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, 2015

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

For the transition period from ______ to ______

Commission File Number: 001-34778

QEP RESOURCES, INC.

(Exact name of registrant as specified in its charter)

STATE OF DELAWARE	87-0287750
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)

1050 17^th Street, Suite 800, Denver, Colorado 80265

(Address of principal executive offices)

Registrant’s telephone number, including area code (303) 672-6900

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer	ý	Accelerated filer	o
Non-accelerated filer	o (Do not check if a smaller reporting company)	Smaller reporting company	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý

At September 30, 2015, there were 176,736,956 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

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

TABLE OF CONTENTS

			Page
PART I. FINANCIAL INFORMATION			2
	ITEM 1.	FINANCIAL STATEMENTS	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014	2
		UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014	3
		UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS AT SEPTEMBER 30, 2015, AND DECEMBER 31, 2014	4
		UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2015 AND 2014	5
		UNAUDITED NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	6
	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	25
	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	45
	ITEM 4.	CONTROLS AND PROCEDURES	50
PART II. OTHER INFORMATION			50
	ITEM 1.	LEGAL PROCEEDINGS	50
	ITEM 1A.	RISK FACTORS	50
	ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	54
	ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	54
	ITEM 4.	MINE SAFETY DISCLOSURES	54
	ITEM 5.	OTHER INFORMATION	54
	ITEM 6.	EXHIBITS	55
SIGNATURES			56

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,
	2015			2014			2015			2014
REVENUES	(in millions, except per share amounts)
Gas sales	$	129.4		$	171.6		$	363.3		$	609.2
Oil sales	211.7			393.5			640.9			1,041.0
NGL sales	16.5			51.1			61.7			179.3
Other revenue	2.8			3.4			12.4			5.1
Purchased gas and oil sales	176.3			290.4			558.6			780.1
Total Revenues	536.7			910.0			1,636.9			2,614.7
OPERATING EXPENSES
Purchased gas and oil expense	175.1			288.4			561.7			775.5
Lease operating expense	56.7			61.1			175.6			177.0
Gas, oil and NGL transportation and other handling costs	78.1			71.1			216.2			198.5
Gathering and other expense	1.3			1.4			4.4			4.8
General and administrative	42.0			49.4			140.7			147.0
Production and property taxes	30.2			59.4			90.7			160.8
Depreciation, depletion and amortization	238.1			251.4			649.3			712.5
Exploration expenses	0.8			0.8			2.7			4.7
Impairment	15.0			0.1			35.5			3.6
Total Operating Expenses	637.3			783.1			1,876.8			2,184.4
Net gain (loss) from asset sales	12.9			(11.8		)	6.9			(210.3		)
OPERATING INCOME (LOSS)	(87.7		)	115.1			(233.0		)	220.0
Realized and unrealized gains (losses) on derivative contracts (Note 8)	153.6			155.7			168.5			(13.2		)
Interest and other income	0.3			4.2			1.5			7.8
Income from unconsolidated affiliates	—			0.1			—			0.2
Interest expense	(36.4		)	(41.5		)	(109.4		)	(128.4		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	29.8			233.6			(172.4		)	86.4
Income tax (provision) benefit	(8.7		)	(79.9		)	61.6			(26.1		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	21.1			153.7			(110.8		)	60.3
Net income from discontinued operations, net of income tax	—			17.4			—			58.2
NET INCOME (LOSS)	$	21.1		$	171.1		$	(110.8	)	$	118.5
Earnings (Loss) Per Common Share
Basic from continuing operations	$	0.12		$	0.85		$	(0.63	)	$	0.34
Basic from discontinued operations	—			0.10			—			0.32
Basic total	$	0.12		$	0.95		$	(0.63	)	$	0.66
Diluted from continuing operations	$	0.12		$	0.84		$	(0.63	)	$	0.34
Diluted from discontinued operations	—			0.10			—			0.32
Diluted total	$	0.12		$	0.94		$	(0.63	)	$	0.66
Weighted-average common shares outstanding
Used in basic calculation	176.7			180.1			176.5			180.0
Used in diluted calculation	176.7			180.6			176.5			180.4
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,
	2015		2014		2015			2014
	(in millions)
Net income (loss)	$	21.1	$	171.1	$	(110.8	)	$	118.5
Other comprehensive income, net of tax:
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss (1)	—		0.2		0.2			0.4
Amortization of prior service cost (2)	0.3		0.7		0.9			2.4
Other comprehensive income	0.3		0.9		1.1			2.8
Comprehensive income (loss)	$	21.4	$	172.0	$	(109.7	)	$	121.3

____________________________

⁽¹⁾  Presented net of income tax expense of $0.2 million during the nine months endedSeptember 30, 2015, and $0.2 million during the nine months endedSeptember 30, 2014.

⁽²⁾  Presented net of income tax expense of $0.1 million and $0.5 million during the three and nine months endedSeptember 30, 2015, respectively, and $0.5 million and $1.5 million during the three and nine months endedSeptember 30, 2014, respectively.

See Notes accompanying the Condensed Consolidated Financial Statements.

3

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2015			December 31, 2014
ASSETS	(in millions)
Current Assets
Cash and cash equivalents	$	495.8		$	1,160.1
Accounts receivable, net	316.2			441.9
Fair value of derivative contracts	183.9			339.0
Gas, oil and NGL inventories, at lower of average cost or market	12.2			13.7
Prepaid expenses and other	32.4			46.8
Total Current Assets	1,040.5			2,001.5
Property, Plant and Equipment (successful efforts method for oil and gas properties)
Proved properties	12,911.5			12,278.7
Unproved properties	839.5			825.2
Marketing and other	298.0			293.8
Material and supplies	35.9			54.3
Total Property, Plant and Equipment	14,084.9			13,452.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,653.7			6,153.0
Marketing and other	82.7			67.8
Total Accumulated Depreciation, Depletion and Amortization	6,736.4			6,220.8
Net Property, Plant and Equipment	7,348.5			7,231.2
Fair value of derivative contracts	17.0			9.9
Other noncurrent assets	50.1			44.2
TOTAL ASSETS	$	8,456.1		$	9,286.8
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	12.8		$	54.7
Accounts payable and accrued expenses	409.2			575.4
Income taxes payable	—			532.1
Production and property taxes	58.8			61.7
Interest payable	33.7			36.4
Deferred income taxes	47.4			84.5
Current portion of long-term debt	176.7			—
Total Current Liabilities	738.6			1,344.8
Long-term debt	2,041.8			2,218.1
Deferred income taxes	1,423.2			1,362.7
Asset retirement obligations	187.7			193.8
Other long-term liabilities	92.7			92.1
Commitments and contingencies (Note 11)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized;  177.1 million and 176.2 million shares issued, respectively	1.8			1.8
Treasury stock - 0.4 million and 0.8 million shares, respectively	(10.0		)	(25.4		)
Additional paid-in capital	544.1			535.3
Retained earnings	3,459.3			3,587.9
Accumulated other comprehensive income (loss)	(23.1		)	(24.3		)
Total Common Shareholders' Equity	3,972.1			4,075.3
TOTAL LIABILITIES AND EQUITY	$	8,456.1		$	9,286.8

See Notes accompanying the Condensed Consolidated Financial Statements.

4

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended
	September 30,
	2015			2014
	(in millions)
OPERATING ACTIVITIES
Net income (loss)	$	(110.8	)	$	118.5
Net income attributable to noncontrolling interest	—			17.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	649.3			755.8
Deferred income taxes	22.7			91.5
Impairment	35.5			3.6
Share-based compensation	23.3			23.7
Pension curtailment loss	11.2			—
Amortization of debt issuance costs and discounts	4.7			5.1
Net (gain) loss from asset sales	(6.9		)	210.3
Income from unconsolidated affiliates	—			(4.6		)
Distributions from unconsolidated affiliates and other	—			5.1
Unrealized (gains) losses on derivative contracts	148.0			(65.9		)
Changes in operating assets and liabilities	(503.1		)	59.0
Net Cash Provided by Operating Activities	273.9			1,219.7
INVESTING ACTIVITIES
Property acquisitions	(23.5		)	(949.7		)
Property, plant and equipment, including dry exploratory well expense	(862.6		)	(1,270.4		)
Proceeds from disposition of assets	5.2			706.2
Acquisition deposit held in escrow	—			50.0
Other investing activities	—			3.2
Net Cash Used in Investing Activities	(880.9		)	(1,460.7		)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(41.9		)	(81.1		)
Long-term debt issued	—			300.0
Long-term debt issuance costs paid	—			(1.1		)
Proceeds from credit facility	—			4,509.0
Repayments of credit facility	—			(4,461.5		)
Treasury stock repurchases	(2.3		)	(6.6		)
Other capital contributions	(0.1		)	5.1
Dividends paid	(10.6		)	(10.8		)
Excess tax (provision) benefit on share-based compensation	(2.4		)	(0.6		)
Distribution to noncontrolling interest	—			(23.3		)
Net Cash (Used in) Provided by Financing Activities	(57.3		)	229.1
Change in cash and cash equivalents	(664.3		)	(11.9		)
Beginning cash and cash equivalents	1,160.1			11.9
Ending cash and cash equivalents	$	495.8		$	—
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	$	107.4		$	128.9
Cash paid for income taxes	492.3			(1.1		)
Non-cash investing activities:
Change in capital expenditure accrual balance	$	(68.9	)	$	66.5

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

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

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

Note 2 – Basis of Presentation of Interim Consolidated Financial Statements

The interim Condensed Consolidated Financial Statements contain the accounts of QEP and its majority-owned or controlled subsidiaries. The Condensed Consolidated Financial Statements were prepared in accordance with United States Generally Accepted Accounting Principles (GAAP) and with the instructions for Quarterly Reports on Form 10-Q and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.

The Condensed Consolidated Financial Statements reflect all normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair statement of financial position and results of operations for the interim periods presented. Interim condensed consolidated financial statements and the year-end balance sheet do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2014.

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

Impairment of Long-Lived Assets

During the three months endedSeptember 30, 2015, QEP Energy recorded impairment charges of $15.0 million, of which $14.4 million was related to proved properties due to lower future oil and gas prices and $0.6 million was related to expiring leaseholds on unproved properties. Of the $14.4 million impairment on proved properties, $13.1 million related to impairments on Other Northern properties, $1.0 million related to impairments on QEP's remaining Midcontinent properties and $0.3 million related to impairments on Permian Basin properties.

During the nine months endedSeptember 30, 2015, QEP Energy recorded impairment charges of $35.5 million, of which $33.8 million was related to proved properties due to lower future oil and gas prices and $1.7 million was related to expiring leaseholds on unproved properties. Of the $33.8 million impairment on proved properties, $18.0 million related to impairments on Other Northern properties, $15.5 million related to impairments on QEP's remaining Midcontinent properties and $0.3 million related to impairments on Permian Basin properties.

Uncertain Tax Position

As of September 30, 2015, QEP had $15.6 million of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which were recorded within "Deferred income taxes" on the Condensed Consolidated Balance Sheet. At December 31, 2014, no uncertain tax positions had been recorded. The uncertain tax positions the Company reported during the third quarter 2015 were expensed during the year ended December 31, 2014. The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authorities. During the nine months ended

6

September 30, 2015, the Company incurred $0.3 million of interest expense related to uncertain tax positions, which was recorded within "Interest expense" on the Condensed Consolidated Statement of Operations.

New Accounting Pronouncements

In September 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) No. 2015-16,Business Combinations (Topic 805),which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not expect that there will be a significant impact on the Company's Consolidated Financial Statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In July 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606), in which the FASB delayed the effective date of the new revenue standard by one year and the amendments are now effective prospectively for reporting periods beginning after December 15, 2017, and early adoption is not permitted. The Company is currently assessing the impact on the Company's Consolidated Financial Statements.

In May 2015, the FASB issued ASU No. 2015-07,Fair Value Measurement (Topic 820), which allows reporting entities to exclude investments measured at net asset value per share under the existing practical expedient in ASC 820 from the fair value hierarchy. It also limits disclosures to investments for which the entity has elected to measure the fair value using the practical expedient. The amendment will be effective retrospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not expect that there will be a significant impact on the Company's Consolidated Financial Statements.

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

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

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

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

Note 3 – Acquisitions and Divestitures

Permian Basin Acquisition

On February 25, 2014, QEP Energy acquired oil and gas properties in the Permian Basin of Texas for an aggregate purchase price of $941.8 million (the Permian Basin Acquisition). The acquired properties consisted of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 270 vertical producing wells in the Permian Basin, which created a new core area of operation for QEP Energy.

The 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 $41.0 million and $110.6 million and a net loss of $1.9 million and $1.0 million were generated from the acquired properties during the three and nine months endedSeptember 30, 2015, respectively. 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.

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

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

The following unaudited, pro forma results of operations are provided for the nine months endedSeptember 30, 2014. Pro forma results are not provided for the three months endedSeptember 30, 2014, or the three and nine months endedSeptember 30, 2015, because the Permian Basin Acquisition occurred during the first quarter of 2014, and therefore the Permian Basin results are included in QEP's results for these periods. These supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the period presented, or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the nine months endedSeptember 30, 2014, the acquired properties' historical results of operations, and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.

		Nine Months Ended
		September 30, 2014
		Actual		Pro forma
	(in millions, except per share data)
Revenues		$	2,614.7	$	2,640.8
Net income		$	118.5	$	125.5
Earnings per common share
Basic		$	0.66	$	0.70
Diluted		$	0.66	$	0.70

7

Divestitures

In December 2014, QEP Energy sold its interest in certain non-core properties in southern Oklahoma for aggregate proceeds of $101.3 million. For the year ended December 31, 2014, QEP Energy recorded a pre-tax gain on sale of $53.3 million. QEP recorded a pre-tax gain on sale of $8.8 million and $5.9 million for the three and nine months endedSeptember 30, 2015, respectively, due to post-closing purchase price adjustments.

In June 2014, QEP Energy sold its interest in certain non-core properties in the Midcontinent area and other non-core assets in the Williston Basin for aggregate proceeds of $675.6 million. QEP recorded a pre-tax loss of $199.4 million for the year ended December 31, 2014. QEP recorded a pre-tax gain on sale of $4.6 million and a pre-tax loss on sale of $21.8 million for the three and nine months endedSeptember 30, 2015, respectively, due to post-closing purchase price adjustments. These gains and losses are reported on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales".

Note 4 – Discontinued Operations

On December 2, 2014, the Company closed on the sale of substantially all of its midstream business, including its ownership interest in QEP Midstream Partners, LP (QEP Midstream) to Tesoro Logistics LP (Tesoro) for total cash proceeds of approximately $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, subject to post-closing adjustments, and QEP recorded a pre-tax gain of approximately $1.8 billion for the year ended December 31, 2014 (Midstream Sale).

The operating results of QEP Field Services Company (QEP Field Services), excluding the Haynesville gathering system (the Discontinued Operations of QEP Field Services), have been classified as discontinued operations on the Condensed Consolidated Statements of Operations and Notes accompanying the Condensed Consolidated Financial Statements for the three and nine months endedSeptember 30, 2014. QEP will have continuing cash outflows to the entities sold as a part of the Midstream Sale for gathering, processing and water handling costs in Pinedale, the Uinta Basin and a portion of its Williston Basin operations. The contracts related to these cash flows vary in length from month-to-month to over a year and will be reviewed periodically in the normal course of business. Historically, these transactions were eliminated in consolidation, as they represented transactions between two related entities but are now reflected as part of the continuing operations for QEP. For the three months endedSeptember 30, 2015 and 2014, cash outflows for these transactions included in continuing operations were $24.9 million and $31.4 million, respectively. For the nine months endedSeptember 30, 2015 and 2014, cash outflows for these transactions included in continuing operations were $94.2 million and $105.4 million, respectively.

In 2013, in connection with QEP's plan to separate its midstream business, the Board of Directors approved an employee retention plan to provide substantially all QEP Field Services' employees as of December 1, 2013, with a one-time lump-sum cash payment on the earlier of December 31, 2014, or whenever the separation of QEP Field Services occurred, conditioned on continued employment with QEP Field Services or a successor through the payment date unless the employee is terminated prior to such date. QEP recognized $10.4 million of costs under this retention plan in 2014, of which $2.3 million and $7.1 million was included within "Discontinued operations, net of income tax" on the Condensed Consolidated Statements of Operations for the three and nine months endedSeptember 30, 2014, respectively.

8

Condensed Consolidated Statement of Operations

The Discontinued Operations of QEP Field Services are summarized below:

	Three Months Ended			Nine Months Ended
	September 30, 2014
	(in millions)
REVENUES
NGL sales	$	28.8		$	94.6
Other revenue	43.1			119.9
Purchased gas and oil sales(1)	(11.9		)	(38.5		)
Total Revenues	60.0			176.0
OPERATING EXPENSES
Purchased gas and oil expense(1)	(12.4		)	(39.5		)
Lease operating expense(1)	(1.7		)	(4.8		)
Natural gas, oil and NGL transport and other handling costs(1)	(10.6		)	(40.1		)
Gathering, processing, and other	22.7			69.8
General and administrative	11.1			34.3
Production and property taxes	2.1			6.1
Depreciation, depletion and amortization	14.3			43.1
Total Operating Expenses	25.5			68.9
Net loss from asset sales	—			(0.1		)
OPERATING INCOME	34.5			107.0
Income from unconsolidated affiliates	1.1			4.4
Interest expense	(1.5		)	(2.8		)
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES (2)	34.1			108.6
Income tax provision	(9.9		)	(32.8		)
NET INCOME FROM DISCONTINUED OPERATIONS	24.2			75.8
Net income attributable to noncontrolling interest	(6.8		)	(17.6		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	17.4		$	58.2

⁽¹⁾  Includes discontinued intercompany eliminations.

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

Condensed Consolidated Statement of Cash Flows

The impact of the Discontinued Operations of QEP Field Services on the Condensed Consolidated Statement of Cash Flows for "Depreciation, depletion and amortization" contained in "Cash flows from operating activities" was $43.1 million for the nine months endedSeptember 30, 2014. 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 for the nine months endedSeptember 30, 2014.

Note 5 – Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP’s unvested restricted shares are included in weighted-average basic common shares outstanding because once the shares are granted, the restricted shares are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted shares receive dividends.

Unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are considered participating securities and are included in the computation of earnings per share pursuant to the two-class method. The

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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, 2015 and 2014, there were no anti-dilutive shares.

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2015	2014	2015	2014
	(in millions)
Weighted-average basic common shares outstanding	176.7	180.1	176.5	180.0
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	—	0.5	—	0.4
Average diluted common shares outstanding	176.7	180.6	176.5	180.4

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 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 $188.5 million and $195.1 million ARO liability for the periods ended September 30, 2015 and December 31, 2014, $0.8 million and $1.3 million were included, respectively, as a current liability within "Accounts payable and accrued expenses" on the Condensed Consolidated Balance Sheets.

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

	Asset Retirement Obligations
	2015
	(in millions)
ARO liability at January 1,	$	195.1
Accretion	6.4
Additions	3.0
Revisions	0.3
Liabilities related to divestitures	(14.8		)
Liabilities settled	(1.5		)
ARO liability at September 30,	$	188.5

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.

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The fair value of financial assets and liabilities at September 30, 2015 and December 31, 2014, is shown in the table below:

	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
	September 30, 2015
Financial Assets
Commodity derivative instruments - short-term	$	—	$	186.4	$	—	$	(2.5	)	$	183.9
Commodity derivative instruments - long-term	—		17.0		—		—			17.0
Total financial assets	$	—	$	203.4	$	—	$	(2.5	)	$	200.9
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	2.5	$	—	$	(2.5	)	$	—
Commodity derivative instruments - long-term	—		—		—		—			—
Total financial liabilities	$	—	$	2.5	$	—	$	(2.5	)	$	—
	December 31, 2014
Financial Assets
Commodity derivative instruments - short-term	$	—	$	339.3	$	—	$	(0.3	)	$	339.0
Commodity derivative instruments - long-term	—		9.9		—		—			9.9
Total financial assets	$	—	$	349.2	$	—	$	(0.3	)	$	348.9
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	0.3	$	—	$	(0.3	)	$	—
Total financial liabilities	$	—	$	0.3	$	—	$	(0.3	)	$	—

_______________________

⁽¹⁾  The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Condensed Consolidated Balance Sheets, as the contracts contain netting provisions. Refer to Note 8 – Derivative Contracts, for additional information regarding the Company's derivative contracts.

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

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	September 30, 2015				December 31, 2014
	(in millions)
Financial assets
Cash and cash equivalents	$	495.8	$	495.8	$	1,160.1	$	1,160.1
Financial liabilities
Checks outstanding in excess of cash balances	$	12.8	$	12.8	$	54.7	$	54.7
Long-term debt	$	2,218.5	$	1,965.5	$	2,218.1	$	2,171.6

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

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The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of the Company’s ARO is presented in Note 6 – Asset Retirement Obligations.

Note 8 – Derivative Contracts

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

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

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

During 2014, QEP also used interest rate swaps to mitigate a portion of its exposure to interest rate volatility associated with its $600.0 million term loan. These interest rate swaps were terminated and settled in December 2014 in conjunction with the extinguishment of QEP's term loan.

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QEP Energy Derivative Contracts

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

Year	Index	Total Volumes	Average Swap price per unit
		(in millions)
Gas sales		(MMBtu)	($/MMBtu)
2015	NYMEX HH	17.5	$	3.48
2015	IFNPCR	12.0	$	3.55
2016	NYMEX HH	22.0	$	3.19
2016	IFNPCR	32.9	$	2.92
2017	NYMEX HH	7.3	$	3.21
Oil sales		(bbls)	($/bbl)
2015	NYMEX WTI	2.6	$	82.09
2015	ICE Brent	0.1	$	104.95
2016	NYMEX WTI	3.3	$	65.43

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

		Total Volume	Average Price		Average Price
Year	Index		Floor		Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2016	NYMEX HH	7.3	$	2.75	$	3.89

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

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

Year	Index Less Differential	Index	Total Volumes	Weighted Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2015	NYMEX HH	IFNPCR	11.0	$	(0.28	)
2016	NYMEX HH	IFNPCR	7.3	$	(0.20	)

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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, 2015:

Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2015	SWAP	IFNPCR	2.4	$	3.25
2016	SWAP	IFNPCR	2.9	$	3.06
Gas purchases			(MMBtu)
2015	SWAP	IFNPCR	1.2	$	2.75

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, 2015		December 31, 2014		September 30, 2015		December 31, 2014
		(in millions)
Current:
Commodity	Fair value of derivative contracts	$	186.4	$	339.3	$	2.5	$	0.3
Long-term:
Commodity	Fair value of derivative contracts	17.0		9.9		—		—
Total derivative instruments		$	203.4	$	349.2	$	2.5	$	0.3

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

	Three Months Ended						Nine Months Ended
Derivative instruments not designated as cash flow hedges	September 30,						September 30,
	2015			2014			2015			2014
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	23.1		$	5.5		$	69.1		$	(23.3	)
Oil derivative contracts	96.8			(12.2		)	245.3			(50.2		)
QEP Marketing
Gas derivative contracts	(0.1		)	(0.4		)	2.1			(2.4		)
Total realized gains (losses) on commodity derivative contracts	119.8			(7.1		)	316.5			(75.9		)
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	3.6			27.6			(19.5		)	9.5
Oil derivative contracts	28.8			133.2			(128.0		)	54.3
QEP Marketing
Gas derivative contracts	1.4			0.7			(0.5		)	1.0
Total unrealized gains (losses) on commodity derivative contracts	33.8			161.5			(148.0		)	64.8
Total realized and unrealized gains (losses) on commodity derivative contracts	$	153.6		$	154.4		$	168.5		$	(11.1	)
Realized gains (losses) on interest rate swaps
Realized gains (losses) on interest rate swaps	$	—		$	(1.3	)	$	—		$	(3.2	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	—			2.6			—			1.1
Total realized gains (losses) on interest rate swaps	$	—		$	1.3		$	—		$	(2.1	)
Total net realized gains (losses) on derivative contracts	$	119.8		$	(8.4	)	$	316.5		$	(79.1	)
Total net unrealized gains (losses) on derivative contracts	33.8			164.1			(148.0		)	65.9
Grand Total	$	153.6		$	155.7		$	168.5		$	(13.2	)

Note 9 – Restructuring Costs

In the third quarter of 2015, QEP announced the closure of its regional office in Tulsa, Oklahoma. As a part of this reorganization, QEP will incur costs associated with termination benefits, relocation of certain employees, exit costs associated with the possible termination of the operating lease for the Tulsa office space and other expenses. QEP also incurred restructuring costs in the first quarter of 2015 as a result of work force reductions unrelated to the closure of its Tulsa office.

QEP anticipates total restructuring costs to be approximately $8.0 million to $12.0 million, of which approximately $5.3 million to $9.3 million is related to the closure of the Tulsa office and $2.7 million for work force reductions unrelated to the closure of the Tulsa office. Approximately $5.5 million is related to termination benefits, approximately $2.8 million is related to relocation of certain employees, and the remaining $3.9 million is related to the possible termination of the operating lease for the Tulsa office space. During the three months endedSeptember 30, 2015, restructuring costs of $3.5 million were incurred related to the Tulsa office closure, of which $2.8 million were termination costs and $0.7 million were relocation costs. During the nine months endedSeptember 30, 2015, restructuring costs of $6.2 million were incurred, of which $2.7 million were termination costs in the first quarter unrelated to the Tulsa office closure, and $2.8 million and $0.7 million of termination and relocation costs, respectively, were incurred in the third quarter related to the Tulsa office closure. All of the costs will be incurred by QEP Energy and are reported within QEP Energy's financial statements. These restructuring costs were recorded

15

within "General and administrative" expense of the Condensed Consolidated Statement of Operations. The Company estimates that the remaining restructuring costs will be incurred during the remainder of 2015 and in 2016.

The following table is a reconciliation of QEP's restructuring liability, which is included within "Accounts payable and accrued expenses" on the Condensed Consolidated Balance Sheets.

