014	2015	2015
Index			IFNPCR	ICE Brent	LLS	LLS													NYMEX WTI	NYMEX WTI	BRENT ICE	NYMEX WTI	IFNPCR	IFNPCR	NYMEX	IFNPCR	NYMEX	IFNPCR
Derivative Liability, Fair Value, Gross Liability	$ 9.1	$ 32.0					$ 9.1	$ 32.0	$ 0	$ 0	$ 0	$ 0.6	$ 2.6	$ 29.4	$ 4.3	$ 2.6	$ 4.2	$ 29.4
Total Volume (in Bcf, Mbbl, millions of gallons, millions of MMBtu)			600,000	200,000	200,000	100,000													3,100,000	7,700,000	400,000	400,000	1,400,000	2,500,000	7,400,000	20,200,000	25,600,000	11,000,000
Average Swap price per unit ($ per unit)			3.86	13.78	4.03	4.03													93.54	90.04	104.95	90.00	4.03	4.07	4.22	4.08	4.14	4.06

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Basis of Presentation of Interim Consolidated Financial Statements

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation of Interim Consolidated Financial Statements

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 for the year ended December 31, 2013.

The preparation of the condensed consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three and nine months ended September 30, 2014, are not necessarily indicative of the results that may be expected for the year ending December 31, 2014.

Reclassifications

The 2013 financial information has been recast so that the basis of presentation is consistent with that of the 2014 financial information. This recast reflects the financial condition and results of operations, excluding the Haynesville Gathering System, of QEP Field Services as discontinued operations, for all periods presented. For a summary of discontinued operations see Note 4 - Discontinued Operations.

During the first nine months of 2013, QEP presented certain credit facility payments and borrowings on a net basis on the Condensed Consolidated Statements of Cash Flow. These borrowings and payments were reclassified to be presented on a gross basis on the Condensed Consolidated Statements of Cash Flow in order to conform with the current period presentation. This reclassification is entirely within "Financing Activities" and has no effect on other categories or total cash on the Condensed Consolidated Statements of Cash Flows or net income or earnings per share on the Condensed Consolidated Statements of Operations.

New accounting pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which broadened the reporting of discontinued operations to a component of an entity that has operations and cash flows that can be clearly distinguished from the rest of the entity. Under this guidance, to be a discontinued operation, a component or group of components must represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2014 and early adoption is permitted. The Company has chosen to early adopt ASU 2014-08 and implemented the amendments in the quarter ended September 30, 2014.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments are effective prospectively for reporting periods beginning after December 15, 2016 and early adoption is not permitted. The Company is currently assessing the impact on the Company's consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Topic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This guidance provides additional information to guide management's evaluation of whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. The update is effective for annual periods beginning on or after December 15, 2016. The Company is currently evaluating the impact of this standard on its financial statements.

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014		Sep. 30, 2014		Dec. 31, 2013
Liabilities Settled Through Divestiture	$ 20.2
Asset retirement obligations	162.3		162.3		163.3
Asset Retirement Obligation, Current	0.9		0.9		1.8
ARO Liability [Roll Forward]
ARO liability, Beginning Balance			165.1	[1]
Accretion			4.9
Liabilities incurred			15.5	[2]
Revisions			(0.3)
Liabilities settled			(22.0)	[3]
ARO liability, Ending Balance	163.2	[4]	163.2	[4]
Midstream Business Held For Sale [Member]
Asset retirement obligations	29.9		29.9		28.5
Permian Basin [Member]
ARO Liability [Roll Forward]
Liabilities incurred			$ 9.7

[1] Excludes $28.5 million of ARO classified as liabilities held for sale on the Condensed Consolidated Balance Sheet.

[2] Additions include $9.7 million related to the Permian Basin Acquisition (see Note 3 - Acquisitions and Divestitures).

[3] Settlements include $20.2 million related to the property sales in the second quarter of 2014 (see Note 3 - Acquisitions and Divestitures).

[4] Excludes $29.9 million of ARO classified as liabilities held for sale on the Condensed Consolidated Balance Sheet.

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Derivative Contracts (Tables)

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Volumes and Average Prices

Year	Type of Contract	Index	Total Volumes	Average Swap price per unit
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	NYMEX	7.4	$	4.22
2014	SWAP	IFNPCR	20.2	$	4.08
2015	SWAP	NYMEX	25.6	$	4.14
2015	SWAP	IFNPCR	11.0	$	4.06
Oil sales			(Bbls)
2014	SWAP	NYMEX WTI	3.1	$	93.54
2015	SWAP	NYMEX WTI	7.7	$	90.04
2015	SWAP	BRENT ICE	0.4	$	104.95
2016	SWAP	NYMEX WTI	0.4	$	90.00

The following table sets forth QEP Energy's oil basis swaps as of September 30, 2014:

Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)
Oil basis swaps			(Bbls)
2014	NYMEX WTI	ICE Brent	0.2	$	13.78
2014	NYMEX WTI	LLS	0.2	$	4.03
2015	NYMEX WTI	LLS	0.1	$	4.03

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 September 30, 2014:

Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	IFNPCR	1.4	$	4.03
2015	SWAP	IFNPCR	2.5	4.07
Gas purchases			(MMBtu)
2014	SWAP	IFNPCR	0.6	$	3.86

Schedule of Interest Rate Derivatives

Notional amount	Type of Contract	Maturity	Fixed Rate Paid	Variable Rate Received
(in millions)
$300.0	Swap	March 2017	1.07%	One-month LIBOR
$300.0	Swap	March 2017	0.86%	One-month LIBOR
$600.0			0.96%

Fair Values of Derivatives by Balance Sheet Location

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	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	36.6	$	5.5	$	4.2	$	29.4
Interest rate swaps	Fair value of derivative contracts	—		—		4.3		2.6
Long-term:
Commodity	Fair value of derivative contracts	9.6		0.4		0.6		—
Interest rate swaps	Fair value of derivative contracts	3.5		0.6		—		—
Total derivative instruments		$	49.7	$	6.5	$	9.1	$	32.0

Effects of Derivative Transactions

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

	Three Months Ended						Nine Months Ended
Derivative instruments not designated as cash flow hedges	September 30,						September 30,
	2014			2013			2014			2013
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	5.5		$	42.5		$	(23.3	)	$	112.0
Oil derivative contracts	(12.2		)	(15.3		)	(50.2		)	(3.7		)
QEP Marketing
Gas derivative contracts	(0.4		)	(0.3		)	(2.4		)	0.7
Total realized gains (losses) on commodity derivative contracts	(7.1		)	26.9			(75.9		)	109.0
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	27.6			(6.6		)	9.5			(9.6		)
Oil derivative contracts	133.2			(46.2		)	54.3			(49.1		)
QEP Marketing
Gas derivative contracts	0.7			0.1			1.0			(0.3		)
Total unrealized gains (losses) on commodity derivative contracts	161.5			(52.7		)	64.8			(59.0		)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	154.4		$	(25.8	)	$	(11.1	)	$	50.0
Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	(1.3	)	$	(0.6	)	$	(3.2	)	$	(1.9	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	2.6			(1.4		)	1.1			3.5
Total realized and unrealized gains (losses) on interest rate swaps	$	1.3		$	(2.0	)	$	(2.1	)	$	1.6
Total net realized gains (losses) on derivative contracts	$	(8.4	)	$	26.3		$	(79.1	)	$	107.1
Total net unrealized gains (losses) on derivative contracts	164.1			(54.1		)	65.9			(55.5		)
Grand Total	$	155.7		$	(27.8	)	$	(13.2	)	$	51.6

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair value of financial assets and liabilities

The fair value measurements of financial assets and liabilities at September 30, 2014, are shown in the table below:

	Fair Value Measurements
	September 30, 2014
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	36.6	$	—	$	(4.0	)	$	32.6
Commodity derivative instruments - long-term	—		9.6		—		(0.4		)	9.2
Interest rate swaps - long-term	—		3.5		—		—			3.5
Total financial assets	$	—	$	49.7	$	—	$	(4.4	)	$	45.3
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	4.2	$	—	$	(4.0	)	$	0.2
Interest rate swaps - short-term	—		4.3		—		—			4.3
Commodity derivative instruments - long-term	—		0.6		—		(0.4		)	0.2
Total financial liabilities	$	—	$	9.1	$	—	$	(4.4	)	$	4.7

____________________________

⁽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 fair value of financial assets and liabilities at December 31, 2013, is shown in the table below:

	Fair Value Measurements
	December 31, 2013
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	5.5	$	—	$	(5.3	)	$	0.2
Commodity derivative instruments - long-term	—		0.4		—		—			0.4
Interest rate swaps - long-term	—		0.6		—		—			0.6
Total financial assets	$	—	$	6.5	$	—	$	(5.3	)	$	1.2
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	29.4	$	—	$	(5.3	)	$	24.1
Interest rate swaps - short-term	—		2.6		—		—			2.6
Total financial liabilities	$	—	$	32.0	$	—	$	(5.3	)	$	26.7

Fair value and related carrying amount of certain financial instruments

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes accompanying the condensed consolidated financial statements in this Quarterly Report on Form 10-Q:

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	September 30, 2014				December 31, 2013
	(in millions)
Financial assets
Cash and cash equivalents	$	—	$	—	$	11.9	$	11.9
Financial liabilities
Checks outstanding in excess of cash balances	$	36.8	$	36.8	$	109.1	$	109.1
Long-term debt	$	3,115.5	$	3,209.3	$	2,997.5	$	3,034.9

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Equity-Based Compensation (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2013
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	10,900,000		10,900,000
Weighted-Average Price [Abstract]
Equity-based compensation			$ 20.7		$ 20.0
Continuing Operations [Member]
Weighted-Average Price [Abstract]
Equity-based compensation	6.4	5.5	17.7		17.9
Discontinued Operations [Member]
Weighted-Average Price [Abstract]
Equity-based compensation	0.9	1.3	3.0		2.1
Stock Options [Member]
Options Outstanding [RollForward]
Outstanding Beginning Balance (in shares)			1,794,187
Granted (in shares)			282,236
Exercised (in shares)			(65,366)
Forfeited (in shares)			(14,842)
Outstanding Ending Balance (in shares)	1,996,215		1,996,215
Options Excercisable (in shares)	1,452,138		1,452,138
Unvested Options (in shares)	544,077		544,077
Weighted-Average Price [Abstract]
Weighted-Average Price, beginning (in dollars per share)			$ 27.90
Weighted-Average Price, Granted (in dollars per share)			$ 31.67
Weighted-Average Price, Exercised (in dollars per share)			$ 22.24
Weighted-Average Price, Forfeited (in dollars per share)			$ 30.53
Weighted-Average Price, Ending (in dollars per share)	$ 28.60		$ 28.60
Weighted-Average Price, Options Excercisable	$ 27.71		$ 27.71
Weighted-Average Price, Unvested Options	$ 30.97		$ 30.97
Weighted-Average Remaining Contractual Term, Outstanding			3 years 5 months 4 days
Aggregate Intrinsic Value, Outstanding	6.3		6.3
Weighted-Average Remaining Contractual Term, Options Excercisable			2 years 6 months 22 days
Aggregate Intrinsic Value, Options Excercisable	6.2		6.2
Weighted-Average Remaining Contractual Term, Unvested Options			5 years 8 months 29 days
Aggregate Intrinsic Value, Unvested Options	0.2		0.2
Intrinsic value of options exercised			0.6		4.2
Unrecognized compensation cost	2.7		2.7
Weighted-average period for recognition of compensation costs			2 years 20 days
Employee Service Share-based Compensation, Cash Received from Exercise of Stock Options			1.5
Restricted Stock [Member]
Options Outstanding [RollForward]
Total fair value of stock that vested			20.2		18.4
Shares Outstanding [Roll Forward]
Balance, beginning (in shares)			1,388,953
Granted (in shares)			968,118
Vested and paid out (in shares)			(637,677)
Forfeited (in shares)			(116,238)
Balance, Ending (in shares)	1,603,156		1,603,156
Weighted-Average Price [Abstract]
Weighted-Average Price, Forfeited (in dollars per share)			$ 30.96
Weighted-Average Price, beginning balance (in dollars per share)			$ 30.96
Weighted-Average Price, Granted (in dollars per share)			$ 31.82		$ 30.03
Weighted-Average Price, Vested and paid out (in dollars per share)			$ 31.63
Weighted-Average Price, Ending Balance (in dollars per share)	$ 31.22		$ 31.22
Unrecognized compensation cost	18.2		18.2
Weighted-average period for recognition of compensation costs			2 years 3 months 4 days
Vesting period (in years)			3 years 0 months 0 days
Performance Share Units [Member]
Shares Outstanding [Roll Forward]
Balance, beginning (in shares)			480,660
Granted (in shares)			252,161
Vested and paid out (in shares)			(55,659)
Forfeited (in shares)			(22,416)
Vested and canceled (in shares)			(51,361)	[1]
Balance, Ending (in shares)	603,385		603,385
Weighted-Average Price [Abstract]
Weighted-Average Price, Forfeited (in dollars per share)			$ 30.47
Weighted-Average Price, beginning balance (in dollars per share)			$ 32.33
Weighted-Average Price, Granted (in dollars per share)			$ 31.71		$ 30.12
Weighted-Average Price, Vested and paid out (in dollars per share)			$ 39.07
Weighted-Average Price, Vested and canceled (in dollars per share)			$ 39.07
Weighted-Average Price, Ending Balance (in dollars per share)	$ 30.92		$ 30.92
Unrecognized compensation cost	$ 3.2		$ 3.2
Weighted-average period for recognition of compensation costs			2 years 24 days

[1] Represents units that were not paid out due to not meeting performance targets. Payout of the performance share units is dependent upon the Company’s total shareholder return compared to a group of its peers over a three-year period.

