Edgar Filing: QEP RESOURCES, INC.

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarter ended June 30, 2010

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

For the transition period from to

QEP RESOURCES, INC.

(Exact name of registrant as specified in its charter)

STATE OF DELAWARE

001-34778

87-0287750

(State or other jurisdiction of

incorporation or organization)

(Commission

File Number)

(I.R.S. Employer

Identification No.)

1050 17^thStreet, Suite 500, Denver, Colorado 80265

(Address of principal executive offices)

Registrant’s telephone number, including area code (303) 672-6961

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 x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 ¨ No ¨

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. (Check one):

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

At June 30, 2010, there were 175,141,412 shares of the registrant’s common stock, $0.01 par value, outstanding.

QEP Resources, Inc.

Form 10-Q for the Quarter Ended June 30, 2010

TABLE OF CONTENTS


		Page
PART I.	FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS (Unaudited)	3

	Consolidated Statements of Income for the three and six months ended June 30, 2010 and 2009	3

	Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009	4

	Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2010 and 2009	5

	Notes Accompanying the Condensed Consolidated Financial Statements	6

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	22

ITEM 4.	CONTROLS AND PROCEDURES	24

PART II.	OTHER INFORMATION

ITEM 1.	LEGAL PROCEEDINGS	24

ITEM 6.	EXHIBITS	25

SIGNATURES		25

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

QEP RESOURCES, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)


	3 Months Ended June 30,						6 Months Ended June 30,
	2010			2009 (recast)			2010			2009 (recast)
	(in millions, except per share amounts)
REVENUES
Natural gas sales	$	260.6		$	264.5		$	525.2		$	542.9
Oil and NGL sales		53.7			37.3			107.7			68.4
Gathering, processing and other		80.4			60.5			162.3			116.5
Marketing sales		134.9			80.4			314.6			197.0

Total Revenues		529.6			442.7			1,109.8			924.8

OPERATING EXPENSES
Marketing purchases		133.9			79.2			311.8			187.3
Lease operating expense		28.6			31.8			56.9			65.7
Gathering, processing and other		19.6			16.5			43.1			36.4
General and administrative		25.7			24.1			50.9			43.1
Separation costs		14.0			—			14.0			—
Production and property taxes		19.0			14.8			41.9			31.2
Depreciation, depletion and amortization		151.6			144.6			299.0			269.3
Exploration		2.7			8.9			6.3			12.0
Abandonment and impairment		9.3			3.8			16.9			7.5

Total Operating Expenses		404.4			323.7			840.8			652.5
Net gain (loss) from asset sales		2.4			(0.4	)		1.5			1.4

OPERATING INCOME		127.6			118.6			270.5			273.7
Interest and other income		2.0			1.0			2.8			3.1
Income from unconsolidated affiliates		0.6			0.5			1.4			1.1
Unrealized and realized (loss) on basis-only swaps		—			(32.4	)		—			(170.7	)
Interest expense		(20.3	)		(15.8	)		(40.2	)		(32.0	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		109.9			71.9			234.5			75.2
Income taxes		(40.4	)		(26.4	)		(86.3	)		(27.3	)

INCOME FROM CONTINUING OPERATIONS		69.5			45.5			148.2			47.9
Discontinued operations, net of income tax		22.0			19.8			43.2			38.6

NET INCOME		91.5			65.3			191.4			86.5
Net income attributable to noncontrolling interest		(0.7	)		(0.6	)		(1.3	)		(1.1	)

NET INCOME ATTRIBUTABLE TO QEP	$	90.8		$	64.7		$	190.1		$	85.4

Earnings Per Common Share Attributable To QEP
Basic from continuing operations	$	0.39		$	0.26		$	0.84		$	0.27
Basic from discontinued operations		0.13			0.11			0.25			0.22

Basic total	$	0.52		$	0.37		$	1.09		$	0.49

Diluted from continuing operations	$	0.39		$	0.26		$	0.83		$	0.27
Diluted from discontinued operations		0.12			0.11			0.24			0.22

Diluted total	$	0.51		$	0.37		$	1.07		$	0.49

Weighted-average common shares outstanding
Used in basic calculation		175.1			174.1			175.0			173.9
Used in diluted calculation		177.6			176.1			177.4			176.0

See notes accompanying the condensed consolidated financial statements

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	June 30, 2010			December 31, 2009 (recast)
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents	$	—		$	19.3
Accounts receivable, net		253.9			272.7
Fair value of derivative contracts		240.0			128.2
Inventories		83.5			91.8
Prepaid expenses and other		26.2			29.2
Deferred income taxes		—			21.2
Current assets of discontinued operations		—			42.8