	Restructuring liability
	(in millions)
Balance at December 31, 2014	$	—
Costs incurred and charged to expense	6.2
Costs paid or otherwise settled	(3.8		)
Balance at September 30, 2015	$	2.4

Note 10 – Debt

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

	September 30, 2015			December 31, 2014
	(in millions)
Revolving Credit Facility due 2019	$	—		$	—
6.05% Senior Notes due 2016	176.8			176.8
6.80% Senior Notes due 2018	134.0			134.0
6.80% Senior Notes due 2020	136.0			136.0
6.875% Senior Notes due 2021	625.0			625.0
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
Less: unamortized discount	(3.3		)	(3.7		)
Total principal amount of debt (including current portion)	2,218.5			2,218.1
Less: current portion of long-term debt	(176.7		)	—
Total long-term debt outstanding	$	2,041.8		$	2,218.1

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

Credit Facility

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

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

During the nine months endedSeptember 30, 2014, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.22%. At September 30, 2015 and December 31, 2014, QEP had no borrowings outstanding under the credit facility, had $3.7 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.

Senior Notes

At September 30, 2015, the Company had $2,221.8 million principal amount of senior notes outstanding with maturities ranging from September 2016 to May 2023 and coupons ranging from 5.25% to 6.875%. The senior notes pay interest semi-annually, are unsecured senior obligations and rank equally with all of our other existing and future unsecured and senior

16

obligations. QEP may redeem all of its senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing QEP’s senior notes contain customary events of default and covenants that may limit QEP’s ability to, among other things, place liens on its property or assets.

Note 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 material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable, and unfavorable resolutions can occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, QEP may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, the ongoing discovery and/or development of information important to the matter. Except for the Rocky Mountain Resources Lawsuit (discussed below), QEP is unable to estimate reasonably possible losses (in excess of recorded accruals, if any) for its material loss contingencies for the reasons set forth above. QEP believes, however, that the resolution of pending proceedings (after accruals, insurance coverage, and indemnification arrangements) will not be material to QEP's financial position but could be material to results of operations in a particular quarter or year.

Litigation

Rocky Mountain Resources Lawsuit - Rocky Mountain Resources, LLC (Rocky Mountain) filed its complaint in March 2011, seeking determination of the existence of a 4% overriding royalty interest in an oil and gas lease. Rocky Mountain alleges that the defendants have failed to pay Rocky Mountain monies associated with the claimed 4% overriding royalty interest since the issuance of the lease by the State of Wyoming in 1980. In February 2015, a jury rendered a verdict against QEP and awarded Rocky Mountain damages in the amount of $16.7 million, including interest. QEP is appealing the verdict to the Wyoming Supreme Court, and, in connection with such appeal, has posted a bond for approximately $20.0 million (representing the amount of the verdict and two years of accrued interest at the statutory rate of 10%). QEP estimates that, notwithstanding the verdict, the range of reasonably possible losses is still zero to approximately $20.0 million.

Yannick Gagné Lawsuit and Related Suits - 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 rail company that transported the crude oil filed for bankruptcy protection following the accident. 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 allege that QEP and the producer defendants, among other things, failed to ensure that the oil was adequately processed to remove volatile gases and vapors, failed to take reasonable care to ensure that the oil was properly labeled and shipped and failed to identify the risk of the train derailment and take action to prevent it. The plaintiffs seek unspecified damages. A court order regarding class certification is pending. Many of the defendants, including QEP, have reached a confidential settlement agreement with trustees in both Canadian and U.S. bankruptcy courts to resolve all of these claims, which is subject to the approval of such courts. During the third quarter of 2015, QEP was served with additional complaints in state and federal courts in Maine, Texas and Illinois, each of which makes similar claims to those in the Yannick Gagné case, and plaintiff's in each matter support the current settlement plans. If the courts approve the current settlement plan, the plan will settle these additional cases.

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Note 12 – Share-Based Compensation

QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and awards performance share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP recognizes expense over the vesting periods for the stock options, restricted shares, and performance share units. There were 9.1 million shares available for future grants under the LTSIP at September 30, 2015. Share-based compensation expense related to continuing operations is recognized within “General and administrative” expense 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 within "Net income from discontinued operations, net of income tax" on the Condensed Consolidated Statement of Operations. During the three and nine months endedSeptember 30, 2015, QEP recognized $7.7 million and $23.3 million, respectively, in total compensation expense related to share-based compensation for continuing operations, compared to $8.1 million and $20.4 million, respectively, during the three and nine months endedSeptember 30, 2014. In addition, during the three and nine months endedSeptember 30, 2014, QEP recognized $1.0 million and $3.3 million, respectively, in total compensation expense related to share-based compensation for discontinued operations.

Stock Options

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

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

	Stock Option Assumptions
Weighted-average grant date fair value of awards granted during the period	$	6.82
Weighted-average risk-free interest rate	1.38		%
Weighted-average expected price volatility	36.8		%
Expected dividend yield	0.37		%
Expected term in years at the date of grant	4.5

Stock option transactions under the terms of the LTSIP are summarized below:

	Options Outstanding		Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
			(per share)		(in years)	(in millions)
Outstanding at December 31, 2014	1,996,215		$	28.60
Granted	425,877		21.69
Exercised	(15,000	)	19.37
Forfeited	(2,817	)	31.31
Canceled	(60,000	)	27.84
Outstanding at September 30, 2015	2,344,275		$	27.42	3.24	$	—
Options Exercisable at September 30, 2015	1,665,825		$	28.32	2.16	$	—
Unvested Options at September 30, 2015	678,450		$	25.20	5.88	$	—

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.1 million and $0.6 million during the nine months endedSeptember 30, 2015 and 2014, respectively. As of September 30, 2015, $2.6 million of unrecognized compensation cost related to stock options granted under the LTSIP, which is

18

included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheet, is expected to be recognized over a weighted-average period of 2.14 years.

Restricted Shares

Restricted share grants typically vest in equal installments over a three-year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The total fair value of restricted stock that vested during the nine months endedSeptember 30, 2015 and 2014, was $21.0 million and $20.2 million, respectively. The weighted-average grant date fair value of restricted stock was $21.02 per share and $31.82 per share for the nine months endedSeptember 30, 2015 and 2014, respectively. As of September 30, 2015, $27.5 million of unrecognized compensation cost related to restricted shares granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheet, is expected to be recognized over a weighted-average vesting period of 2.24 years.

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

	Restricted Shares Outstanding		Weighted- Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2014	1,426,453		$	31.02
Granted	1,484,567		21.02
Vested	(683,562	)	30.67
Forfeited	(93,425	)	27.20
Unvested balance at September 30, 2015	2,134,033		$	24.35

Performance Share Units

The performance share units' cash payouts are dependent upon the Company’s total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units but have historically been delivered in cash. Beginning with awards granted in 2015, the Company has the option to settle earned awards in cash or shares of common stock under the Company's LTSIP; however, as of September 30, 2015, the Company expects to settle all awards in cash. The weighted-average grant date fair value of the performance share units was $21.69 per share and $31.71 per share for the nine months endedSeptember 30, 2015 and 2014, respectively. As of September 30, 2015, $2.7 million of unrecognized compensation cost, which is included within "Other long-term liabilities" on the Condensed Consolidated Balance Sheet and represents the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 1.90 years.

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

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

____________________________

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

Note 13 – Employee Benefits

Pension and other postretirement benefits

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

The Pension Plan is a closed, qualified defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. During the nine months endedSeptember 30, 2015, the Company made contributions of $2.0 million to the Pension Plan and expects to contribute $2.0 million to the Pension Plan during the remainder of 2015. Contributions to the Pension Plan increase plan assets.

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

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. During the nine months endedSeptember 30, 2015, the Company made contributions of $2.9 million to its SERP and expects to contribute an additional $1.5 million to its SERP during the remainder of 2015. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and will be closed to new participants effective January 1, 2016.

The Medical Plan is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired employees. During the nine months endedSeptember 30, 2015, the Company made contributions of $0.4 million to its Medical Plan and expects to contribute an additional $0.1 million to its Medical Plan during the remainder of 2015. Contributions to the Medical Plan are used to fund current benefit payments.

19

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.5		$	0.6		$	1.5		$	2.0
Interest cost	1.3			1.2			3.7			4.0
Expected return on plan assets	(1.5		)	(1.4		)	(4.3		)	(3.8		)
Amortization of prior service costs (1)	0.4			1.1			1.3			3.6
Amortization of actuarial losses (1)	0.1			0.2			0.4			0.6
Curtailment loss (2)	—			—			11.2			2.0
Special termination benefits (3)	—			—			—			0.3
Periodic expense	$	0.8		$	1.7		$	13.8		$	8.7
Medical Plan benefits
Interest cost	$	0.1		$	—		$	0.2		$	0.2
Amortization of prior service costs (1)	—			0.1			0.1			0.3
Curtailment loss (2)	—			—			—			0.4
Periodic expense	$	0.1		$	0.1		$	0.3		$	0.9

____________________________

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

⁽²⁾  A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. For the nine months endedSeptember 30, 2015, these expenses are included on the Condensed Consolidated Statements of Operations within "General and administrative" expense as the expenses incurred in that period related to the Pension Plan amendment (see above). For the nine months endedSeptember 30, 2014, these expenses are included within "Net gain (loss) from asset sales" as the expenses incurred in that period related to the Midcontinent property sales (see Note 3 – Acquisitions and Divestitures).

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

During the three and nine months endedSeptember 30, 2015, for continuing operations, QEP recognized $0.9 million and $14.1 million, respectively, in employee benefit expense, compared to $1.4 million and $8.2 million, respectively, during the three and nine months endedSeptember 30, 2014. During the three and nine months endedSeptember 30, 2014, for discontinued operations, QEP recognized $0.4 million and $1.4 million, respectively, in employee benefit expense.

20

Note 14 – Operations by Line of Business

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

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

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

	QEP Energy			QEP Marketing  and Other			Eliminations			QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	382.6		$	154.1		$	—		$	536.7
From affiliated customers	—			263.4			(263.4		)	—
Total Revenues	382.6			417.5			(263.4		)	536.7
OPERATING EXPENSES
Purchased gas and oil expense	23.6			412.1			(260.6		)	175.1
Lease operating expense	56.7			—			—			56.7
Gas, oil and NGL transportation and other handling costs	80.1			—			(2.0		)	78.1
Gathering and other expense	—			1.3			—			1.3
General and administrative	41.2			1.6			(0.8		)	42.0
Production and property taxes	29.9			0.3			—			30.2
Depreciation, depletion and amortization	235.7			2.4			—			238.1
Impairment and exploration expense	15.8			—			—			15.8
Total Operating Expenses	483.0			417.7			(263.4		)	637.3
Net gain (loss) from asset sales	13.2			(0.3		)	—			12.9
OPERATING INCOME (LOSS)	(87.2		)	(0.5		)	—			(87.7		)
Realized and unrealized gains (losses) on derivative contracts	152.3			1.3			—			153.6
Interest and other income	0.9			52.0			(52.6		)	0.3
Interest expense	(52.4		)	(36.6		)	52.6			(36.4		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	13.6			16.2			—			29.8
Income tax (provision) benefit	(2.8		)	(5.9		)	—			(8.7		)
NET INCOME (LOSS)	$	10.8		$	10.3		$	—		$	21.1

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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  and Other			Eliminations			Discontinued Operations		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 and oil 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	49.0			1.4			(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	527.3			673.6			(417.8		)	—		783.1
Net gain (loss) from assets sales	(11.9		)	0.1			—			—		(11.8		)
OPERATING INCOME (LOSS)	113.7			1.4			—			—		115.1
Realized and unrealized gains (losses) 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 (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	214.8			18.8			—			—		233.6
Income tax (provision) benefit	(69.1		)	(10.8		)	—			—		(79.9		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	145.7			8.0			—			—		153.7
Net income from discontinued operations, net of income tax	—			—			—			17.4		17.4
NET INCOME (LOSS)	$	145.7		$	8.0		$	—		$	17.4	$	171.1

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The following table is a summary of operating results for the nine months endedSeptember 30, 2015, by line of business:

	QEP Energy			QEP Marketing  and Other			Eliminations			QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	1,143.8		$	493.1		$	—		$	1,636.9
From affiliated customers	—			719.0			(719.0		)	—
Total Revenues	1,143.8			1,212.1			(719.0		)	1,636.9
OPERATING EXPENSES
Purchased gas and oil expense	71.6			1,200.3			(710.2		)	561.7
Lease operating expense	175.6			—			—			175.6
Gas, oil and NGL transportation and other handling costs	223.0			—			(6.8		)	216.2
Gathering and other expense	—			4.4			—			4.4
General and administrative	137.4			5.3			(2.0		)	140.7
Production and property taxes	88.6			2.1			—			90.7
Depreciation, depletion and amortization	641.6			7.7			—			649.3
Impairment and exploration expense	38.2			—			—			38.2
Total Operating Expenses	1,376.0			1,219.8			(719.0		)	1,876.8
Net gain (loss) from asset sales	11.9			(5.0		)	—			6.9
OPERATING INCOME (LOSS)	(220.3		)	(12.7		)	—			(233.0		)
Realized and unrealized gains (losses) on derivative contracts	166.9			1.6			—			168.5
Interest and other income (expense)	0.5			153.1			(152.1		)	1.5
Interest expense	(152.2		)	(109.3		)	152.1			(109.4		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(205.1		)	32.7			—			(172.4		)
Income tax (provision) benefit	73.2			(11.6		)	—			61.6
NET INCOME (LOSS)	$	(131.9	)	$	21.1		$	—		$	(110.8	)

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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  and Other			Eliminations			Discontinued Operations		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 and oil 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	146.5			3.1			(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	1,529.0			1,788.3			(1,132.9		)	—		2,184.4
Net gain (loss) from assets sales	(210.3		)	—			—			—		(210.3		)
OPERATING INCOME (LOSS)	214.0			6.0			—			—		220.0
Realized and unrealized gains (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 (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	49.4			37.0			—			—		86.4
Income tax (provision) benefit	(9.0		)	(17.1		)	—			—		(26.1		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	40.4			19.9			—			—		60.3
Net income from discontinued operations, net of income tax	—			—			—			58.2		58.2
NET INCOME (LOSS)	$	40.4		$	19.9		$	—		$	58.2	$	118.5

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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 2014 Annual Report on Form 10-K/A and analyzes the changes in the results of operations between the three and nine months endedSeptember 30, 2015 and 2014. For definitions of commonly used oil and gas terms found in this Quarterly Report on Form 10-Q, please refer to the “Glossary of Commonly Used Terms” provided in QEP’s 2014 Annual Report on Form 10-K/A.

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

OVERVIEW

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

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

Strategies

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

• operate in a safe and environmentally responsible manner;

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

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

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

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

• build contiguous acreage positions that drive operating efficiencies;

• be the operator of our assets, whenever possible;

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

• actively market our production to maximize value;

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

• attract and retain the best people; and

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

In response to the current commodity price environment, we have reduced drilling and completion activities, slowed production growth, and continue to preserve liquidity and expect to continue these strategies in 2016. We have reduced the number of QEP operated drilling rigs to eight at the end of the third quarter of 2015 compared to a high of 21 during 2014. We have reduced our annual capital expenditure budget for 2015 to approximately $1.0 billion from $2.7 billion in 2014, which included $941.8 million for the Permian Basin Acquisition (defined below). We are focused on driving improved operating performance by optimizing reservoir development, enhancing well completion designs and aggressively pursuing cost reductions.

25

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

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

Discontinued Operations

On December 2, 2014, the Company closed on the sale of substantially all of its midstream business, including the Company's ownership interest in QEP Midstream Partners, LP (QEP Midstream), to Tesoro Logistics LP (Tesoro) for total cash proceeds of approximately $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, subject to post-closing adjustments, and QEP recorded a pre-tax gain of approximately $1.8 billion for the year endedDecember 31, 2014 (Midstream Sale). As a result of the Midstream Sale, the QEP Field Services Company (QEP Field Services) reporting segment, excluding the retained ownership of Haynesville gathering system (Haynesville Gathering), has been classified as a discontinued operation on the Condensed Consolidated Statement of Operations and the Notes accompanying the Condensed Consolidated Financial Statements. For reporting purposes, Haynesville Gathering 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 consisted of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 270 vertical producing wells in the Permian Basin, which created a new core area of operation for QEP Energy.

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

Divestitures

The Company periodically divests select non-core assets. In December 2014, QEP sold its interest in certain non-core properties in southern Oklahoma for aggregate proceeds of approximately $101.3 million. In June 2014, QEP sold its interests in certain non-core properties in the Midcontinent area and other non-core assets in the Williston Basin for aggregate proceeds of approximately $675.6 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, carbonate or shale layers that underlie broad geographic areas. The lateral continuity of such resource plays means that aside from wells abandoned due to mechanical issues, the Company does not expect to drill many unsuccessful wells as it develops these resource plays. Resource plays allow the Company the opportunity to gain considerable operational efficiencies through high-density, repeatable drilling and completion operations. The Company has a large inventory of lower-risk, predictable development drilling locations across its acreage holdings in the onshore United States that provide a solid base for growth in organic production and reserves.

26

Financial and Operating Results

During the three months endedSeptember 30, 2015, QEP:

• Achieved record equivalent production of 86.7 Bcfe, a 9% increase over the same period in 2014;

• Maintained $495.8 million in cash and cash equivalents and have nothing drawn under our $1.8 billion credit facility;

• Generated net income of $21.1 million, or $0.12 per diluted share;

• Achieved Adjusted EBITDA (a non-GAAP financial measure defined and reconciled below) of $273.1 million, which exceeded third quarter capital expenditures;

• Increased oil production to 5,162.1 Mbbls, a 10% increase over 2014, including record production in the Permian Basin and near-record production in the Williston Basin;

• Increased natural gas production to 48.0 Bcf, a 15% increase over 2014, including record natural gas production in Pinedale and in the Uinta Basin; and

• Reduced lease operating and transportation expense by $0.15/Mcfe to $1.57/Mcfe.

During the nine months endedSeptember 30, 2015, QEP:

• Achieved record equivalent production of 242.8 Bcfe, a 3% increase over the same period in 2014;

• Increased oil production to 14,519.4 Mbbls, a 21% increase over 2014, including 88% growth in the Permian Basin and 23% growth in the Williston Basin; and

• Increased natural gas production to 135.1 Bcf, including record production in Pinedale and in the Uinta Basin.

Factors Affecting Results of Operations

Oil, Gas, and NGL Prices

Changes in the market prices for gas, oil, and NGL directly impact many aspects of QEP's business, including its financial condition, revenues, results of operations, planned drilling activity and related capital expenditures, liquidity, rate of growth, costs of goods and services required to drill and complete wells, and the carrying value of its oil and natural gas properties. Historically, field-level prices received for QEP's gas, oil and NGL production have been volatile and unpredictable, and that volatility is expected to continue.

In recent years, domestic crude oil and natural gas supplies have grown dramatically, driven by advances in drilling and completion technologies, including horizontal drilling and multi-stage hydraulic fracturing. These changes have allowed producers to extract increased quantities of hydrocarbons from shale, tight sand formations, and other unconventional reservoirs. Increased natural gas supplies, particularly in the eastern portion of the country, have resulted in downward pressure on U.S. natural gas prices and a high degree of pricing variability among different regional natural gas pricing hubs. High natural gas demand in 2014, driven primarily by unusually cold winter weather, resulted in improved natural gas prices in the first half of 2014, but continued growth in production, a more normal winter during the 2014-2015 heating season, and adequate storage levels led to natural gas price declines later in the year and in 2015. Similarly, growth in U.S. oil production combined with global crude oil supplies that exceed global demand and other factors, such as a strong U.S. dollar, led to a dramatic weakening of global oil prices starting in late 2014, which has continued into 2015.

NGL prices have also been affected by increased U.S. hydrocarbon production and insufficient domestic demand and export capacity. Prices of heavier NGL components, typically correlated to crude oil prices, have declined consistently with weakening oil prices, while ethane and propane prices have decreased as a result of growing North American oversupply. In addition, QEP's NGL prices are affected by ethane recovery or rejection. When ethane is recovered as a discrete NGL component instead of being sold as part of the natural gas stream, the average sales price of an NGL barrel decreases as the ethane price is generally lower than the prices of the remaining NGL components. As permitted in our processing agreements, QEP recovers ethane when gas processing economics support the recovery of ethane from the natural gas stream. When gas processing economics do not support ethane recovery, the Company rejects ethane when possible.

During 2014, the NYMEX-WTI oil monthly average spot price ranged from a high of $105.79 per barrel in June 2014 to a low of $59.29 per barrel in December 2014, while the NYMEX-HH natural gas one-month future price ranged from a high of $5.15 per MMBtu in February 2014 to a low of $3.65 per MMBtu in November 2014. Prices continue to be volatile in 2015 as the NYMEX-WTI oil monthly average spot price fell to a low of $38.22 per barrel in August 2015 and the NYMEX-HH natural gas one-month future price fell to a low of $2.49 per MMBtu in April 2015.

Due to increased global economic uncertainty and the corresponding volatility of commodity prices, QEP has built a strong liquidity position to ensure financial flexibility and has reduced drilling and completion activity and decreased planned capital expenditures. QEP uses commodity derivatives to reduce the volatility of the prices QEP receives for a portion of its production

27

and to partially protect cash flow and returns on invested capital from a drop in commodity prices. Generally, QEP intends to enter into commodity derivative contracts for approximately 50% to 75% of its forecasted annual production by the end of the first quarter of each fiscal year. At September 30, 2015, assuming forecasted 2015 annual production of 323 Bcfe, QEP Energy had approximately 53% of its forecasted gas equivalent production for the remainder of 2015 covered with fixed-price swaps, including 61% of its forecasted gas production and 54% of its forecasted oil production. As QEP has entered into additional derivative contracts in 2015, the average swap price of the contract is significantly lower than the contracts entered into prior to 2015 and therefore, may not contribute as much to QEP's net realized prices for future production. See Part 1, Item 3 “Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk Management” for further details concerning QEP’s commodity derivatives transactions. QEP Energy has allocated approximately 96% of its forecasted 2015 drilling and completion capital expenditure budget to oil and liquids-rich gas projects in its portfolio.

Global Geopolitical and Macroeconomic Factors

QEP continues to monitor the global economy, including Europe's economic outlook; political unrest in Eastern Europe, the Middle East, and Africa; slowing growth in Asia, particularly in China; the United States' federal budget deficit; changes in regulatory oversight policy; commodity price volatility; the potential impact of rising interest rates; volatility in various global currencies; and other factors. A dramatic decline in regional or global economic conditions, a major recession or depression, regional political instability, economic sanctions, war, or other factors beyond the control of QEP could have a significant impact on gas, oil and NGL supply, demand and prices, the Company's ability to continue its planned drilling programs on federal and Native American lands, and could materially impact the Company's financial position, results of operations and cash flow from operations.

Supply, Demand and Other Market Risk Factors

During the last five years, the U.S. natural gas directed drilling rig count has decreased as producers reduced drilling activity for dry natural gas in response to lower natural gas prices and directed investment toward oil and liquid-rich projects. Over the same period of time, U.S. natural gas production has continued to grow, particularly in the Marcellus Shale region, as efficiency gains have allowed more wells to be drilled and completed per operating rig, higher per-well natural gas production from horizontal wells as a result of investment focused on more prolific resources, and increased amounts of natural gas produced in association with crude oil. As a result, U.S. natural gas production continued to increase into 2015, despite the gradually decreasing rig-count. Strong natural gas demand from electric power generation, cold winter weather during the 2013-2014 heating season, and other demand sources caused a general firming of natural gas prices during the second half of 2013 and into the first half of 2014. Natural gas prices weakened in the second half of 2014 and into 2015 due to more typical winter season demand levels and continued increases in supply. QEP expects U.S. natural gas prices to remain range-bound over the near term. Relatively low natural gas prices in recent years have caused U.S. E&P companies, including QEP, to shift capital investments away from predominantly dry gas areas toward plays that produce crude oil, condensate and liquids-rich gas.

The reallocation of drilling capital has caused domestic NGL production to increase dramatically. Increased NGL production and price dislocations from infrastructure bottlenecks in certain regions have all contributed to a weakening of domestic NGL prices, particularly ethane and, more recently, propane. QEP expects that ethane prices will continue to be range-bound and ethane processing economics challenged until new ethylene crackers and export facilities are built. Propane prices have declined as a result of abnormally high inventory levels, limited domestic demand and insufficient export capacity. An increase in exports and typical seasonal demand is expected to draw down propane inventories to more normal levels over the coming year. The prices of heavier components of the NGL barrel have weakened as a result of the decline in crude oil prices.

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

28

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 decline and/or drilling and completion costs increase. The cash flow model that the Company uses to assess proved properties for impairment includes numerous assumptions, such as management's estimates of future gas, oil and NGL production, market outlook on forward commodity prices, operating and development costs, and discount rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward gas, oil or NGL prices alone could result in an impairment of properties. During the year ended December 31, 2014, the Company recorded impairments of $1.1 billion primarily due to impairments of proved property in the Southern Region associated with lower future prices as of December 31, 2014. Additionally, the Company recorded $35.5 million of impairment expense during the first three quarters of 2015, of which $33.8 million was related to proved properties due to lower future oil and gas prices and $1.7 million was related to expiring leaseholds on unproved properties. If future commodity prices decline further, there could be additional impairment charges to our oil and gas assets or other investments.

Multi-Well Pad Drilling

To reduce the costs of well location construction and rig mobilization and demobilization and to obtain other efficiencies, QEP utilizes multi-well pad drilling where practical. In certain of our producing areas, wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location. As a result, multi-well pad drilling delays the commencement of production, which may cause volatility in QEP’s quarterly operating results. 

Critical Accounting Estimates

QEP’s significant accounting policies are described in Item 8 of Part II of its 2014 Annual Report on Form 10-K/A. The Company’s Condensed Consolidated Financial Statements are prepared in accordance with GAAP. The preparation of the Company’s Condensed Consolidated Financial Statements requires management to make assumptions and estimates that affect the reported results of operations and financial position. QEP’s accounting policies on oil and gas reserves, successful efforts accounting for oil and gas operations, impairment of oil and gas properties, asset retirement obligations, accounting for derivative contracts, revenue recognition, environmental obligations, litigation and other contingencies, benefit plan obligations, share-based compensation, income taxes, and purchase price allocations, among others, may involve a high degree of complexity and judgment on the part of management.