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Fair Value Measurements - Fair Value of Financial Assets and Liabilities (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Financial Assets
Derivative Asset, Fair Value, Gross	$ 49.7		$ 6.5
Financial liabilities
Derivative Liability, Fair Value, Gross	9.1		32.0
Fair Value, Measurements, Recurring [Member]
Financial Assets
Net amount of derivative assets presented on condensed consolidated balance sheets	45.3		1.2
Financial liabilities
Net amount of derivative liabilities presented on condensed consolidated balance sheets	4.7		26.7
Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	0		0
Financial liabilities
Derivative Liability, Fair Value, Gross	0		0
Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	49.7		6.5
Financial liabilities
Derivative Liability, Fair Value, Gross	9.1		32.0
Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	0		0
Financial liabilities
Derivative Liability, Fair Value, Gross	0		0
Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	(4.4)	[1]	(5.3)	[1]
Financial liabilities
Derivative Liability, Fair Value, Gross	(4.4)	[1]	(5.3)	[1]
Long-term [Member] | Interest Rate Swap [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			0.6
Financial liabilities
Derivative Liability, Fair Value, Gross	0		0
Long-term [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member]
Financial Assets
Net amount of derivative assets presented on condensed consolidated balance sheets	3.5		0.6
Long-term [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	0		0
Long-term [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	3.5		0.6
Long-term [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	0		0
Long-term [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	0	[1]	0	[1]
Long-term [Member] | Commodity Contract [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			0.4
Financial liabilities
Derivative Liability, Fair Value, Gross			0
Long-term [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member]
Financial Assets
Net amount of derivative assets presented on condensed consolidated balance sheets	9.2		0.4
Financial liabilities
Net amount of derivative liabilities presented on condensed consolidated balance sheets	0.2
Long-term [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	0		0
Financial liabilities
Derivative Liability, Fair Value, Gross	0
Long-term [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	9.6		0.4
Financial liabilities
Derivative Liability, Fair Value, Gross	0.6
Long-term [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	0		0
Financial liabilities
Derivative Liability, Fair Value, Gross	0
Long-term [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	(0.4)	[1]	0	[1]
Financial liabilities
Derivative Liability, Fair Value, Gross	(0.4)	[1]
Short-term [Member] | Interest Rate Swap [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	0		0
Financial liabilities
Derivative Liability, Fair Value, Gross			2.6
Short-term [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member]
Financial liabilities
Net amount of derivative liabilities presented on condensed consolidated balance sheets	4.3		2.6
Short-term [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Financial liabilities
Derivative Liability, Fair Value, Gross	0		0
Short-term [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Financial liabilities
Derivative Liability, Fair Value, Gross	4.3		2.6
Short-term [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Financial liabilities
Derivative Liability, Fair Value, Gross	0		0
Short-term [Member] | Interest Rate Swap [Member] | Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member]
Financial liabilities
Derivative Liability, Fair Value, Gross	0	[1]	0	[1]
Short-term [Member] | Commodity Contract [Member]
Financial Assets
Derivative Asset, Fair Value, Gross			5.5
Financial liabilities
Derivative Liability, Fair Value, Gross			29.4
Short-term [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member]
Financial Assets
Net amount of derivative assets presented on condensed consolidated balance sheets	32.6		0.2
Financial liabilities
Net amount of derivative liabilities presented on condensed consolidated balance sheets	0.2		24.1
Short-term [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	0		0
Financial liabilities
Derivative Liability, Fair Value, Gross	0		0
Short-term [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	36.6		5.5
Financial liabilities
Derivative Liability, Fair Value, Gross	4.2		29.4
Short-term [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	0		0
Financial liabilities
Derivative Liability, Fair Value, Gross	0		0
Short-term [Member] | Commodity Contract [Member] | Fair Value, Measurements, Recurring [Member] | Netting Adjustments [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	(4.0)	[1]	(5.3)	[1]
Financial liabilities
Derivative Liability, Fair Value, Gross	$ (4.0)	[1]	$ (5.3)	[1]

[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.

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Restructuring Costs (Tables)

9 Months Ended

Sep. 30, 2014

Restructuring Costs [Abstract]

Reconciliation of QEP Energy's restructuring cost

	Total Restructuring Costs
	Total Expected to be Incurred		Recognized in Income
			Period from Inception to September 30, 2014		Three Months Ended September 30,				Nine Months Ended September 30,
					2014		2013		2014		2013
Continuing Operations:	(in millions)
QEP Energy
One-time termination benefits	$	3.3	$	3.3	$	—	$	0.1	$	—	$	0.4
Retention & relocation expense	3.7		3.7		—		0.1		—		0.3
Lease termination costs	0.6		0.6		—		—		—		—
Total restructuring costs	$	7.6	$	7.6	$	—	$	0.2	—		0.7
QEP Marketing & Other
One-time termination benefits	$	0.3	$	0.3	$	—	$	0.1	$	—	$	0.1
Total restructuring costs	$	0.3	$	0.3	$	—	$	0.1	$	—	$	0.1
Total QEP
One-time termination benefits	$	3.6	$	3.6	$	—	$	0.2	$	—	$	0.5
Retention & relocation expense	3.7		3.7		—		0.1		—		0.3
Lease termination costs	0.6		0.6		—		—		—		—
Total restructuring costs	$	7.9	$	7.9	$	—	$	0.3	$	—	$	0.8

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Debt (Tables)

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Debt Outstanding

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

	September 30, 2014			December 31, 2013
	(in millions)
QEP's revolving credit facility due 2016	$	297.5		$	480.0
Term loan due 2017	600.0			300.0
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	3,119.3			3,001.8
Less unamortized discount	(3.8		)	(4.3		)
Total long-term debt outstanding	$	3,115.5		$	2,997.5

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Nature of Business

9 Months Ended

Sep. 30, 2014

Nature Of Business [Abstract]

Nature of Business

Nature of Business

QEP Resources, Inc. (QEP or the Company) is a holding company with two major 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 a underground gas storage reservoir (QEP Marketing and Other).

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

In December 2013, QEP's Board of Directors authorized the Company to develop a plan to separate its midstream business, QEP Field Services, including the Company's interest in QEP Midstream Partners, LP (“QEP Midstream”), from QEP. Between December 2013 and September 2014, the Company evaluated transaction alternatives, including selling or merging the midstream business or spinning the midstream business off to its shareholders. In June 2014, QEP filed a registration statement on Form 10 with the U.S. Securities and Exchange Commission (SEC) in preparation for a potential spinoff of QEP Field Services as a separate publicly traded company. Concurrently, the Company evaluated selling or merging its midstream business. In September 2014, based on the proposals received, the Company's Board of Directors authorized QEP's management to engage in the negotiation of terms of a definitive transaction with Tesoro Logistics LP ("Tesoro"). In October 2014, the Company announced that its wholly owned subsidiary, 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 to Tesoro in an all cash transaction valued at $2.5 billion, including $230.0 million to refinance debt at QEP Midstream. The transaction is subject to customary closing conditions and regulatory approvals, and is expected to close before year-end 2014. On October 31, 2014, the Federal Trade Commission granted early termination, ending the Hart Scott Rodino waiting period for the transaction. The decision to sell the midstream business is a result of the Company’s ongoing review of strategic alternatives to maximize shareholder value. QEP will retain ownership of QEP Field Services’ Haynesville Gathering System. As a result of the pending transaction, the QEP Field Services reporting segment, excluding the retained ownership of the Haynesville Gathering System, has been classified as assets and liabilities held for sale on the Condensed Consolidated Balance Sheet and 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.

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

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Equity-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2014

Share-based Compensation [Abstract]

Schedule of calculated fair value of options granted and major assumptions used

	Stock Option Assumptions
	Nine Months Ended
	September 30, 2014
Weighted-average grant-date fair value of awards granted during the period	$	10.11
Weighted-average risk-free interest rate	1.31		%
Weighted-average expected price volatility	37.1		%
Expected dividend yield	0.25		%
Expected term in years at the date of grant	4.5

Summary of stock option transactions under the terms of LTSIP

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, 2013	1,794,187		$	27.90
Granted	282,236		31.67
Exercised	(65,366	)	22.24
Forfeited	(14,842	)	30.53
Outstanding at September 30, 2014	1,996,215		$	28.60	3.43	$	6.3
Options Exercisable at September 30, 2014	1,452,138		$	27.71	2.56	$	6.2
Unvested Options at September 30, 2014	544,077		$	30.97	5.75	$	0.2

Restricted Share Units Activity

	Restricted Shares Outstanding		Weighted- Average Grant-Date Fair Value
			(per share)
Unvested balance at December 31, 2013	1,388,953		$	30.96
Granted	968,118		31.82
Vested	(637,677	)	31.63
Forfeited	(116,238	)	30.96
Unvested balance at September 30, 2014	1,603,156		$	31.22

Schedule of Performance Share Units Activity

	Performance Share Units Outstanding		Weighted- Average Grant-Date Fair Value
Unvested balance at December 31, 2013	480,660		$	32.33
Granted	252,161		31.71
Vested and paid out	(55,659	)	39.07
Canceled (1)	(51,361	)	39.07
Forfeited	(22,416	)	30.47
Unvested balance at September 30, 2014	603,385		$	30.92

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Discontinued Operations - Income Statement Impact of Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
NGL sales	$ 51.1		$ 47.7		$ 179.3		$ 144.4
Other revenue	3.4		2.8		5.1		8.7
Purchased gas, oil and NGL sales	290.4		220.4		780.1		644.9
Total Revenues	910.0		719.5		2,614.7		2,064.8
Purchased gas, oil and NGL expense	288.4		219.5		775.5		650.3
Lease operating expense	61.1		43.5		177.0		130.2
Natural gas, oil and NGL transportation and other handling costs	71.1		58.6		198.5		158.5
Gathering, processing and other	1.4		2.1		4.8		6.4
General and administrative	49.4		40.7		147.0		116.8
Production and property taxes	59.4		40.6		160.8		113.7
Depreciation, depletion and amortization	251.4		238.4		712.5		719.3
Total operating expenses	783.1		649.0		2,184.4		1,908.7
Net loss from asset sales	(11.8)		12.8		(210.3)		113.4
OPERATING INCOME	115.1		83.3		220.0		269.5
Interest income and other loss	4.2		6.1		7.8		22.7
Income from unconsolidated affiliates					4.6		3.7
Interest expense	(41.5)		(41.4)		(128.4)		(124.7)
Net income attributable to noncontrolling interest					(17.6)		(5.8)
DISCONTINUED OPERATIONS, NET OF INCOME TAX	17.4		25.2		58.2		74.8
Income from discontinued operations before income taxes attributable to QEP from QEP Midstream	7.9		7.9		20.4		26.2
Ownership percentage	57.80%				57.80%
Midstream Business Held For Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
NGL sales	28.8		23.6		94.6		70.6
Other revenue	43.1		44.2		119.9		126.4
Purchased gas, oil and NGL sales	(11.9)	[1]	(14.4)	[1]	(38.5)	[1]	(41.5)	[1]
Total Revenues	60.0		53.4		176.0		155.5
Purchased gas, oil and NGL expense	(12.4)	[1]	(14.4)	[1]	(39.5)	[1]	(41.4)	[1]
Lease operating expense	(1.7)	[1]	(0.8)	[1]	(4.8)	[1]	(2.6)	[1]
Natural gas, oil and NGL transportation and other handling costs	(10.6)	[1]	(21.7)	[1]	(40.1)	[1]	(53.0)	[1]
Gathering, processing and other	22.7		20.3		69.8		60.1
General and administrative	11.1		8.6		34.3		19.4
Production and property taxes	2.1		1.8		6.1		4.0
Depreciation, depletion and amortization	14.3		14.7		43.1		37.8
Total operating expenses	25.5		8.5		68.9		24.3
Net loss from asset sales	0		(0.1)		(0.1)		(0.5)
OPERATING INCOME	34.5		44.8		107.0		130.7
Interest income and other loss	0		(2.1)		0		(13.7)
Income from unconsolidated affiliates	1.1		0.8		4.4		3.7
Interest expense	(1.5)		(0.3)		(2.8)		2.3
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES	34.1	[2]	43.2	[2]	108.6	[2]	123.0	[2]
Income taxes	(9.9)		(14.2)		(32.8)		(42.4)
NET INCOME FROM DISCONTINUED OPERATIONS	24.2		29.0		75.8		80.6
Net income attributable to noncontrolling interest	$ (6.8)		$ (3.8)		$ (17.6)		$ (5.8)

[1] Includes discontinued intercompany eliminations

[2] Includes income from discontinued operations before income taxes attributable to QEP from QEP Midstream (of which QEP owns 57.8%) of $7.9 million and $20.4 million for the three and nine months ended September 30, 2014, respectively, and $7.9 million and $26.2 million for the three and nine months ended September 30, 2013, respectively