Total Current Assets		603.6			605.2

Property, Plant and Equipment (successful efforts method for gas and oil properties)		7,857.2			7,191.0
Accumulated depreciation, depletion and amortization		(2,380.6	)		(2,099.7	)
Cost-of-service properties of discontinued operations, net		—			593.9

Net Property, Plant and Equipment		5,476.6			5,685.2

Investment in unconsolidated affiliates		44.2			43.9
Goodwill		60.0			60.1
Fair value of derivative contracts		152.9			61.2
Other noncurrent assets		19.1			10.0
Noncurrent assets of discontinued operations		—			15.8

TOTAL ASSETS	$	6,356.4		$	6,481.4


LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$	14.6		$	—
Accounts payable and accrued expenses		388.1			434.5
Fair value of derivative contracts		129.5			149.7
Deferred income taxes		26.6			—
Current portion of long-term debt		150.0			—
Current liabilities of discontinued operations		—			91.4

Total Current Liabilities		708.8			675.6

Long-term debt, less current portion		1,096.8			1,348.7
Deferred income taxes		1,318.0			1,175.8
Asset retirement obligations		141.3			124.7
Fair value of derivative contracts		68.1			140.6
Other long-term liabilities		77.4			34.4
Noncurrent liabilities of discontinued operations		—			172.9
EQUITY
Common stock		1.8			1.7
Additional paid-in capital		382.3			126.8
Retained earnings		2,298.2			2,538.2
Accumulated other comprehensive income		209.9			87.1

Total Common Shareholders’ Equity		2,892.2			2,753.8
Noncontrolling interest		53.8			54.9

Total Equity		2,946.0			2,808.7

TOTAL LIABILITIES AND EQUITY	$	6,356.4		$	6,481.4

See notes accompanying the condensed consolidated financial statements

QEP RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	6 Months Ended June 30,
	2010			2009 (recast)
	(in millions)
OPERATING ACTIVITIES
Net income	$	191.4		$	86.5
Discontinued operations, net of income tax		(43.2	)		(38.6	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		299.6			269.8
Deferred income taxes		117.2			23.5
Abandonment and impairment		16.9			7.5
Share-based compensation		7.1			7.4
Dry exploratory well expense		—			3.7
Net (gain) loss from asset sales		(1.4	)		(1.4	)
(Income) from unconsolidated affiliates		(1.4	)		(1.1	)
Distributions from unconsolidated affiliates and other		1.2			0.3
Unrealized (gain) loss on basis-only swaps		(62.1	)		162.7
Changes in operating assets and liabilities		(57.2	)		45.3

Net Cash Provided By Operating Activities Of Continuing Operations		468.1			565.6


INVESTING ACTIVITIES
Property, plant and equipment, including dry exploratory well expense		(656.1	)		(564.8	)
Proceeds from disposition of assets		4.7			6.3
Change in notes receivable		52.9			2.9

Net Cash Used In Investing Activities Of Continuing Operations		(598.5	)		(555.6	)


FINANCING ACTIVITIES
Checks outstanding in excess of cash balances		14.6			7.7
Long-term debt issued		—			50.0
Long-term debt issuance costs paid		(9.8	)		(0.1	)
Long-term debt repaid		(102.0	)		—
Change in notes payable		(39.3	)		(89.4	)
Equity contribution		250.0			—
Distribution to noncontrolling interest		(2.4	)		(3.3	)

Net Cash Used In Financing Activities Of Continuing Operations		111.1			(35.1	)

CASH USED IN CONTINUING OPERATIONS		(19.3	)		(25.1	)

Cash provided by operating activities of discontinued operations		68.6			88.5
Cash used in investing activities of discontinued operations		(39.9	)		(58.3	)
Cash provided by financing activities of discontinued operations		(26.9	)		(25.4	)
Effect of change in cash and cash equivalents of discontinued operations		(1.8	)		(4.8	)

Change in cash and cash equivalents		(19.3	)		(25.1	)
Beginning cash and cash equivalents		19.3			25.1

Ending cash and cash equivalents	$	—		$	—

See notes accompanying the condensed consolidated financial statements

QEP RESOURCES, INC.