RESULTS OF OPERATIONS

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

Net Income

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2015		2014		Change			2015			2014		Change
	(in millions, except per share amounts)
QEP Energy	$	10.8	$	145.7	$	(134.9	)	$	(131.9	)	$	40.4	$	(172.3	)
QEP Marketing and Other	10.3		8.0		2.3			21.1			19.9		1.2
Net income (loss) from continuing operations	21.1		153.7		(132.6		)	(110.8		)	60.3		(171.1		)
Net income from discontinued operations, net of income tax	—		17.4		(17.4		)	—			58.2		(58.2		)
Net income (loss)	$	21.1	$	171.1	$	(150.0	)	$	(110.8	)	$	118.5	$	(229.3	)
Diluted earnings per share from continuing operations	$	0.12	$	0.84	$	(0.72	)	$	(0.63	)	$	0.34	$	(0.97	)
Diluted earnings per share from discontinued operations	—		0.10		(0.10		)	—			0.32		(0.32		)
Diluted earnings per share	$	0.12	$	0.94	$	(0.82	)	$	(0.63	)	$	0.66	$	(1.29	)
Average diluted shares	176.7		180.6		(3.9		)	176.5			180.4		(3.9		)

29

QEP generated net income from continuing operations during the third quarter of 2015 of $21.1 million, or $0.12 per diluted share, compared to net income from continuing operations of $153.7 million, or $0.84 per diluted share, in the third quarter of 2014. The change in the third quarter of 2015 compared to the third quarter of 2014 was due to a $134.9 milliondecrease in QEP Energy’s net income, partially offset by a $2.3 millionincrease in QEP Marketing and Other's net income. QEP Energy's net income decrease was primarily due to decreases in average field-level prices for gas, oil and NGL, decreased NGL production and lower unrealized derivative gains. These decreases were partially offset by increased realized derivative gains, increased oil and gas production and lower operating expenses in the third quarter of 2015 compared to the third quarter of 2014. QEP Marketing and Other's net income increased in the third quarter of 2015 primarily due to a lower interest expense in the third quarter of 2015 compared to the third quarter of 2014 due to lower average debt levels, lower realized derivative losses and a higher resale margin in the third quarter of 2015 compared to the third quarter of 2014. These increases were partially offset by decreased interest and other income in the third quarter of 2015 compared to the third quarter of 2014.

QEP generated a net loss from continuing operations during the first three quarters of 2015 of $110.8 million, or $0.63 per diluted share, compared to net income from continuing operations of $60.3 million, or $0.34 per diluted share, in the first three quarters of 2014. The change in the first three quarters of 2015 compared to the first three quarters of 2014 was due to a $172.3 million decrease in QEP Energy’s net income, partially offset by a $1.2 millionincrease in QEP Marketing and Other's net income. QEP Energy's decrease was primarily due to decreases in average field-level prices for gas, oil and NGL and decreased NGL production. These decreases were partially offset by realized derivative instrument gains in the first three quarters of 2015 compared to realized derivative instrument losses in the first three quarters of 2014, a net gain from asset sales of $11.9 million in the first three quarters of 2015, compared to a $210.3 million net loss from asset sales in the first three quarters of 2014, as well as increased oil and gas production and lower operating expenses in the first three quarters of 2015 compared to the first three quarters of 2014. QEP Marketing and Other's net income increased in the first three quarters of 2015 primarily due to lower interest expense due to lower average debt levels during the first three quarters of 2015, partially offset by a net loss from asset sales of $5.0 million during first three quarters of 2015 related to post-closing adjustments for the Midstream Sale and a lower resale margin in the first three quarters of 2015 compared to the first three quarters of 2014.

Adjusted EBITDA

Management believes Adjusted EBITDA (a non-GAAP measure) is an important measure of the Company's financial and operating performance that allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. Management defines Adjusted EBITDA as earnings before interest, income taxes, depreciation, depletion and amortization (EBITDA), adjusted to exclude changes in fair value of derivative contracts, exploration expenses, gains and losses from asset sales, impairment, and certain other non-cash and/or non-recurring items.

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

	Three Months Ended September 30,							Nine Months Ended September 30,
	2015		2014		Change			2015		2014		Change
	(in millions)
QEP Energy	$	271.0	$	368.9	$	(97.9	)	$	773.0	$	1,064.0	$	(291.0	)
QEP Marketing and Other	2.1		2.0		0.1			2.3		8.2		(5.9		)
Adjusted EBITDA from continuing operations	273.1		370.9		(97.8		)	775.3		1,072.2		(296.9		)
Adjusted EBITDA from discontinued operations	—		38.4		(38.4		)	—		124.2		(124.2		)
Adjusted EBITDA	$	273.1	$	409.3	$	(136.2	)	$	775.3	$	1,196.4	$	(421.1	)

Adjusted EBITDA from continuing operations decreased to $273.1 million in the third quarter of 2015 from $370.9 million in the third quarter of 2014, due to a 47% decrease in the average equivalent field-level price as well as an 18%decrease in NGL production, partially offset by a 10%increase in oil production, a 15%increase in gas production and higher realized gains on derivative contracts.

Adjusted EBITDA from continuing operations decreased to $775.3 million in the first three quarters of 2015 from $1,072.2 million in the first three quarters of 2014, due to a 43% decrease in the average equivalent field-level price as well as a 32%decrease in NGL production, partially offset by a 21%increase in oil production and higher realized gains on derivative contracts.

30

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

	QEP Energy			QEP Marketing and Other(1)			Continuing Operations			Discontinued Operations		QEP Consolidated
Three Months Ended September 30, 2015	(in millions)
Net income (loss)	$	10.8		$	10.3		$	21.1		$	—	$	21.1
Unrealized (gains) losses on derivative contracts	(32.4		)	(1.4		)	(33.8		)	—		(33.8		)
Net (gain) loss from asset sales	(13.2		)	0.3			(12.9		)	—		(12.9		)
Interest and other (income) expense	(0.9		)	0.6			(0.3		)	—		(0.3		)
Income tax provision (benefit)	2.8			5.9			8.7			—		8.7
Interest expense (income)	52.4			(16.0		)	36.4			—		36.4
Depreciation, depletion and amortization	235.7			2.4			238.1			—		238.1
Impairment	15.0			—			15.0			—		15.0
Exploration expenses	0.8			—			0.8			—		0.8
Adjusted EBITDA	$	271.0		$	2.1		$	273.1		$	—	$	273.1
Three Months Ended September 30, 2014
Net income (loss)	$	145.7		$	8.0		$	153.7		17.4		$	171.1
Unrealized (gains) losses on derivative contracts	(160.8		)	(3.3		)	(164.1		)	—		(164.1		)
Net (gain) loss from asset sales	11.9			(0.1		)	11.8			—		11.8
Interest and other (income) expense	(3.9		)	(0.3		)	(4.2		)	—		(4.2		)
Income tax provision (benefit)	69.1			10.8			79.9			9.9		89.8
Interest expense (income) (3)	57.0			(15.5		)	41.5			0.8		42.3
Depreciation, depletion and amortization (4)	249.0			2.4			251.4			10.3		261.7
Impairment	0.1			—			0.1			—		0.1
Exploration expenses	0.8			—			0.8			—		0.8
Adjusted EBITDA	$	368.9		$	2.0		$	370.9		$	38.4	$	409.3
Nine Months Ended September 30, 2015
Net income (loss)	$	(131.9	)	$	21.1		$	(110.8	)	$	—	$	(110.8	)
Unrealized (gains) losses on derivative contracts	147.5			0.5			148.0			—		148.0
Net (gain) loss from asset sales	(11.9		)	5.0			(6.9		)	—		(6.9		)
Interest and other (income) expense	(0.5		)	(1.0		)	(1.5		)	—		(1.5		)
Income tax provision (benefit)	(73.2		)	11.6			(61.6		)	—		(61.6		)
Interest expense (income)	152.2			(42.8		)	109.4			—		109.4
Pension curtailment loss (2)	11.0			0.2			11.2			—		11.2
Depreciation, depletion and amortization	641.6			7.7			649.3			—		649.3
Impairment	35.5			—			35.5			—		35.5
Exploration expenses	2.7			—			2.7			—		2.7
Adjusted EBITDA	$	773.0		$	2.3		$	775.3		$	—	$	775.3
Nine Months Ended September 30, 2014
Net income (loss)	$	40.4		$	19.9		$	60.3		58.2		$	118.5
Unrealized (gains) losses on derivative contracts	(63.8		)	(2.1		)	(65.9		)	—		(65.9		)

31

	QEP Energy			QEP Marketing and Other(1)			Continuing Operations			Discontinued Operations		QEP Consolidated
Net (gain) loss from asset sales	210.3			—			210.3			0.1		210.4
Interest and other (income) expense	(7.4		)	(0.4		)	(7.8		)	—		(7.8		)
Income tax provision (benefit)	9.0			17.1			26.1			32.8		58.9
Interest expense (income) (3)	162.5			(34.1		)	128.4			1.7		130.1
Depreciation, depletion and amortization (4)	704.7			7.8			712.5			31.4		743.9
Impairment	3.6			—			3.6			—		3.6
Exploration expenses	4.7			—			4.7			—		4.7
Adjusted EBITDA	$	1,064.0		$	8.2		$	1,072.2		$	124.2	$	1,196.4

____________________________

⁽¹⁾  Includes intercompany eliminations.

⁽²⁾  The pension curtailment loss is a non-cash loss that was incurred during the nine months endedSeptember 30, 2015, due to changes in the Company's pension plan (see Note 13 – Employee Benefits in Part 1, Item 1 of this Quarterly Report on Form 10-Q for additional information). The Company believes that the pension curtailment loss does not reflect expected future operating performance or provide meaningful comparisons to past operating performance and therefore has excluded the loss from the calculation of Adjusted EBITDA.

⁽³⁾  Excludes noncontrolling interest's share of $0.7 million and $1.1 million during the three and nine months endedSeptember 30, 2014, respectively, of interest expense attributable to QEP Midstream.

⁽⁴⁾  Excludes noncontrolling interest's share of $4.0 million and $11.7 million during the three and nine months endedSeptember 30, 2014, respectively, of depreciation, depletion and amortization attributable to Rendezvous Gas Services, L.L.C and QEP Midstream.

32

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,
	2015			2014			Change			2015			2014			Change
REVENUES	(in millions)
Gas sales	$	129.3		$	171.6		$	(42.3	)	$	363.3		$	609.2		$	(245.9	)
Oil sales	211.7			393.5			(181.8		)	640.8			1,040.7			(399.9		)
NGL sales	16.6			51.1			(34.5		)	61.6			179.0			(117.4		)
Purchased gas sales	23.7			33.3			(9.6		)	71.5			120.2			(48.7		)
Other	1.3			3.4			(2.1		)	6.6			4.2			2.4
Total Revenues	382.6			652.9			(270.3		)	1,143.8			1,953.3			(809.5		)
OPERATING EXPENSES
Purchased gas expense	23.6			32.8			(9.2		)	71.6			120.9			(49.3		)
Lease operating expense	56.7			61.1			(4.4		)	175.6			177.0			(1.4		)
Gas, oil and NGL transportation and other handling costs	80.1			75.2			4.9			223.0			211.8			11.2
General and administrative	41.2			49.0			(7.8		)	137.4			146.5			(9.1		)
Production and property taxes	29.9			59.3			(29.4		)	88.6			159.8			(71.2		)
Depreciation, depletion and amortization	235.7			249.0			(13.3		)	641.6			704.7			(63.1		)
Exploration expenses	0.8			0.8			—			2.7			4.7			(2.0		)
Impairment	15.0			0.1			14.9			35.5			3.6			31.9
Total Operating Expenses	483.0			527.3			(44.3		)	1,376.0			1,529.0			(153.0		)
Net gain (loss) from asset sales	13.2			(11.9		)	25.1			11.9			(210.3		)	222.2
OPERATING INCOME (LOSS)	(87.2		)	113.7			(200.9		)	(220.3		)	214.0			(434.3		)
Realized gains (losses) on derivative instruments	119.9			(6.7		)	126.6			314.4			(73.5		)	387.9
Unrealized gains (losses) on derivative instruments	32.4			160.8			(128.4		)	(147.5		)	63.8			(211.3		)
Interest and other income (expense)	0.9			3.9			(3.0		)	0.5			7.4			(6.9		)
Income from unconsolidated affiliates	—			0.1			(0.1		)	—			0.2			(0.2		)
Interest expense	(52.4		)	(57.0		)	4.6			(152.2		)	(162.5		)	10.3
NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	13.6			214.8			(201.2		)	(205.1		)	49.4			(254.5		)
Income tax (provision) benefit	(2.8		)	(69.1		)	66.3			73.2			(9.0		)	82.2
NET INCOME (LOSS)	$	10.8		$	145.7		$	(134.9	)	$	(131.9	)	$	40.4		$	(172.3	)
Production volumes (Bcfe)
Northern Region
Pinedale	26.3			26.4			(0.1		)	73.0			72.6			0.4
Williston Basin	29.8			25.4			4.4			83.8			61.6			22.2
Uinta Basin	8.8			6.8			2.0			23.0			19.8			3.2
Other Northern	2.7			1.9			0.8			7.8			7.9			(0.1		)
Southern Region
Haynesville/Cotton Valley	11.2			11.4			(0.2		)	33.3			38.9			(5.6		)
Permian Basin	7.3			5.0			2.3			18.4			10.4			8.0
Midcontinent	0.6			2.3			(1.7		)	3.5			25.6			(22.1		)
Total production	86.7			79.2			7.5			242.8			236.8			6.0
Total equivalent prices (per Mcfe)
Average equivalent field-level price	$	4.12		$	7.77		$	(3.65	)	$	4.39		$	7.72		$	(3.33	)
Commodity derivative impact	1.38			(0.08		)	1.46			1.29			(0.31		)	1.60
Net realized equivalent price	$	5.50		$	7.69		$	(2.19	)	$	5.68		$	7.41		$	(1.73	)

33

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 endedSeptember 30, 2015, compared to the three and nine months endedSeptember 30, 2014:

	Gas			Oil			NGL			Total
	(in millions)
QEP Energy Production Revenues
Three months ended September 30, 2014 Revenues	$	171.6		$	393.5		$	51.1		$	616.2
Changes associated with volumes (1)	25.4			41.2			(9.0		)	57.6
Changes associated with prices (2)	(67.7		)	(223.0		)	(25.5		)	(316.2		)
Three months ended September 30, 2015 Revenues	$	129.3		$	211.7		$	16.6		$	357.6
QEP Energy Production Revenues
Nine months ended September 30, 2014 Revenues	$	609.2		$	1,040.7		$	179.0		$	1,828.9
Changes associated with volumes (1)	0.8			222.3			(56.6		)	166.5
Changes associated with prices (2)	(246.7		)	(622.2		)	(60.8		)	(929.7		)
Nine months ended September 30, 2015 Revenues	$	363.3		$	640.8		$	61.6		$	1,065.7

____________________________

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

⁽²⁾  The revenue variance attributed to the change in price is calculated by multiplying the change in average field-level prices from the three and nine months endedSeptember 30, 2015, as compared to the three and nine months endedSeptember 30, 2014, by volumes for the three and nine months endedSeptember 30, 2015. Pricing changes are driven by changes in commodity field-level prices, excluding the impact from commodity derivatives.

Gas Volumes and Prices

	Three Months Ended September 30,							Nine Months Ended September 30,
	2015		2014		Change			2015		2014			Change
Gas production volumes (Bcf)
Northern Region
Pinedale	23.0		19.9		3.1			63.5		54.9			8.6
Williston Basin	2.8		1.8		1.0			8.5		3.7			4.8
Uinta Basin	7.0		4.5		2.5			17.6		12.9			4.7
Other Northern	2.4		1.7		0.7			6.9		6.8			0.1
Southern Region
Haynesville/Cotton Valley	11.1		11.3		(0.2		)	33.0		38.6			(5.6		)
Permian Basin	1.3		1.1		0.2			3.2		2.2			1.0
Midcontinent	0.4		1.5		(1.1		)	2.4		15.8			(13.4		)
Total production	48.0		41.8		6.2			135.1		134.9			0.2
Gas prices (per Mcf)
Northern Region	$	2.71	$	4.07	$	(1.36	)	$	2.68	$	4.50		$	(1.82	)
Southern Region	2.64		4.17		(1.53		)	2.71		4.53			(1.82		)
Average field-level price	$	2.69	$	4.10	$	(1.41	)	$	2.69	$	4.52		$	(1.83	)
Commodity derivative impact	0.48		0.13		0.35			0.51		(0.18		)	0.69
Net realized price	$	3.17	$	4.23	$	(1.06	)	$	3.20	$	4.34		$	(1.14	)

Gas revenues decreased$42.3 million, or 25%, in the third quarter of 2015 when compared to the third quarter of 2014, due to lower field-level prices, partially offset by higher gas production. Average field-level gas prices decreased 34% in the third quarter of 2015 compared to the third quarter of 2014 driven by a decrease in average NYMEX-HH natural gas prices for the

34

comparable period. The 15% increase in production volumes was primarily driven by production increases in Pinedale due to continued net well completions in 2014 and 2015, in the Uinta Basin due to higher performing well completions and in the Williston Basin due to continued development. These production increases were partially offset by the divestitures of non-core Midcontinent properties in the fourth quarter of 2014 and a production decrease in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program.

Gas revenues decreased$245.9 million, or 40%, in the first three quarters of 2015 when compared to the first three quarters of 2014, due to lower field-level prices, partially offset by higher gas production. Average field-level gas prices decreased 40% in the first three quarters of 2015 compared to the first three quarters of 2014 driven by a decrease in average NYMEX-HH natural gas prices for the comparable period. The increase in production volumes was primarily driven by production increases in Pinedale due to continued net well completions in 2014 and 2015, in the Williston Basin due to continued development and in the Uinta Basin due to higher performing well completions. These production increases were mostly offset by the divestitures of non-core Midcontinent properties in the second and fourth quarters of 2014 and a production decrease in Haynesville/Cotton Valley due to the continued suspension of QEP's operated drilling program.

Oil Volumes and Prices

	Three Months Ended September 30,								Nine Months Ended September 30,
	2015		2014			Change			2015		2014			Change
Oil production volumes (Mbbls)
Northern Region
Pinedale	190.4		172.1			18.3			511.9		464.9			47.0
Williston Basin	3,915.8		3,692.0			223.8			11,116.5		9,043.7			2,072.8
Uinta Basin	242.4		230.3			12.1			666.0		672.6			(6.6		)
Other Northern	43.5		24.9			18.6			132.9		166.0			(33.1		)
Southern Region
Haynesville/Cotton Valley	9.4		10.8			(1.4		)	26.1		31.4			(5.3		)
Permian Basin	742.7		474.1			268.6			1,942.6		1,032.3			910.3
Midcontinent	17.9		68.2			(50.3		)	123.4		554.1			(430.7		)
Total production	5,162.1		4,672.4			489.7			14,519.4		11,965.0			2,554.4
Oil prices (per bbl)
Northern Region	$	40.05	$	83.74		$	(43.69	)	$	43.21	$	86.19		$	(42.98	)
Southern Region	46.50		87.74			(41.24		)	49.64		92.02			(42.38		)
Average field-level price	$	41.01	$	84.21		$	(43.20	)	$	44.13	$	86.98		$	(42.85	)
Commodity derivative impact	18.75		(2.60		)	21.35			16.90		(4.20		)	21.10
Net realized price	$	59.76	$	81.61		$	(21.85	)	$	61.03	$	82.78		$	(21.75	)

Oil revenues decreased$181.8 million, or 46%, in the third quarter of 2015 when compared to the third quarter of 2014, due to lower average field-level prices, partially offset by higher volumes. Average field-level oil prices decreased 51% in the third quarter of 2015 compared to the third quarter of 2014 driven by a substantial decrease in average NYMEX-WTI and ICE Brent oil prices between the comparable periods. The 10%increase in production volumes was primarily driven by increases in the Permian and Williston basins due to continued development drilling and well completions. These production increases were partially offset by a production decrease in the Midcontinent due to the divestitures of non-core properties in the fourth quarter of 2014.

Oil revenues decreased$399.9 million, or 38%, in the first three quarters of 2015 when compared to the first three quarters of 2014, due to lower average field-level prices, partially offset by higher volumes. Average field-level oil prices decreased 49% in the first three quarters of 2015 compared to the first three quarters of 2014, driven by a substantial decrease in average NYMEX-WTI and ICE Brent oil prices between the comparable periods. The 21%increase in production volumes was primarily driven by an increase in the Williston Basin due to continued development drilling and well completions. The Company also had anincrease in production of 910.3 Mbbls from the Permian Basin due to continued development of the area combined with nine months of production in 2015 compared to seven months of production in 2014. These production increases were partially offset by a production decrease in the Midcontinent due to the divestitures of non-core properties in the second and fourth quarters of 2014.

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NGL Volumes and Prices

	Three Months Ended September 30,							Nine Months Ended September 30,
	2015		2014		Change			2015		2014		Change
NGL production volumes (Mbbls)
Northern Region
Pinedale	350.7		915.3		(564.6		)	1,067.5		2,484.1		(1,416.6		)
Williston Basin	588.7		239.7		349.0			1,430.3		605.0		825.3
Uinta Basin	59.1		161.5		(102.4		)	238.8		478.3		(239.5		)
Other Northern	4.9		6.4		(1.5		)	14.1		11.7		2.4
Southern Region
Haynesville/Cotton Valley	6.2		9.7		(3.5		)	20.1		28.5		(8.4		)
Permian Basin	268.0		179.9		88.1			596.8		343.3		253.5
Midcontinent	9.3		51.0		(41.7		)	64.7		1,066.9		(1,002.2		)
Total production	1,286.9		1,563.5		(276.6		)	3,432.3		5,017.8		(1,585.5		)
NGL prices (per bbl)
Northern Region	$	13.26	$	34.19	$	(20.93	)	$	19.09	$	36.24	$	(17.15	)
Southern Region	11.41		24.35		(12.94		)	13.25		34.27		(21.02		)
Average field-level price	12.85		32.68		(19.83		)	$	17.93	$	35.68	$	(17.75	)
Commodity derivative impact	—		—		—			—		—		—
Net realized price	$	12.85	$	32.68	$	(19.83	)	$	17.93	$	35.68	$	(17.75	)

NGL revenues decreased$34.5 million, or 68%, during the third quarter of 2015 when compared to the third quarter of 2014, due to decreased production volumes and a decreased average price per barrel. Pinedale and Uinta Basin NGL volumes decreased primarily due to ethane rejection in the third quarter of 2015 compared to ethane recovery in the third quarter of 2014. Midcontinent NGL volumes decreased due to divestitures of non-core properties in the fourth quarter of 2014. These decreases were partially offset by increases in NGL volumes in the Williston and Permian basins as a result of increased development drilling and well completions. NGL prices decreased 61% during the third quarter of 2015 compared to the third quarter of 2014, which was driven by a significant decrease in the pricing of the NGL components, particularly the heavier components, which have weakened as a result of the decline in crude oil prices.

NGL revenues decreased$117.4 million, or 66%, during the first three quarters of 2015 when compared to the first three quarters of 2014, due to decreased production volumes and a decreased average price per barrel. Pinedale and Uinta Basin NGL volumes decreased primarily due to ethane rejection in the first three quarters of 2015 compared to ethane recovery in the first three quarters of 2014. Additionally, Midcontinent NGL volumes decreased due to divestitures of non-core properties in the second and fourth quarters of 2014. These decreases were partially offset by increases in NGL volumes in the Williston and Permian basins as a result of increased development drilling and well completions combined with nine months of production from the Permian Basin in 2015 compared to seven months of production in 2014. NGL prices decreased 50% during the first three quarters of 2015 compared to the first three quarters of 2014, which was driven by a significant in the pricing of the NGL components, particularly the heavier components, which have weakened as a result of the decline in crude oil prices.

QEP Energy Resale Margin

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

	Three Months Ended September 30,									Nine Months Ended September 30,
	2015			2014			Change			2015			2014			Change
Resale Margin	(in millions)
Purchased gas sales	$	23.7		$	33.3		$	(9.6	)	$	71.5		$	120.2		$	(48.7	)
Purchased gas expense	(23.6		)	(32.8		)	9.2			(71.6		)	(120.9		)	49.3
Resale margin	$	0.1		$	0.5		$	(0.4	)	$	(0.1	)	$	(0.7	)	$	0.6

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During the third quarter of 2015, QEP Energy recorded income on resale margin of $0.1 million compared to income of $0.5 million in the third quarter of 2014. During the first three quarters of 2015, QEP Energy recorded a loss on resale margin of $0.1 million compared to a loss of $0.7 million in the first three quarters of 2014. These margins were the result of QEP Energy's purchase and sale transactions to utilize pipeline transportation commitments in Louisiana.

QEP Energy Drilling Activity

The following table presents operated and non-operated well completions for the three and nine months endedSeptember 30, 2015:

	Operated Completions				Non-operated Completions
	Three Months Ended		Nine Months Ended		Three Months Ended		Nine Months Ended
	September 30, 2015		September 30, 2015		September 30, 2015		September 30, 2015
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale (1)	28	17.9	83	53.7	—	—	—	—
Williston Basin	24	20.0	60	47.2	35	1.5	68	4.2
Uinta Basin	2	2.0	11	11.0	2	0.1	19	0.2
Other Northern	3	3.0	4	4.0	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	7	1.4	20	2.9
Permian Basin (2)	7	6.4	31	26.9	—	—	1	0.3
Midcontinent	—	—	—	—	—	—	4	0.1

____________________________

⁽¹⁾  Gross completions includes eight wells for the nine months endedSeptember 30, 2015, in which QEP only owns a small overriding royalty interest.

⁽²⁾  Operated completions includes eight gross, 7.4 net, vertical wells for the nine months endedSeptember 30, 2015.

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

	Operated				Non-operated
	Drilling		Waiting on completion		Drilling		Waiting on completion
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Northern Region
Pinedale	5	2.9	27	16.1	—	—	—	—
Williston Basin	9	9.0	19	15.6	—	—	24	0.8
Uinta Basin	8	8.0	—	—	—	—	—	—
Other Northern	—	—	—	—	—	—	—	—
Southern Region
Haynesville/Cotton Valley	—	—	—	—	2	0.3	8	1.2
Permian Basin	5	5.0	2	1.8	—	—	1	0.6
Midcontinent	—	—	—	—	—	—	2	0.1

The term "gross" refers to all wells or acreage in which QEP has at least a partial working interest and the term "net" refers to QEP's ownership represented by that working interest. Each gross well completed in more than one producing zone is counted as a single well. QEP utilizes multi-well pad drilling where practical. In certain of our producing areas, wells drilled are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location. As a result, QEP had 48 gross operated wells waiting on completion as of September 30, 2015, of which 27 wells were in Pinedale, 19 wells were in the Williston Basin and two wells were in the Permian Basin.