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Debt (Narrative) (Details) (USD $)	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 3,119,300,000	$ 3,119,300,000		$ 3,001,800,000
Revolving credit facility origination fees		(1,100,000)
Less unamortized discount	(3,800,000)	(3,800,000)		(4,300,000)
Debt Maturity Period	5 years 0 months 0 days
Proceeds from Issuance of Long-term Debt		300,000,000	0
Principal amount of senior notes outstanding	2,221,800,000	2,221,800,000
Debt Instrument, Maturity Date Range, Start		Sep. 01, 2016
Debt Instrument, Maturity Date Range, End		May 01, 2023
Senior Notes, stated interest rate, minimum (in hundredths)		5.25%
Senior Notes, stated interest rate, maximim (in hundredths)		6.875%
Revolving Credit Facility due 2016 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	297,500,000	297,500,000		480,000,000
Maturity date of long-term debt		Aug. 25, 2016
Borrowing capacity	1,500,000,000	1,500,000,000
Potential increased borrowing capacity	2,000,000,000	2,000,000,000
NumberOfMaturityDateExtensions	2	2
Additional period with in which maturity to be extended		1 year
Weighted-average interest rate (in hundredths)	2.22%	2.22%	2.56%
Amount outstanding	297,500,000	297,500,000
Letters of credit outstanding	3,800,000	3,800,000
Term Loan due 2017 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	600,000,000	600,000,000		300,000,000
Maturity date of long-term debt		Apr. 18, 2017
Additional period with in which maturity to be extended		1 year
Weighted-average interest rate (in hundredths)	2.26%	2.26%	2.23%
6.05% Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	176,800,000	176,800,000		176,800,000
Long-term debt, interest rate (in hundredths)	6.05%	6.05%
Maturity date of long-term debt		Sep. 01, 2016
6.80% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 134,000,000	$ 134,000,000		$ 134,000,000
Long-term debt, interest rate (in hundredths)	6.80%	6.80%
Maturity date of long-term debt		Apr. 01, 2018

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
REVENUES
Gas sales	$ 171.6	$ 194.8	$ 609.2	$ 610.5
Oil sales	393.5	253.8	1,041.0	656.3
NGL sales	51.1	47.7	179.3	144.4
Other revenue	3.4	2.8	5.1	8.7
Purchased gas, oil and NGL sales	290.4	220.4	780.1	644.9
Total Revenues	910.0	719.5	2,614.7	2,064.8
OPERATING EXPENSES
Purchased gas, oil and NGL expense	288.4	219.5	775.5	650.3
Lease operating expense	61.1	43.5	177.0	130.2
Gas, oil and NGL transportation and other handling costs	71.1	58.6	198.5	158.5
Gathering and other expense	1.4	2.1	4.8	6.4
General and administrative	49.4	40.7	147.0	116.8
Production and property taxes	59.4	40.6	160.8	113.7
Depreciation, depletion and amortization	251.4	238.4	712.5	719.3
Exploration expenses	0.8	1.8	4.7	9.5
Impairment	0.1	3.8	3.6	4.0
Total operating expenses	783.1	649.0	2,184.4	1,908.7
Net gain (loss) from asset sales	(11.8)	12.8	(210.3)	113.4
OPERATING INCOME	115.1	83.3	220.0	269.5
Realized and unrealized gains (losses) on derivative contracts (See Note 8)	155.7	(27.8)	(13.2)	51.6
Interest and other income	4.2	6.1	7.8	22.7
Income from unconsolidated affiliates	0.1	0	0.2	0
Interest expense	(41.5)	(41.4)	(128.4)	(124.7)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	233.6	20.2	86.4	219.1
Income tax provision	(79.9)	(8.1)	(26.1)	(82.5)
NET INCOME FROM CONTINUING OPERATIONS	153.7	12.1	60.3	136.6
Discontinued operations, net of income tax	17.4	25.2	58.2	74.8
NET INCOME ATTRIBUTABLE TO QEP	$ 171.1	$ 37.3	$ 118.5	$ 211.4
Earnings Per Common Share Attributable to QEP
Earnings Per Share, Basic	$ 0.95	$ 0.21	$ 0.66	$ 1.18
Earnings Per Share, Diluted	$ 0.94	$ 0.21	$ 0.66	$ 1.18
Weighted-average common shares outstanding
Used in basic calculation (in shares)	180.1	179.3	180.0	179.2
Used in diluted calculation (in shares)	180.6	179.5	180.4	179.4
Dividends per common share (in dollars per share)	$ 0.02	$ 0.02	$ 0.06	$ 0.06
Continuing Operations [Member]
Earnings Per Common Share Attributable to QEP
Earnings Per Share, Basic	$ 0.85	$ 0.07	$ 0.34	$ 0.76
Earnings Per Share, Diluted	$ 0.84	$ 0.07	$ 0.34	$ 0.76
Discontinued Operations [Member]
Earnings Per Common Share Attributable to QEP
Earnings Per Share, Basic	$ 0.10	$ 0.14	$ 0.32	$ 0.42
Earnings Per Share, Diluted	$ 0.10	$ 0.14	$ 0.32	$ 0.42

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Fair Value Measurements Fair Value Measurements - Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	$ 0	$ 11.9	$ 123.0	$ 0
Checks outstanding in excess of cash balances	36.8	109.1
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	3,209.3	3,034.9
Cash and Cash Equivalents, at Carrying Value	0	11.9
Checks outstanding in excess of cash balances	36.8	109.1
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	3,115.5	2,997.5
Cash and Cash Equivalents, at Carrying Value	0	11.9
Checks outstanding in excess of cash balances	$ 36.8	$ 109.1

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
EQUITY
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	500	500
Common stock, shares issued (in shares)	180.9	179.7
Treasury stock (in shares)	0.8	0.4

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Operations by Line of Business (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Revenues
Total Revenues	$ 910.0	$ 719.5	$ 2,614.7	$ 2,064.8
Operating expenses
Purchased gas, oil and NGL expense	288.4	219.5	775.5	650.3
Lease operating expense	61.1	43.5	177.0	130.2
Natural gas, oil and NGL transportation and other handling costs	71.1	58.6	198.5	158.5
Gathering, processing and other	1.4	2.1	4.8	6.4
General and administrative	49.4	40.7	147.0	116.8
Production and property taxes	59.4	40.6	160.8	113.7
Depreciation, depletion and amortization	251.4	238.4	712.5	719.3
Other operating expenses	0.9	5.6	8.3	13.5
Total operating expenses	783.1	649.0	2,184.4	1,908.7
Net gain (loss) from asset sales	(11.8)	12.8	(210.3)	113.4
Operating income (loss)	115.1	83.3	220.0	269.5
Realized and unrealized gains (losses) on derivative contracts	155.7	(27.8)	(13.2)	51.6
Interest and other income	4.2	6.1	7.8	22.7
Income from unconsolidated affiliates	0.1	0	0.2	0
Interest expense	(41.5)	(41.4)	(128.4)	(124.7)
Income (loss) before income taxes	233.6	20.2	86.4	219.1
Income taxes	(79.9)	(8.1)	(26.1)	(82.5)
Income from continuing operations	153.7	12.1	60.3	136.6
Discontinued operations, net of income tax	17.4	25.2	58.2	74.8
Net income attributable to QEP	171.1	37.3	118.5	211.4
Assets	10,276.2		10,276.2		9,394.9
Unaffiliated customers [Member]
Revenues
Total Revenues	910.0	719.5	2,614.7	2,064.8
Affiliated customers [Member]
Revenues
Total Revenues	0	0	0	0
QEP Energy [Member]
Revenues
Total Revenues	652.9	538.5	1,953.3	1,575.2
Operating expenses
Purchased gas, oil and NGL expense	32.8	39.2	120.9	159.8
Lease operating expense	61.1	43.5	177.0	130.2
Natural gas, oil and NGL transportation and other handling costs	75.2	65.1	211.8	180.8
Gathering, processing and other	0	0	0	0
General and administrative	44.3	33.5	132.0	100.2
Production and property taxes	59.3	40.4	159.8	112.7
Depreciation, depletion and amortization	249.0	236.0	704.7	712.1
Other operating expenses	0.9	5.6	8.3	13.5
Total operating expenses	522.6	463.3	1,514.5	1,409.3
Net gain (loss) from asset sales	(11.9)	12.8	(210.3)	113.4
Operating income (loss)	118.4	88.0	228.5	279.3
Realized and unrealized gains (losses) on derivative contracts	154.1	(25.6)	(9.7)	49.6
Interest and other income	3.9	2.6	7.4	7.5
Income from unconsolidated affiliates	0.1	0	0.2
Interest expense	(57.0)	(49.2)	(162.5)	(143.4)
Income (loss) before income taxes	219.5	15.8	63.9	193.0
Income taxes	(72.7)	(6.2)	(14.6)	(71.1)
Income from continuing operations	146.8	9.6	49.3	121.9
Net income attributable to QEP	146.8	9.6	49.3	121.9
QEP Energy [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	652.9	538.5	1,953.3	1,575.2
QEP Energy [Member] | Affiliated customers [Member]
Revenues
Total Revenues	0	0	0	0
QEP Marketing and Other [Member]
Revenues
Total Revenues	674.9	446.6	1,794.3	1,175.6
Operating expenses
Purchased gas, oil and NGL expense	668.3	438.2	1,771.6	1,150.5
Lease operating expense	0	0	0	0
Natural gas, oil and NGL transportation and other handling costs	0	0	0	0
Gathering, processing and other	1.4	2.1	4.8	6.4
General and administrative	6.1	8.4	17.6	20.3
Production and property taxes	0.1	0.2	1.0	1.0
Depreciation, depletion and amortization	2.4	2.4	7.8	7.2
Other operating expenses	0		0	0
Total operating expenses	678.3	451.3	1,802.8	1,185.4
Net gain (loss) from asset sales	0.1	0	0	0
Operating income (loss)	(3.3)	(4.7)	(8.5)	(9.8)
Realized and unrealized gains (losses) on derivative contracts	1.6	(2.2)	(3.5)	2.0
Interest and other income	56.6	52.2	162.0	158.4
Income from unconsolidated affiliates	0	0	0
Interest expense	(40.8)	(40.9)	(127.5)	(124.5)
Income (loss) before income taxes	14.1	4.4	22.5	26.1
Income taxes	(7.2)	(1.9)	(11.5)	(11.4)
Income from continuing operations	6.9	2.5	11.0	14.7
Net income attributable to QEP	6.9	2.5	11.0	14.7
QEP Marketing and Other [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	257.1	181.0	661.4	489.6
QEP Marketing and Other [Member] | Affiliated customers [Member]
Revenues
Total Revenues	417.8	265.6	1,132.9	686.0
Elimination [Member]
Revenues
Total Revenues	(417.8)	(265.6)	(1,132.9)	(686.0)
Operating expenses
Purchased gas, oil and NGL expense	(412.7)	(257.9)	(1,117.0)	(660.0)
Lease operating expense	0	0	0	0
Natural gas, oil and NGL transportation and other handling costs	(4.1)	(6.5)	(13.3)	(22.3)
Gathering, processing and other	0	0	0	0
General and administrative	(1.0)	(1.2)	(2.6)	(3.7)
Production and property taxes	0	0	0	0
Depreciation, depletion and amortization	0	0	0	0
Other operating expenses	0	0	0	0
Total operating expenses	(417.8)	(265.6)	(1,132.9)	(686.0)
Net gain (loss) from asset sales		0	0	0
Operating income (loss)	0	0	0	0
Realized and unrealized gains (losses) on derivative contracts	0	0	0	0
Interest and other income	(56.3)	(48.7)	(161.6)	(143.2)
Income from unconsolidated affiliates	0	0	0
Interest expense	56.3	48.7	161.6	143.2
Income (loss) before income taxes	0	0	0	0
Income taxes	0	0	0	0
Income from continuing operations	0	0	0	0
Net income attributable to QEP	0	0	0	0
Elimination [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	0	0	0	0
Elimination [Member] | Affiliated customers [Member]
Revenues
Total Revenues	$ (417.8)	$ (265.6)	$ (1,132.9)	$ (686.0)

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Nature of Business Nature of Business (Narrative) (Details) (USD $)	Sep. 30, 2014
Nature Of Business [Abstract]
Value of midstream business sold	$ 2,500,000,000
Debt refinancing included in sale of midstream business	$ 230,000,000

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Subsequent Event

9 Months Ended

Sep. 30, 2014

Subsequent Event [Abstract]

Subsequent Events

Subsequent Events

On October 19, 2014, QEP announced that its wholly owned subsidiary, QEP Field Services, had entered into a definitive agreement to sell its midstream business, including its ownership interest in QEP Midstream, to Tesoro in an all cash transaction valued at $2.5 billion, including $230.0 million to refinance debt at QEP Midstream. QEP will retain ownership of QEP Field Services’ Haynesville Gathering System. The transaction is subject to customary closing conditions and regulatory approvals and is expected to close in the fourth quarter of 2014.

On October 31, 2014, QEP entered into two purchase and sale agreements to divest non-core properties in southern Oklahoma for an aggregate sale price of $108 million, subject to customary purchase price adjustments. The aggregate net book value of the properties being sold is approximately $37 million as of September 30, 2014. Any gain or loss on the sale recorded by the Company will be determined based upon the final purchase price, which is subject to customary purchase price adjustments. The Company expects to close the transactions by year end.