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Nature of Business

QEP Resources, Inc. (QEP or the Company), is a natural gas-focused energy company. QEP is a holding company with three major lines of business – gas and oil exploration and production, midstream field services, and energy marketing – which are conducted through three principal subsidiaries:

•

QEP Energy Company (QEP Energy) acquires, explores for, develops and produces natural gas, oil, and natural gas liquids (NGL);

•

QEP Field Services Company (QEP Field Services) provides midstream field services including natural gas-gathering and processing services for affiliates and third parties; and

•

QEP Marketing Company (QEP Marketing) markets equity and third-party natural gas and oil, provides risk-management services, and owns and operates an underground gas-storage reservoir.

QEP operates in the Rocky Mountain and Midcontinent regions of the United States of America and is headquartered in Denver, Colorado. Principal offices are located in Salt Lake City, Utah; Oklahoma City, Oklahoma; Tulsa, Oklahoma; and Rock Springs, Wyoming.

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 U.S. 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 presentation of financial position and results of operations for the interim periods presented. Interim condensed consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2009.

The preparation of the condensed consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect the amounts of revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three- and six-months ended June 30, 2010, are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.

Effective May 18, 2010, registrant Questar Market Resources, Inc. (Market Resources) merged with and into its newly-formed, wholly-owned subsidiary, QEP, a Delaware corporation in order to reincorporate in the State of Delaware (the Reincorporation Merger). The Reincorporation Merger was effected pursuant to an Agreement and Plan of Merger entered into between Market Resources and QEP. The Reincorporation Merger was approved by the boards of directors of Market Resources and QEP and submitted to a vote of, and approved by, Questar Corporation (Questar), as sole shareholder of Market Resources, and by Market Resources, as sole shareholder of QEP on May 18, 2010. As a result of the Reincorporation Merger, QEP is the surviving entity and successor registrant to Market Resources.

On June 30, 2010 (the Distribution Date), all of the shares of common stock of QEP were distributed through a tax-free, pro rata dividend to Questar shareholders (the Spin-off). Each Questar shareholder received one share of QEP common stock for each share of Questar common stock held (including fractional shares) at the close of business on the record date, which was June 18, 2010. In conjunction with the Spin-off, QEP distributed the common stock of its wholly-owned subsidiary, Wexpro Company (Wexpro), to Questar. In addition, Questar contributed $250 million of equity to QEP prior to the Spin-off.

QEP reported expenses of $14.0 million in the second quarter of 2010 related to the Spin-off. The expenses consisted primarily of fees and expenses for financial, legal and tax advisory services and for severance expenses for terminated employees.

The 2009 financial information has been recast so that the basis of presentation is consistent with that of the 2010 financial information. This recast reflects the financial condition and results of operations of Wexpro, as discontinued operations for all periods presented. For a summary of discontinued operations see Note 3. Certain reclassifications were made to prior-period financial statements to conform with the current presentation.

All dollar and share amounts in this quarterly report on Form 10-Q are in millions, except where otherwise noted.

Note 3 – Discontinued Operations

Wexpro’s operating results are reflected in this quarterly report on Form 10-Q as discontinued operations and summarized below:


	3 Months Ended June 30,						6 Months Ended June 30,
	2010			2009			2010			2009
	(in millions, except per share amounts)
Revenues	$	64.5		$	56.7		$	131.2		$	118.6

Income before income taxes		34.3			30.9			67.4			60.1
Income taxes		(12.3	)		(11.1	)		(24.2	)		(21.5	)

Discontinued operations, net of income taxes	$	22.0		$	19.8		$	43.2		$	38.6


Earnings per common share attributable to QEP
Basic from discontinued operations	$	0.13		$	0.11		$	0.25		$	0.22
Diluted from discontinued operations		0.12			0.11			0.24			0.22

Note 4 – Comprehensive Income

Comprehensive income is the sum of net income attributable to QEP as reported in the Consolidated Statements of Income and other comprehensive income. Other comprehensive income includes changes in the market value of commodity-based derivative instruments and recognition of the under-funded position of the defined benefit pension plan and other postretirement benefits plans. These transactions are not the culmination of the earnings process but result from periodically adjusting historical balances to fair value. Income or loss associated with commodity-based derivative instruments is realized when the gas, oil or NGL underlying the derivative instrument is sold. Comprehensive income attributable to QEP is shown below:


	3 Months Ended June 30,						6 Months Ended June 30,
	2010			2009			2010			2009
	(in millions)
Net income	$	91.5		$	65.3		$	191.4		$	86.5
Other comprehensive income (loss)
Net unrealized income (loss) on derivatives		(65.0	)		(229.6	)		234.2			(140.0	)
Pension and postretirement liabilities		(38.7	)		—			(38.7	)		—
Other		(0.1	)		—			—			—
Income taxes		38.6			85.4			(72.7	)		52.0