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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,
	2015		2014		Change			2015		2014		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	2.72	$	3.14	$	(0.42	)	$	2.64	$	2.98	$	(0.34	)
Lease operating expense	0.65		0.77		(0.12		)	0.72		0.75		(0.03		)
Gas, oil and NGL transportation and other handling costs	0.92		0.95		(0.03		)	0.92		0.89		0.03
Production and property taxes	0.34		0.75		(0.41		)	0.36		0.67		(0.31		)
Operating Expenses	$	4.63	$	5.61	$	(0.98	)	$	4.64	$	5.29	$	(0.65	)

Depreciation, depletion and amortization (DD&A). DD&A expense decreased $13.3 million, or $0.42 per Mcfe, in the third quarter of 2015 compared to the third quarter of 2014, due to decreases in Haynesville/Cotton Valley and the Midcontinent, partially offset by an increase in the Williston Basin. The decrease in Haynesville/Cotton Valley was a result of declining production and a rate decrease due to an impairment at year-end 2014, while the decrease in the Midcontinent was a result of the fourth quarter 2014 property sales. The increase in the Williston Basin DD&A expense primarily relates to increased production.

DD&A expense decreased $63.1 million, or $0.34 per Mcfe, in the first three quarters of 2015 compared to the first three quarters of 2014, due to decreases in Haynesville/Cotton Valley and the Midcontinent, partially offset by an increase in the Williston Basin. The decrease in Haynesville/Cotton Valley was a result of declining production and a rate decrease due to an impairment at year-end 2014, while the decrease in the Midcontinent was a result of the second and fourth quarter 2014 property sales. The increase in the Williston Basin DD&A expense primarily relates to increased production.

Lease operating expense. QEP Energy’s LOE decreased $4.4 million, or $0.12 per Mcfe, during the third quarter of 2015 compared to the third quarter of 2014. The decrease was driven by a decrease in the Permian Basin as a result of lower maintenance and repairs expenses and a decrease in the Midcontinent as a result of divestitures of non-core properties in the fourth quarter of 2014. Partially offsetting the decrease was an increase in the Williston Basin due to increased production.

QEP Energy’s LOE decreased $1.4 million, or $0.03 per Mcfe, during the first three quarters of 2015 compared to the first three quarters of 2014. The decrease was primarily driven by a decrease in the Midcontinent as a result of divestitures of non-core properties in the second and fourth quarters of 2014. This decrease was partially offset by increases due to the Permian Basin Acquisition late in the first quarter of 2014, which are oil properties that have higher operating costs and higher well count, and by increased production in the Williston Basin.

Gas, oil and NGL transportation and other handling costs. Gas, oil and NGL transportation and other handling costs increased $4.9 million in the third quarter of 2015 when compared to the third quarter of 2014. The increase in expense was primarily attributable to an increase in Haynesville/Cotton Valley, partially offset by decreases in the Midcontinent and the Uinta Basin. The increase in Haynesville was primarily the result of recognizing approximately $8.4 million of fees for historical unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP has a working interest. QEP is disputing these charges and has filed a legal claim against the operator. The decrease in the Midcontinent is due to divestitures of non-core properties in the fourth quarter of 2014 and the decrease in the Uinta Basin is primarily a result of decreased NGL volumes due to ethane rejection third quarter of 2015 compared to ethane recovery in the third quarter of 2014 and processing in refrigeration in the third quarter of 2015.

Gas, oil and NGL transportation and other handling costs increased $11.2 million, or $0.03 per Mcfe, in the first three quarters of 2015 when compared to the first three quarters of 2014. The increase in expense was primarily attributable to additional expenses incurred in Haynesville as a result of recognizing approximately $8.4 million of fees for historical unutilized gathering and transportation capacity that was charged to QEP by the operator of wells in which QEP has a working interest. QEP is disputing these charges and has filed a legal claim against the operator. Additionally, there was an increase in expenses in Pinedale due to deficiency payments on NGL volume commitments as a result of lower ethane volumes in 2015 and in the Permian Basin due to higher contractual rates. These increases were partially offset by a decrease in the Midcontinent due to divestitures of non-core properties in the second and fourth quarters of 2014.

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Production and property taxes. In most states in which QEP Energy operates, QEP pays production taxes based on a percentage of field-level revenue, except in Louisiana, where severance taxes are volume-based. Production taxes decreased $29.4 million, or $0.41 per Mcfe, during the third quarter of 2015 primarily as a result of decreased gas, oil and NGL revenues due to decreased prices.

Production taxes decreased $71.2 million, or $0.31 per Mcfe, during the first three quarters of 2015 primarily as a result of decreased gas, oil and NGL revenues due to decreased prices.

Exploration expense. Exploration expenses remained flat during the third quarter of 2015 and decreased $2.0 million during the first three quarters of 2015 compared to the 2014 equivalent periods. The decrease in the first three quarters of 2015 is primarily related to lower exploration-related labor expenses.

Impairment expense. Impairment expense was $15.0 million for the third quarter of 2015, of which $14.4 million was related to proved properties due to lower future oil and gas prices and $0.6 million was related to expiring leaseholds on unproved properties. Of the $14.4 million impairment on proved properties, $13.1 million related to impairments in the Other Northern properties, $1.0 million related to impairments on QEP's remaining Midcontinent properties and $0.3 million related to impairments on Permian Basin properties. Impairment expense was $0.1 million for the third quarter of 2014 due to unproved property impairments resulting from changes in drilling plans.

Impairment expense was $35.5 million during the first three quarters of 2015, of which $33.8 million was related to proved properties due to lower future oil and gas prices and $1.7 million was related to expiring leaseholds on unproved properties. Of the $33.8 million impairment on proved properties, $18.0 million related to impairments on Other Northern properties, $15.5 million related to impairments on QEP's remaining Midcontinent properties and $0.3 million related to impairments on Permian Basin properties. Impairment expense was $3.6 million in the first three quarters of 2014 due to unproved property impairments resulting from changes in drilling plans.

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QEP MARKETING AND OTHER

QEP Marketing and Other includes the results of operations from QEP Marketing Company, including the operation of a gas gathering system and an underground gas storage facility and corporate activities. 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,
	2015			2014			Change			2015			2014			Change
	(in millions)
REVENUES
Purchased gas and oil sales	$	413.2		$	669.9		$	(256.7	)	$	1,197.3		$	1,777.0		$	(579.7	)
Other	4.3			5.0			(0.7		)	14.8			17.3			(2.5		)
Total Revenues	417.5			674.9			(257.4		)	1,212.1			1,794.3			(582.2		)
OPERATING EXPENSES
Purchased gas and oil expense	412.1			668.3			(256.2		)	1,200.3			1,771.6			(571.3		)
Gathering and other expense	1.3			1.4			(0.1		)	4.4			4.8			(0.4		)
General and administrative	1.6			1.4			0.2			5.3			3.1			2.2
Production and property taxes	0.3			0.1			0.2			2.1			1.0			1.1
Depreciation, depletion and amortization	2.4			2.4			—			7.7			7.8			(0.1		)
Total Operating Expenses	417.7			673.6			(255.9		)	1,219.8			1,788.3			(568.5		)
Net gain (loss) from asset sales	(0.3		)	0.1			(0.4		)	(5.0		)	—			(5.0		)
OPERATING INCOME (LOSS)	(0.5		)	1.4			(1.9		)	(12.7		)	6.0			(18.7		)
Realized gains (losses) on derivative instruments	(0.1		)	(1.7		)	1.6			2.1			(5.6		)	7.7
Unrealized gains (losses) on derivative instruments	1.4			3.3			(1.9		)	(0.5		)	2.1			(2.6		)
Interest and other income	52.0			56.6			(4.6		)	153.1			162.0			(8.9		)
Interest expense	(36.6		)	(40.8		)	4.2			(109.3		)	(127.5		)	18.2
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	16.2			18.8			(2.6		)	32.7			37.0			(4.3		)
Income tax (provision) benefit	(5.9		)	(10.8		)	4.9			(11.6		)	(17.1		)	5.5
NET INCOME (LOSS)	$	10.3		$	8.0		$	2.3		$	21.1		$	19.9		$	1.2

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,
	2015			2014			Change			2015			2014			Change
Resale Margin	(in millions)
Purchased gas and oil sales	$	413.2		$	669.9		$	(256.7	)	$	1,197.3		$	1,777.0		$	(579.7	)
Purchased gas and oil expense	(412.1		)	(668.3		)	256.2			(1,200.3		)	(1,771.6		)	571.3
Realized gains (losses) on derivative instruments	(0.1		)	(1.7		)	1.6			2.1			(5.6		)	7.7
Resale margin	$	1.0		$	(0.1	)	$	1.1		$	(0.9	)	$	(0.2	)	$	(0.7	)

Purchased gas and oil sales decreased by $256.7 million, or 38%, during the third quarter of 2015 compared to the third quarter of 2014, due to a $229.2 million decrease in resale oil sales and a $27.5 million decrease in resale gas sales. Resale oil sales decreased due to a 108% decrease in resale price, partially offset by a 15% increase in resale volumes. Resale gas sales decreased due to a 53% decrease in resale price, partially offset by a 19% increase in resale volumes.

Purchased gas and oil sales decreased by $579.7 million, or 33%, during the first three quarters of 2015 compared to the first three quarters of 2014, due to a $410.3 million decrease in resale oil sales and a $169.4 million decrease in resale gas sales.

40

Resale oil sales decreased due to a 101% decrease in resale price, partially offset by a 27% increase in resale volumes. Resale gas sales decreased due to a 41% decrease in resale price and a 10% decrease in resale volumes.

Purchased gas and oil expense, which includes transportation expense, decreased by $256.2 million, or 38%, in the third quarter of 2015 compared to the third quarter of 2014, due to a $229.5 million decrease in resale oil purchases and a $26.7 million decrease in resale gas purchases. Resale oil purchases expense decreased due to a 47% decrease in resale purchase price, partially offset by a 14% increase in resale purchase volumes. Resale gas purchases expense decreased due to a 37% decrease in the resale purchase price, partially offset by a 16% increase in resale purchase volumes.

Purchased gas and oil expense, which includes transportation expense, decreased by $571.3 million, or 32%, in the first three quarters of 2015 compared to the first three quarters of 2014, due to a $410.8 million decrease in resale oil purchases and a $160.5 million decrease in resale gas purchases. Resale oil purchases expense decreased due to a 48% decrease in resale purchase price offset by a 34% increase in resale purchase volumes. Resale gas purchases expense decreased due to a 38% decrease in the resale purchase price, partially offset by a 5% increase in resale purchase volumes.

QEP Resources

Other Consolidated Expenses and Income from Continuing and Discontinued Operations

General and administrative expense. During the third quarter of 2015, general and administrative (G&A) expense decreased $7.4 million, or 15%, compared to the third quarter of 2014, primarily due to a $5.1 million decrease in labor, benefits and other employee expenses, a $3.5 million decrease in professional and outside services and compensation expense mainly related to the 2014 Enterprise Resource Planning (ERP) system implementation and a $2.6 million decrease in the mark-to-market value of the Deferred Compensation Wrap Plan and Cash Incentive Plan (CIP) due to a decrease in QEP's stock price. These decreases were partially offset by a $3.2 million increase for severance payments and restructuring costs related to the Tulsa office closure (see Note 9 – Restructuring Costs in Part 1, Item 1 of this Quarterly Report on Form 10-Q for additional information).

During the first three quarters of 2015, G&A expense decreased $6.3 million, or 4%, compared to the first three quarters of 2014, primarily due to a $16.2 million decrease in professional and outside services and compensation expense mainly related to the 2014 ERP system implementation and a $6.5 million decrease in labor, benefits and employee expenses. These decreases were partially offset by an $11.2 million pension curtailment loss recognized in the second quarter of 2015 related to changes in the Company's pension plan (see Note 13 – Employee Benefits in Part 1, Item 1 of this Quarterly Report on Form 10-Q for additional information) and a $5.3 million increase in restructuring costs and severance payments related to workforce reduction efforts in the first quarter of 2015 and the Tulsa office closure in the third quarter of 2015 (see Note 9 – Restructuring Costs in Part 1, Item 1 of this Quarterly Report on Form 10-Q for additional information).

Net gain (loss) from asset sales. QEP recognized a gain on sale of assets of $12.9 million during the third quarter of 2015 compared to a loss on sale of $11.8 million in the third quarter of 2014. The gain on sale of assets recognized during the third quarter of 2015 was primarily due to a $13.1 million gain in post-closing adjustments related to QEP Energy's 2014 Midcontinent property sales, partially offset by a loss in post-closing adjustments related to the Midstream Sale in 2014. The loss on sale recognized during the third quarter of 2014 primarily related to post-closing adjustments on QEP Energy's 2014 Midcontinent property sales.

QEP recognized a gain on sale of assets of $6.9 million during the first three quarters of 2015 compared to a loss on sale of assets of $210.3 million in the first three quarters of 2014. The gain on sale of assets recognized during the first three quarters of 2015 was primarily due to an $11.2 million gain in post-closing adjustments related to QEP Energy's 2014 Midcontinent property sales, partially offset by a $5.0 million loss in post-closing adjustments related to the Midstream Sale in 2014. The loss on sale 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.

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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 2015, gains on commodity derivative instruments were $153.6 million, of which $119.8 million were realized gains and $33.8 million were unrealized gains. 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. 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. All of QEP's interest rate swaps were terminated and settled in the fourth quarter of 2014.

During the first three quarters of 2015, gains on commodity derivative instruments were $168.5 million, of which $316.5 million were realized gains, partially offset by $148.0 million of unrealized losses. During the first three quarters of 2014, losses on commodity derivative instruments were $11.1 million, of which $75.9 million were realized losses, partially offset by $64.8 million of unrealized gains. 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.

Interest expense. Interest expense decreased $5.1 million, or 12%, during the three months endedSeptember 30, 2015, compared to the three months endedSeptember 30, 2014. The decrease was attributable to average debt levels in the third quarter of 2015 that were $1,294.9 million, or 37%, lower than average debt levels in the third quarter of 2014. The decrease in average debt levels is primarily related to repaying all outstanding borrowings under the revolving credit facility and repaying the $600.0 million term loan from the proceeds of the Midstream Sale in December 2014.

Interest expense decreased $19.0 million, or 15%, during the nine months endedSeptember 30, 2015, compared to the nine months endedSeptember 30, 2014. The decrease was attributable to average debt levels in the first three quarters of 2015 that were $838.2 million, or 27%, lower than average debt levels in the first three quarters of 2014. The decrease in average debt levels is primarily related to repaying all outstanding borrowings under the revolving credit facility and repaying the $600.0 million term loan from the proceeds of the Midstream Sale in December 2014.

Income taxes. Income tax expense was $8.7 million during the third quarter of 2015 compared to $79.9 million during the third quarter of 2014. The income tax rate was 29.2% during the third quarter of 2015 compared to a rate of 34.2% during the third quarter of 2014. The decrease in income tax rate was primarily the result of a change in the composition of income between subsidiaries and the states in which the subsidiaries are taxed.

Income tax benefit was $61.6 million during the first three quarters of 2015 compared to income tax expense of $26.1 million during the first three quarters of 2014. The income tax rate was 35.7% during the first three quarters of 2015 compared to a rate of 30.2% during the first three quarters of 2014. The income tax benefit recognized in 2015 was primarily the result of a loss before income taxes for the first three quarters of 2015. The increase in income tax rate was primarily the result of a 2014 reduction in the state income tax blended rate and a valuation allowance recorded during the first three quarters of 2014 related to Oklahoma net operating loss carryforwards.

Discontinued operations.Discontinued operations represent results of operations from QEP Field Services, excluding Haynesville Gathering. During the third quarter of 2014, net income from discontinued operations was $17.4 million, primarily attributable to other revenue of $43.1 million, which primarily consists of gathering and processing revenue, and NGL sales revenue of $28.8 million, partially offset by gathering, processing and other expense of $22.7 million, DD&A of $14.3 million and G&A of $11.1 million.

During the first three quarters of 2014, net income from discontinued operations was $58.2 million, primarily attributable to other revenue of $119.9 million, which primarily consists of gathering and processing revenue, and NGL sales revenue of $94.6 million, partially offset by gathering, processing and other expense of $69.8 million, DD&A of $43.1 million and G&A of $34.3 million.

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LIQUIDITY AND CAPITAL RESOURCES

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

The following table provides QEP’s available liquidity and debt to equity ratio compared to December 31, 2014:

	September 30, 2015			December 31, 2014
	(in millions, except %)
Cash and cash equivalents	$	495.8		$	1,160.1
Amount available under the QEP credit facility (1)	1,796.3			1,796.3
Total liquidity	$	2,292.1		$	2,956.4
Total debt	2,218.5			$	2,218.1
Total common shareholders' equity	$	3,972.1		$	4,075.3
Ratio of debt to total capital (2)	36		%	35		%

____________________________

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

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

Credit Facility

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

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

During the nine months endedSeptember 30, 2014, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.22%. At September 30, 2015 and December 31, 2014, QEP had no borrowings outstanding under the credit facility, had $3.7 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement. At October 23, 2015, QEP had no borrowings outstanding under the credit facility and had $4.4 million of letters of credit outstanding under the credit facility.

Senior Notes

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

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

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

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

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

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

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

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Cash Flow from Operating Activities

Cash flows from operations are primarily affected by gas, oil and NGL production volumes and commodity prices (including the effects of settlements of the Company’s derivative contracts) and by changes in working capital. QEP enters into commodity derivative transactions covering a substantial, but varying, portion of its anticipated future gas, oil and NGL production for the next 12 to 24 months.

Net cash from operating activities decreased $945.8 million during the first three quarters of 2015 compared to the first three quarters of 2014, due to a decrease in changes in operating assets and liabilities, lower non-cash adjustments to net income and a net loss incurred during the first three quarters of 2015 compared to net income in the first three quarters of 2014. Changes in operating assets and liabilities decreased $562.1 million, mainly due to a decrease in income taxes payable of $574.0 million, primarily from taxes on the gain on the Midstream Sale, which was paid in 2015. Net cash from operating activities is presented below:

	Nine Months Ended September 30,
	2015			2014		Change
	(in millions)
Net income (loss)	$	(110.8	)	$	118.5	$	(229.3	)
Net income attributable to noncontrolling interest	—			17.6		(17.6		)
Non-cash adjustments to net income	887.8			1,024.6		(136.8		)
Changes in operating assets and liabilities	(503.1		)	59.0		(562.1		)
Net cash (used in) provided by operating activities	$	273.9		$	1,219.7	$	(945.8	)

Cash Flow from Investing Activities

In the first three quarters of 2015, net cash used in investing activities was $880.9 million, compared to $1,460.7 million in the first three quarters of 2014. This decrease in investing activities was due to a 60% decrease in capital expenditures on a cash basis. Capital expenditures decreased primarily because of the Permian Basin Acquisition, which closed in the first quarter of 2014 for a total purchase price of $941.8 million, as well as a reduction in capital activity due to the current price environment. A comparison of capital expenditures for the first three quarters of 2015 and 2014 and a forecast for calendar year 2015 are presented in the table below:

	Nine Months Ended								Current Forecast Twelve Months Ended
	September 30,
	2015		2014			Change			December 31, 2015
	(in millions)
QEP Energy	$	812.3	$	2,225.9		$	(1,413.6	)	$	1,012.5
QEP Marketing and Other	4.9		10.1			(5.2		)	7.5
Continuing Operations	817.2		2,236.0			(1,418.8		)	1,020.0
Discontinued Operations	—		50.6			(50.6		)	—
Total accrued capital expenditures	817.2		2,286.6			(1,469.4		)	1,020.0
Change in accruals	68.9		(66.5		)	135.4			—
Total cash capital expenditures	$	886.1	$	2,220.1		$	(1,334.0	)	$	1,020.0

In the first three quarters of 2015, QEP Energy's capital expenditures, on an accrual basis, were $812.3 million, a decrease of $1,413.6 million compared to the first three quarters of 2014, primarily driven by the Permian Basin Acquisition which occurred in 2014 for a total purchase price of $941.8 million. In addition, capital expenditures decreased $280.6 million in the Williston Basin, $96.7 million in Pinedale and $49.8 million in the Permian Basin due to reductions in QEP's operations in response to the current price environment and $42.8 million in the Midcontinent due to 2014 divestitures. During the first three quarters of 2015, QEP Energy had acquisitions of approximately $23.5 million.

At September 30, 2015, the midpoint of our forecasted capital investment for 2015 is approximately $1.0 billion. QEP intends to fund capital expenditures with cash flow from operating activities, cash on hand and, if needed, borrowings under its

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revolving credit facility. As a result of the decline in oil and gas prices, forecasted capital investment for drilling and completion activities in 2015 is expected to be significantly lower than in 2014. QEP plans minimal capital expenditures for the Haynesville Shale and other dry-gas development areas in 2015 and plans to focus investment during 2015 on higher return projects, including oil-directed horizontal drilling in the Williston Basin and the Permian Basin. QEP Energy has allocated approximately 96% of its forecasted 2015 drilling and completion capital expenditure budget to oil and liquids-rich gas plays. QEP plans to invest approximately $7.5 million in capital expenditures related to corporate activities. The aggregate levels of capital expenditures for 2015 and the allocation of those expenditures are dependent on a variety of factors, including drilling results, gas, oil and NGL prices, industry conditions, the extent to which properties or working interests are acquired, the availability of capital resources to fund the expenditures and changes in management’s business assessments as to where QEP’s capital can be most profitably deployed. Accordingly, the actual levels of capital expenditures and the allocation of those expenditures may vary materially from QEP’s estimates.

Cash Flow from Financing Activities

In the first three quarters of 2015, net cash used in financing activities was $57.3 million compared to net cash provided by financing activities of $229.1 million in the first three quarters of 2014. During the first three quarters of 2015, QEP had checks outstanding in excess of cash balances of $41.9 million and $10.6 million of regular quarterly dividend payments. During the first three quarters of 2014, QEP had borrowings from the credit facility of $4,509.0 million (offset by repayments on the credit facility of $4,461.5 million) as well as an additional issuance of $300.0 million under its term loan, which were used to fund the Permian Basin Acquisition. These borrowings were offset by checks outstanding in excess of cash balances of $81.1 million, $23.3 million of distributions to noncontrolling interest, and $10.8 million of regular quarterly dividends payment during the first three quarters of 2014.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

QEP’s primary market risk exposures arise from changes in the market price for gas, oil and NGL, and volatility in interest rates. These risks can affect revenues and cash flows from operating, investing and financing activities. Commodity prices have historically been volatile and are subject to wide fluctuations in response to relatively minor changes in supply and demand. If commodity prices fluctuate significantly, revenues and cash flow may significantly decrease or increase. QEP Energy and QEP Marketing also have long-term contracts for pipeline capacity, and are obligated to pay for transportation services with no guarantee that QEP will be able to fully utilize the contractual capacity of these transportation commitments. In addition, an additional non-cash impairment expense on the Company’s oil and gas properties may be required if future oil and gas commodity prices experience a sustained, significant decline. Furthermore, the Company’s credit facility has a floating interest rate, which exposes 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 and collars to manage commodity price risk and periodically interest rate swaps to manage interest rate risk.

Commodity Price Risk Management

QEP uses commodity price derivative instruments in the normal course of business to reduce the risk of adverse commodity price movements. However, these arrangements typically limit future gains from favorable price movements. The types of commodity derivative instruments currently utilized by the Company are fixed-price swaps and collars. The volume of commodity derivative instruments utilized by the Company may vary from year-to-year based on QEP's forecasted production. The 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, 2015, QEP held commodity price derivative contracts totaling 123.8 million MMBtu of gas and 6.0 million barrels of oil.

The following table presents QEP's derivative positions as of October 23, 2015. See Note 8 – Derivative Contracts in Part 1, Item 1 of this Quarterly Report on Form 10-Q for open derivative positions as of September 30, 2015.

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QEP Energy Commodity Derivative Swap Positions
Year	Index	Total Volumes	Average Swap price per unit
		(in millions)
Gas sales		(MMBtu)
2015	NYMEX HH	11.6	$	3.48
2015	IFNPCR	7.9	$	3.55
2016	NYMEX HH	22.0	$	3.19
2016	IFNPCR	32.9	$	2.92
2017	NYMEX HH	7.3	$	3.21
Oil Sales		(bbls)
2015	NYMEX WTI	2.6	$	82.09
2015	ICE Brent	0.1	$	104.95
2016	NYMEX WTI	4.8	$	61.40
2017	NYMEX WTI	1.5	$	54.61

QEP Energy Gas Collars
		Total Volume	Average Price		Average Price
Year	Index		Floor		Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2016	NYMEX HH	7.3	$	2.75	$	3.89

QEP Energy Gas Basis Swaps
Year	Index Less Differential	Index	Total Volumes	Weighted Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2015	NYMEX HH	IFNPCR	7.3	$	(0.28	)
2016	NYMEX HH	IFNPCR	7.3	$	(0.20	)

QEP Marketing Commodity Derivative Positions
Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2015	SWAP	IFNPCR	2.4	$	3.28
2016	SWAP	IFNPCR	3.7	$	2.97
Gas purchases			(MMBtu)
2015	SWAP	IFNPCR	1.8	$	2.51

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

	Commodity derivative contracts
	(in millions)
Net fair value of oil and gas derivative contracts outstanding at December 31, 2014	$	348.9
Contracts settled	(316.5		)
Change in oil and gas prices on futures markets	99.1
Contracts added	69.4
Net fair value of oil and gas derivative contracts outstanding at September 30, 2015	$	200.9

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

	September 30, 2015
	(in millions)
Net fair value - asset (liability)	$	200.9
Fair value if market prices of oil and gas and basis differentials decline by 10%	220.9
Fair value if market prices of oil and gas and basis differentials increase by 10%	180.8

Utilizing the actual derivative volumes, a 10% increase in underlying commodity prices would reduce the fair value of these instruments by $20.1 million, while a 10% decrease in underlying commodity prices would increase the fair value of these instruments by $20.0 million as of September 30, 2015. However, a gain or loss eventually would be offset by the actual sales value of the physical production covered by the derivative instruments. For additional information regarding the Company’s commodity derivative transactions, see Note 8 – Derivative Contracts in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Interest Rate Risk Management

The Company’s ability to borrow and the rates offered by lenders can be adversely affected by illiquid credit markets as described in the risk factors in Item 1A of Part I of the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2014. The Company’s credit facility has a floating interest rate, which exposes QEP to interest rate risk. At September 30, 2015, the Company did not have any borrowings outstanding under its revolving credit facility.