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Acquisitions & Divestitures (Narrative) (Details) (USD $) In Millions, unless otherwise specified	4 Months Ended	9 Months Ended			3 Months Ended	9 Months Ended
	Jun. 30, 2014	Sep. 30, 2014 acre		Sep. 30, 2014 Term Loan due 2017 [Member]	Sep. 30, 2014 Permian Basin [Member]	Sep. 30, 2014 Permian Basin [Member]
Business Acquisition [Line Items]
Liabilities incurred		$ 15.5	[1]			$ 9.7
Aggregate sale price of assets disposed		702.3
Pretax loss on sale of assets		210.4
Consideration Held In Escrow Pending Title Defects		28.7
Payments to Acquire Businesses, Gross					941.8
Payments to Acquire Businesses Net		941.8
Net acres of producing and undeveloped oil and gas properties		26,500
Number of vertical producing wells		270
Escrow Deposit		50.0
Borrowings to Fund Acquisition				300.0
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	114.2
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual	23.1
Business Acquisition, Transaction Costs		0.6
Debt Issuance Cost		$ 1.1

[1] Additions include $9.7 million related to the Permian Basin Acquisition (see Note 3 - Acquisitions and Divestitures).

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Acquisitions & Divestitures (Tables)

9 Months Ended

Sep. 30, 2014

Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]

Business Combination, Separately Recognized Transactions [Table Text Block]

	As of September 30, 2014
	(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

Business Acquisition, Pro Forma Information [Table Text Block]

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2013		2014		2014		2013		2013
	Actual		Pro forma		Actual		Pro forma		Actual		Pro forma
					(in millions, except per share data)
Revenues	$	719.5	$	776.5	$	2,614.7	$	2,640.8	$	2,064.8	$	2,195.4
Net income (loss) attributable to QEP	37.3		54.2		118.5		125.5		211.4		240.4
Earnings per common share attributable to QEP
Basic	$	0.21	$	0.30	$	0.66	$	0.70	$	1.18	$	1.34
Diluted	0.21		0.30		0.66		0.70		1.18		1.34

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
OPERATING ACTIVITIES
Net income attributable to QEP	$ 118.5	$ 211.4
Net income attributable to noncontrolling interest	17.6	5.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	755.8	757.1
Deferred income taxes	91.5	39.3
Impairment	3.6	4.0
Equity-based compensation	20.7	20.0
Amortization of debt issuance costs and discounts	5.1	4.7
Net loss (gain) from asset sales	210.3	(113.0)
Income from unconsolidated affiliates	(4.6)	(3.7)
Distributions from unconsolidated affiliates and other	5.1	5.9
Unrealized (gain) loss on derivative contracts	(65.9)	55.5
Changes in operating assets and liabilities	62.0	(8.1)
Net Cash Provided by Operating Activities	1,219.7	978.9
INVESTING ACTIVITIES
Property acquisitions	(949.7)	(39.3)
Property, plant and equipment, including dry exploratory well expense	(1,270.4)	(1,089.6)
Proceeds from disposition of assets	706.2	208.3
Acquisition deposit held in escrow	50.0	0
Other investing activities	3.2	0
Net Cash Used in Investing Activities	(1,460.7)	(920.6)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(81.1)	(38.1)
Long-term debt issued	300.0	0
Long-term debt issuance costs paid	(1.1)	(3.0)
Proceeds from credit facility	4,509.0	2,132.5
Repayments of credit facility	(4,461.5)	(2,457.5)
Treasury stock repurchases	(6.6)	(8.7)
Net proceeds from the issuance of QEP Midstream common units	0	449.6
Other capital contributions	5.1	3.6
Dividends paid	(10.8)	(10.8)
Excess tax (provisions) benefit on equity-based compensation	(0.6)	1.3
Distribution to noncontrolling interest	(23.3)	(4.2)
Net Cash Provided by Financing Activities	229.1	64.7
Change in cash and cash equivalents	(11.9)	123.0
Beginning cash and cash equivalents	11.9	0
Ending cash and cash equivalents	0	123.0
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	128.9	120.1
Cash paid for income taxes	(1.1)	49.4
Non-cash investing activities
Change in capital expenditure accrual balance	$ 66.5	$ 53.7

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Statement of Comprehensive Income [Abstract]
Net income attributable to QEP	$ 171.1		$ 37.3		$ 118.5		$ 211.4
Other comprehensive (loss) income, net of tax:
Reclassification of previously deferred derivative gains(1)	0	[1]	(19.7)	[1]	0	[1]	(60.4)	[1]
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss	0.2	[2]	0.4	[2]	0.4	[2]	1.1	[2]
Amortization of prior service cost	0.7	[3]	0.8	[3]	2.4	[3]	2.5	[3]
Total pension and other postretirement plans adjustments	0.9		1.2		2.8		3.6
Other comprehensive loss	0.9		(18.5)		2.8		(56.8)
Comprehensive (loss) income attributable to QEP	$ 172.0		$ 18.8		$ 121.3		$ 154.6

[1] Presented net of income tax benefit of $11.7 million and $35.8 million during the three and nine months ended September 30, 2013

[2] Presented net of income tax expense of $0.2 million during the nine months ended September 30, 2014 and $0.2 million and $0.7 million during the three and nine months ended September 30, 2013, respectively.

[3] Presented net of income tax expense of $0.5 million and $1.5 million during the three and nine months ended September 30, 2014, respectively, and $0.5 million and $1.5 million during the three and nine months ended September 30, 2013, respectively.

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Debt

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Debt

Debt

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

	September 30, 2014			December 31, 2013
	(in millions)
QEP's revolving credit facility due 2016	$	297.5		$	480.0
Term loan due 2017	600.0			300.0
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	3,119.3			3,001.8
Less unamortized discount	(3.8		)	(4.3		)
Total long-term debt outstanding	$	3,115.5		$	2,997.5

Of the total debt outstanding on September 30, 2014, amounts outstanding under QEP's revolving credit facility due August 25, 2016, QEP's term loan due April 18, 2017, the 6.05% Senior Notes due September 1, 2016, and the 6.80% Senior Notes due April 1, 2018, will mature within the next five years.

Credit Facilities

QEP's Credit Facility

QEP’s unsecured revolving credit facility, which matures in August 2016, provides for loan commitments of $1.5 billion from a group of financial institutions. The credit facility provides for borrowings at short-term interest rates and contains customary covenants and restrictions. The credit facility also contains an accordion provision that would allow for the amount of the facility to be increased to $2.0 billion and a provision whereby the maturity can be extended for up to two additional one-year periods, with the agreement of the lenders.

During the nine months endedSeptember 30, 2014 and 2013, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.22% and 2.56%, respectively. At September 30, 2014 and December 31, 2013, QEP was in compliance with the covenants under the credit agreement. At September 30, 2014, there was $297.5 million outstanding and $3.8 million of letters of credit issued under the credit facility.

Term Loan

QEP's $600.0 million unsecured term loan facility provides for borrowings at short-term interest rates and contains covenants, restrictions, and interest rates that are substantially the same as QEP’s revolving credit facility. The term loan matures in April 2017, and the maturity date may be extended one year with the agreement of the lenders. In conjunction with the Permian Basin Acquisition, QEP borrowed an incremental $300.0 million available under the facility and increased total borrowings under the term loan to $600.0 million. There were no changes to the maturity date, pricing or covenants in the credit agreement. QEP incurred $1.1 million of debt issuance costs associated with the new term loan issuance.

During the nine months endedSeptember 30, 2014 and 2013, QEP’s weighted-average interest rate on borrowings from the term loan was 2.26% and 2.23%, respectively. At September 30, 2014 and December 31, 2013, QEP was in compliance with the covenants under the term loan credit agreement.

Senior Notes

At September 30, 2014, 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.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	QEP RESOURCES, INC.
Entity Central Index Key	0001108827
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding	180,149,080
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2014

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Contingencies

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Contingencies

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 can be reasonably estimated 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 could 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, and/or the ongoing discovery and development of information important to the matter. QEP's litigation loss contingencies are discussed below. Except for the Rocky Mountain Resources, the Questar Gas Company, and the XTO Energy Inc. matters discussed below, QEP is unable to estimate reasonably possible losses (in excess of recorded accruals, if any) for these 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.

Environmental Claims

In October 2009, QEP received a cease and desist order from the U.S. Army Corps of Engineers (COE) to refrain from unpermitted work resulting in the discharge of dredged and/or fill material into waters of the United States at three sites located in Caddo and Red River Parishes, Louisiana. Region 6 of the U.S. Environmental Protection Agency (EPA) has assumed lead responsibility for enforcement of the cease and desist order and any possible future orders for the removal of unauthorized fills and/or civil penalties under the Clean Water Act. On June 28, 2013, the EPA issued to QEP an Administrative Complaint for the alleged violations. QEP and the EPA reached an agreement to settle the alleged violations through an Administrative Order, under the terms of which QEP paid an administrative penalty of $0.2 million. The Administrative Order is final. In 2012, QEP completed a field audit, which identified 112 additional instances affecting approximately 90 acres where work may have been conducted in violation of the Clean Water Act. QEP has disclosed each of these instances to the EPA under the EPA's Audit Policy (to reduce penalties) and to the COE. QEP is working with the EPA and the COE to resolve these matters, which will require the Company to undertake certain mitigation and permitting activities, and may require QEP to pay a monetary penalty.

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.

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 attaches to 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. On October 8, 2014, Rocky Mountain, Ultra Resources, Inc. (Ultra) and Lance Oil and Gas Company (Lance) reached a confidential agreement resolving the application of the 4% override as to production by Ultra and Lance and filed a stipulation to dismiss the lawsuit with respect to Ultra and Lance. The stipulation has no effect on the claims asserted against QEP or Wexpro.There are several affirmative defenses that remain to be tried and QEP continues to vigorously defend the case. A trial date is scheduled for February 2015. QEP estimates, based in part on damages asserted by the plaintiff, that the range of reasonably possible outcomes is no loss to a loss of approximately $20.0 million.

Gatti et al v. State of Louisiana et al, 589,350, 19th JDC, Parish of East Baton Rouge, Louisiana. In this putative class action arising out of the unitization practices and orders of the Louisiana Commissioner of Conservation (Commissioner), plaintiffs seek to represent a class of all Haynesville Shale mineral owners (alleged to be over 50,000 in number) against the Commissioner and all Haynesville Shale unit operators. Plaintiffs filed their complaint on April 8, 2010, and claim that the Commissioner exceeded his statutory authority in creating and perpetuating units larger than the area that can be efficiently and economically drained by a single well. They seek declaratory relief that would nullify all such improper orders, along with an unspecified amount of monetary damages from the unit operators sufficient to compensate the putative class members for the alleged dilution of their true interest in unit production as a result of "oversized" units and the "cloud on title" caused by having excessive and improperly sized units purport to hold their mineral leases via unit operations. All defendants filed exceptions to the plaintiffs' petition on the primary ground that plaintiffs had failed to comply with the exclusive statutory judicial review procedure (Louisiana Revised Statutes 30:12), which the trial court granted, dismissing the action in its entirety. On January 15, 2014, the Louisiana First Circuit Court of Appeal reversed and reinstated plaintiffs' claims. Defendants asked for review by the Louisiana Supreme Court and on August 25, 2014, the Supreme Court reversed the Court of Appeals and dismissed the plaintiffs’ claim without prejudice as originally ordered by the District Court.

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. 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 are ongoing.

Litigation related to discontinued operations:

In accordance with the terms of the Membership Interest Purchase Agreement, dated as of October 19, 2014, by and between QEP Field Services and Tesoro, Tesoro has agreed to indemnify QEP Field Services and its affiliates for any liabilities or claims associated with Questar Gas Company and XTO Energy litigation. Therefore, following the closing of the Tesoro transaction, QEP believes it will have no significant exposure to liability for the following litigation matters.

Questar Gas Company v. QEP Field Services Company, Civil No. 120902969, Third Judicial District Court, State of Utah. QEP Field Services' former affiliate, Questar Gas Company (QGC), filed this complaint in state court in Utah on May 1, 2012, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, and an accounting and declaratory judgment related to a 1993 gathering agreement (the 1993 Agreement) executed when the parties were affiliates. Specific monetary damages are not asserted. Under the 1993 Agreement, certain of QEP Field Services' systems provide gathering services to QGC charging an annual gathering rate which is based on the cost of service. QGC is disputing the annual calculation of the gathering rate. The annual gathering rate has been calculated in the same manner under the 1993 Agreement since it was amended in 1998, without any prior objection or challenge by QGC. At the closing of the QEP Midstream initial public offering (IPO), the assets and agreement discussed above were assigned to QEP Midstream. QGC amended its complaint to add QEP Midstream as a defendant in the litigation. QEP agreed to indemnify QEP Midstream for costs, expenses and other losses incurred by QEP Midstream in connection with the QGC dispute, subject to certain limitations, as set forth in the Omnibus Agreement entered into between QEP Midstream and QEP in connection with the IPO. QGC netted the disputed amount from its monthly payments of the gathering fees to QEP Field Services and has continued to net such amounts from its monthly payment to QEP Midstream. As of September 30, 2014, QEP Midstream has deferred revenue of $13.2 million, which was included in "Current liabilities of discontinued operations held for sale" on the Condensed Consolidated Balance Sheet, related to the QGC disputed amount. QEP Field Services has filed counterclaims seeking damages and a declaratory judgment relating to its gathering services under the 1993 Agreement.