Net other comprehensive income (loss)		(65.2	)		(144.2	)		122.8			(88.0	)

Comprehensive income (loss)		26.3			(78.9	)		314.2			(1.5	)
Comprehensive income attributable to noncontrolling interest		(0.7	)		(0.6	)		(1.3	)		(1.1	)

Comprehensive income (loss) attributable to QEP	$	25.6		($	79.5	)	$	312.9		($	2.6	)

The components of accumulated other comprehensive income (AOCI), net of income taxes, shown on the Condensed Consolidated Balance Sheets are as follows:


	June 30, 2010			December 31, 2009		Change
	(in millions)
Net unrealized gain on derivatives	$	234.2		$	87.1	$	147.1
Pension and postretirement liabilities		(24.3	)		—		(24.3	)

Accumulated other comprehensive income	$	209.9		$	87.1	$	122.8

Note 5 – Earnings Per Share

Basic earnings per share (EPS) is computed by dividing net income attributable to QEP by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. Because of the pro rata nature of the share distribution arising from the Spin-off, historical share counts are identical to those of Questar for the corresponding periods. A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:


	3 Months Ended June 30,		6 Months Ended June 30,
	2010	2009 (recast)	2010	2009 (recast)
	(in millions)
Weighted-average basic common shares outstanding	175.1	174.1	175.0	173.9
Potential number of shares issuable under the Long-term Stock Incentive Plan	2.5	2.0	2.4	2.1

Average diluted common shares outstanding	177.6	176.1	177.4	176.0

Note 6 – Asset Retirement Obligations

QEP records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible long-lived assets. At QEP, ARO apply primarily to abandonment costs associated with gas and oil wells, production facilities and certain other properties. The fair values of retirement costs are estimated by Company personnel based on abandonment costs of similar properties available to field operations and depreciated over the life of the related assets. Revisions to ARO estimates result from changes in expected cash flows or material changes in estimated retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Income or expense resulting from the settlement of ARO liabilities is included in net gain or (loss) from asset sales on the Consolidated Statements of Income. Changes in ARO were as follows:


	2010			2009 (recast)
	(in millions)
ARO liability at January 1,	$	124.7		$	116.7
Accretion		4.2			3.8
Liabilities incurred		12.6			1.3
Revisions		0.5			—
Liabilities settled		(0.7	)		(1.3	)

ARO liability at June 30,	$	141.3		$	120.5

Note 7 – Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are presented in the table below and exclude amounts that were capitalized and subsequently expensed in the period. All of these costs have been capitalized for less than one year.


	2010			2009
	(in millions)
Balance at January 1,	$	51.7		$	17.0
Additions to capitalized exploratory well costs pending the determination of proved reserves		1.0			35.2
Reclassifications to property, plant and equipment after the determination of proved reserves		(47.9	)		(14.3	)
Capitalized exploratory well costs charged to expense		—			(2.7	)

Balance at June 30,	$	4.8		$	35.2

Note 8 – Fair Value Measurements

QEP measures and discloses fair values in accordance with the provisions of ASC 820 “Fair Value Measurements and Disclosures”. ASC 820 establishes a fair value hierarchy of Levels 1, 2 and 3 based on inputs with Level 1 measures calculated from the most observable inputs. Level 1 inputs are unadjusted quoted prices 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. The Level 2 fair value of derivative contracts (see Note 9) is based on market prices posted on the NYMEX on the last trading day of the reporting period and industry-standard discounted cash flow models. The Level 3 fair value of derivative contracts is based on NYMEX market prices in combination with unobservable volatility inputs and industry-standard option pricing 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.

Certain of QEP’s derivative instruments, however, 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, 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 a counterparty exists.

QEP did not have any assets or liabilities measured at fair value on a non-recurring basis at June 30, 2010, or at December 31, 2009. The fair value of assets and liabilities at June 30, 2010, is shown in the table below:

Fair Value Measurements
June 30, 2010

Level 2

Level 3

Netting
Adjustments

Total

(in millions)

Assets

Derivative contracts - short term

386.6

15.7

($ 162.3

)

240.0

Derivative contracts - long term

213.5

12.0

(72.6

)

152.9

Total assets

600.1

27.7

($ 234.9

)

392.9

Liabilities

Derivative contracts - short term

291.7

0.1

($ 162.3

)

129.5

Derivative contracts - long term

140.5

0.2

(72.6

)

68.1

Total liabilities

432.2

0.3

($ 234.9

)