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

Forward-Looking Statements

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

• our growth strategies;

• strong liquidity position providing financial flexibility;

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

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

• our continued evaluation of, and ability to pursue, acquisition opportunities;

• inventory of drilling locations;

• drilling plans;

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

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• results from planned drilling operations and production operations;

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

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

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

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

• impact of global geopolitical and macroeconomic events;

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

• pro forma results for acquired properties;

• divestitures of non-core assets;

• expected gain or loss on sale of assets;

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

• timing and impact of proposed environmental legislation and studies;

• compliance with governmental regulations;

• the outcome of contingencies such as legal proceedings;

• assumptions regarding equity compensation;

• recognition of compensation costs related to equity compensation grants;

• expected contributions to our employee benefit plans;

• employee benefit plan losses;

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

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

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

• uncertain tax benefits;

• impact of new accounting pronouncements;

• impact of shutting in wells;

• factors impacting our ability to transport oil and gas;

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

• impact of sale of our midstream business;

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

• factors impacting the timing and amount of share repurchases.

Any or all forward-looking statements may turn out to be incorrect. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Factors that could cause actual results to differ materially include, but are not limited to the following:

• the risk factors discussed in Part I, Item 1A of the Company’s Annual Report on Form 10-K/A for the year ended December 31, 2014 and Part II, Item 1A of this Quarterly Report on Form 10-Q;

• changes in gas, oil and NGL prices;

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

• drilling results;

• shortages of oilfield equipment, services and personnel;

• lack of available pipeline, processing and refining capacity;

• our ability to successfully integrate acquired assets;

• the outcome of contingencies such as legal proceedings;

• permitting delays;

• operating risks such as unexpected drilling conditions;

• weather conditions;

• the availability and cost of debt and equity financing;

• changes in laws or regulations;

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

• derivative activities;

• volatility in the commodity-futures market;

• failure of internal controls and procedures;

• failure of our information technology infrastructure or applications;

• elimination of federal income tax deductions for oil and gas exploration and development costs;

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• regulatory approvals and compliance with contractual obligations;

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

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

• competitive conditions;

• production levels;

• reserve levels; and

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

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

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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

Changes in Internal Controls.

There were no changes in the Company's internal controls over financial reporting that occurred during the quarter ended September 30, 2015, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Yannick Gagné Lawsuit and Related Suits - 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 rail company that transported the crude oil filed for bankruptcy protection following the accident. 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 allege that QEP and the producer defendants, among other things, failed to ensure that the oil was adequately processed to remove volatile gases and vapors, failed to take reasonable care to ensure that the oil was properly labeled and shipped and failed to identify the risk of the train derailment and take action to prevent it. The plaintiffs seek unspecified damages. A court order regarding class certification is pending. Many of the defendants, including QEP, have reached a confidential settlement agreement with trustees in both Canadian and U.S. bankruptcy courts to resolve all of these claims, which is subject to the approval of such courts. During the third quarter of 2015, QEP was served with additional complaints in state and federal courts in Maine, Texas and Illinois, each of which makes similar claims to those in the Yannick Gagné case, and plaintiff's in each matter support the current settlement plans. If the courts approve the current settlement plan, the plan will settle these additional cases.

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ITEM 1A. RISK FACTORS

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

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

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

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

The EPA is also considering other potential regulation of hydraulic fracturing activities. For example, in April 2015, the EPA published proposed pretreatment standards for the oil and gas extraction industry. The proposed regulations would address discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly owned treatment works. The EPA is also collecting information as part of a nationwide study into the effects of hydraulic fracturing on drinking water. In June 2015, the EPA released a draft assessment of the potential impacts to drinking water resources from hydraulic fracturing for public comment and peer review. The results of this study, which has not been finalized, could result in additional regulations, which could lead to operational burdens similar to those described above. The EPA has also issued an advance

51

notice of proposed rulemaking and initiated a public participation process under the Toxic Substances Control Act (TSCA) to seek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanisms for obtaining this information. Additionally, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that the EPA add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals" under the Toxics Release Inventory (TRI) program of the Emergency Planning and Community Right-to-Know Act. The EPA has agreed to respond to the groups’ request by October 30, 2015, and the case has been stayed pending the EPA’s response.

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

Requirements to reduce gas flaring could have an adverse effect on our operations. Wells in the Bakken and Three Forks formations in North Dakota, where QEP has significant operations, produce natural gas as well as crude oil. Constraints in the current gas gathering and processing network in certain areas have resulted in some of that natural gas being flared instead of gathered, processed and sold. In June 2014, the North Dakota Industrial Commission, North Dakota's chief energy regulator, adopted a policy to reduce the volume of natural gas flared from oil wells in the Bakken and Three Forks formations. The Commission is requiring operators to develop gas capture plans that describe how much natural gas is expected to be produced, how it will be delivered to a processor and where it will be processed. Production caps or penalties will be imposed on certain wells that cannot meet the capture goals. The Bureau of Land Management (BLM) has also indicated its intent to pursue a rulemaking related to further controls on the venting and flaring of natural gas on BLM land. A proposed rule has been sent to the White House Office of Management and Budget. 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.

QEP is subject to complex federal, state, tribal, local and other laws and regulations that could adversely affect its cost of doing business and recording of proved reserves. QEP's operations are subject to extensive federal, state, tribal and local tax, energy, environmental, health and safety laws and regulations. The failure to comply with applicable laws and regulations can result in substantial penalties and may threaten the Company's authorization to operate.

Environmental laws and regulations are complex, change frequently and have tended to become more onerous over time. The regulatory burden on the Company's operations increases its cost of doing business and, consequently, affects its profitability. In addition to the costs of compliance, substantial costs may be incurred to take corrective actions at both owned and previously owned facilities. Accidental spills and leaks requiring cleanup may occur in the ordinary course of QEP's business. As standards change, the Company may incur significant costs in cases where past operations followed practices that were considered acceptable at the time, but now require remedial work to meet current standards. Failure to comply with these laws and regulations may result in fines, significant costs for remedial activities, or injunctions that could limit the scope of QEP's planned operations.

In May 2015, the EPA and the Army Corps of Engineers issued a pre-publication final rule defining the jurisdictional “waters of the United States” regulated under the Clean Water Act. The final rule, which has been stayed pending the outcome of litigation, could increase the scope of waters subject to federal jurisdiction under the Clean Water Act.

52

New federal Clean Air Act regulations at 40 C.F.R Part 60, Subpart OOOO (Subpart OOOO) became effective in 2012, with further amendments effective in 2013 and 2014. Subpart OOOO imposes air quality controls and requirements upon QEP's operations and is undergoing further reconsideration by the EPA, which may result in more stringent air quality controls and requirements for QEP’s operations. For example, in September 2015, the EPA published proposed updates to Subpart OOOO to achieve additional methane and volatile organic compound reductions from the oil and natural gas industry. The proposed rule would include, among others, new requirements for finding and repairing leaks at new well sites and green completion requirements for oil wells. Additionally, many states are adopting more stringent air permitting and other air quality control regulations specific to oil and gas exploration, production, gathering and processing that go beyond the requirements of federal regulations.

On December 17, 2014, the EPA proposed to revise and lower the existing 75 parts per billion (ppb) national ambient air quality standard (NAAQS) for ozone under the federal Clean Air Act to a range within 65-70 ppb. On October 1, 2015, the EPA announced its final ruling to lower the standard to 70 ppb. A lowered ozone NAAQS could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which QEP operates. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

In September 2015, the EPA published a proposed rule regarding source determination and permitting requirements for the onshore oil and gas industry under the Clean Air Act. The proposed rule seeks public comment on two approaches for defining the term “adjacent,” which is one of three factors used to determine whether oil and gas equipment and activities are considered part of a source that is subject to major source permitting requirements under the Clean Air Act permitting programs. Depending on the EPA’s final approach, the oil and gas industry could be subject to increased air quality permitting costs and more stringent control requirements.

In September 2015, the EPA also issued a proposed Federal Implementation Plan (FIP) to implement the Federal Minor New Source Review Program in Indian Country for oil and natural gas production. The proposed FIP may apply to QEP’s operations on the Fort Berthold Reservation in the Williston Basin, North Dakota. The proposed FIP would incorporate emission limits and other requirements for various federal air quality standards. By incorporating these requirements, the FIP would apply emission limits for a range of equipment and processes used in oil and natural gas production.

FERC has jurisdiction over the operation of QEP Marketing's Clear Creek underground gas storage facility by virtue of the facility's connection to interstate pipelines (also subject to FERC jurisdiction) at both its inlet and outlet. Clear Creek is subject to specific FERC regulations governing interstate transmission facilities and activities, including but not limited to rates charged for transmission, open access/non-discrimination, and public disclosure via an electronic bulletin board of daily capacity and flows.

In May 2015, the U.S. Department of Transportation issued its final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing, and certification requirements.

53

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

The following repurchases of QEP shares were made by QEP in association with vested restricted stock awards withheld for

taxes.

Period	Total shares purchased (1)	Weighted- average price paid per share		Total shares purchased as part of publicly announced plans or programs	Remaining dollar amount that may be purchased under the plans or programs
July 1, 2015 - July 31, 2015	—	$	—	—	$	400.3
August 1, 2015 - August 31, 2015	34	13.63		—	400.3
September 1, 2015 - September 30, 2015	31,659	13.12		—	400.3

____________________________

⁽¹⁾  All of the 31,693 shares purchased during the three-month period ended September 30, 2015, were acquired from employees in connection with the settlement of income tax and related benefit withholding obligations arising from vesting in restricted stock grants. These shares were not part of a publicly announced program to purchase common stock. Stock options that are net settled do not involve the acquisition of any shares.

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

54

ITEM 6. EXHIBITS

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

Exhibit No.	Exhibits
3.1	Certificate of Incorporation dated May 18, 2010. (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on May 24, 2010.)
3.2	Amended and Restated Bylaws, deemed effective October 27, 2014. (Incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K filed with the Securities and Exchange Commission on October 29, 2014.)
31.1	Certification signed by Charles B. Stanley, QEP Resources, Inc.’s Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification signed by Richard J. Doleshek, QEP Resources, Inc.’s Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification signed by Charles B. Stanley and Richard J. Doleshek, QEP Resources, Inc.’s Chief Executive Officer and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

____________________________

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

55

SIGNATURES

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

	QEP RESOURCES, INC.
	(Registrant)
October 28, 2015	/s/ Charles B. Stanley
	Charles B. Stanley,
	Chairman, President and Chief Executive Officer
October 28, 2015	/s/ Richard J. Doleshek
	Richard J. Doleshek,
	Executive Vice President and Chief Financial Officer

56

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.

October 28, 2015

/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.

October 28, 2015

/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, 2015, as filed with the Securities and Exchange Commission on the date hereof (the Report), Charles B. Stanley, Chairman, President and Chief Executive Officer of the Company, and Richard J. Doleshek, Executive Vice President and Chief Financial Officer, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge:

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

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

	QEP RESOURCES, INC.
October 28, 2015
	/s/ Charles B. Stanley
	Charles B. Stanley
	Chairman, President and Chief Executive Officer
October 28, 2015
	/s/ Richard J. Doleshek
	Richard J. Doleshek
	Executive Vice President and Chief Financial Officer

XML

Discontinued Operations (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Value of midstream business sold					$ 2,500.0
Debt Refinanced In Business Sale					230.0
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax					1,800.0
Discontinued Operation, Amount of Continuing Cash Flows after Disposal	$ 24.9	$ 31.4	$ 94.2	$ 105.4
Depreciation, depletion and amortization	$ 238.1	251.4	$ 649.3	712.5
Employee Retention Bonus Cost					$ 10.4
Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income (Loss) Attributable to Parent		7.9		20.4
Depreciation, depletion and amortization		14.3		43.1
Payments to Acquire Oil and Gas Property and Equipment				45.6
Employee Retention Bonus Cost		$ 2.3		$ 7.1

XML

Share-Based Compensation (Narrative) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for future grants	9.1		9.1
Share-based compensation			$ 23.3	$ 23.7
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of options exercised			0.1	$ 0.6
Unrecognized compensation costs	$ 2.6		$ 2.6
Weighted average period for recognition of equity-based compensation expense			2 years 1 month 19 days
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants			$ 21.02	$ 31.82
Unrecognized compensation costs	27.5		$ 27.5
Weighted average period for recognition of equity-based compensation expense			2 years 2 months 26 days
Award vesting period			3 years
Total fair value of stock that vested during the period			$ 21.0	$ 20.2
Performance Share Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value, grants			$ 21.69	$ 31.71
Unrecognized compensation costs	2.7		$ 2.7
Weighted average period for recognition of equity-based compensation expense			1 year 10 months 26 days
Continuing Operations [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	$ 7.7	$ 8.1	$ 23.3	$ 20.4
Discontinued Operations [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation		$ 1.0		$ 3.3

XML

Derivative Contracts Gain (Loss) in Statement of Financial Performance (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative [Line Items]
Realized gain (loss) derivative contracts not designated as hedging instruments	$ 119.8	$ (8.4)	$ 316.5	$ (79.1)
Unrealized gain (loss) derivative contracts not designated as hedging instruments	33.8	164.1	(148.0)	65.9
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	153.6	155.7	168.5	(13.2)
Realized and unrealized gains on commodity derivative instruments [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	119.8	(7.1)	316.5	(75.9)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	33.8	161.5	(148.0)	64.8
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	153.6	154.4	168.5	(11.1)
Natural gas derivative contracts [Member] | Realized and unrealized gains on commodity derivative instruments [Member] | QEP Energy [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	23.1	5.5	69.1	(23.3)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	3.6	27.6	(19.5)	9.5
Natural gas derivative contracts [Member] | Realized and unrealized gains on commodity derivative instruments [Member] | QEP Marketing [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	(0.1)	(0.4)	2.1	(2.4)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	1.4	0.7	(0.5)	1.0
Oil derivative contracts [Member] | Realized and unrealized gains on commodity derivative instruments [Member] | QEP Energy [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	96.8	(12.2)	245.3	(50.2)
Unrealized gain (loss) on commodity derivative contracts not designated as hedging instruments	28.8	133.2	(128.0)	54.3
Interest Rate Swap [Member] | Realized And Unrealized Gains Losses On Interest Rate Swaps [Member]
Derivative [Line Items]
Realized gain (loss) on commodity derivative contracts not designated as hedging instruments	0.0	(1.3)	0.0	(3.2)
Gain (Loss) on Interest Rate Derivative Instruments Not Designated as Hedging Instruments	0.0	2.6	0.0	1.1
Realized and Unrealized Gain (Loss) on Commodity Derivative Contracts Not Designated as Hedging Instruments	$ 0.0	$ 1.3	$ 0.0	$ (2.1)

XML

Share-Based Compensation Fair Value Of Options Granted And Major Assumptions Used (Details)	9 Months Ended
	Sep. 30, 2015 $ / shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted-average grant-date fair value of awards granted during the period	$ 6.82
Weighted-average risk-free interest rate	1.38%
Weighted-average expected price volatility	36.80%
Expected dividend yield	0.37%
Expected term in years at the date of grant	4 years 6 months

XML

Derivative Contracts Schedule Of Commodity Derivative Contracts (Details) MMBTU in Millions	9 Months Ended
	Sep. 30, 2015 USD ($) MMBTU $ / MMBTU
Natural Gas Sales [Member] | QEP Energy [Member] | Year 2015 [Member] | NYMEX HH [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	NYMEX HH
Derivative, Nonmonetary Notional Amount	17.5
Underlying, Derivative Asset | $ / MMBTU	3.48
Natural Gas Sales [Member] | QEP Energy [Member] | Year 2015 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	IFNPCR
Derivative, Nonmonetary Notional Amount	12.0
Underlying, Derivative Asset | $ / MMBTU	3.55
Natural Gas Sales [Member] | QEP Energy [Member] | Year 2016 [Member] | NYMEX HH [Member]
Derivative [Line Items]
Derivative Contract Year	2016
Derivative, Underlying Basis	NYMEX HH
Derivative, Nonmonetary Notional Amount	22.0
Underlying, Derivative Asset | $ / MMBTU	3.19
Natural Gas Sales [Member] | QEP Energy [Member] | Year 2016 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2016
Derivative, Underlying Basis	IFNPCR
Derivative, Nonmonetary Notional Amount	32.9
Underlying, Derivative Asset | $ / MMBTU	2.92
Natural Gas Sales [Member] | QEP Energy [Member] | Year 2017 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2017
Derivative, Underlying Basis	NYMEX HH
Derivative, Nonmonetary Notional Amount	7.3
Underlying, Derivative Asset | $ / MMBTU	3.21
Natural Gas Sales [Member] | QEP Marketing [Member] | Year 2015 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	IFNPCR
Derivative, Nonmonetary Notional Amount	2.4
Underlying, Derivative Asset | $ / MMBTU	3.25
Natural Gas Sales [Member] | QEP Marketing [Member] | Year 2016 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2016
Derivative, Underlying Basis	IFNPCR
Derivative, Nonmonetary Notional Amount	2.9
Underlying, Derivative Asset | $ / MMBTU	3.06
Purchased Gas and Oil Expense [Member] | QEP Marketing [Member] | Year 2015 [Member] | IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	IFNPCR
Derivative, Nonmonetary Notional Amount	1.2
Underlying, Derivative Asset | $ / MMBTU	2.75
Natural Gas [Member] | QEP Energy [Member] | Year 2016 [Member] | NYMEX HH [Member]
Derivative [Line Items]
Derivative Contract Year	2016
Derivative, Underlying Basis	NYMEX HH
Derivative, Nonmonetary Notional Amount	7.3
Derivative Average Price Floor | $	$ 2.75
Derivative Average Price Ceiling | $	$ 3.89
Oil Sales [Member] | QEP Energy [Member] | Year 2015 [Member] | NYMEX WTI [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	NYMEX WTI
Derivative, Nonmonetary Notional Amount	2.6
Underlying, Derivative Asset | $ / MMBTU	82.09
Oil Sales [Member] | QEP Energy [Member] | Year 2015 [Member] | BRENT ICE [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	ICE Brent
Derivative, Nonmonetary Notional Amount	0.1
Underlying, Derivative Asset | $ / MMBTU	104.95
Oil Sales [Member] | QEP Energy [Member] | Year 2016 [Member] | NYMEX WTI [Member]
Derivative [Line Items]
Derivative Contract Year	2016
Derivative, Underlying Basis	NYMEX WTI
Derivative, Nonmonetary Notional Amount	3.3
Underlying, Derivative Asset | $ / MMBTU	65.43
Gas Basis Swaps [Member] | QEP Energy [Member] | Year 2015 [Member] | NYMEX HH LESS IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2015
Derivative, Underlying Basis	IFNPCR
Derivative, Nonmonetary Notional Amount	11.0
Underlying, Derivative Asset | $ / MMBTU	(0.28)
Gas Basis Swaps [Member] | QEP Energy [Member] | Year 2016 [Member] | NYMEX HH LESS IFNPCR [Member]
Derivative [Line Items]
Derivative Contract Year	2016
Derivative, Underlying Basis	IFNPCR
Derivative, Nonmonetary Notional Amount	7.3
Underlying, Derivative Asset | $ / MMBTU	(0.20)

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Operations by Line of Business (Tables)

9 Months Ended

Sep. 30, 2015

Segment Reporting Information [Line Items]

Summary of operating results by line of business

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

	QEP Energy			QEP Marketing  and Other			Eliminations			QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	382.6		$	154.1		$	—		$	536.7
From affiliated customers	—			263.4			(263.4		)	—
Total Revenues	382.6			417.5			(263.4		)	536.7
OPERATING EXPENSES
Purchased gas and oil expense	23.6			412.1			(260.6		)	175.1
Lease operating expense	56.7			—			—			56.7
Gas, oil and NGL transportation and other handling costs	80.1			—			(2.0		)	78.1
Gathering and other expense	—			1.3			—			1.3
General and administrative	41.2			1.6			(0.8		)	42.0
Production and property taxes	29.9			0.3			—			30.2
Depreciation, depletion and amortization	235.7			2.4			—			238.1
Impairment and exploration expense	15.8			—			—			15.8
Total Operating Expenses	483.0			417.7			(263.4		)	637.3
Net gain (loss) from asset sales	13.2			(0.3		)	—			12.9
OPERATING INCOME (LOSS)	(87.2		)	(0.5		)	—			(87.7		)
Realized and unrealized gains (losses) on derivative contracts	152.3			1.3			—			153.6
Interest and other income	0.9			52.0			(52.6		)	0.3
Interest expense	(52.4		)	(36.6		)	52.6			(36.4		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	13.6			16.2			—			29.8
Income tax (provision) benefit	(2.8		)	(5.9		)	—			(8.7		)
NET INCOME (LOSS)	$	10.8		$	10.3		$	—		$	21.1

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

	QEP Energy			QEP Marketing  and Other			Eliminations			Discontinued Operations		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 and oil 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	49.0			1.4			(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	527.3			673.6			(417.8		)	—		783.1
Net gain (loss) from assets sales	(11.9		)	0.1			—			—		(11.8		)
OPERATING INCOME (LOSS)	113.7			1.4			—			—		115.1
Realized and unrealized gains (losses) 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 (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	214.8			18.8			—			—		233.6
Income tax (provision) benefit	(69.1		)	(10.8		)	—			—		(79.9		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	145.7			8.0			—			—		153.7
Net income from discontinued operations, net of income tax	—			—			—			17.4		17.4
NET INCOME (LOSS)	$	145.7		$	8.0		$	—		$	17.4	$	171.1

The following table is a summary of operating results for the nine months endedSeptember 30, 2015, by line of business:

	QEP Energy			QEP Marketing  and Other			Eliminations			QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	1,143.8		$	493.1		$	—		$	1,636.9
From affiliated customers	—			719.0			(719.0		)	—
Total Revenues	1,143.8			1,212.1			(719.0		)	1,636.9
OPERATING EXPENSES
Purchased gas and oil expense	71.6			1,200.3			(710.2		)	561.7
Lease operating expense	175.6			—			—			175.6
Gas, oil and NGL transportation and other handling costs	223.0			—			(6.8		)	216.2
Gathering and other expense	—			4.4			—			4.4
General and administrative	137.4			5.3			(2.0		)	140.7
Production and property taxes	88.6			2.1			—			90.7
Depreciation, depletion and amortization	641.6			7.7			—			649.3
Impairment and exploration expense	38.2			—			—			38.2
Total Operating Expenses	1,376.0			1,219.8			(719.0		)	1,876.8
Net gain (loss) from asset sales	11.9			(5.0		)	—			6.9
OPERATING INCOME (LOSS)	(220.3		)	(12.7		)	—			(233.0		)
Realized and unrealized gains (losses) on derivative contracts	166.9			1.6			—			168.5
Interest and other income (expense)	0.5			153.1			(152.1		)	1.5
Interest expense	(152.2		)	(109.3		)	152.1			(109.4		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(205.1		)	32.7			—			(172.4		)
Income tax (provision) benefit	73.2			(11.6		)	—			61.6
NET INCOME (LOSS)	$	(131.9	)	$	21.1		$	—		$	(110.8	)

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

	QEP Energy			QEP Marketing  and Other			Eliminations			Discontinued Operations		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 and oil 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	146.5			3.1			(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	1,529.0			1,788.3			(1,132.9		)	—		2,184.4
Net gain (loss) from assets sales	(210.3		)	—			—			—		(210.3		)
OPERATING INCOME (LOSS)	214.0			6.0			—			—		220.0
Realized and unrealized gains (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 (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	49.4			37.0			—			—		86.4
Income tax (provision) benefit	(9.0		)	(17.1		)	—			—		(26.1		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	40.4			19.9			—			—		60.3
Net income from discontinued operations, net of income tax	—			—			—			58.2		58.2
NET INCOME (LOSS)	$	40.4		$	19.9		$	—		$	58.2	$	118.5

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Share-Based Compensation Schedule of Restricted Stock Transactions (Details) - Restricted Stock [Member] - $ / shares	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period	1,426,453
Shares granted	1,484,567
Shares vested	(683,562)
Shares forfeited	(93,425)
Unvested balance at end of period	2,134,033
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted average grant date fair value, beginning of period	$ 31.02
Weighted average grant date fair value, grants	21.02	$ 31.82
Weighted average grant date fair value, vested	30.67
Weighted average grant date fair value, forfeited	27.20
Weighted average grant date fair value, end of period	$ 24.35

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2015

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,
	2015	2014	2015	2014
	(in millions)
Weighted-average basic common shares outstanding	176.7	180.1	176.5	180.0
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	—	0.5	—	0.4
Average diluted common shares outstanding	176.7	180.6	176.5	180.4

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Restructuring Costs Restructuring Reserve Roll Forward (Details) $ in Millions	9 Months Ended
	Sep. 30, 2015 USD ($)
Restructuring Reserve [Roll Forward]
Balance at beginning of period	$ 0.0
Costs incurred and charged to expense	6.2
Costs paid or otherwise settled	(3.8)
Balance at end of period	$ 2.4

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Asset Retirement Obligations (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation, Current	$ 0.8	$ 1.3
ARO Liability [Roll Forward]
ARO liability, Beginning Balance	195.1
Accretion	6.4
Additions	3.0
Revisions	0.3
Liabilities related to divestitures	(14.8)
Liabilities settled	(1.5)
ARO liability, Ending Balance	$ 188.5

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Acquisitions & Divestitures Supplemental Proforma Results of Operations (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Business Acquisition [Line Items]
Total Revenues	$ 536.7	$ 910.0	$ 1,636.9	$ 2,614.7
Net income	$ 21.1	$ 171.1	$ (110.8)	$ 118.5
Earnings Per Share, Basic	$ 0.12	$ 0.95	$ (0.63)	$ 0.66
Earnings Per Share, Diluted	$ 0.12	$ 0.94	$ (0.63)	$ 0.66
Permian Basin Acquisition [Member]
Business Acquisition [Line Items]
Total Revenues				$ 2,614.7
Net income				$ 118.5
Earnings Per Share, Basic				$ 0.66
Earnings Per Share, Diluted				$ 0.66
Business Acquisition, Pro Forma Revenue				$ 2,640.8
Business Acquisition, Pro Forma Net Income (Loss)				$ 125.5
Business Acquisition, Pro Forma Earnings Per Share, Basic				$ 0.70
Business Acquisition, Pro Forma Earnings Per Share, Diluted				$ 0.70