XTO Energy Inc. v. QEP Field Services Company, Civil No. 140900709, Third Judicial District Court, State of Utah. XTO Energy Inc. (XTO), filed this complaint in Utah state court on January 30, 2014, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, unjust enrichment and an accounting related to a 2010 gas processing agreement (the Agreement). QEP Field Services processes XTO’s natural gas on a firm basis under the Agreement. The Agreement requires QEP Field Services to transport, fractionate and market XTO’s natural gas liquids derived from XTO’s processed gas. XTO is seeking monetary damages related to QEP Field Services allocation of charges related to XTO’s share of natural gas liquid transportation, fractionation and marketing costs associated with shortfalls in contractual firm processing volumes.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Other comprehensive income (loss), tax
Tax expense (benefit) on gains (losses) on changes in unrealized fair value of derivatives designated as cash flow hedges		$ (11.7)		$ (35.8)
Pension and other postretirement plans adjustments:
Tax expense (benefit) on net unamortized gain (loss) incurred		0.2	0.2	0.7
Tax expense (benefit) on prior service cost incurred	$ 0.5	$ 0.5	$ 1.5	$ 1.5

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Earnings Per Share

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income attributable to QEP 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 equity-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The Company’s unvested restricted stock awards contain non-forfeitable dividend rights and participate equally with common stock with respect to dividends issued or declared. However, the Company’s unvested restricted stock does not have a contractual obligation to share in losses of the Company. The Company’s unexercised stock options do not contain rights to dividends. Under the two-class method, the earnings used to determine basic earnings per common share are reduced by an amount allocated to participating securities. When the Company records a net loss, none of the loss is allocated to the participating securities since the securities are not obligated to share in Company losses. Use of the two-class method has an insignificant impact on the calculation of basic and diluted earnings per common share. During the three and nine months endedSeptember 30, 2014 and 2013, there were no anti-dilutive shares.

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2014	2013	2014	2013
	(in millions)
Weighted-average basic common shares outstanding	180.1	179.3	180.0	179.2
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	0.5	0.2	0.4	0.2
Average diluted common shares outstanding	180.6	179.5	180.4	179.4

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Discontinued Operations

9 Months Ended

Sep. 30, 2014

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]

Discontinued Operations

In December 2013, QEP's Board of Directors authorized the Company to develop a plan to separate its midstream business, QEP Field Services, including the Company's interest in QEP Midstream, from QEP. Between December 2013 and September 2014, the Company evaluated transaction alternatives, including selling or merging the midstream business or spinning the midstream business off to its shareholders. In June 2014, QEP filed a registration statement on Form 10 with the SEC in preparation for a potential spinoff of QEP Field Services as a separate publicly traded company. Concurrently, the Company evaluated selling or merging its midstream business. In September 2014, based on the proposals received, the Company's Board of Directors authorized QEP's management to engage in the negotiation of terms of a definitive transaction with Tesoro. In October 2014, the Company announced that its wholly owned subsidiary, 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 to Tesoro in an all cash transaction valued at $2.5 billion, including $230.0 million to refinance debt at QEP Midstream. The transaction is subject to customary closing conditions and regulatory approvals, and is expected to close before year-end 2014. On October 31, 2014, the Federal Trade Commission granted early termination, ending the Hart Scott Rodino waiting period for the transaction. The decision to sell the midstream business is a result of the Company’s ongoing review of strategic alternatives to maximize shareholder value and represents a significant milestone in the strategic repositioning of the Company. As of September 30, 2014, the operating results and financial position of QEP Field Services, excluding its retained ownership of the Haynesville Gathering System, were classified as discontinued operations as well as assets and liabilities held for sale on its balance sheet. After the transaction closes, QEP will have continuing cash outflows to our discontinued midstream business for gathering, processing and water handling costs in Pinedale, the Uinta Basin and a portion of its Williston Basin operations. These contracts 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 and are now reflected as part of the continuing operations for QEP. For the three months endedSeptember 30, 2014 and 2013, cash outflows for these transactions that are included in continuing operations were $19.0 million and $25.9 million, respectively. For the nine months endedSeptember 30, 2014 and 2013, cash outflows for these transactions that are included in continuing operations were $64.1 million and $67.2 million, respectively.

Condensed Consolidated Income Statement

The discontinued operations of QEP Field Services (excluding results of the Haynesville Gathering System) are summarized below:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(in millions, except per share amounts)
REVENUES
NGL sales	$	28.8		$	23.6		$	94.6		$	70.6
Other revenue	43.1			44.2			119.9			126.4
Purchased gas, oil and NGL sales(1)	(11.9		)	(14.4		)	(38.5		)	(41.5		)
Total Revenues	60.0			53.4			176.0			155.5
OPERATING EXPENSES
Purchased gas, oil and NGL expense(1)	(12.4		)	(14.4		)	(39.5		)	(41.4		)
Lease operating expense(1)	(1.7		)	(0.8		)	(4.8		)	(2.6		)
Natural gas, oil and NGL transport & other handling costs(1)	(10.6		)	(21.7		)	(40.1		)	(53.0		)
Gathering, processing, and other	22.7			20.3			69.8			60.1
General and administrative	11.1			8.6			34.3			19.4
Production and property taxes	2.1			1.8			6.1			4.0
Depreciation, depletion and amortization	14.3			14.7			43.1			37.8
Total Operating Expenses	25.5			8.5			68.9			24.3
Net loss from asset sales	—			(0.1		)	(0.1		)	(0.5		)
OPERATING INCOME	34.5			44.8			107.0			130.7
Interest income and other loss	—			(2.1		)	—			(13.7		)
Income from unconsolidated affiliates	1.1			0.8			4.4			3.7
Interest expense	(1.5		)	(0.3		)	(2.8		)	2.3
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES (2)	34.1			43.2			108.6			123.0
Income taxes	(9.9		)	(14.2		)	(32.8		)	(42.4		)
NET INCOME FROM DISCONTINUED OPERATIONS	24.2			29.0			75.8			80.6
Net income attributable to noncontrolling interest	(6.8		)	(3.8		)	(17.6		)	(5.8		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	17.4		$	25.2		$	58.2		$	74.8

⁽¹⁾ Includes discontinued intercompany eliminations

⁽²⁾ Includes income from discontinued operations before income taxes attributable to QEP from QEP Midstream (of which QEP owns 57.8%) of $7.9 million and $20.4 million for the three and nine months ended September 30, 2014, respectively, and $7.9 million and $26.2 million for the three and nine months ended September 30, 2013, respectively.

Condensed Consolidated Balance Sheet

The current and noncurrent assets and liabilities of QEP Field Services, excluding the retained Haynesville Gathering System, are as follows:

	September 30, 2014			December 31, 2013
Cash and cash equivalents	$	27.1		$	18.1
Accounts receivable, net	71.8			53.9
Income taxes receivable	—			38.4
Deferred income taxes - current	7.0			2.7
Prepaid expenses and other	32.4			8.9
Current assets of discontinued operations held for sale	$	138.3		$	122.0
Property, Plant and Equipment
Midstream field services	$	1,550.5		$	1,500.8
Material and supplies	6.5			4.8
Total Property, Plant and Equipment	1,557.0			1,505.6
Less Accumulated Depreciation, Depletion and Amortization
Midstream field services	(422.2		)	(381.6		)
Net Property, Plant and Equipment	1,134.8			1,124.0
Investment in unconsolidated affiliates	35.9			39.0
Other noncurrent assets	3.5			4.7
Noncurrent assets of discontinued operations held for sale	$	1,174.2		$	1,167.7
Accounts payable and accrued expenses	$	85.6		$	74.1
Accrued income taxes	70.2			—
Production and property taxes	5.4			1.2
Interest payable	0.4			—
Current liabilities of discontinued operations held for sale	$	161.6		$	75.3
Long-term debt	$	230.0		$	—
Deferred income taxes	126.5			195.7
Asset retirement obligations	29.9			28.5
Other long-term liabilities	15.6			14.1
Noncurrent liabilities of discontinued operations held for sale	$	402.0		$	238.3

Condensed Consolidated Statement of Cash Flows

The impact of the QEP Field Services discontinued operations, excluding the Haynesville Gathering System, on the Condensed Consolidated Statement of Cash Flows for "Depreciation, depletion and amortization" contained in "Cash flows from operating activities" was $43.1 million and $37.8 million for the nine months ended September 30, 2014 and 2013, respectively. The impact on cash used for "Property, plant and equipment, including dry exploratory well expense" contained in "Cash flows from investing activities" was $45.6 million and $57.4 million for the nine months ended September 30, 2014 and 2013, respectively.

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Basis of Presentation of Interim Consolidated Financial Statements (Policies)

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

New accounting pronouncements

New accounting pronouncements

In April 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, which broadened the reporting of discontinued operations to a component of an entity that has operations and cash flows that can be clearly distinguished from the rest of the entity. Under this guidance, to be a discontinued operation, a component or group of components must represent a strategic shift that has (or will have) a major effect on an entity's operations and financial results. The amendments are effective prospectively for reporting periods beginning on or after December 15, 2014 and early adoption is permitted. The Company has chosen to early adopt ASU 2014-08 and implemented the amendments in the quarter ended September 30, 2014.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The amendments are effective prospectively for reporting periods beginning after December 15, 2016 and early adoption is not permitted. The Company is currently assessing the impact on the Company's consolidated financial statements.

In August 2014, the FASB issued ASU No. 2014-15, Presentation of Financial Statements-Going Concern (Topic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern. This guidance provides additional information to guide management's evaluation of whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. The update is effective for annual periods beginning on or after December 15, 2016. The Company is currently evaluating the impact of this standard on its financial statements.

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Equity-Based Compensation

9 Months Ended

Sep. 30, 2014

Share-based Compensation [Abstract]

Equity-Based Compensation

Equity-Based Compensation

QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and awards performance-based share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP recognizes expense over time as the stock options, restricted shares, and performance-based share units vest. Deferred equity-based compensation is included in additional paid-in capital in the Condensed Consolidated Balance Sheets. There were 10.9 million shares available for future grants under the LTSIP at September 30, 2014. Equity-based compensation expense related to continuing operations is recognized in “General and administrative” on the Condensed Consolidated Statements of Operations, and expenses related to discontinued operations (including compensation expense related to the QEP Midstream Long Term Incentive Plan) are reflected in "Discontinued operations, net of income tax". During the three and nine months ended September 30, 2014 for continuing operations, QEP recognized $6.4 million and $17.7 million in total compensation expense related to equity-based compensation compared to $5.5 million and $17.9 million during the three and nine months ended September 30, 2013, respectively. During the three and nine months ended September 30, 2014 for discontinued operations, QEP recognized $0.9 million and $3.0 million in total compensation expense related to equity-based compensation compared to $1.3 million and $2.1 million during the three and nine months ended September 30, 2013, respectively.

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:

	Stock Option Assumptions
	Nine Months Ended
	September 30, 2014
Weighted-average grant-date fair value of awards granted during the period	$	10.11
Weighted-average risk-free interest rate	1.31		%
Weighted-average expected price volatility	37.1		%
Expected dividend yield	0.25		%
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, 2013	1,794,187		$	27.90
Granted	282,236		31.67
Exercised	(65,366	)	22.24
Forfeited	(14,842	)	30.53
Outstanding at September 30, 2014	1,996,215		$	28.60	3.43	$	6.3
Options Exercisable at September 30, 2014	1,452,138		$	27.71	2.56	$	6.2
Unvested Options at September 30, 2014	544,077		$	30.97	5.75	$	0.2

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.6 million and $4.2 million during the nine months endedSeptember 30, 2014 and 2013, respectively. As of September 30, 2014, $2.7 million of unrecognized compensation cost related to stock options granted under the LTSIP is expected to be recognized over a weighted-average period of 2.05 years. During the nine months endedSeptember 30, 2014, QEP received $1.5 million in cash upon the exercise of stock options during 2014.

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 nine months endedSeptember 30, 2014 and 2013 was $20.2 million and $18.4 million, respectively. The weighted average grant-date fair value of restricted stock was $31.82 per share and $30.03 per share for the nine months endedSeptember 30, 2014 and 2013, respectively. As of September 30, 2014, $18.2 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 2.26 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, 2013	1,388,953		$	30.96
Granted	968,118		31.82
Vested	(637,677	)	31.63
Forfeited	(116,238	)	30.96
Unvested balance at September 30, 2014	1,603,156		$	31.22

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 delivered in cash at the end of the performance period. The weighted average grant-date fair value of the performance share units was $31.71 per share and $30.12 per share for the nine months endedSeptember 30, 2014 and 2013, respectively. As of September 30, 2014, $3.2 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 2.07 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, 2013	480,660		$	32.33
Granted	252,161		31.71
Vested and paid out	(55,659	)	39.07
Canceled (1)	(51,361	)	39.07
Forfeited	(22,416	)	30.47
Unvested balance at September 30, 2014	603,385		$	30.92

____________________________

⁽¹⁾  Represents units that were not paid out due to not meeting performance targets. Payout of the performance share units is dependent upon the Company’s total shareholder return compared to a group of its peers over a three-year period.

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Derivative Contracts

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Contracts

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 to realize a known price 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 basis swaps to achieve a fixed price swap for a portion of its oil that it sells at prices that reference ICE Brent and Light Louisiana Sweet (LLS).