197.6

QEP did not have any Level 3 assets or liabilities during the first half of 2009. The change in the fair value of Level 3 assets and liabilities for the first half of 2010 is shown below:


	Derivative Contracts 2010
	(in millions)
Balance at January 1,	$ 5.5
Realized gains and losses included in revenues	2.6
Unrealized gains and losses included in other comprehensive income	21.9
Settlements	(2.6	)

Balance at June 30,	$ 27.4

The fair value of assets and liabilities at December 31, 2009, is shown in the table below:


	Fair Value Measurements December 31, 2009 (recast)
	Level 2		Level 3		Netting Adjustments			Total
	(in millions)
*Assets*
Derivative contracts - short term	$	312.6	$	2.4	($	186.8	)	$	128.2
Derivative contracts - long term		194.3		16.1		(149.2	)		61.2

Total assets	$	506.9	$	18.5	($	336.0	)	$	189.4


*Liabilities*
Derivative contracts - short term	$	334.4	$	2.1	($	186.8	)	$	149.7
Derivative contracts - long term		278.9		10.9		(149.2	)		140.6

Total liabilities	$	613.3	$	13.0	($	336.0	)	$	290.3

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


	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
	June 30, 2010				December 31, 2009 (recast)
	(in millions)
*Financial assets*
Cash and cash equivalents	$	—	$	—	$	19.3	$	19.3
Notes receivable		—		—		52.9		52.9
*Financial liabilities*
Checks outstanding in excess of cash balances	$	14.6	$	14.6	$	—	$	—
Notes payable		—		—		39.3		39.3
Long-term debt		1,246.8		1,275.2		1,348.7		1,394.1

The carrying amounts of cash and cash equivalents, notes receivable, checks outstanding in excess of cash balances and notes payable approximate fair value. The fair value of fixed-rate long-term debt is based on the discounted present value of cash flows using the Company’s current credit-risk adjusted borrowing rates. The carrying amount of variable-rate long-term debt approximates fair value.

Note 9 – Derivative Contracts

QEP’s subsidiaries use commodity-price derivative instruments in the normal course of business. QEP has established policies and procedures for managing commodity-price risks through the use of derivative instruments. QEP uses derivative instruments to support rate of return targets and to protect cash flow from downward movements in commodity prices. However, these same instruments typically limit future gains from favorable price movements. Derivative contracts are currently in place for a significant share of QEP Energy-owned gas and oil production and a portion of QEP Marketing gas marketing transactions. The volume of production with associated derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. QEP may match derivative contracts with up to 100% of forecast production from proved reserves when prices meet earnings and cash flow objectives. QEP does not enter into derivative instruments for speculative purposes.

QEP uses derivative instruments known as fixed-price swaps and costless collars to realize a known price or range of prices for a specific volume of production delivered into a regional sales point. Swap agreements do not require the physical transfer of natural gas between the parties at settlement. Swap transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the relevant volume, for the settlement period. Collars are combinations of put and call options that have a floor price and a ceiling price and are only triggered if the settlement price is outside the range of the floor and ceiling prices. In the past, QEP Energy has also used natural gas basis-only swaps to protect rate of return targets and protect cash flows from widening natural gas-price basis differentials. However, natural gas basis-only swaps exposed the Company to losses from narrowing natural gas price-basis differentials. As of December 31, 2009, all of the Company’s basis-only swaps were paired with fixed-price swaps and re-designated as cash flow hedges. Changes in the fair value of the derivative instruments subsequent to the re-designation were recorded in AOCI. Fair value changes occurring prior to re-designation were recorded in income.

QEP enters into derivative instruments that do not have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement dates. Derivative-arrangement 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 transacting with multiple counterparties.

All derivative instruments are required to be recorded on the balance sheet as either assets or liabilities measured at their fair values. The designation of a derivative instrument as a hedge and its ability to meet hedge accounting criteria determines how the change in fair value of the derivative instrument is reflected in the consolidated financial statements. A derivative instrument qualifies for hedge accounting, if at inception, the derivative is expected to be highly effective in offsetting the underlying hedged cash flows. Generally, QEP’s derivative instruments are matched to equity gas and oil production and are highly effective, thus qualifying as cash flow hedges. Changes in the fair value of effective cash flow hedges are recorded as a component of AOCI on the Condensed Consolidated Balance Sheets and reclassified to earnings as gas and oil sales when the underlying physical transactions occur. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. Costless collars qualify for cash flow hedge accounting. A basis-only swap does not qualify for hedge accounting treatment. QEP regularly reviews the effectiveness of derivative instruments. The ineffective portion of cash flow hedges and the mark to market adjustment of basis-only swaps are recognized in the determination of net income.