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Debt Schedule of Debt Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Less unamortized discount	$ (3.3)	$ (3.7)
Long-term Debt	2,218.5	2,218.1
Less: current portion of long-term debt	(176.7)	0.0
Total long-term debt outstanding	2,041.8	2,218.1
Revolving Credit Facility due 2019 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	0.0	0.0
6.05% Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	176.8	176.8
6.80% Senior Notes due 2018 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	134.0	134.0
6.80% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	136.0	136.0
6.875% Senior Notes Due 2021 [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	625.0	625.0
5.375% 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

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Operations by Line of Business (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues
Total Revenues	$ 536.7	$ 910.0	$ 1,636.9	$ 2,614.7
Operating expenses
Purchased gas and oil expense	175.1	288.4	561.7	775.5
Lease operating expense	56.7	61.1	175.6	177.0
Natural gas, oil and NGL transportation and other handling costs	78.1	71.1	216.2	198.5
Gathering, processing and other	1.3	1.4	4.4	4.8
General and administrative	42.0	49.4	140.7	147.0
Production and property taxes	30.2	59.4	90.7	160.8
Depreciation, depletion and amortization	238.1	251.4	649.3	712.5
Other operating expenses	15.8	0.9	38.2	8.3
Total operating expenses	637.3	783.1	1,876.8	2,184.4
Net gain (loss) from asset sales	12.9	(11.8)	6.9	(210.3)
Operating income (loss)	(87.7)	115.1	(233.0)	220.0
Realized and unrealized gains (losses) on derivative contracts	153.6	155.7	168.5	(13.2)
Interest and other income (expense)	0.3	4.2	1.5	7.8
Income from unconsolidated affiliates	0.0	0.1	0.0	0.2
Interest expense	(36.4)	(41.5)	(109.4)	(128.4)
Income (loss) before income taxes	29.8	233.6	(172.4)	86.4
Income taxes	(8.7)	(79.9)	61.6	(26.1)
Income from continuing operations	21.1	153.7	(110.8)	60.3
Net income from discontinued operations, net of income tax	0.0	17.4	0.0	58.2
Net income (loss)	21.1	171.1	(110.8)	118.5
Unaffiliated customers [Member]
Revenues
Total Revenues	536.7	910.0	1,636.9	2,614.7
Affiliated customers [Member]
Revenues
Total Revenues	0.0	0.0	0.0	0.0
QEP Energy [Member]
Revenues
Total Revenues	382.6	652.9	1,143.8	1,953.3
Operating expenses
Purchased gas and oil expense	23.6	32.8	71.6	120.9
Lease operating expense	56.7	61.1	175.6	177.0
Natural gas, oil and NGL transportation and other handling costs	80.1	75.2	223.0	211.8
Gathering, processing and other	0.0	0.0	0.0	0.0
General and administrative	41.2	49.0	137.4	146.5
Production and property taxes	29.9	59.3	88.6	159.8
Depreciation, depletion and amortization	235.7	249.0	641.6	704.7
Other operating expenses	15.8	0.9	38.2	8.3
Total operating expenses	483.0	527.3	1,376.0	1,529.0
Net gain (loss) from asset sales	13.2	(11.9)	11.9	(210.3)
Operating income (loss)	(87.2)	113.7	(220.3)	214.0
Realized and unrealized gains (losses) on derivative contracts	152.3	154.1	166.9	(9.7)
Interest and other income (expense)	0.9	3.9	0.5	7.4
Income from unconsolidated affiliates		0.1		0.2
Interest expense	(52.4)	(57.0)	(152.2)	(162.5)
Income (loss) before income taxes	13.6	214.8	(205.1)	49.4
Income taxes	(2.8)	(69.1)	73.2	(9.0)
Income from continuing operations		145.7		40.4
Net income from discontinued operations, net of income tax		0.0		0.0
Net income (loss)	10.8	145.7	(131.9)	40.4
QEP Energy [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	382.6	652.9	1,143.8	1,953.3
QEP Energy [Member] | Affiliated customers [Member]
Revenues
Total Revenues	0.0	0.0	0.0	0.0
QEP Marketing and Other [Member]
Revenues
Total Revenues	417.5	674.9	1,212.1	1,794.3
Operating expenses
Purchased gas and oil expense	412.1	668.3	1,200.3	1,771.6
Lease operating expense	0.0	0.0	0.0	0.0
Natural gas, oil and NGL transportation and other handling costs	0.0	0.0	0.0	0.0
Gathering, processing and other	1.3	1.4	4.4	4.8
General and administrative	1.6	1.4	5.3	3.1
Production and property taxes	0.3	0.1	2.1	1.0
Depreciation, depletion and amortization	2.4	2.4	7.7	7.8
Other operating expenses	0.0	0.0	0.0	0.0
Total operating expenses	417.7	673.6	1,219.8	1,788.3
Net gain (loss) from asset sales	(0.3)	0.1	(5.0)	0.0
Operating income (loss)	(0.5)	1.4	(12.7)	6.0
Realized and unrealized gains (losses) on derivative contracts	1.3	1.6	1.6	(3.5)
Interest and other income (expense)	52.0	56.6	153.1	162.0
Income from unconsolidated affiliates		0.0		0.0
Interest expense	(36.6)	(40.8)	(109.3)	(127.5)
Income (loss) before income taxes	16.2	18.8	32.7	37.0
Income taxes	(5.9)	(10.8)	(11.6)	(17.1)
Income from continuing operations		8.0		19.9
Net income from discontinued operations, net of income tax		0.0		0.0
Net income (loss)	10.3	8.0	21.1	19.9
QEP Marketing and Other [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	154.1	257.1	493.1	661.4
QEP Marketing and Other [Member] | Affiliated customers [Member]
Revenues
Total Revenues	263.4	417.8	719.0	1,132.9
Elimination [Member]
Revenues
Total Revenues	(263.4)	(417.8)	(719.0)	(1,132.9)
Operating expenses
Purchased gas and oil expense	(260.6)	(412.7)	(710.2)	(1,117.0)
Lease operating expense	0.0	0.0	0.0	0.0
Natural gas, oil and NGL transportation and other handling costs	(2.0)	(4.1)	(6.8)	(13.3)
Gathering, processing and other	0.0	0.0	0.0	0.0
General and administrative	(0.8)	(1.0)	(2.0)	(2.6)
Production and property taxes	0.0	0.0	0.0	0.0
Depreciation, depletion and amortization	0.0	0.0	0.0	0.0
Other operating expenses	0.0	0.0	0.0	0.0
Total operating expenses	(263.4)	(417.8)	(719.0)	(1,132.9)
Net gain (loss) from asset sales	0.0	0.0	0.0	0.0
Operating income (loss)	0.0	0.0	0.0	0.0
Realized and unrealized gains (losses) on derivative contracts	0.0	0.0	0.0	0.0
Interest and other income (expense)	(52.6)	(56.3)	(152.1)	(161.6)
Income from unconsolidated affiliates		0.0		0.0
Interest expense	52.6	56.3	152.1	161.6
Income (loss) before income taxes	0.0	0.0	0.0	0.0
Income taxes	0.0	0.0	0.0	0.0
Income from continuing operations		0.0		0.0
Net income from discontinued operations, net of income tax		0.0		0.0
Net income (loss)	0.0	0.0	0.0	0.0
Elimination [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues	0.0	0.0	0.0	0.0
Elimination [Member] | Affiliated customers [Member]
Revenues
Total Revenues	$ (263.4)	(417.8)	$ (719.0)	(1,132.9)
Discontinued Operations [Member]
Revenues
Total Revenues		0.0		0.0
Operating expenses
Purchased gas and oil expense		0.0		0.0
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		0.0		0.0
General and administrative		0.0		0.0
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		0.0		0.0
Net gain (loss) from asset sales		0.0		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 (expense)		0.0		0.0
Income from unconsolidated affiliates		0.0		0.0
Interest expense		0.0		0.0
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 from discontinued operations, net of income tax		17.4		58.2
Net income (loss)		17.4		58.2
Discontinued Operations [Member] | Unaffiliated customers [Member]
Revenues
Total Revenues		0.0		0.0
Discontinued Operations [Member] | Affiliated customers [Member]
Revenues
Total Revenues		$ 0.0		$ 0.0

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Derivative Contracts Schedule of Derivatives Financial Statement Presentation (Details) - Fair Value, Inputs, Level 2 [Member] - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 203.4	$ 349.2
Derivative Liability, Fair Value, Gross	2.5	0.3
Commodity Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	203.4	349.2
Derivative Liability, Fair Value, Gross	2.5	0.3
Commodity Contract [Member] | Short-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	186.4	339.3
Derivative Liability, Fair Value, Gross	2.5	0.3
Commodity Contract [Member] | Long-term [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Asset	17.0	9.9
Derivative Liability, Fair Value, Gross	$ 0.0	$ 0.0

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Basis of Presentation of Interim Consolidated Financial Statements

9 Months Ended

Sep. 30, 2015

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/A for the year ended December 31, 2014.

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

Impairment of Long-Lived Assets

During the three months endedSeptember 30, 2015, QEP Energy recorded impairment charges of $15.0 million, of which $14.4 million was related to proved properties due to lower future oil and gas prices and $0.6 million was related to expiring leaseholds on unproved properties. Of the $14.4 million impairment on proved properties, $13.1 million related to impairments on Other Northern properties, $1.0 million related to impairments on QEP's remaining Midcontinent properties and $0.3 million related to impairments on Permian Basin properties.

During the nine months endedSeptember 30, 2015, QEP Energy recorded impairment charges of $35.5 million, of which $33.8 million was related to proved properties due to lower future oil and gas prices and $1.7 million was related to expiring leaseholds on unproved properties. Of the $33.8 million impairment on proved properties, $18.0 million related to impairments on Other Northern properties, $15.5 million related to impairments on QEP's remaining Midcontinent properties and $0.3 million related to impairments on Permian Basin properties.

Uncertain Tax Position

As of September 30, 2015, QEP had $15.6 million of unrecognized tax benefits related to uncertain tax positions for asset sales that occurred in 2014, which were recorded within "Deferred income taxes" on the Condensed Consolidated Balance Sheet. At December 31, 2014, no uncertain tax positions had been recorded. The uncertain tax positions the Company reported during the third quarter 2015 were expensed during the year ended December 31, 2014. The benefits of uncertain tax positions taken or expected to be taken on income tax returns is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authorities. During the nine months endedSeptember 30, 2015, the Company incurred $0.3 million of interest expense related to uncertain tax positions, which was recorded within "Interest expense" on the Condensed Consolidated Statement of Operations.

New Accounting Pronouncements

In September 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) No. 2015-16,Business Combinations (Topic 805),which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not expect that there will be a significant impact on the Company's Consolidated Financial Statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In July 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606), in which the FASB delayed the effective date of the new revenue standard by one year and the amendments are now effective prospectively for reporting periods beginning after December 15, 2017, and early adoption is not permitted. The Company is currently assessing the impact on the Company's Consolidated Financial Statements.

In May 2015, the FASB issued ASU No. 2015-07,Fair Value Measurement (Topic 820), which allows reporting entities to exclude investments measured at net asset value per share under the existing practical expedient in ASC 820 from the fair value hierarchy. It also limits disclosures to investments for which the entity has elected to measure the fair value using the practical expedient. The amendment will be effective retrospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not expect that there will be a significant impact on the Company's Consolidated Financial Statements.

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

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

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

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

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Fair Value Measurements Fair Value of Financial Assets and Liabilities (Details) - Fair Value, Measurements, Recurring [Member] - USD ($) $ in Millions		Sep. 30, 2015	Dec. 31, 2014
Financial Assets
Net amount of derivative assets presented on condensed consolidated balance sheets		$ 200.9	$ 348.9
Financial liabilities
Net amount of derivative liabilities presented on condensed consolidated balance sheets		0.0	0.0
Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		203.4	349.2
Financial liabilities
Derivative Liability, Fair Value, Gross		2.5	0.3
Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Netting Adjustments [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	[1]	(2.5)	(0.3)
Financial liabilities
Derivative Liability, Fair Value, Gross	[1]	(2.5)	(0.3)
Commodity Contract [Member] | Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		203.4	349.2
Financial liabilities
Derivative Liability, Fair Value, Gross		2.5	0.3
Long-term [Member] | Commodity Contract [Member]
Financial Assets
Net amount of derivative assets presented on condensed consolidated balance sheets		17.0	9.9
Financial liabilities
Net amount of derivative liabilities presented on condensed consolidated balance sheets		0.0
Long-term [Member] | Commodity Contract [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0
Long-term [Member] | Commodity Contract [Member] | Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		17.0	9.9
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Long-term [Member] | Commodity Contract [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0
Long-term [Member] | Commodity Contract [Member] | Netting Adjustments [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	[1]	0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross	[1]	0.0
Short-term [Member] | Commodity Contract [Member]
Financial Assets
Net amount of derivative assets presented on condensed consolidated balance sheets		183.9	339.0
Financial liabilities
Net amount of derivative liabilities presented on condensed consolidated balance sheets		0.0	0.0
Short-term [Member] | Commodity Contract [Member] | Level 1 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Short-term [Member] | Commodity Contract [Member] | Level 2 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		186.4	339.3
Financial liabilities
Derivative Liability, Fair Value, Gross		2.5	0.3
Short-term [Member] | Commodity Contract [Member] | Level 3 [Member]
Financial Assets
Derivative Asset, Fair Value, Gross		0.0	0.0
Financial liabilities
Derivative Liability, Fair Value, Gross		0.0	0.0
Short-term [Member] | Commodity Contract [Member] | Netting Adjustments [Member]
Financial Assets
Derivative Asset, Fair Value, Gross	[1]	(2.5)	(0.3)
Financial liabilities
Derivative Liability, Fair Value, Gross	[1]	$ (2.5)	$ (0.3)

[1] The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Condensed Consolidated Balance Sheets, as the contracts contain netting provisions. Refer to Note 8 – Derivative Contracts, for additional information regarding the Company's derivative contracts.

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Restructuring Costs (Tables)

9 Months Ended

Sep. 30, 2015

Restructuring and Related Activities [Abstract]

Schedule of Restructuring Reserve by Type of Cost [Table Text Block]

	Restructuring liability
	(in millions)
Balance at December 31, 2014	$	—
Costs incurred and charged to expense	6.2
Costs paid or otherwise settled	(3.8		)
Balance at September 30, 2015	$	2.4

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Derivative Contracts (Tables)

9 Months Ended

Sep. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]

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

Year	Index	Total Volumes	Average Swap price per unit
		(in millions)
Gas sales		(MMBtu)	($/MMBtu)
2015	NYMEX HH	17.5	$	3.48
2015	IFNPCR	12.0	$	3.55
2016	NYMEX HH	22.0	$	3.19
2016	IFNPCR	32.9	$	2.92
2017	NYMEX HH	7.3	$	3.21
Oil sales		(bbls)	($/bbl)
2015	NYMEX WTI	2.6	$	82.09
2015	ICE Brent	0.1	$	104.95
2016	NYMEX WTI	3.3	$	65.43

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

		Total Volume	Average Price		Average Price
Year	Index		Floor		Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2016	NYMEX HH	7.3	$	2.75	$	3.89

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

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

Year	Index Less Differential	Index	Total Volumes	Weighted Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2015	NYMEX HH	IFNPCR	11.0	$	(0.28	)
2016	NYMEX HH	IFNPCR	7.3	$	(0.20	)

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, 2015:

Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2015	SWAP	IFNPCR	2.4	$	3.25
2016	SWAP	IFNPCR	2.9	$	3.06
Gas purchases			(MMBtu)
2015	SWAP	IFNPCR	1.2	$	2.75

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

		Gross asset derivative instruments fair value				Gross liability derivative instruments fair value
	Balance Sheet line item	September 30, 2015		December 31, 2014		September 30, 2015		December 31, 2014
		(in millions)
Current:
Commodity	Fair value of derivative contracts	$	186.4	$	339.3	$	2.5	$	0.3
Long-term:
Commodity	Fair value of derivative contracts	17.0		9.9		—		—
Total derivative instruments		$	203.4	$	349.2	$	2.5	$	0.3

Derivative Instruments, Gain (Loss) [Table Text Block]

	Three Months Ended						Nine Months Ended
Derivative instruments not designated as cash flow hedges	September 30,						September 30,
	2015			2014			2015			2014
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	23.1		$	5.5		$	69.1		$	(23.3	)
Oil derivative contracts	96.8			(12.2		)	245.3			(50.2		)
QEP Marketing
Gas derivative contracts	(0.1		)	(0.4		)	2.1			(2.4		)
Total realized gains (losses) on commodity derivative contracts	119.8			(7.1		)	316.5			(75.9		)
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	3.6			27.6			(19.5		)	9.5
Oil derivative contracts	28.8			133.2			(128.0		)	54.3
QEP Marketing
Gas derivative contracts	1.4			0.7			(0.5		)	1.0
Total unrealized gains (losses) on commodity derivative contracts	33.8			161.5			(148.0		)	64.8
Total realized and unrealized gains (losses) on commodity derivative contracts	$	153.6		$	154.4		$	168.5		$	(11.1	)
Realized gains (losses) on interest rate swaps
Realized gains (losses) on interest rate swaps	$	—		$	(1.3	)	$	—		$	(3.2	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	—			2.6			—			1.1
Total realized gains (losses) on interest rate swaps	$	—		$	1.3		$	—		$	(2.1	)
Total net realized gains (losses) on derivative contracts	$	119.8		$	(8.4	)	$	316.5		$	(79.1	)
Total net unrealized gains (losses) on derivative contracts	33.8			164.1			(148.0		)	65.9
Grand Total	$	153.6		$	155.7		$	168.5		$	(13.2	)

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Share-Based Compensation Schedule Of Stock Option Transactions (Details) - USD ($) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding at beginning of period	1,996,215
Options granted	425,877
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	(15,000)
Options forfeited	(2,817)
Options cancelled	(60,000)
Outstanding at end of period	2,344,275
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Weighted average exercise price, beginning of year	$ 28.60
Weighted average exercise price, granted in period	21.69
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price	19.37
Weighted average exercise price, forfeited in period	31.31
Weighted average exercise price, canceled in period	27.84
Weighted average exercise price, end of year	$ 27.42
Options exercisable, shares	1,665,825
Options exercisable, weighted average exercise price	$ 28.32
Unvested options, shares	678,450
Unvested options, weighted average exercise price	$ 25.20
Weighted average remaining contractual term, options outstanding	3 years 2 months 25 days
Weighted average remaining contractual term, options exercisable	2 years 1 month 27 days
Weighted average remaining contractual term, options unvested	5 years 10 months 17 days
Aggregate intrinsic value, options outstanding	$ 0.0
Aggregate intrinsic value, options exercisable	0.0
Aggregate intrinsic value, options unvested	0.0
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of options exercised	$ 0.1	$ 0.6

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Fair Value Measurements Fair Value and Related Carrying Amount of Certain Financial Instruments (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	$ 495.8	$ 1,160.1
Checks outstanding in excess of cash balances	12.8	54.7
Long-term debt	1,965.5	2,171.6
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, at Carrying Value	495.8	1,160.1
Checks outstanding in excess of cash balances	12.8	54.7
Long-term Debt	$ 2,218.5	$ 2,218.1

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Debt (Tables)

9 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Debt Outstanding

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

	September 30, 2015			December 31, 2014
	(in millions)
Revolving Credit Facility due 2019	$	—		$	—
6.05% Senior Notes due 2016	176.8			176.8
6.80% Senior Notes due 2018	134.0			134.0
6.80% Senior Notes due 2020	136.0			136.0
6.875% Senior Notes due 2021	625.0			625.0
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
Less: unamortized discount	(3.3		)	(3.7		)
Total principal amount of debt (including current portion)	2,218.5			2,218.1
Less: current portion of long-term debt	(176.7		)	—
Total long-term debt outstanding	$	2,041.8		$	2,218.1

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Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

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

	Stock Option Assumptions
Weighted-average grant date fair value of awards granted during the period	$	6.82
Weighted-average risk-free interest rate	1.38		%
Weighted-average expected price volatility	36.8		%
Expected dividend yield	0.37		%
Expected term in years at the date of grant	4.5

Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]

Stock option transactions under the terms of the LTSIP are summarized below:

	Options Outstanding		Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
			(per share)		(in years)	(in millions)
Outstanding at December 31, 2014	1,996,215		$	28.60
Granted	425,877		21.69
Exercised	(15,000	)	19.37
Forfeited	(2,817	)	31.31
Canceled	(60,000	)	27.84
Outstanding at September 30, 2015	2,344,275		$	27.42	3.24	$	—
Options Exercisable at September 30, 2015	1,665,825		$	28.32	2.16	$	—
Unvested Options at September 30, 2015	678,450		$	25.20	5.88	$	—

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity [Table Text Block]

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

	Restricted Shares Outstanding		Weighted- Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2014	1,426,453		$	31.02
Granted	1,484,567		21.02
Vested	(683,562	)	30.67
Forfeited	(93,425	)	27.20
Unvested balance at September 30, 2015	2,134,033		$	24.35

Schedule of Other Share-based Compensation, Activity [Table Text Block]

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

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

____________________________

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

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Nature of Business

9 Months Ended

Sep. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Nature of Business

Nature of Business

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

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

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

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Employee Benefits (Tables)

9 Months Ended

Sep. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.5		$	0.6		$	1.5		$	2.0
Interest cost	1.3			1.2			3.7			4.0
Expected return on plan assets	(1.5		)	(1.4		)	(4.3		)	(3.8		)
Amortization of prior service costs (1)	0.4			1.1			1.3			3.6
Amortization of actuarial losses (1)	0.1			0.2			0.4			0.6
Curtailment loss (2)	—			—			11.2			2.0
Special termination benefits (3)	—			—			—			0.3
Periodic expense	$	0.8		$	1.7		$	13.8		$	8.7
Medical Plan benefits
Interest cost	$	0.1		$	—		$	0.2		$	0.2
Amortization of prior service costs (1)	—			0.1			0.1			0.3
Curtailment loss (2)	—			—			—			0.4
Periodic expense	$	0.1		$	0.1		$	0.3		$	0.9

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Discontinued Operations Income Statement Impact of Discontinued Operations (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
NGL sales		$ 16.5	$ 51.1	$ 61.7	$ 179.3
Other revenue		2.8	3.4	12.4	5.1
Purchased gas and oil sales		176.3	290.4	558.6	780.1
Total Revenues		536.7	910.0	1,636.9	2,614.7
Purchased gas and oil expense		175.1	288.4	561.7	775.5
Lease operating expense		56.7	61.1	175.6	177.0
Natural gas, oil and NGL transportation and other handling costs		78.1	71.1	216.2	198.5
Gathering, processing and other		1.3	1.4	4.4	4.8
General and administrative		42.0	49.4	140.7	147.0
Production and property taxes		30.2	59.4	90.7	160.8
Depreciation, depletion and amortization		238.1	251.4	649.3	712.5
Total operating expenses		637.3	783.1	1,876.8	2,184.4
Gain (Loss) on Disposition of Property Plant Equipment		12.9	(11.8)	6.9	(210.3)
OPERATING INCOME		(87.7)	115.1	(233.0)	220.0
Income from unconsolidated affiliates				0.0	4.6
Interest expense		(36.4)	(41.5)	(109.4)	(128.4)
Net income attributable to noncontrolling interest				0.0	(17.6)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX		$ 0.0	17.4	$ 0.0	58.2
Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
NGL sales			28.8		94.6
Other revenue			43.1		119.9
Purchased gas and oil sales	[1]		(11.9)		(38.5)
Total Revenues			60.0		176.0
Purchased gas and oil expense	[1]		(12.4)		(39.5)
Lease operating expense	[1]		(1.7)		(4.8)
Natural gas, oil and NGL transportation and other handling costs	[1]		(10.6)		(40.1)
Gathering, processing and other			22.7		69.8
General and administrative			11.1		34.3
Production and property taxes			2.1		6.1
Depreciation, depletion and amortization			14.3		43.1
Total operating expenses			25.5		68.9
Gain (Loss) on Disposition of Property Plant Equipment			0.0		(0.1)
OPERATING INCOME			34.5		107.0
Income from unconsolidated affiliates			1.1		4.4
Interest expense			(1.5)		(2.8)
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES	[2]		34.1		108.6
Income taxes			(9.9)		(32.8)
NET INCOME FROM DISCONTINUED OPERATIONS			24.2		75.8
Net income attributable to noncontrolling interest			(6.8)		(17.6)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX			17.4		58.2
Income from discontinued operations before income taxes attributable to QEP from QEP Midstream			$ 7.9		$ 20.4
Ownership percentage			57.80%		57.80%

[1] Includes discontinued intercompany eliminations

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

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Contingencies (Narrative) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2015 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Loss Contingency, Range of Possible Loss, Minimum	$ 0.0
Loss Contingency, Range of Possible Loss, Maximum	20.0
Litigation Settlement, Amount	$ 16.7
Litigation Settlement Statutory Interest Rate	10.00%
Loss Contingency Bond Posted	$ 20.0