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.

Effective January 1, 2012, QEP elected to de-designate all of its gas, oil and NGL derivative contracts that were previously designated as cash flow hedges and discontinue hedge accounting prospectively. As a result of discontinuing hedge accounting, the mark-to-market values at December 31, 2011, were fixed in Accumulated Other Comprehensive Income (AOCI) as of the de-designation date and are being reclassified into the Condensed Consolidated Statements of Operations as the transactions settle and affect earnings. During the nine months endedSeptember 30, 2013, $60.4 million of unrealized gains, after tax, were reclassified from AOCI into the Condensed Consolidated Statements of Operations in "Realized and unrealized losses on derivative contracts" as the transactions settled. All realized and unrealized gains and losses from derivative instruments incurred after January 1, 2012, are presented in the Condensed Consolidated Statements of Operations in "Realized and unrealized losses on derivative contracts" below operating income.

QEP also uses interest rate swaps to mitigate a portion of its exposure to interest rate volatility risk 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%. The average effective interest rate on the $600.0 million term loan when combined with the fixed interest rate swaps for the nine months endedSeptember 30, 2014 was 3.21%. The interest rate swaps settle monthly and will mature in March 2017.

QEP Energy Derivative Contracts

The following table sets forth QEP Energy’s quantities and average prices for its commodity derivative contracts as of September 30, 2014: 

Year	Type of Contract	Index	Total Volumes	Average Swap price per unit
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	NYMEX	7.4	$	4.22
2014	SWAP	IFNPCR	20.2	$	4.08
2015	SWAP	NYMEX	25.6	$	4.14
2015	SWAP	IFNPCR	11.0	$	4.06
Oil sales			(Bbls)
2014	SWAP	NYMEX WTI	3.1	$	93.54
2015	SWAP	NYMEX WTI	7.7	$	90.04
2015	SWAP	BRENT ICE	0.4	$	104.95
2016	SWAP	NYMEX WTI	0.4	$	90.00

The following table sets forth QEP Energy's oil basis swaps as of September 30, 2014:

Year	Index	Index Less Differential	Total Volumes	Weighted Average Differential
			(in millions)
Oil basis swaps			(Bbls)
2014	NYMEX WTI	ICE Brent	0.2	$	13.78
2014	NYMEX WTI	LLS	0.2	$	4.03
2015	NYMEX WTI	LLS	0.1	$	4.03

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 September 30, 2014:

Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2014	SWAP	IFNPCR	1.4	$	4.03
2015	SWAP	IFNPCR	2.5	4.07
Gas purchases			(MMBtu)
2014	SWAP	IFNPCR	0.6	$	3.86

QEP's Derivative Contracts

The following table sets forth QEP’s notional amount and interest rate for its interest rate swaps outstanding as of September 30, 2014:

Notional amount	Type of Contract	Maturity	Fixed Rate Paid	Variable Rate Received
(in millions)
$300.0	Swap	March 2017	1.07%	One-month LIBOR
$300.0	Swap	March 2017	0.86%	One-month LIBOR
$600.0			0.96%

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	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
		(in millions)				(in millions)
Current:
Commodity	Fair value of derivative contracts	$	36.6	$	5.5	$	4.2	$	29.4
Interest rate swaps	Fair value of derivative contracts	—		—		4.3		2.6
Long-term:
Commodity	Fair value of derivative contracts	9.6		0.4		0.6		—
Interest rate swaps	Fair value of derivative contracts	3.5		0.6		—		—
Total derivative instruments		$	49.7	$	6.5	$	9.1	$	32.0

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

	Three Months Ended						Nine Months Ended
Derivative instruments not designated as cash flow hedges	September 30,						September 30,
	2014			2013			2014			2013
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	5.5		$	42.5		$	(23.3	)	$	112.0
Oil derivative contracts	(12.2		)	(15.3		)	(50.2		)	(3.7		)
QEP Marketing
Gas derivative contracts	(0.4		)	(0.3		)	(2.4		)	0.7
Total realized gains (losses) on commodity derivative contracts	(7.1		)	26.9			(75.9		)	109.0
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	27.6			(6.6		)	9.5			(9.6		)
Oil derivative contracts	133.2			(46.2		)	54.3			(49.1		)
QEP Marketing
Gas derivative contracts	0.7			0.1			1.0			(0.3		)
Total unrealized gains (losses) on commodity derivative contracts	161.5			(52.7		)	64.8			(59.0		)
Total realized and unrealized gains (losses) on commodity derivative contracts	$	154.4		$	(25.8	)	$	(11.1	)	$	50.0
Realized gains (losses) on interest rate swaps
Realized losses on interest rate swaps	$	(1.3	)	$	(0.6	)	$	(3.2	)	$	(1.9	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	2.6			(1.4		)	1.1			3.5
Total realized and unrealized gains (losses) on interest rate swaps	$	1.3		$	(2.0	)	$	(2.1	)	$	1.6
Total net realized gains (losses) on derivative contracts	$	(8.4	)	$	26.3		$	(79.1	)	$	107.1
Total net unrealized gains (losses) on derivative contracts	164.1			(54.1		)	65.9			(55.5		)
Grand Total	$	155.7		$	(27.8	)	$	(13.2	)	$	51.6

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Subsequent Event (Details) (USD $)	Sep. 30, 2014
Subsequent Event [Line Items]
Value of midstream business sold	$ 2,500,000,000
Debt refinancing included in sale of midstream business	230,000,000
Aggregate sale price for announced divestiture	108,000,000
Net book value of property disposed	$ 37,000,000

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2014

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

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, production facilities, 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 $163.2 million and $165.1 million ARO liability for continuing operations for the periods ended September 30, 2014 and December 31, 2013, $0.9 million and $1.8 million was 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 continuing operations for the periods specified below:

	Asset Retirement Obligations
	2014
	(in millions)
ARO liability at January 1, (1)	$	165.1
Accretion	4.9
Additions(2)	15.5
Revisions	(0.3		)
Liabilities settled(3)	(22.0		)
ARO liability at September 30,(4)	$	163.2

____________________________

⁽¹⁾ Excludes $28.5 million of ARO classified as liabilities held for sale on the Condensed Consolidated Balance Sheet.

⁽²⁾ Additions include $9.7 million related to the Permian Basin Acquisition (see Note 3 - Acquisitions and Divestitures).

⁽³⁾ Settlements include $20.2 million related to the property sales in the second quarter of 2014 (see Note 3 - Acquisitions and Divestitures).

⁽⁴⁾ Excludes $29.9 million of ARO classified as liabilities held for sale on the Condensed Consolidated Balance Sheet.

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Fair Value Measurements

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

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.

In addition, QEP has interest rate swaps that it has determined are Level 2 financial instruments. The fair values of the interest rate swaps are determined using the market standard methodology of discounting the future expected cash flows that would occur under the contractual terms of the swap. The variable interest rates used in the calculation of projected cash flows are based on an expectation of future interest rates derived from observable market interest rate curves. QEP incorporates credit valuation adjustments to reflect both its nonperformance risk and the respective counterparty's nonperformance risk in the fair value measurements. While the credit valuation adjustments are not observable inputs, they are not significant to the overall valuation and the other inputs used to value the interest rate swaps are observable Level 2 inputs.

The fair value measurements of financial assets and liabilities at September 30, 2014, are shown in the table below:

	Fair Value Measurements
	September 30, 2014
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	36.6	$	—	$	(4.0	)	$	32.6
Commodity derivative instruments - long-term	—		9.6		—		(0.4		)	9.2
Interest rate swaps - long-term	—		3.5		—		—			3.5
Total financial assets	$	—	$	49.7	$	—	$	(4.4	)	$	45.3
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	4.2	$	—	$	(4.0	)	$	0.2
Interest rate swaps - short-term	—		4.3		—		—			4.3
Commodity derivative instruments - long-term	—		0.6		—		(0.4		)	0.2
Total financial liabilities	$	—	$	9.1	$	—	$	(4.4	)	$	4.7

____________________________

⁽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 fair value of financial assets and liabilities at December 31, 2013, is shown in the table below:

	Fair Value Measurements
	December 31, 2013
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
Financial Assets
Commodity derivative instruments - short-term	$	—	$	5.5	$	—	$	(5.3	)	$	0.2
Commodity derivative instruments - long-term	—		0.4		—		—			0.4
Interest rate swaps - long-term	—		0.6		—		—			0.6
Total financial assets	$	—	$	6.5	$	—	$	(5.3	)	$	1.2
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	29.4	$	—	$	(5.3	)	$	24.1
Interest rate swaps - short-term	—		2.6		—		—			2.6
Total financial liabilities	$	—	$	32.0	$	—	$	(5.3	)	$	26.7

_______________________

⁽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
	September 30, 2014				December 31, 2013
	(in millions)
Financial assets
Cash and cash equivalents	$	—	$	—	$	11.9	$	11.9
Financial liabilities
Checks outstanding in excess of cash balances	$	36.8	$	36.8	$	109.1	$	109.1
Long-term debt	$	3,115.5	$	3,209.3	$	2,997.5	$	3,034.9

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 remaining reserve lives. A reconciliation of the Company’s ARO is presented in Note 6 – Asset Retirement Obligations.

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Restructuring Costs

9 Months Ended

Sep. 30, 2014

Restructuring Costs [Abstract]

Restructuring Costs

Restructuring Costs

In December 2013, QEP announced its plan to pursue a separation of its midstream business, QEP Field Services. In connection with this announcement, 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 occurs, 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 expects to recognize $10.3 million of costs under this retention plan and has $7.9 million accrued since inception as of September 30, 2014. During the three and nine months ended September 30, 2014, $2.3 million and $7.1 million, respectively, was accrued under this retention plan, and are included in "Discontinued operations, net of income tax" on the Condensed Consolidated Statements of Operations.

During 2012, QEP began incurring costs related to the closure of its Oklahoma City office and the subsequent consolidation of its Southern Region operations into a single regional office located in Tulsa. Additionally, during 2012, QEP began incurring additional restructuring and reorganization costs related to consolidating various corporate and accounting functions to the Denver corporate headquarters. The creation of one office for QEP’s Southern Region as well as the consolidation of corporate and accounting functions increased efficiency, team-based collaboration and organizational productivity. As part of the reorganization, QEP incurred costs associated with the severance, retention and relocation of employees, additional pension expenses, exit costs associated with the termination of operating leases arising from office space that will no longer be utilized by the Company and other expenses. All restructuring costs related to the 2012 office consolidations and continued operations were incurred and settled by December 31, 2013.

The following table summarizes, by line of business, each major type of restructuring cost expected to be incurred and the total amounts recorded in "General and administrative" expense on the Condensed Consolidated Statements of Operations for the respective periods indicated:

	Total Restructuring Costs
	Total Expected to be Incurred		Recognized in Income
			Period from Inception to September 30, 2014		Three Months Ended September 30,				Nine Months Ended September 30,
					2014		2013		2014		2013
Continuing Operations:	(in millions)
QEP Energy
One-time termination benefits	$	3.3	$	3.3	$	—	$	0.1	$	—	$	0.4
Retention & relocation expense	3.7		3.7		—		0.1		—		0.3
Lease termination costs	0.6		0.6		—		—		—		—
Total restructuring costs	$	7.6	$	7.6	$	—	$	0.2	—		0.7
QEP Marketing & Other
One-time termination benefits	$	0.3	$	0.3	$	—	$	0.1	$	—	$	0.1
Total restructuring costs	$	0.3	$	0.3	$	—	$	0.1	$	—	$	0.1
Total QEP
One-time termination benefits	$	3.6	$	3.6	$	—	$	0.2	$	—	$	0.5
Retention & relocation expense	3.7		3.7		—		0.1		—		0.3
Lease termination costs	0.6		0.6		—		—		—		—
Total restructuring costs	$	7.9	$	7.9	$	—	$	0.3	$	—	$	0.8

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Operations by Line of Business (Tables)

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Summary of operating results by line of business

Operations by Line of Business

QEP’s lines of business include oil and gas exploration and production (QEP Energy); and marketing, the Haynesville Gathering System, an underground storage reservoir, and corporate (QEP Marketing & 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.