	3 Months Ended June 30,						6 Months Ended June 30,
	2010			2009			2010			2009
	(in millions)
*Effect of derivative instruments designated as cash flow hedges*
Gains recognized in AOCI for the effective portion of hedges	$	31.3		($	50.3	)	$	375.9		$	197.2
Gains (losses) reclassified from AOCI into income for the effective portion of hedges
Natural gas sales		97.5			171.3			143.1			311.1
Oil and NGL sales		(1.8	)		1.3			(3.8	)		5.9
Marketing sales		—			10.0			—			24.1
Marketing purchases		0.6			(3.3	)		2.4			(3.9	)
Gain (loss) recognized in income for the ineffective portion of hedges
Interest and other income		0.3			(0.2	)		(0.1	)		(0.2	)
*Effect of derivative instruments not designated as hedges*
Unrealized gain (loss) on basis-only swaps		27.4			(27.8	)		62.1			(162.7	)
Realized (loss) on basis-only swaps		(27.4	)		(4.6	)		(62.1	)		(8.0	)

Based on June 30, 2010 prices, $144.0 million will be settled and reclassified from AOCI to the Consolidated Statements of Income in the next 12 months. The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation in the Condensed Consolidated Balance Sheets.


	June 30, 2010		December 31, 2009
	(in millions)
*Assets*
Fixed-price swaps	$	386.6	$	312.6
Option contracts		15.7		2.4

Fair value of derivative instruments - short term	$	402.3	$	315.0

Fixed-price swaps	$	213.5	$	194.3
Option contracts		12.0		16.1

Fair value of derivative instruments - long term	$	225.5	$	210.4

*Liabilities*
Fixed-price swaps	$	173.3	$	212.7
Option contracts		0.1		2.1
Basis-only swaps		118.4		121.7

Fair value of derivative instruments - short term	$	291.8	$	336.5

Fixed-price swaps	$	81.6	$	161.2
Option contracts		0.2		10.9
Basis-only swaps		58.9		117.7

Fair value of derivative instruments - long term	$	140.7	$	289.8

All previously reported basis-only swaps have been combined with fixed-price NYMEX natural gas swaps for 2010 and 2011 and now qualify as cash flow hedges. The following table sets forth QEP’s volumes and average net-to-the-well prices for transactions with associated risk management derivative contracts as of June 30, 2010:

QEP Energy Production


Year	Time Periods	Quantity	Average hedge price per Mcf or Bbl, net to the well^(a) (estimated)
Gas (Bcf) Fixed-price Swaps
2010	6 months	76.4	$5.26
2011	12 months	102.1	4.91
2012	12 months	40.6	5.91
2013	12 months	47.2	5.98

Gas (Bcf) Collars
			Floor- Ceiling
2010	6 months	3.4	$4.65-$6.51
2011	12 months	27.7	4.63–6.66

Oil (Mbbl) Fixed-price Swaps
2010	6 months	460	$60.66

Oil (Mbbl) Collars
			Floor- Ceiling
2010	6 months	368	$47.60–$96.10
2011	12 months	1,095	51.73–102.10
*QEP Marketing Transactions*
Year	Time Periods	Quantity	Average hedged price per MMBtu
Gas Sales (millions of MMBtu) Fixed-price Swaps
2010	6 months	3.9	$5.31
2011	12 months	2.6	5.62

Gas Purchases (millions of MMBtu) Fixed-price Swaps
2010	6 months	1.5	$4.48
2011	12 months	0.3	6.20

(a)

The fixed-price swap and collar prices are reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price.

Note 10 – Share-Based Compensation

QEP issues stock options and restricted shares to certain officers, employees and non-employee directors under its Long-term Stock Incentive Plan (LTSIP) and recognizes expense over time as the stock options or restricted shares vest. Prior to the Spin-off, Questar granted share-based compensation to certain QEP employees using Questar common stock as the basis. Stock options or restricted stock awards outstanding as of the Distribution Date were adjusted in order to generally preserve the benefits or potential benefits intended to be made available under the LTSIP. All such stock options were divided into two separate options, one relating to Questar common stock and one relating to QEP common stock. Each holder of Questar restricted stock was issued additional restricted shares of QEP common stock on a pro rata basis. The exercise price of options and the grant-day price of restricted shares were adjusted by the ratio of the closing price of QEP and Questar common stock on June 30, 2010.