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
REVENUES
Gas sales		$ 129.4	$ 171.6	$ 363.3	$ 609.2
Oil sales		211.7	393.5	640.9	1,041.0
NGL sales		16.5	51.1	61.7	179.3
Other revenue		2.8	3.4	12.4	5.1
Purchased gas and oil sales		176.3	290.4	558.6	780.1
Total Revenues		536.7	910.0	1,636.9	2,614.7
OPERATING EXPENSES
Purchased gas and oil expense		175.1	288.4	561.7	775.5
Lease operating expense		56.7	61.1	175.6	177.0
Gas, oil and NGL transportation and other handling costs		78.1	71.1	216.2	198.5
Gathering and other expense		1.3	1.4	4.4	4.8
General and administrative		42.0	49.4	140.7	147.0
Production and property taxes		30.2	59.4	90.7	160.8
Depreciation, depletion and amortization		238.1	251.4	649.3	712.5
Exploration expenses		0.8	0.8	2.7	4.7
Impairment		15.0	0.1	35.5	3.6
Total operating expenses		637.3	783.1	1,876.8	2,184.4
Net gain (loss) from asset sales		12.9	(11.8)	6.9	(210.3)
OPERATING INCOME (LOSS)		(87.7)	115.1	(233.0)	220.0
Realized and unrealized gains (losses) on derivative contracts (Note 8)		153.6	155.7	168.5	(13.2)
Interest and other income		0.3	4.2	1.5	7.8
Income from unconsolidated affiliates		0.0	0.1	0.0	0.2
Interest expense		(36.4)	(41.5)	(109.4)	(128.4)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		29.8	233.6	(172.4)	86.4
Income tax (provision) benefit		(8.7)	(79.9)	61.6	(26.1)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS		21.1	153.7	(110.8)	60.3
Net income from discontinued operations, net of income tax		0.0	17.4	0.0	58.2
NET INCOME (LOSS)		$ 21.1	$ 171.1	$ (110.8)	$ 118.5
Earnings Per Common Share Attributable to QEP
Earnings Per Share, Basic		$ 0.12	$ 0.95	$ (0.63)	$ 0.66
Earnings Per Share, Diluted		$ 0.12	$ 0.94	$ (0.63)	$ 0.66
Weighted-average common shares outstanding
Used in basic calculation (in shares)		176.7	180.1	176.5	180.0
Used in diluted calculation (in shares)		176.7	180.6	176.5	180.4
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		0.12	0.85	(0.63)	0.34
Earnings Per Share, Diluted		0.12	$ 0.84	(0.63)	$ 0.34
Discontinued Operations [Member]
REVENUES
NGL sales			$ 28.8		$ 94.6
Other revenue			43.1		119.9
Purchased gas and oil sales	[1]		(11.9)		(38.5)
Total Revenues			60.0		176.0
OPERATING EXPENSES
Purchased gas and oil expense	[1]		(12.4)		(39.5)
Lease operating expense	[1]		(1.7)		(4.8)
Gas, oil and NGL transportation and other handling costs	[1]		(10.6)		(40.1)
Gathering and other expense			22.7		69.8
General and administrative			11.1		34.3
Production and property taxes			2.1		6.1
Depreciation, depletion and amortization			14.3		43.1
Total operating expenses			25.5		68.9
Net gain (loss) from asset sales			0.0		(0.1)
OPERATING INCOME (LOSS)			34.5		107.0
Interest expense			(1.5)		(2.8)
Net income from discontinued operations, net of income tax			$ 17.4		$ 58.2
Earnings Per Common Share Attributable to QEP
Earnings Per Share, Basic		0.00	$ 0.10	0.00	$ 0.32
Earnings Per Share, Diluted		$ 0.00	$ 0.10	$ 0.00	$ 0.32

[1] Includes discontinued intercompany eliminations

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Derivative Contracts (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Derivative [Line Items]
Maximum Forecasted Production Covered By Derivatives	100.00%
Minimum [Member]
Derivative [Line Items]
Expected Annual Production Covered By Derivatives	50.00%
Maximum [Member]
Derivative [Line Items]
Expected Annual Production Covered By Derivatives	75.00%
Term Loan due 2017 [Member]
Derivative [Line Items]
Line of Credit Maximum Borrowing Capacity		$ 600.0

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares shares in Millions	Sep. 30, 2015	Dec. 31, 2014
EQUITY
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	500.0	500.0
Common stock, shares issued (in shares)	177.1	176.2
Treasury stock (in shares)	0.4	0.8

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Employee Benefits (Narrative) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension curtailment loss				$ 11.2	$ 0.0
Funded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension Contributions				2.0
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year				2.0
Unfunded Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension Contributions				2.9
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year				1.5
Other Postretirement Benefit Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension curtailment loss	[1]	$ 0.0	$ 0.0	0.0	0.4
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year				0.1
Other Postretirement Benefits Payments				0.4
Continuing Operations [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Other Postretirement Benefit Expense		$ 0.9	1.4	$ 14.1	8.2
Discontinued Operations [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Other Postretirement Benefit Expense			$ 0.4		$ 1.4

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

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Acquisitions & Divestitures (Narrative) (Details) - Permian Basin [Member] $ in Millions	3 Months Ended	7 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2015 USD ($)	Sep. 30, 2014 USD ($)	Sep. 30, 2015 USD ($)	Dec. 31, 2014 USD ($) a
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross				$ 941.8
Net acres of producing and undeveloped oil and gas properties | a				26,500
Number of vertical producing wells				270
Business Combination, Pro Forma Information, Revenue of Acquiree since Acquisition Date, Actual	$ 41.0	$ 114.2	$ 110.6
Business Combination, Pro Forma Information, Earnings or Loss of Acquiree since Acquisition Date, Actual	$ (1.9)	$ 23.1	$ (1.0)

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Basis of Presentation of Interim Consolidated Financial Statements (Policies)

9 Months Ended

Sep. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

New accounting pronouncements

New Accounting Pronouncements

In September 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) No. 2015-16,Business Combinations (Topic 805),which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendment will be effective prospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not expect that there will be a significant impact on the Company's Consolidated Financial Statements.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. In July 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606), in which the FASB delayed the effective date of the new revenue standard by one year and the amendments are now effective prospectively for reporting periods beginning after December 15, 2017, and early adoption is not permitted. The Company is currently assessing the impact on the Company's Consolidated Financial Statements.

In May 2015, the FASB issued ASU No. 2015-07,Fair Value Measurement (Topic 820), which allows reporting entities to exclude investments measured at net asset value per share under the existing practical expedient in ASC 820 from the fair value hierarchy. It also limits disclosures to investments for which the entity has elected to measure the fair value using the practical expedient. The amendment will be effective retrospectively for reporting periods beginning on or after December 15, 2015, and early adoption is permitted. The Company is currently assessing the ASU and does not expect that there will be a significant impact on the Company's Consolidated Financial Statements.

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

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

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

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

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Acquisitions & Divestitures Schedule Of Purchase Accounting Entries (Details) - Permian Basin [Member] $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($)
Significant Acquisitions and Disposals [Line Items]
Payments to Acquire Businesses, Gross	$ 941.8
Fair value of assets acquired (liabilities assumed)	941.8
Proved Property [Member]
Significant Acquisitions and Disposals [Line Items]
Fair value of assets acquired (liabilities assumed)	472.1
Unproved Property [Member]
Significant Acquisitions and Disposals [Line Items]
Fair value of assets acquired (liabilities assumed)	480.6
Asset Retirement Obligation [Member]
Significant Acquisitions and Disposals [Line Items]
Fair value of assets acquired (liabilities assumed)	(9.7)
Other Liabilities [Member]
Significant Acquisitions and Disposals [Line Items]
Fair value of assets acquired (liabilities assumed)	$ (1.2)

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Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2015

Discontinued Operations and Disposal Groups [Abstract]

Income Statement Impact Of Discontinued Operations [Table Text Block]

	Three Months Ended			Nine Months Ended
	September 30, 2014
	(in millions)
REVENUES
NGL sales	$	28.8		$	94.6
Other revenue	43.1			119.9
Purchased gas and oil sales(1)	(11.9		)	(38.5		)
Total Revenues	60.0			176.0
OPERATING EXPENSES
Purchased gas and oil expense(1)	(12.4		)	(39.5		)
Lease operating expense(1)	(1.7		)	(4.8		)
Natural gas, oil and NGL transport and other handling costs(1)	(10.6		)	(40.1		)
Gathering, processing, and other	22.7			69.8
General and administrative	11.1			34.3
Production and property taxes	2.1			6.1
Depreciation, depletion and amortization	14.3			43.1
Total Operating Expenses	25.5			68.9
Net loss from asset sales	—			(0.1		)
OPERATING INCOME	34.5			107.0
Income from unconsolidated affiliates	1.1			4.4
Interest expense	(1.5		)	(2.8		)
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES (2)	34.1			108.6
Income tax provision	(9.9		)	(32.8		)
NET INCOME FROM DISCONTINUED OPERATIONS	24.2			75.8
Net income attributable to noncontrolling interest	(6.8		)	(17.6		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	17.4		$	58.2

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
OPERATING ACTIVITIES
Net income (loss)	$ (110.8)	$ 118.5
Net income attributable to noncontrolling interest	0.0	17.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	649.3	755.8
Deferred income taxes	22.7	91.5
Impairment	35.5	3.6
Share-based compensation	23.3	23.7
Pension curtailment loss	11.2	0.0
Amortization of debt issuance costs and discounts	4.7	5.1
Net (gain) loss from asset sales	(6.9)	210.3
Income from unconsolidated affiliates	0.0	(4.6)
Distributions from unconsolidated affiliates and other	0.0	5.1
Unrealized (gains) loss on derivative contracts	148.0	(65.9)
Changes in operating assets and liabilities	(503.1)	59.0
Net Cash Provided by Operating Activities	273.9	1,219.7
INVESTING ACTIVITIES
Property acquisitions	(23.5)	(949.7)
Property, plant and equipment, including dry exploratory well expense	(862.6)	(1,270.4)
Proceeds from disposition of assets	5.2	706.2
Acquisition deposit held in escrow	0.0	50.0
Other investing activities	0.0	3.2
Net Cash Used in Investing Activities	(880.9)	(1,460.7)
FINANCING ACTIVITIES
Checks outstanding in excess of cash balances	(41.9)	(81.1)
Long-term debt issued	0.0	300.0
Long-term debt issuance costs paid	0.0	(1.1)
Proceeds from credit facility	0.0	4,509.0
Repayments of credit facility	0.0	(4,461.5)
Treasury stock repurchases	(2.3)	(6.6)
Other capital contributions	(0.1)	5.1
Dividends paid	(10.6)	(10.8)
Excess tax (provision) benefit on equity-based compensation	(2.4)	(0.6)
Distribution to noncontrolling interest	0.0	(23.3)
Net Cash (Used In) Provided by Financing Activities	(57.3)	229.1
Change in cash and cash equivalents	(664.3)	(11.9)
Beginning cash and cash equivalents	1,160.1	11.9
Ending cash and cash equivalents	495.8	0.0
Supplemental Disclosures:
Cash paid for interest, net of capitalized interest	107.4	128.9
Cash paid for income taxes	492.3	(1.1)
Non-cash investing activities
Change in capital expenditure accrual balance	$ (68.9)	$ 66.5

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ 21.1	$ 171.1	$ (110.8)	$ 118.5
Pension and other postretirement plans adjustments:
Amortization of net actuarial loss	[1]		0.2	0.2	0.4
Amortization of prior service cost	[2]	0.3	0.7	0.9	2.4
Other comprehensive income		0.3	0.9	1.1	2.8
Comprehensive income (loss)		$ 21.4	$ 172.0	$ (109.7)	$ 121.3

[1] Presented net of income tax expense of $0.2 million during the nine months ended September 30, 2015, and $0.2 million during the nine months ended September 30, 2014.

[2] Presented net of income tax expense of $0.1 million and $0.5 million during the three and nine months ended September 30, 2015, respectively, and $0.5 million and $1.5 million during the three and nine months ended September 30, 2014, respectively.

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Debt

9 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Debt

Debt

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

	September 30, 2015			December 31, 2014
	(in millions)
Revolving Credit Facility due 2019	$	—		$	—
6.05% Senior Notes due 2016	176.8			176.8
6.80% Senior Notes due 2018	134.0			134.0
6.80% Senior Notes due 2020	136.0			136.0
6.875% Senior Notes due 2021	625.0			625.0
5.375% Senior Notes due 2022	500.0			500.0
5.25% Senior Notes due 2023	650.0			650.0
Less: unamortized discount	(3.3		)	(3.7		)
Total principal amount of debt (including current portion)	2,218.5			2,218.1
Less: current portion of long-term debt	(176.7		)	—
Total long-term debt outstanding	$	2,041.8		$	2,218.1

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

Credit Facility

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

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

During the nine months endedSeptember 30, 2014, QEP’s weighted-average interest rate on borrowings from its credit facility was 2.22%. At September 30, 2015 and December 31, 2014, QEP had no borrowings outstanding under the credit facility, had $3.7 million in letters of credit outstanding under the credit facility and was in compliance with the covenants under the credit agreement.

Senior Notes

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

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Document and Entity Information	9 Months Ended
	Sep. 30, 2015 shares
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	176,736,956
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q3
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015

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Contingencies

9 Months Ended

Sep. 30, 2015

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 material loss contingency when its occurrence is probable and damages are reasonably estimable based on the anticipated most likely outcome or the minimum amount within a range of possible outcomes. Because legal proceedings are inherently unpredictable, and unfavorable resolutions can occur, assessing contingencies is highly subjective and requires judgments about uncertain future events. When evaluating contingencies, QEP may be unable to provide a meaningful estimate due to a number of factors, including the procedural status of the matter in question, the presence of complex or novel legal theories, the ongoing discovery and/or development of information important to the matter. Except for the Rocky Mountain Resources Lawsuit (discussed below), QEP is unable to estimate reasonably possible losses (in excess of recorded accruals, if any) for its material loss contingencies for the reasons set forth above. QEP believes, however, that the resolution of pending proceedings (after accruals, insurance coverage, and indemnification arrangements) will not be material to QEP's financial position but could be material to results of operations in a particular quarter or year.

Litigation

Rocky Mountain Resources Lawsuit - Rocky Mountain Resources, LLC (Rocky Mountain) filed its complaint in March 2011, seeking determination of the existence of a 4% overriding royalty interest in an oil and gas lease. Rocky Mountain alleges that the defendants have failed to pay Rocky Mountain monies associated with the claimed 4% overriding royalty interest since the issuance of the lease by the State of Wyoming in 1980. In February 2015, a jury rendered a verdict against QEP and awarded Rocky Mountain damages in the amount of $16.7 million, including interest. QEP is appealing the verdict to the Wyoming Supreme Court, and, in connection with such appeal, has posted a bond for approximately $20.0 million (representing the amount of the verdict and two years of accrued interest at the statutory rate of 10%). QEP estimates that, notwithstanding the verdict, the range of reasonably possible losses is still zero to approximately $20.0 million.

Yannick Gagné Lawsuit and Related Suits - 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 rail company that transported the crude oil filed for bankruptcy protection following the accident. 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 allege that QEP and the producer defendants, among other things, failed to ensure that the oil was adequately processed to remove volatile gases and vapors, failed to take reasonable care to ensure that the oil was properly labeled and shipped and failed to identify the risk of the train derailment and take action to prevent it. The plaintiffs seek unspecified damages. A court order regarding class certification is pending. Many of the defendants, including QEP, have reached a confidential settlement agreement with trustees in both Canadian and U.S. bankruptcy courts to resolve all of these claims, which is subject to the approval of such courts. During the third quarter of 2015, QEP was served with additional complaints in state and federal courts in Maine, Texas and Illinois, each of which makes similar claims to those in the Yannick Gagné case, and plaintiff's in each matter support the current settlement plans. If the courts approve the current settlement plan, the plan will settle these additional cases.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Pension and other postretirement plans adjustments:
Tax expense on net unamortized loss incurred	$ 0.0	$ 0.0	$ 0.2	$ 0.2
Tax expense on prior service cost incurred	$ 0.1	$ 0.5	$ 0.5	$ 1.5

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Earnings Per Share

9 Months Ended

Sep. 30, 2015

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

Basic earnings per share (EPS) are computed by dividing net income by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. QEP’s unvested restricted shares are included in weighted-average basic common shares outstanding because once the shares are granted, the restricted shares are considered issued and outstanding, the historical forfeiture rate is minimal and the restricted shares receive dividends.

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

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2015	2014	2015	2014
	(in millions)
Weighted-average basic common shares outstanding	176.7	180.1	176.5	180.0
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	—	0.5	—	0.4
Average diluted common shares outstanding	176.7	180.6	176.5	180.4

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Discontinued Operations

9 Months Ended

Sep. 30, 2015

Discontinued Operations and Disposal Groups [Abstract]

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

Discontinued Operations

On December 2, 2014, the Company closed on the sale of substantially all of its midstream business, including its ownership interest in QEP Midstream Partners, LP (QEP Midstream) to Tesoro Logistics LP (Tesoro) for total cash proceeds of approximately $2.5 billion, including $230.0 million to refinance debt at QEP Midstream, subject to post-closing adjustments, and QEP recorded a pre-tax gain of approximately $1.8 billion for the year ended December 31, 2014 (Midstream Sale).

The operating results of QEP Field Services Company (QEP Field Services), excluding the Haynesville gathering system (the Discontinued Operations of QEP Field Services), have been classified as discontinued operations on the Condensed Consolidated Statements of Operations and Notes accompanying the Condensed Consolidated Financial Statements for the three and nine months endedSeptember 30, 2014. QEP will have continuing cash outflows to the entities sold as a part of the Midstream Sale for gathering, processing and water handling costs in Pinedale, the Uinta Basin and a portion of its Williston Basin operations. The contracts related to these cash flows vary in length from month-to-month to over a year and will be reviewed periodically in the normal course of business. Historically, these transactions were eliminated in consolidation, as they represented transactions between two related entities but are now reflected as part of the continuing operations for QEP. For the three months endedSeptember 30, 2015 and 2014, cash outflows for these transactions included in continuing operations were $24.9 million and $31.4 million, respectively. For the nine months endedSeptember 30, 2015 and 2014, cash outflows for these transactions included in continuing operations were $94.2 million and $105.4 million, respectively.

In 2013, in connection with QEP's plan to separate its midstream business, the Board of Directors approved an employee retention plan to provide substantially all QEP Field Services' employees as of December 1, 2013, with a one-time lump-sum cash payment on the earlier of December 31, 2014, or whenever the separation of QEP Field Services occurred, conditioned on continued employment with QEP Field Services or a successor through the payment date unless the employee is terminated prior to such date. QEP recognized $10.4 million of costs under this retention plan in 2014, of which $2.3 million and $7.1 million was included within "Discontinued operations, net of income tax" on the Condensed Consolidated Statements of Operations for the three and nine months endedSeptember 30, 2014, respectively.

Condensed Consolidated Statement of Operations

The Discontinued Operations of QEP Field Services are summarized below:

	Three Months Ended			Nine Months Ended
	September 30, 2014
	(in millions)
REVENUES
NGL sales	$	28.8		$	94.6
Other revenue	43.1			119.9
Purchased gas and oil sales(1)	(11.9		)	(38.5		)
Total Revenues	60.0			176.0
OPERATING EXPENSES
Purchased gas and oil expense(1)	(12.4		)	(39.5		)
Lease operating expense(1)	(1.7		)	(4.8		)
Natural gas, oil and NGL transport and other handling costs(1)	(10.6		)	(40.1		)
Gathering, processing, and other	22.7			69.8
General and administrative	11.1			34.3
Production and property taxes	2.1			6.1
Depreciation, depletion and amortization	14.3			43.1
Total Operating Expenses	25.5			68.9
Net loss from asset sales	—			(0.1		)
OPERATING INCOME	34.5			107.0
Income from unconsolidated affiliates	1.1			4.4
Interest expense	(1.5		)	(2.8		)
INCOME FROM DISCONTINUED OPERATIONS BEFORE INCOME TAXES (2)	34.1			108.6
Income tax provision	(9.9		)	(32.8		)
NET INCOME FROM DISCONTINUED OPERATIONS	24.2			75.8
Net income attributable to noncontrolling interest	(6.8		)	(17.6		)
NET INCOME FROM DISCONTINUED OPERATIONS, NET OF INCOME TAX	$	17.4		$	58.2

⁽¹⁾  Includes discontinued intercompany eliminations.

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

Condensed Consolidated Statement of Cash Flows

The impact of the Discontinued Operations of QEP Field Services on the Condensed Consolidated Statement of Cash Flows for "Depreciation, depletion and amortization" contained in "Cash flows from operating activities" was $43.1 million for the nine months endedSeptember 30, 2014. 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 for the nine months endedSeptember 30, 2014.

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Acquisitions & Divestitures (Tables)

9 Months Ended

Sep. 30, 2015

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

Business Combination, Separately Recognized Transactions [Table Text Block]

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]

		Nine Months Ended
		September 30, 2014
		Actual		Pro forma
	(in millions, except per share data)
Revenues		$	2,614.7	$	2,640.8
Net income		$	118.5	$	125.5
Earnings per common share
Basic		$	0.66	$	0.70
Diluted		$	0.66	$	0.70

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Share-Based Compensation

9 Months Ended

Sep. 30, 2015

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Compensation Related Costs, Share-based Payments [Text Block]

Share-Based Compensation

QEP issues stock options and restricted shares under its Long-Term Stock Incentive Plan (LTSIP) and awards performance share units under its Cash Incentive Plan (CIP) to certain officers, employees, and non-employee directors. QEP recognizes expense over the vesting periods for the stock options, restricted shares, and performance share units. There were 9.1 million shares available for future grants under the LTSIP at September 30, 2015. Share-based compensation expense related to continuing operations is recognized within “General and administrative” expense 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 within "Net income from discontinued operations, net of income tax" on the Condensed Consolidated Statement of Operations. During the three and nine months endedSeptember 30, 2015, QEP recognized $7.7 million and $23.3 million, respectively, in total compensation expense related to share-based compensation for continuing operations, compared to $8.1 million and $20.4 million, respectively, during the three and nine months endedSeptember 30, 2014. In addition, during the three and nine months endedSeptember 30, 2014, QEP recognized $1.0 million and $3.3 million, respectively, in total compensation expense related to share-based compensation for discontinued operations.

Stock Options

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

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

	Stock Option Assumptions
Weighted-average grant date fair value of awards granted during the period	$	6.82
Weighted-average risk-free interest rate	1.38		%
Weighted-average expected price volatility	36.8		%
Expected dividend yield	0.37		%
Expected term in years at the date of grant	4.5

Stock option transactions under the terms of the LTSIP are summarized below:

	Options Outstanding		Weighted- Average Exercise Price		Weighted-Average Remaining Contractual Term	Aggregate Intrinsic Value
			(per share)		(in years)	(in millions)
Outstanding at December 31, 2014	1,996,215		$	28.60
Granted	425,877		21.69
Exercised	(15,000	)	19.37
Forfeited	(2,817	)	31.31
Canceled	(60,000	)	27.84
Outstanding at September 30, 2015	2,344,275		$	27.42	3.24	$	—
Options Exercisable at September 30, 2015	1,665,825		$	28.32	2.16	$	—
Unvested Options at September 30, 2015	678,450		$	25.20	5.88	$	—

The total intrinsic value (the difference between the market price at the exercise date and the exercise price) of options exercised was $0.1 million and $0.6 million during the nine months endedSeptember 30, 2015 and 2014, respectively. As of September 30, 2015, $2.6 million of unrecognized compensation cost related to stock options granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheet, is expected to be recognized over a weighted-average period of 2.14 years.

Restricted Shares

Restricted share grants typically vest in equal installments over a three-year period from the grant date. The grant date fair value is determined based on the closing bid price of the Company's common stock on the grant date. The total fair value of restricted stock that vested during the nine months endedSeptember 30, 2015 and 2014, was $21.0 million and $20.2 million, respectively. The weighted-average grant date fair value of restricted stock was $21.02 per share and $31.82 per share for the nine months endedSeptember 30, 2015 and 2014, respectively. As of September 30, 2015, $27.5 million of unrecognized compensation cost related to restricted shares granted under the LTSIP, which is included within "Additional paid-in capital" on the Condensed Consolidated Balance Sheet, is expected to be recognized over a weighted-average vesting period of 2.24 years.

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

	Restricted Shares Outstanding		Weighted- Average Grant Date Fair Value
			(per share)
Unvested balance at December 31, 2014	1,426,453		$	31.02
Granted	1,484,567		21.02
Vested	(683,562	)	30.67
Forfeited	(93,425	)	27.20
Unvested balance at September 30, 2015	2,134,033		$	24.35

Performance Share Units

The performance share units' cash payouts are dependent upon the Company’s total shareholder return compared to a group of its peers over a three-year period. The awards are denominated in share units but have historically been delivered in cash. Beginning with awards granted in 2015, the Company has the option to settle earned awards in cash or shares of common stock under the Company's LTSIP; however, as of September 30, 2015, the Company expects to settle all awards in cash. The weighted-average grant date fair value of the performance share units was $21.69 per share and $31.71 per share for the nine months endedSeptember 30, 2015 and 2014, respectively. As of September 30, 2015, $2.7 million of unrecognized compensation cost, which is included within "Other long-term liabilities" on the Condensed Consolidated Balance Sheet and represents the fair market value of performance shares granted, is expected to be recognized over a weighted-average vesting period of 1.90 years.

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

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

____________________________

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

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Derivative Contracts

9 Months Ended

Sep. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

Derivative Contracts

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

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

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

During 2014, QEP also used interest rate swaps to mitigate a portion of its exposure to interest rate volatility associated with its $600.0 million term loan. These interest rate swaps were terminated and settled in December 2014 in conjunction with the extinguishment of QEP's term loan.