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

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	652.9		$	257.1		$	—		$	910.0
From affiliated customers	—			417.8			(417.8		)	—
Total revenues	652.9			674.9			(417.8		)	910.0
Operating expenses
Purchased gas, oil and NGL expense	32.8			668.3			(412.7		)	288.4
Lease operating expense	61.1			—			—			61.1
Gas, oil and NGL transportation and other handling costs	75.2			—			(4.1		)	71.1
Gathering and other expense	—			1.4			—			1.4
General and administrative	44.3			6.1			(1.0		)	49.4
Production and property taxes	59.3			0.1			—			59.4
Depreciation, depletion and amortization	249.0			2.4			—			251.4
Impairment and exploration expense	0.9			—			—			0.9
Total operating expenses	522.6			678.3			(417.8		)	783.1
Net (loss) gain from asset sales	(11.9		)	0.1						(11.8		)
Operating income (loss)	118.4			(3.3		)	—			115.1
Realized and unrealized gains on derivative contracts	154.1			1.6			—			155.7
Interest and other income	3.9			56.6			(56.3		)	4.2
Income from unconsolidated affiliates	0.1			—			—			0.1
Interest expense	(57.0		)	(40.8		)	56.3			(41.5		)
Income before income taxes	219.5			14.1			—			233.6
Income tax provision	(72.7		)	(7.2		)	—			(79.9		)
Income from continuing operations	146.8			6.9			—			153.7
Net income from discontinued operations, net of income tax	—			—			—			17.4
Net income attributable to QEP	$	146.8		$	6.9		$	—		$	171.1

The following table is a summary of operating results for the three months endedSeptember 30, 2013, by line of business:

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	538.5		$	181.0		$	—		$	719.5
From affiliated customers	—			265.6			(265.6		)	—
Total revenues	538.5			446.6			(265.6		)	719.5
Operating expenses
Purchased gas, oil and NGL expense	39.2			438.2			(257.9		)	219.5
Lease operating expense	43.5			—			—			43.5
Gas, oil and NGL transportation and other handling costs	65.1			—			(6.5		)	58.6
Gathering and other expense	—			2.1			—			2.1
General and administrative	33.5			8.4			(1.2		)	40.7
Production and property taxes	40.4			0.2			—			40.6
Depreciation, depletion and amortization	236.0			2.4			—			238.4
Impairment and exploration expense	5.6						—			5.6
Total operating expenses	463.3			451.3			(265.6		)	649.0
Net gain from assets sales	12.8			—			—			12.8
Operating income (loss)	88.0			(4.7		)	—			83.3
Realized and unrealized losses on derivative contracts	(25.6		)	(2.2		)	—			(27.8		)
Interest and other income	2.6			52.2			(48.7		)	6.1
Income from unconsolidated affiliates	—			—			—			—
Interest expense	(49.2		)	(40.9		)	48.7			(41.4		)
Income before income taxes	15.8			4.4			—			20.2
Income tax (provision) benefit	(6.2		)	(1.9		)	—			(8.1		)
Income from continuing operations	9.6			2.5			—			12.1
Net income from discontinued operations, net of income tax	—			—			—			25.2
Net income attributable to QEP	$	9.6		$	2.5		$	—		$	37.3

The following table is a summary of operating results for the nine months endedSeptember 30, 2014, by line of business:

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	1,953.3		$	661.4		$	—		$	2,614.7
From affiliated customers	—			1,132.9			(1,132.9		)	—
Total revenues	1,953.3			1,794.3			(1,132.9		)	2,614.7
Operating expenses
Purchased gas, oil and NGL expense	120.9			1,771.6			(1,117.0		)	775.5
Lease operating expense	177.0			—			—			177.0
Gas, oil and NGL transportation and other handling costs	211.8			—			(13.3		)	198.5
Gathering and other expense	—			4.8			—			4.8
General and administrative	132.0			17.6			(2.6		)	147.0
Production and property taxes	159.8			1.0			—			160.8
Depreciation, depletion and amortization	704.7			7.8			—			712.5
Impairment and exploration expense	8.3			—			—			8.3
Total operating expenses	1,514.5			1,802.8			(1,132.9		)	2,184.4
Net loss from asset sales	(210.3		)	—			—			(210.3		)
Operating income (loss)	228.5			(8.5		)	—			220.0
Realized and unrealized losses on derivative contracts	(9.7		)	(3.5		)	—			(13.2		)
Interest and other income	7.4			162.0			(161.6		)	7.8
Income from unconsolidated affiliates	0.2			—			—			0.2
Interest expense	(162.5		)	(127.5		)	161.6			(128.4		)
Income before income taxes	63.9			22.5			—			86.4
Income tax provision	(14.6		)	(11.5		)	—			(26.1		)
Income from continuing operations	49.3			11.0			—			60.3
Net income from discontinued operations, net of income tax	—			—			—			58.2
Net income attributable to QEP	$	49.3		$	11.0		$	—		$	118.5

The following table is a summary of operating results for the nine months endedSeptember 30, 2013, by line of business:

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	1,575.2		$	489.6		$	—		$	2,064.8
From affiliated customers	—			686.0			(686.0		)	—
Total revenues	1,575.2			1,175.6			(686.0		)	2,064.8
Operating expenses
Purchased gas, oil and NGL expense	159.8			1,150.5			(660.0		)	650.3
Lease operating expense	130.2			—			—			130.2
Gas, oil and NGL transportation and other handling costs	180.8			—			(22.3		)	158.5
Gathering and other expense	—			6.4			—			6.4
General and administrative	100.2			20.3			(3.7		)	116.8
Production and property taxes	112.7			1.0			—			113.7
Depreciation, depletion and amortization	712.1			7.2			—			719.3
Impairment and exploration expense	13.5			—			—			13.5
Total operating expenses	1,409.3			1,185.4			(686.0		)	1,908.7
Net gain from asset sales	113.4			—			—			113.4
Operating income (loss)	279.3			(9.8		)	—			269.5
Realized and unrealized gains on derivative contracts	49.6			2.0			—			51.6
Interest and other income	7.5			158.4			(143.2		)	22.7
Interest expense	(143.4		)	(124.5		)	143.2			(124.7		)
Income before income taxes	193.0			26.1			—			219.1
Income tax provision	(71.1		)	(11.4		)	—			(82.5		)
Income for continuing operations	121.9			14.7			—			136.6
Net income from discontinued operations, net of income tax	—			—			—			74.8
Net income attributable to QEP	$	121.9		$	14.7		$	—		$	211.4

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Restructuring Costs Restructuring Costs - Narrative (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014
Restructuring and Related Activities [Abstract]
Estimated restructuring costs		$ 10.3
Restructuring costs incurred from inception to reporting date		7.9
Restructuring and Related Cost, Incurred Cost	$ 2.3	$ 7.1

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Operations by Line of Business

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Operations by Line of Business

Operations by Line of Business

QEP’s lines of business include oil and gas exploration and production (QEP Energy); and marketing, the Haynesville Gathering System, an underground storage reservoir, and corporate (QEP Marketing & 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.

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

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	652.9		$	257.1		$	—		$	910.0
From affiliated customers	—			417.8			(417.8		)	—
Total revenues	652.9			674.9			(417.8		)	910.0
Operating expenses
Purchased gas, oil and NGL expense	32.8			668.3			(412.7		)	288.4
Lease operating expense	61.1			—			—			61.1
Gas, oil and NGL transportation and other handling costs	75.2			—			(4.1		)	71.1
Gathering and other expense	—			1.4			—			1.4
General and administrative	44.3			6.1			(1.0		)	49.4
Production and property taxes	59.3			0.1			—			59.4
Depreciation, depletion and amortization	249.0			2.4			—			251.4
Impairment and exploration expense	0.9			—			—			0.9
Total operating expenses	522.6			678.3			(417.8		)	783.1
Net (loss) gain from asset sales	(11.9		)	0.1						(11.8		)
Operating income (loss)	118.4			(3.3		)	—			115.1
Realized and unrealized gains on derivative contracts	154.1			1.6			—			155.7
Interest and other income	3.9			56.6			(56.3		)	4.2
Income from unconsolidated affiliates	0.1			—			—			0.1
Interest expense	(57.0		)	(40.8		)	56.3			(41.5		)
Income before income taxes	219.5			14.1			—			233.6
Income tax provision	(72.7		)	(7.2		)	—			(79.9		)
Income from continuing operations	146.8			6.9			—			153.7
Net income from discontinued operations, net of income tax	—			—			—			17.4
Net income attributable to QEP	$	146.8		$	6.9		$	—		$	171.1

The following table is a summary of operating results for the three months endedSeptember 30, 2013, by line of business:

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	538.5		$	181.0		$	—		$	719.5
From affiliated customers	—			265.6			(265.6		)	—
Total revenues	538.5			446.6			(265.6		)	719.5
Operating expenses
Purchased gas, oil and NGL expense	39.2			438.2			(257.9		)	219.5
Lease operating expense	43.5			—			—			43.5
Gas, oil and NGL transportation and other handling costs	65.1			—			(6.5		)	58.6
Gathering and other expense	—			2.1			—			2.1
General and administrative	33.5			8.4			(1.2		)	40.7
Production and property taxes	40.4			0.2			—			40.6
Depreciation, depletion and amortization	236.0			2.4			—			238.4
Impairment and exploration expense	5.6						—			5.6
Total operating expenses	463.3			451.3			(265.6		)	649.0
Net gain from assets sales	12.8			—			—			12.8
Operating income (loss)	88.0			(4.7		)	—			83.3
Realized and unrealized losses on derivative contracts	(25.6		)	(2.2		)	—			(27.8		)
Interest and other income	2.6			52.2			(48.7		)	6.1
Income from unconsolidated affiliates	—			—			—			—
Interest expense	(49.2		)	(40.9		)	48.7			(41.4		)
Income before income taxes	15.8			4.4			—			20.2
Income tax (provision) benefit	(6.2		)	(1.9		)	—			(8.1		)
Income from continuing operations	9.6			2.5			—			12.1
Net income from discontinued operations, net of income tax	—			—			—			25.2
Net income attributable to QEP	$	9.6		$	2.5		$	—		$	37.3

The following table is a summary of operating results for the nine months endedSeptember 30, 2014, by line of business:

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	1,953.3		$	661.4		$	—		$	2,614.7
From affiliated customers	—			1,132.9			(1,132.9		)	—
Total revenues	1,953.3			1,794.3			(1,132.9		)	2,614.7
Operating expenses
Purchased gas, oil and NGL expense	120.9			1,771.6			(1,117.0		)	775.5
Lease operating expense	177.0			—			—			177.0
Gas, oil and NGL transportation and other handling costs	211.8			—			(13.3		)	198.5
Gathering and other expense	—			4.8			—			4.8
General and administrative	132.0			17.6			(2.6		)	147.0
Production and property taxes	159.8			1.0			—			160.8
Depreciation, depletion and amortization	704.7			7.8			—			712.5
Impairment and exploration expense	8.3			—			—			8.3
Total operating expenses	1,514.5			1,802.8			(1,132.9		)	2,184.4
Net loss from asset sales	(210.3		)	—			—			(210.3		)
Operating income (loss)	228.5			(8.5		)	—			220.0
Realized and unrealized losses on derivative contracts	(9.7		)	(3.5		)	—			(13.2		)
Interest and other income	7.4			162.0			(161.6		)	7.8
Income from unconsolidated affiliates	0.2			—			—			0.2
Interest expense	(162.5		)	(127.5		)	161.6			(128.4		)
Income before income taxes	63.9			22.5			—			86.4
Income tax provision	(14.6		)	(11.5		)	—			(26.1		)
Income from continuing operations	49.3			11.0			—			60.3
Net income from discontinued operations, net of income tax	—			—			—			58.2
Net income attributable to QEP	$	49.3		$	11.0		$	—		$	118.5

The following table is a summary of operating results for the nine months endedSeptember 30, 2013, by line of business:

	QEP Energy			QEP Marketing  & Other			Eliminations			QEP Consolidated
	(in millions)
Revenues
From unaffiliated customers	$	1,575.2		$	489.6		$	—		$	2,064.8
From affiliated customers	—			686.0			(686.0		)	—
Total revenues	1,575.2			1,175.6			(686.0		)	2,064.8
Operating expenses
Purchased gas, oil and NGL expense	159.8			1,150.5			(660.0		)	650.3
Lease operating expense	130.2			—			—			130.2
Gas, oil and NGL transportation and other handling costs	180.8			—			(22.3		)	158.5
Gathering and other expense	—			6.4			—			6.4
General and administrative	100.2			20.3			(3.7		)	116.8
Production and property taxes	112.7			1.0			—			113.7
Depreciation, depletion and amortization	712.1			7.2			—			719.3
Impairment and exploration expense	13.5			—			—			13.5
Total operating expenses	1,409.3			1,185.4			(686.0		)	1,908.7
Net gain from asset sales	113.4			—			—			113.4
Operating income (loss)	279.3			(9.8		)	—			269.5
Realized and unrealized gains on derivative contracts	49.6			2.0			—			51.6
Interest and other income	7.5			158.4			(143.2		)	22.7
Interest expense	(143.4		)	(124.5		)	143.2			(124.7		)
Income before income taxes	193.0			26.1			—			219.1
Income tax provision	(71.1		)	(11.4		)	—			(82.5		)
Income for continuing operations	121.9			14.7			—			136.6
Net income from discontinued operations, net of income tax	—			—			—			74.8
Net income attributable to QEP	$	121.9		$	14.7		$	—		$	211.4

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Components of basic and diluted shares used in EPS

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2014	2013	2014	2013
	(in millions)
Weighted-average basic common shares outstanding	180.1	179.3	180.0	179.2
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	0.5	0.2	0.4	0.2
Average diluted common shares outstanding	180.6	179.5	180.4	179.4

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Derivative Contracts - Schedule of Derivatives Financial Statement Presentation (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	$ 49.7	$ 6.5
Derivative Liability, Fair Value, Gross Liability	9.1	32.0
Interest Rate Swap [Member] | Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	0	0
Derivative Liability, Fair Value, Gross Liability		2.6
Interest Rate Swap [Member] | Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross		0.6
Derivative Liability, Fair Value, Gross Liability	0	0
Commodity Contract [Member] | Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross		5.5
Derivative Liability, Fair Value, Gross Liability		29.4
Commodity Contract [Member] | Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross		0.4
Derivative Liability, Fair Value, Gross Liability		0
Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	49.7	6.5
Derivative Liability, Fair Value, Gross Liability	9.1	32.0
Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Swap [Member] | Short-term [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	4.3	2.6
Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Interest Rate Swap [Member] | Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	3.5	0.6
Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	36.6	5.5
Derivative Liability, Fair Value, Gross Liability	4.2	29.4
Fair Value, Inputs, Level 2 [Member] | Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member] | Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross	9.6	0.4
Derivative Liability, Fair Value, Gross Liability	$ 0.6