QEP recognizes expense over time as the stock options or restricted shares vest. First half share-based compensation expense amounted to $7.1 million in 2010 compared to $7.4 million in 2009. Deferred share-based compensation, representing the unvested value of restricted share awards, amounted to $15.0 million at June 30, 2010. Deferred share-based compensation is included in common stock on the Condensed Consolidated Balance Sheets. There were 15.0 million shares available for future grants at June 30, 2010.

QEP uses the Black-Scholes-Merton mathematical model in estimating the fair value of stock options for accounting purposes. 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 was intended for measuring the value of options traded on an exchange. The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:


	Stock Option Variables 6 Months Ended June 30, 2010
Fair value of options at grant date	$	27.55
Risk-free interest rate		2.30	%
Expected price volatility		30.3	%
Expected dividend yield		1.18	%
Expected life in years		5.2

Unvested stock options decreased by 60,211 to 822,784 shares in the first half of 2010. Stock-option transactions under the terms of the LTSIP recast for the effect of the Spin-off are summarized below:


	Options Outstanding		Price Range		Weighted- average Price
Balance at January 1, 2010 (recast)	1,762,494		$	5.08 - $27.84	$	17.78
Granted	219,800			27.55		27.55
Exercised	(23,000	)		5.08		5.08
Forfeited	(5,000	)		23.97		23.97

Balance at June 30, 2010	1,954,294		$	7.78 - $27.84	$	19.01


Options Outstanding					Options Exercisable			Unvested Options
Range of exercise prices	Number outstanding at June 30, 2010	Weighted- average remaining term in years	Weighted- average exercise price		Number exercisable at June 30, 2010	Weighted- average exercise price		Number unvested at June 30, 2010	Weighted- average exercise price
$7.78 – $8.12	337,842	1.6	$	7.95	337,842	$	7.95	—	$	—
9.19 – 9.49	297,878	2.3		9.23	297,878		9.23	—		—
11.89 – 19.37	246,774	5.2		18.94	91,779		18.21	154,995		19.37
$22.95 – $27.84	1,071,800	5.2		25.23	404,011		25.42	667,789		25.11

	1,954,294	4.1	$	19.01	1,131,510	$	15.35	822,784	$	24.03

Restricted-share grants typically vest in equal installments over a three- or four-year period from the grant date. Several grants vest in a single installment after a specified period. The weighted-average vesting period of unvested restricted shares at June 30, 2010, was 23 months. Transactions involving restricted shares under the terms of the LTSIP recast for the effect of the Spin-off are summarized below:


	Unvested Restricted Shares		Price Range		Weighted- average Price
Balance at January 1, 2010 (recast)	603,306		$	17.02 - $47.53	$	29.46
Granted	272,200			27.55 – 33.84		27.69
Distributed	(215,512	)		19.86 – 47.53		28.81
Forfeited	(9,696	)		22.59 – 45.81		28.07

Balance at June 30, 2010	650,298		$	17.02 - $47.53	$	28.95

As a result of the Spin-off and bifurcation of share-based awards, Questar stock options and restricted shares were granted to certain officers, employees and non-employee directors of QEP. The awards include 822,784 unvested stock options with a weighted-average price of $11.43 per share and 650,298 unvested restricted shares with a weighted-average price of $13.77 per share. QEP will recognize expense in future periods for these unvested share-based awards. In addition, certain Questar officers, employees and non-employee directors received 3,024,883 QEP stock options.

Note 11 – Employee Benefits

In association with the Spin-off, the Company established a life insurance plan covering a majority of its employees and defined-benefit pension and postretirement medical plans providing coverage to less than half of its employees. On the Distribution Date, Questar transferred certain assets and liabilities from its life insurance, defined-benefit pension, and postretirement medical plans related to QEP employees into QEP’s plans. The transfer resulted in the establishment of liabilities of $38.7 million related to the unfunded portions of the defined-benefit pension plan and other postretirement benefits with corresponding amounts in AOCI. Approximately half of the estimated $5.6 million of pension and postretirement benefits expense for 2010 was recorded in the first half of 2010.