QEP Energy Derivative Contracts

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

Year	Index	Total Volumes	Average Swap price per unit
		(in millions)
Gas sales		(MMBtu)	($/MMBtu)
2015	NYMEX HH	17.5	$	3.48
2015	IFNPCR	12.0	$	3.55
2016	NYMEX HH	22.0	$	3.19
2016	IFNPCR	32.9	$	2.92
2017	NYMEX HH	7.3	$	3.21
Oil sales		(bbls)	($/bbl)
2015	NYMEX WTI	2.6	$	82.09
2015	ICE Brent	0.1	$	104.95
2016	NYMEX WTI	3.3	$	65.43

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

		Total Volume	Average Price		Average Price
Year	Index		Floor		Ceiling
		(in millions)
		(MMBtu)	($/MMBtu)		($/MMBtu)
2016	NYMEX HH	7.3	$	2.75	$	3.89

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

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

Year	Index Less Differential	Index	Total Volumes	Weighted Average Differential
			(in millions)
			(MMBtu)	($/MMBtu)
2015	NYMEX HH	IFNPCR	11.0	$	(0.28	)
2016	NYMEX HH	IFNPCR	7.3	$	(0.20	)

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, 2015:

Year	Type of Contract	Index	Total Volumes	Average Swap price per MMBtu
			(in millions)
Gas sales			(MMBtu)
2015	SWAP	IFNPCR	2.4	$	3.25
2016	SWAP	IFNPCR	2.9	$	3.06
Gas purchases			(MMBtu)
2015	SWAP	IFNPCR	1.2	$	2.75

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, 2015		December 31, 2014		September 30, 2015		December 31, 2014
		(in millions)
Current:
Commodity	Fair value of derivative contracts	$	186.4	$	339.3	$	2.5	$	0.3
Long-term:
Commodity	Fair value of derivative contracts	17.0		9.9		—		—
Total derivative instruments		$	203.4	$	349.2	$	2.5	$	0.3

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

	Three Months Ended						Nine Months Ended
Derivative instruments not designated as cash flow hedges	September 30,						September 30,
	2015			2014			2015			2014
Realized gains (losses) on commodity derivative contracts	(in millions)
QEP Energy
Gas derivative contracts	$	23.1		$	5.5		$	69.1		$	(23.3	)
Oil derivative contracts	96.8			(12.2		)	245.3			(50.2		)
QEP Marketing
Gas derivative contracts	(0.1		)	(0.4		)	2.1			(2.4		)
Total realized gains (losses) on commodity derivative contracts	119.8			(7.1		)	316.5			(75.9		)
Unrealized gains (losses) on commodity derivative contracts
QEP Energy
Gas derivative contracts	3.6			27.6			(19.5		)	9.5
Oil derivative contracts	28.8			133.2			(128.0		)	54.3
QEP Marketing
Gas derivative contracts	1.4			0.7			(0.5		)	1.0
Total unrealized gains (losses) on commodity derivative contracts	33.8			161.5			(148.0		)	64.8
Total realized and unrealized gains (losses) on commodity derivative contracts	$	153.6		$	154.4		$	168.5		$	(11.1	)
Realized gains (losses) on interest rate swaps
Realized gains (losses) on interest rate swaps	$	—		$	(1.3	)	$	—		$	(3.2	)
Unrealized gains (losses) on interest rate swaps
Unrealized gains (losses) on interest rate swaps	—			2.6			—			1.1
Total realized gains (losses) on interest rate swaps	$	—		$	1.3		$	—		$	(2.1	)
Total net realized gains (losses) on derivative contracts	$	119.8		$	(8.4	)	$	316.5		$	(79.1	)
Total net unrealized gains (losses) on derivative contracts	33.8			164.1			(148.0		)	65.9
Grand Total	$	153.6		$	155.7		$	168.5		$	(13.2	)

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Employee Benefits Schedule of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension curtailment loss				$ 11.2	$ 0.0
Other Postretirement Benefit Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Interest cost		$ 0.1	$ 0.0	0.2	0.2
Amortization of prior service costs	[1]	0.0	0.1	0.1	0.3
Pension curtailment loss	[2]	0.0	0.0	0.0	0.4
Periodic expense		0.1	0.1	0.3	0.9
Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost		0.5	0.6	1.5	2.0
Interest cost		1.3	1.2	3.7	4.0
Expected return on plan assets		(1.5)	(1.4)	(4.3)	(3.8)
Amortization of prior service costs	[1]	0.4	1.1	1.3	3.6
Amortization of actuarial losses	[1]	0.1	0.2	0.4	0.6
Pension curtailment loss	[2]	0.0	0.0	11.2	2.0
Special Termination Benefits	[3]	0.0	0.0	0.0	0.3
Periodic expense		$ 0.8	$ 1.7	$ 13.8	$ 8.7

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

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

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

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2015

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 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 $188.5 million and $195.1 million ARO liability for the periods ended September 30, 2015 and December 31, 2014, $0.8 million and $1.3 million were included, respectively, as a current liability within "Accounts payable and accrued expenses" on the Condensed Consolidated Balance Sheets.

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

	Asset Retirement Obligations
	2015
	(in millions)
ARO liability at January 1,	$	195.1
Accretion	6.4
Additions	3.0
Revisions	0.3
Liabilities related to divestitures	(14.8		)
Liabilities settled	(1.5		)
ARO liability at September 30,	$	188.5

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Fair Value Measurements

9 Months Ended

Sep. 30, 2015

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.

The fair value of financial assets and liabilities at September 30, 2015 and December 31, 2014, is shown in the table below:

	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
	September 30, 2015
Financial Assets
Commodity derivative instruments - short-term	$	—	$	186.4	$	—	$	(2.5	)	$	183.9
Commodity derivative instruments - long-term	—		17.0		—		—			17.0
Total financial assets	$	—	$	203.4	$	—	$	(2.5	)	$	200.9
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	2.5	$	—	$	(2.5	)	$	—
Commodity derivative instruments - long-term	—		—		—		—			—
Total financial liabilities	$	—	$	2.5	$	—	$	(2.5	)	$	—
	December 31, 2014
Financial Assets
Commodity derivative instruments - short-term	$	—	$	339.3	$	—	$	(0.3	)	$	339.0
Commodity derivative instruments - long-term	—		9.9		—		—			9.9
Total financial assets	$	—	$	349.2	$	—	$	(0.3	)	$	348.9
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	0.3	$	—	$	(0.3	)	$	—
Total financial liabilities	$	—	$	0.3	$	—	$	(0.3	)	$	—

_______________________

⁽¹⁾  The Company nets its derivative contract assets and liabilities outstanding with the same counterparty on the Condensed Consolidated Balance Sheets, as the contracts contain netting provisions. Refer to Note 8 – Derivative Contracts, for additional information regarding the Company's derivative contracts.

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

	Carrying Amount		Level 1 Fair Value		Carrying Amount		Level 1 Fair Value
	September 30, 2015				December 31, 2014
	(in millions)
Financial assets
Cash and cash equivalents	$	495.8	$	495.8	$	1,160.1	$	1,160.1
Financial liabilities
Checks outstanding in excess of cash balances	$	12.8	$	12.8	$	54.7	$	54.7
Long-term debt	$	2,218.5	$	1,965.5	$	2,218.1	$	2,171.6

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

The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of asset retirement obligations include plugging costs and reserve lives. A reconciliation of the Company’s ARO is presented in Note 6 – Asset Retirement Obligations.

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Restructuring Costs

9 Months Ended

Sep. 30, 2015

Restructuring and Related Activities [Abstract]

Restructuring and Related Activities Disclosure [Text Block]

Restructuring Costs

In the third quarter of 2015, QEP announced the closure of its regional office in Tulsa, Oklahoma. As a part of this reorganization, QEP will incur costs associated with termination benefits, relocation of certain employees, exit costs associated with the possible termination of the operating lease for the Tulsa office space and other expenses. QEP also incurred restructuring costs in the first quarter of 2015 as a result of work force reductions unrelated to the closure of its Tulsa office.

QEP anticipates total restructuring costs to be approximately $8.0 million to $12.0 million, of which approximately $5.3 million to $9.3 million is related to the closure of the Tulsa office and $2.7 million for work force reductions unrelated to the closure of the Tulsa office. Approximately $5.5 million is related to termination benefits, approximately $2.8 million is related to relocation of certain employees, and the remaining $3.9 million is related to the possible termination of the operating lease for the Tulsa office space. During the three months endedSeptember 30, 2015, restructuring costs of $3.5 million were incurred related to the Tulsa office closure, of which $2.8 million were termination costs and $0.7 million were relocation costs. During the nine months endedSeptember 30, 2015, restructuring costs of $6.2 million were incurred, of which $2.7 million were termination costs in the first quarter unrelated to the Tulsa office closure, and $2.8 million and $0.7 million of termination and relocation costs, respectively, were incurred in the third quarter related to the Tulsa office closure. All of the costs will be incurred by QEP Energy and are reported within QEP Energy's financial statements. These restructuring costs were recorded within "General and administrative" expense of the Condensed Consolidated Statement of Operations. The Company estimates that the remaining restructuring costs will be incurred during the remainder of 2015 and in 2016.

The following table is a reconciliation of QEP's restructuring liability, which is included within "Accounts payable and accrued expenses" on the Condensed Consolidated Balance Sheets.

	Restructuring liability
	(in millions)
Balance at December 31, 2014	$	—
Costs incurred and charged to expense	6.2
Costs paid or otherwise settled	(3.8		)
Balance at September 30, 2015	$	2.4

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Basis of Presentation of Interim Consolidated Financial Statements (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Asset Impairment Charges	$ 15.0	$ 0.1	$ 35.5	$ 3.6
Unrecognized Tax Benefits	15.6		15.6
Interest expense related to uncertain tax position			0.3
Proved Property [Member]
Asset Impairment Charges	14.4		33.8
Unproved Property [Member]
Asset Impairment Charges	0.6		1.7
Other Northern [Member]
Asset Impairment Charges	13.1		18.0
Midcontinent [Member]
Asset Impairment Charges	1.0		15.5
Permian Basin [Member]
Asset Impairment Charges	$ 0.3		$ 0.3

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Debt (Narrative) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Debt Instrument [Line Items]
Debt Maturity Period	5 years
Principal amount of senior notes outstanding	$ 2,221.8
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 2019 [Member]
Debt Instrument [Line Items]
Maturity date of long-term debt	Dec. 02, 2019
Borrowing capacity	$ 1,800.0
Weighted-average interest rate (in hundredths)			2.22%
Letters of credit outstanding	$ 3.7	$ 3.7
6.05% Senior Notes due 2016 [Member]
Debt Instrument [Line Items]
Long-term debt, interest rate (in hundredths)	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, interest rate (in hundredths)	6.80%
Maturity date of long-term debt	Apr. 01, 2018
6.80% Senior Notes Due 2020 [Member]
Debt Instrument [Line Items]
Long-term debt, interest rate (in hundredths)	6.80%
Maturity date of long-term debt	Mar. 01, 2020

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Operations by Line of Business

9 Months Ended

Sep. 30, 2015

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 oil and gas marketing, operation of a gas gathering system and an underground gas storage facility and corporate activities (QEP Marketing and Other). The lines of business are managed separately and therefore the financial information is presented separately due to the distinct differences in the nature of operations of each line of business, among other factors.

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

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

	QEP Energy			QEP Marketing  and Other			Eliminations			QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	382.6		$	154.1		$	—		$	536.7
From affiliated customers	—			263.4			(263.4		)	—
Total Revenues	382.6			417.5			(263.4		)	536.7
OPERATING EXPENSES
Purchased gas and oil expense	23.6			412.1			(260.6		)	175.1
Lease operating expense	56.7			—			—			56.7
Gas, oil and NGL transportation and other handling costs	80.1			—			(2.0		)	78.1
Gathering and other expense	—			1.3			—			1.3
General and administrative	41.2			1.6			(0.8		)	42.0
Production and property taxes	29.9			0.3			—			30.2
Depreciation, depletion and amortization	235.7			2.4			—			238.1
Impairment and exploration expense	15.8			—			—			15.8
Total Operating Expenses	483.0			417.7			(263.4		)	637.3
Net gain (loss) from asset sales	13.2			(0.3		)	—			12.9
OPERATING INCOME (LOSS)	(87.2		)	(0.5		)	—			(87.7		)
Realized and unrealized gains (losses) on derivative contracts	152.3			1.3			—			153.6
Interest and other income	0.9			52.0			(52.6		)	0.3
Interest expense	(52.4		)	(36.6		)	52.6			(36.4		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	13.6			16.2			—			29.8
Income tax (provision) benefit	(2.8		)	(5.9		)	—			(8.7		)
NET INCOME (LOSS)	$	10.8		$	10.3		$	—		$	21.1

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

	QEP Energy			QEP Marketing  and Other			Eliminations			Discontinued Operations		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 and oil 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	49.0			1.4			(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	527.3			673.6			(417.8		)	—		783.1
Net gain (loss) from assets sales	(11.9		)	0.1			—			—		(11.8		)
OPERATING INCOME (LOSS)	113.7			1.4			—			—		115.1
Realized and unrealized gains (losses) 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 (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	214.8			18.8			—			—		233.6
Income tax (provision) benefit	(69.1		)	(10.8		)	—			—		(79.9		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	145.7			8.0			—			—		153.7
Net income from discontinued operations, net of income tax	—			—			—			17.4		17.4
NET INCOME (LOSS)	$	145.7		$	8.0		$	—		$	17.4	$	171.1

The following table is a summary of operating results for the nine months endedSeptember 30, 2015, by line of business:

	QEP Energy			QEP Marketing  and Other			Eliminations			QEP Consolidated
	(in millions)
REVENUES
From unaffiliated customers	$	1,143.8		$	493.1		$	—		$	1,636.9
From affiliated customers	—			719.0			(719.0		)	—
Total Revenues	1,143.8			1,212.1			(719.0		)	1,636.9
OPERATING EXPENSES
Purchased gas and oil expense	71.6			1,200.3			(710.2		)	561.7
Lease operating expense	175.6			—			—			175.6
Gas, oil and NGL transportation and other handling costs	223.0			—			(6.8		)	216.2
Gathering and other expense	—			4.4			—			4.4
General and administrative	137.4			5.3			(2.0		)	140.7
Production and property taxes	88.6			2.1			—			90.7
Depreciation, depletion and amortization	641.6			7.7			—			649.3
Impairment and exploration expense	38.2			—			—			38.2
Total Operating Expenses	1,376.0			1,219.8			(719.0		)	1,876.8
Net gain (loss) from asset sales	11.9			(5.0		)	—			6.9
OPERATING INCOME (LOSS)	(220.3		)	(12.7		)	—			(233.0		)
Realized and unrealized gains (losses) on derivative contracts	166.9			1.6			—			168.5
Interest and other income (expense)	0.5			153.1			(152.1		)	1.5
Interest expense	(152.2		)	(109.3		)	152.1			(109.4		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(205.1		)	32.7			—			(172.4		)
Income tax (provision) benefit	73.2			(11.6		)	—			61.6
NET INCOME (LOSS)	$	(131.9	)	$	21.1		$	—		$	(110.8	)

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

	QEP Energy			QEP Marketing  and Other			Eliminations			Discontinued Operations		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 and oil 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	146.5			3.1			(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	1,529.0			1,788.3			(1,132.9		)	—		2,184.4
Net gain (loss) from assets sales	(210.3		)	—			—			—		(210.3		)
OPERATING INCOME (LOSS)	214.0			6.0			—			—		220.0
Realized and unrealized gains (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 (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	49.4			37.0			—			—		86.4
Income tax (provision) benefit	(9.0		)	(17.1		)	—			—		(26.1		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	40.4			19.9			—			—		60.3
Net income from discontinued operations, net of income tax	—			—			—			58.2		58.2
NET INCOME (LOSS)	$	40.4		$	19.9		$	—		$	58.2	$	118.5

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2015

Asset Retirement Obligation [Abstract]

Asset retirement obligations roll forward

	Asset Retirement Obligations
	2015
	(in millions)
ARO liability at January 1,	$	195.1
Accretion	6.4
Additions	3.0
Revisions	0.3
Liabilities related to divestitures	(14.8		)
Liabilities settled	(1.5		)
ARO liability at September 30,	$	188.5

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Restructuring Costs Narrative (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015 USD ($)	Sep. 30, 2015 USD ($)
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost		$ 6.2
Unrelated to Tulsa Restructuring [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	$ 2.7	2.7
Tulsa Regional Office [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost	3.5
One-time Termination Benefits [Member] | Unrelated to Tulsa Restructuring [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost		2.7
One-time Termination Benefits [Member] | Tulsa Regional Office [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	5.5	5.5
Restructuring and Related Cost, Incurred Cost	2.8	2.8
Employee Relocation [Member] | Tulsa Regional Office [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	2.8	2.8
Restructuring and Related Cost, Incurred Cost	0.7	0.7
Facility Closing [Member] | Tulsa Regional Office [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	3.9	3.9
Minimum [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	8.0	8.0
Minimum [Member] | Tulsa Regional Office [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	5.3	5.3
Maximum [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	12.0	12.0
Maximum [Member] | Tulsa Regional Office [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Expected Cost	$ 9.3	$ 9.3

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Earnings Per Share Components of Basic and Diluted Shares Used In EPS Calculation (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Earnings Per Share [Abstract]
Weighted-average basic common shares outstanding	176.7	180.1	176.5	180.0
Potential number of shares issuable upon exercise of in-the-money stock options under the Long-term Stock Incentive Plan	0.0	0.5	0.0	0.4
Average diluted common shares outstanding	176.7	180.6	176.5	180.4

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CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 495.8	$ 1,160.1
Accounts receivable, net	316.2	441.9
Fair value of derivative contracts	183.9	339.0
Gas, oil and NGL inventories at lower of average cost or market	12.2	13.7
Prepaid expenses and other	32.4	46.8
Total Current Assets	1,040.5	2,001.5
Property, Plant and Equipment (successful efforts method for gas and oil properties)
Proved properties	12,911.5	12,278.7
Unproved properties	839.5	825.2
Marketing and resources	298.0	293.8
Material and supplies	35.9	54.3
Total Property, Plant and Equipment	14,084.9	13,452.0
Less Accumulated Depreciation, Depletion and Amortization
Exploration and production	6,653.7	6,153.0
Marketing and other	82.7	67.8
Total Accumulated Depreciation, Depletion and Amortization	6,736.4	6,220.8
Net Property, Plant and Equipment	7,348.5	7,231.2
Fair value of derivative contracts	17.0	9.9
Other noncurrent assets	50.1	44.2
TOTAL ASSETS	8,456.1	9,286.8
Current Liabilities
Checks outstanding in excess of cash balances	12.8	54.7
Accounts payable and accrued expenses	409.2	575.4
Income taxes payable	0.0	532.1
Production and property taxes	58.8	61.7
Interest payable	33.7	36.4
Deferred income taxes	47.4	84.5
Current portion of long-term debt	176.7	0.0
Total Current Liabilities	738.6	1,344.8
Long-term debt	2,041.8	2,218.1
Deferred income taxes	1,423.2	1,362.7
Asset retirement obligations	187.7	193.8
Other long-term liabilities	$ 92.7	$ 92.1
Commitments and contingencies (Note 11)
EQUITY
Common stock - par value $0.01 per share; 500.0 million shares authorized; 177.1 million and 176.2 million shares issued, respectively	$ 1.8	$ 1.8
Treasury stock - 0.4 million and 0.8 million shares, respectively	(10.0)	(25.4)
Additional paid-in capital	544.1	535.3
Retained earnings	3,459.3	3,587.9
Accumulated other comprehensive income (loss)	(23.1)	(24.3)
Total Common Shareholders' Equity	3,972.1	4,075.3
TOTAL LIABILITIES AND EQUITY	$ 8,456.1	$ 9,286.8

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Acquisitions & Divestitures

9 Months Ended

Sep. 30, 2015

Business Combinations [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 (the Permian Basin Acquisition). The acquired properties consisted of approximately 26,500 net acres of producing and undeveloped oil and gas properties and approximately 270 vertical producing wells in the Permian Basin, which created a new core area of operation for QEP Energy.

The 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 $41.0 million and $110.6 million and a net loss of $1.9 million and $1.0 million were generated from the acquired properties during the three and nine months endedSeptember 30, 2015, respectively. 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.

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

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

The following unaudited, pro forma results of operations are provided for the nine months endedSeptember 30, 2014. Pro forma results are not provided for the three months endedSeptember 30, 2014, or the three and nine months endedSeptember 30, 2015, because the Permian Basin Acquisition occurred during the first quarter of 2014, and therefore the Permian Basin results are included in QEP's results for these periods. These supplemental pro forma results of operations are provided for illustrative purposes only and may not be indicative of the actual results that would have been achieved by the acquired properties for the period presented, or that may be achieved by such properties in the future. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. The pro forma information is based on QEP's consolidated results of operations for the nine months endedSeptember 30, 2014, the acquired properties' historical results of operations, and estimates of the effect of the transaction on the combined results. The pro forma results of operations have been prepared by adjusting the historical results of QEP to include the historical results of the acquired properties based on information provided by the seller and the impact of the purchase price allocation. The pro forma results of operations do not include any cost savings or other synergies that may result from the Permian Basin Acquisition or any estimated costs that have been or will be incurred by the Company to integrate the acquired properties.

		Nine Months Ended
		September 30, 2014
		Actual		Pro forma
	(in millions, except per share data)
Revenues		$	2,614.7	$	2,640.8
Net income		$	118.5	$	125.5
Earnings per common share
Basic		$	0.66	$	0.70
Diluted		$	0.66	$	0.70

Divestitures

In December 2014, QEP Energy sold its interest in certain non-core properties in southern Oklahoma for aggregate proceeds of $101.3 million. For the year ended December 31, 2014, QEP Energy recorded a pre-tax gain on sale of $53.3 million. QEP recorded a pre-tax gain on sale of $8.8 million and $5.9 million for the three and nine months endedSeptember 30, 2015, respectively, due to post-closing purchase price adjustments.

In June 2014, QEP Energy sold its interest in certain non-core properties in the Midcontinent area and other non-core assets in the Williston Basin for aggregate proceeds of $675.6 million. QEP recorded a pre-tax loss of $199.4 million for the year ended December 31, 2014. QEP recorded a pre-tax gain on sale of $4.6 million and a pre-tax loss on sale of $21.8 million for the three and nine months endedSeptember 30, 2015, respectively, due to post-closing purchase price adjustments. These gains and losses are reported on the Condensed Consolidated Statements of Operations within "Net gain (loss) from asset sales".

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Share-Based Compensation Schedule Of Performance Share Unit Transactions (Details) - Performance Share Units [Member] - $ / shares	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested balance at beginning of period	552,209
Shares granted	234,085
Shares vested	(131,665)
Shares vested and canceled	(14,612)
Shares forfeited	(6,792)
Unvested balance at end of period	633,225
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Additional Disclosures [Abstract]
Weighted average grant date fair value, beginning of period	$ 30.85
Weighted average grant date fair value, grants	21.69	$ 31.71
Weighted average grant date fair value, vested	30.77
Weighted average grant date fair value, vested and canceled	30.77
Weighted average grant date fair value, forfeited	28.29
Weighted average grant date fair value, end of period	$ 27.52

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2015

Fair Value Disclosures [Abstract]

Fair value of financial assets and liabilities

The fair value of financial assets and liabilities at September 30, 2015 and December 31, 2014, is shown in the table below:

	Fair Value Measurements
	Gross Amounts of Assets and Liabilities						Netting Adjustments(1)			Net Amounts Presented on the Condensed Consolidated Balance Sheets
	Level 1		Level 2		Level 3
	(in millions)
	September 30, 2015
Financial Assets
Commodity derivative instruments - short-term	$	—	$	186.4	$	—	$	(2.5	)	$	183.9
Commodity derivative instruments - long-term	—		17.0		—		—			17.0
Total financial assets	$	—	$	203.4	$	—	$	(2.5	)	$	200.9
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	2.5	$	—	$	(2.5	)	$	—
Commodity derivative instruments - long-term	—		—		—		—			—
Total financial liabilities	$	—	$	2.5	$	—	$	(2.5	)	$	—
	December 31, 2014
Financial Assets
Commodity derivative instruments - short-term	$	—	$	339.3	$	—	$	(0.3	)	$	339.0
Commodity derivative instruments - long-term	—		9.9		—		—			9.9
Total financial assets	$	—	$	349.2	$	—	$	(0.3	)	$	348.9
Financial Liabilities
Commodity derivative instruments - short-term	$	—	$	0.3	$	—	$	(0.3	)	$	—
Total financial liabilities	$	—	$	0.3	$	—	$	(0.3	)	$	—

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, 2015				December 31, 2014
	(in millions)
Financial assets
Cash and cash equivalents	$	495.8	$	495.8	$	1,160.1	$	1,160.1
Financial liabilities
Checks outstanding in excess of cash balances	$	12.8	$	12.8	$	54.7	$	54.7
Long-term debt	$	2,218.5	$	1,965.5	$	2,218.1	$	2,171.6

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Acquisitions & Divestitures Divestitures Narrative (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Sep. 30, 2015	Dec. 31, 2014
Midcontinent Divestitures [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Property, Plant, and Equipment			$ 675.6
Gain (Loss) on Disposition of Oil and Gas and Timber Property	$ 4.6	$ (21.8)	(199.4)
Southern Region Divestitures [Member]
Significant Acquisitions and Disposals [Line Items]
Proceeds from Sale of Property, Plant, and Equipment			101.3
Gain (Loss) on Disposition of Oil and Gas and Timber Property	$ 8.8	$ 5.9	$ 53.3

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Employee Benefits

9 Months Ended

Sep. 30, 2015

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Pension and Other Postretirement Benefits Disclosure [Text Block]

Employee Benefits

Pension and other postretirement benefits

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

The Pension Plan is a closed, qualified defined-benefit pension plan that is funded and provides pension benefits to certain QEP employees. During the nine months endedSeptember 30, 2015, the Company made contributions of $2.0 million to the Pension Plan and expects to contribute $2.0 million to the Pension Plan during the remainder of 2015. Contributions to the Pension Plan increase plan assets.

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

The SERP is a nonqualified retirement plan that is unfunded and provides pension benefits to certain QEP employees. During the nine months endedSeptember 30, 2015, the Company made contributions of $2.9 million to its SERP and expects to contribute an additional $1.5 million to its SERP during the remainder of 2015. Contributions to the SERP are used to fund current benefit payments. The SERP was amended and restated in June 2015 and will be closed to new participants effective January 1, 2016.

The Medical Plan is unfunded and provides other postretirement benefits including certain health care and life insurance benefits for certain retired employees. During the nine months endedSeptember 30, 2015, the Company made contributions of $0.4 million to its Medical Plan and expects to contribute an additional $0.1 million to its Medical Plan during the remainder of 2015. Contributions to the Medical Plan are used to fund current benefit payments.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Pension Plan and SERP benefits	(in millions)
Service cost	$	0.5		$	0.6		$	1.5		$	2.0
Interest cost	1.3			1.2			3.7			4.0
Expected return on plan assets	(1.5		)	(1.4		)	(4.3		)	(3.8		)
Amortization of prior service costs (1)	0.4			1.1			1.3			3.6
Amortization of actuarial losses (1)	0.1			0.2			0.4			0.6
Curtailment loss (2)	—			—			11.2			2.0
Special termination benefits (3)	—			—			—			0.3
Periodic expense	$	0.8		$	1.7		$	13.8		$	8.7
Medical Plan benefits
Interest cost	$	0.1		$	—		$	0.2		$	0.2
Amortization of prior service costs (1)	—			0.1			0.1			0.3
Curtailment loss (2)	—			—			—			0.4
Periodic expense	$	0.1		$	0.1		$	0.3		$	0.9

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

⁽²⁾  A curtailment is recognized immediately when there is a significant reduction in, or an elimination of, defined benefit accruals for current employees' future services. For the nine months endedSeptember 30, 2015, these expenses are included on the Condensed Consolidated Statements of Operations within "General and administrative" expense as the expenses incurred in that period related to the Pension Plan amendment (see above). For the nine months endedSeptember 30, 2014, these expenses are included within "Net gain (loss) from asset sales" as the expenses incurred in that period related to the Midcontinent property sales (see Note 3 – Acquisitions and Divestitures).

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

During the three and nine months endedSeptember 30, 2015, for continuing operations, QEP recognized $0.9 million and $14.1 million, respectively, in employee benefit expense, compared to $1.4 million and $8.2 million, respectively, during the three and nine months endedSeptember 30, 2014. During the three and nine months endedSeptember 30, 2014, for discontinued operations, QEP recognized $0.4 million and $1.4 million, respectively, in employee benefit expense.