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Discontinued Operations - Assets and Liabilities of Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and cash equivalents	$ 0	$ 11.9	$ 123.0	$ 0
Accounts receivable, net	599.4	316.3
Deferred income taxes - current	0	27.9
Prepaid expenses and other	50.8	45.4
Current assets of discontinued operations held for sale	138.3	122.0
Midstream field services	197.5	197.3
Material and supplies	55.3	54.3
Total Property, Plant and Equipment	13,191.5	12,573.6
Midstream field services	(34.3)	(28.1)
Other noncurrent assets	39.4	46.6
Noncurrent assets of discontinued operations held for sale	1,174.2	1,167.7
Production and property taxes	73.5	49.4
Interest payable	34.1	37.2
Current liabilities of discontinued operations held for sale	161.6	75.3
Long-term debt	3,115.5	2,997.5
Deferred income taxes	1,500.8	1,364.9
Asset retirement obligations	162.3	163.3
Other long-term liabilities	90.3	94.5
Noncurrent liabilities of discontinued operations held for sale	402.0	238.3
Midstream Business Held For Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash and cash equivalents	27.1	18.1
Accounts receivable, net	71.8	53.9
Income taxes receivable	0	38.4
Deferred income taxes - current	7.0	2.7
Prepaid expenses and other	32.4	8.9
Current assets of discontinued operations held for sale	138.3	122.0
Midstream field services	1,550.5	1,500.8
Material and supplies	6.5	4.8
Total Property, Plant and Equipment	1,557.0	1,505.6
Midstream field services	(422.2)	(381.6)
Net Property, Plant and Equipment	1,134.8	1,124.0
Investment in unconsolidated affiliates	35.9	39.0
Other noncurrent assets	3.5	4.7
Noncurrent assets of discontinued operations held for sale	1,174.2	1,167.7
Accounts payable and accrued expenses	85.6	74.1
Accrued income taxes	70.2	0
Production and property taxes	5.4	1.2
Interest payable	0.4	0
Current liabilities of discontinued operations held for sale	161.6	75.3
Long-term debt	230.0	0
Deferred income taxes	126.5	195.7
Asset retirement obligations	29.9	28.5
Other long-term liabilities	15.6	14.1
Noncurrent liabilities of discontinued operations held for sale	$ 402.0	$ 238.3

XML

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current Assets
Cash and cash equivalents	$ 0	$ 11.9
Accounts receivable, net	599.4	316.3
Fair value of derivative contracts	32.6	0.2
Gas, oil and NGL inventories at lower of average cost or market	16.4	13.4
Deferred income taxes - current	0	27.9
Prepaid expenses and other	50.8	45.4
Current assets of discontinued operations held for sale	138.3	122.0
Total Current Assets	837.5	537.1
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	11,723.0	11,571.4
Unproved properties	1,120.5	665.1
Midstream	197.5	197.3
Marketing and resources	95.2	85.5
Material and supplies	55.3	54.3
Total Property, Plant and Equipment	13,191.5	12,573.6
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	4,915.0	4,930.9
Midstream	34.3	28.1
Marketing and resources	29.8	22.1
Total Accumulated Depreciation, Depletion and Amortization	4,979.1	4,981.1
Net Property, Plant and Equipment	8,212.4	7,592.5
Fair value of derivative contracts	12.7	1.0
Restricted cash	0	50.0
Other noncurrent assets	39.4	46.6
Noncurrent assets of discontinued operations held for sale	1,174.2	1,167.7
TOTAL ASSETS	10,276.2	9,394.9
Current Liabilities
Checks outstanding in excess of cash balances	36.8	109.1
Accounts payable and accrued expenses	691.4	361.9
Production and property taxes	73.5	49.4
Interest payable	34.1	37.2
Fair value of derivative contracts	4.5	26.7
Deferred income taxes	2.9	0
Current liabilities of discontinued operations held for sale	161.6	75.3
Total Current Liabilities	1,004.8	659.6
Long-term debt	3,115.5	2,997.5
Deferred income taxes	1,500.8	1,364.9
Asset retirement obligations	162.3	163.3
Fair value of derivative contracts	0.2	0
Other long-term liabilities	90.3	94.5
Noncurrent liabilities of discontinued operations held for sale	402.0	238.3
Commitments and contingencies
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 180.9 million and 179.7 million shares issued, respectively	1.8	1.8
Treasury stock - 0.8 million and 0.4 million shares, respectively	(25.1)	(14.9)
Additional paid-in capital	527.2	498.4
Retained earnings	3,025.4	2,917.8
Accumulated other comprehensive loss	(23.7)	(26.5)
Total Common Shareholders' Equity	3,505.6	3,376.6
Noncontrolling interest	494.7	500.2
Total Equity	4,000.3	3,876.8
TOTAL LIABILITIES AND EQUITY	$ 10,276.2	$ 9,394.9

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Acquisitions & Divestitures

9 Months Ended

Sep. 30, 2014

Acquisitions [Abstract]

Acquisitions [Text Block]

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, subject to post-closing purchase price adjustments (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 $114.2 million and net income of $23.1 million were generated from the acquired properties from February 25, 2014, to September 30, 2014, and are included in QEP's Condensed Consolidated Statements of Operations. During the nine months endedSeptember 30, 2014, QEP Energy incurred acquisition-related costs of $0.6 million, which are included in "General and administrative" on the Condensed Consolidated Statement of Operations for the nine months endedSeptember 30, 2014. QEP incurred $1.1 million of debt issuance costs associated with increasing the size of term loan borrowings to fund a portion of the acquisition, which are included in "Other noncurrent assets" on the Condensed Consolidated Balance Sheet as of September 30, 2014.

QEP Energy recorded the Permian Basin Acquisition on its Condensed Consolidated Balance Sheet as of September 30, 2014. The following table presents a summary of the Company's purchase accounting entries:

	As of September 30, 2014
	(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 nine months endedSeptember 30, 2014, and the three and nine months endedSeptember 30, 2013. Pro forma results are not provided for the three months ended September 30, 2014, because the Permian Basin Acquisition occurred during the first quarter of 2014, and therefore there is no pro forma impact on the third quarter of 2014. 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 and nine months ended September 30, 2014 and 2013, 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 preliminary 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				Nine Months Ended
	September 30,				September 30,
	2013		2013		2014		2014		2013		2013
	Actual		Pro forma		Actual		Pro forma		Actual		Pro forma
					(in millions, except per share data)
Revenues	$	719.5	$	776.5	$	2,614.7	$	2,640.8	$	2,064.8	$	2,195.4
Net income (loss) attributable to QEP	37.3		54.2		118.5		125.5		211.4		240.4
Earnings per common share attributable to QEP
Basic	$	0.21	$	0.30	$	0.66	$	0.70	$	1.18	$	1.34
Diluted	0.21		0.30		0.66		0.70		1.18		1.34

Divestitures

In June 2014, QEP Energy sold its interests in certain non-core properties in the Midcontinent area and other non-core assets in the Williston Basin for total cash proceeds of $702.3 million, subject to post-closing purchase price adjustments, and recorded a pre-tax loss of $210.4 million on QEP's Statements of Operations and Condensed Consolidated Statement of Operations in "Net loss from asset sales" for the nine months ended September 30, 2014. An additional $28.7 million of consideration is currently being held in escrow related to unresolved title defects.

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Employee Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Loss on curtailment					$ 2.4
Expense related to special termination benefits					0.3
Continuing Operations [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Recurring employee benefit expense	1.4		2.3		5.5		7.6
Discontinued Operations [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Recurring employee benefit expense	0.4		0.7		1.4		1.9
Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	0.6		0.7		2.0		2.6
Interest cost	1.2		1.2		4.0		3.7
Expected return on plan assets	(1.4)		(0.9)		(3.8)		(2.9)
Amortization of prior service costs	1.1	[1]	1.2	[1]	3.6	[1]	3.7	[1]
Loss on curtailment	0				2.0
Expense related to special termination benefits	0		0		0.3		0
Amortization of actuarial loss	0.2	[1]	0.5	[1]	0.6	[1]	1.7	[1]
Periodic expense	1.7		2.7		8.7		8.8
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	0		0.1		0		0.1
Interest cost	0		0		0.2		0.2
Amortization of prior service costs	0.1	[2]	0.1	[2]	0.3	[2]	0.3	[2]
Recognized net actuarial loss	0		0.1		0		0.1
Loss on curtailment	0				0.4		0
Periodic expense	0.1		0.3		0.9		0.7
Funded Pension Plan [Member] | Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to pension plan					8.1
Unfunded Pension Plan [Member] | Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to pension plan					4.4
Expected to contribute to pension plans	0.6
Other Postretirement Benefit Plans, Defined Benefit [Member] | Pension [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected to contribute to pension plans	$ 0.1

[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."

[2] Amortization of prior service costs out of AOCI are recognized in the Condensed Consolidated Statements of Operations in "General and administrative."

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2014

Asset Retirement Obligation [Abstract]

Asset retirement obligations roll forward

	Asset Retirement Obligations
	2014
	(in millions)
ARO liability at January 1, (1)	$	165.1
Accretion	4.9
Additions(2)	15.5
Revisions	(0.3		)
Liabilities settled(3)	(22.0		)
ARO liability at September 30,(4)	$	163.2

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Acquisitions & Divestitures Supplemental Proforma Results of Operations (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Business Acquisition [Line Items]
Total Revenues	$ 910.0	$ 719.5	$ 2,614.7	$ 2,064.8
Net income attributable to QEP	171.1	37.3	118.5	211.4
Earnings Per Share, Basic	$ 0.95	$ 0.21	$ 0.66	$ 1.18
Earnings Per Share, Diluted	$ 0.94	$ 0.21	$ 0.66	$ 1.18
Business Acquisition, Pro Forma Revenue		776.5	2,640.8	2,195.4
Business Acquisition, Pro Forma Net Income (Loss)		$ 54.2	$ 125.5	$ 240.4
Business Acquisition, Pro Forma Earnings Per Share, Basic		$ 0.30	$ 0.70	$ 1.34
Business Acquisition, Pro Forma Earnings Per Share, Diluted		$ 0.30	$ 0.70	$ 1.34

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Employee Benefits

9 Months Ended

Sep. 30, 2014

Compensation and Retirement Disclosure [Abstract]

Employee Benefits

Employee Benefits

The Company maintains closed, defined-benefit pension and postretirement medical plans. QEP's pension plans include a qualified and a nonqualified retirement plan. The Company's postretirement medical plan is unfunded and provides certain health care and life insurance benefits for certain retired employees. During the nine months endedSeptember 30, 2014, the Company made contributions of $8.1 million to its funded qualified pension plan and $4.4 million to its unfunded nonqualified retirement plan. Contributions to funded qualified plans increase plan assets while contributions to unfunded nonqualified plans are used to fund current benefit payments. During the remainder of 2014, the Company expects to contribute $0.6 million to its unfunded nonqualified pension plans and $0.1 million for retiree health care and life insurance benefits. No additional funding in 2014 is expected for its funded qualified pension plan. During the three and nine months ended September 30, 2014 for continuing operations, QEP recognized $1.4 million and $5.5 million, respectively, in recurring employee benefit expense compared to $2.3 million and $7.6 million, respectively, during the three and nine months ended September 30, 2013. During the three and nine months ended September 30, 2014 for discontinued operations, QEP recognized $0.4 million and $1.4 million, respectively, in recurring employee benefit expense compared to $0.7 million and $1.9 million, respectively, during the three and nine months ended September 30, 2013.

During the nine months endedSeptember 30, 2014, the Company recognized a $2.4 million expense on curtailment and a $0.3 million expense for special termination benefits in connection with the second quarter 2014 property sales in the Midcontinent area (see Note 3 - Acquisitions and Divestitures). A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for present employees' future services. These expenses are included within “Net gain (loss) from asset sales” on the Condensed Consolidated Statement of Operations for the nine months endedSeptember 30, 2014.

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

	Pension
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
	(in millions)
Service cost	$	0.6		$	0.7		$	2.0		$	2.6
Interest cost	1.2			1.2			4.0			3.7
Expected return on plan assets	(1.4		)	(0.9		)	(3.8		)	(2.9		)
Amortization of prior service costs (1)	1.1			1.2			3.6			3.7
Amortization of actuarial losses (1)	0.2			0.5			0.6			1.7
Curtailment cost	—			—			2.0			—
Special termination benefits	—			—			0.3			—
Periodic expense	$	1.7		$	2.7		$	8.7		$	8.8

____________________________

⁽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				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
	(in millions)
Service cost	$	—	$	0.1	$	—	$	0.1
Interest cost	—		—		0.2		0.2
Amortization of prior service costs (1)	0.1		0.1		0.3		0.3
Recognized net actuarial loss	—		0.1		—		0.1
Curtailment cost	—				0.4		—
Periodic expense	$	0.1	$	0.3	$	0.9	$	0.7

____________________________

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