Note 12 – Operations by Line of Business

QEP’s lines of business information is presented according to senior management’s basis for evaluating performance considering the differences in the nature of operations, products, services and regulation among other factors. Following is a summary of operations by line of business:


	3 Months Ended June 30,					6 Months Ended June 30,
	2010			2009 (recast)		2010			2009 (recast)
	(in millions)
*Revenues from Unaffiliated Customers*
QEP Energy	$	315.8		$	302.9	$	635.5		$	613.7
QEP Field Services		78.5			59.0		158.8			113.5
QEP Marketing and other		135.3			80.8		315.5			197.6

Total	$	529.6		$	442.7	$	1,109.8		$	924.8


*Revenues from Affiliated Companies*
QEP Field Services	$	0.6		$	0.4	$	1.2		$	0.9
QEP Marketing and other		112.4			73.4		255.7			164.3

Total	$	113.0		$	73.8	$	256.9		$	165.2


*Operating Income*
QEP Energy	$	101.0		$	93.3	$	204.8		$	220.5
QEP Field Services		39.5			24.2		76.6			43.8
QEP Marketing and other		1.1			1.1		3.1			9.4
Certain separation costs		(14.0	)		—		(14.0	)		—

Total	$	127.6		$	118.6	$	270.5		$	273.7


*Income From Continuing Operations Attributable to QEP*
QEP Energy	$	52.6		$	29.6	$	106.4		$	14.7
QEP Field Services		24.3			14.5		47.5			25.9
QEP Marketing and other		0.5			0.8		1.6			6.2
Certain separation costs		(8.6	)		—		(8.6	)		—

Total	$	68.8		$	44.9	$	146.9		$	46.8

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

The following information updates the discussion of QEP’s financial condition provided in its 2009 Form 10-K filing, and analyzes the changes in the results of operations between the three- and six-month periods ended June 30, 2010 and 2009. For definitions of commonly used gas and oil terms found in this report on Form 10-Q, please refer to the “Glossary of Commonly Used Terms” provided in QEP’s 2009 Form 10-K.

RESULTS OF OPERATIONS

Following are comparisons of income from continuing operations attributable to QEP by line of business:


	3 Months Ended June 30,								6 Months Ended June 30,
	2010			2009		Change			2010			2009		Change
	(in millions, except per share amounts)
QEP Energy	$	52.6		$	29.6	$	23.0		$	106.4		$	14.7	$	91.7
QEP Field Services		24.3			14.5		9.8			47.5			25.9		21.6
QEP Marketing and other		0.5			0.8		(0.3	)		1.6			6.2		(4.6	)
Certain separation costs		(8.6	)		—		(8.6	)		(8.6	)		—		(8.6	)

Income from continuing operations attributable to QEP	$	68.8		$	44.9	$	23.9		$	146.9		$	46.8	$	100.1

Earnings per diluted share from continuing operations	$	0.39		$	0.26	$	0.13		$	0.83		$	0.27	$	0.56
Average diluted shares		177.6			176.1		1.5			177.4			176.0		1.4

QEP ENERGY

QEP Energy reported net income of $52.6 million in the second quarter of 2010 compared with $29.6 million in the 2009 quarter. Net income for the first half of 2010 increased 624% to $106.4 million compared to $14.7 million a year earlier. Higher realized crude oil and NGL prices and increased 2010 production largely offset lower realized natural gas prices in both periods. Changes in unrealized basis-only swaps increased net income $17.2 million in the 2010 quarter compared to a loss of $17.5 million in the year-earlier period. Following is a summary of QEP Energy financial and operating results:


	3 Months Ended June 30,									6 Months Ended June 30,
	2010			2009			Change			2010			2009			Change
	(in millions)
*Operating Income*
Revenues
Natural gas sales	$	260.6		$	264.5		($	3.9	)	$	525.2		$	542.9		($	17.7	)
Oil and NGL sales		53.7			37.3			16.4			107.7			68.4			39.3
Other		1.5			1.1			0.4			2.6			2.4			0.2

Total Revenues		315.8			302.9			12.9			635.5			613.7			21.8

Operating expenses
Lease operating expense		29.3			32.2			(2.9	)		58.1			66.6			(8.5	)
General and administrative		18.9			17.6			1.3			38.0			33.2			4.8
Production and property taxes		17.9			13.6			4.3			39.6			29.0			10.6
Depreciation, depletion and amortization		139.2			133.2			6.0			274.3			246.5			27.8
Exploration		2.7			8.9			(6.2	)		6.3			12.0			(5.7	)
Abandonment and impairment		9.3			3.8			5.5			16.9			7.5			9.4

Total Operating Expenses		217.3			209.3			8.0			433.2			394.8			38.4
Net gain (loss) from asset sales		2.5			(0.3	)		2.8			2.5			1.6			0.9

Operating Income	$	101.0		$	93.3		$	7.7		$	204.8		$	220.5		($	15.7	)

Unrealized gain (loss) on basis-only swaps	$	27.4		($	27.8	)	$	55.2		$	62.1		($	162.7	)	$	224.8
Realized (loss) on basis-only swaps	($	27.4	)	($	4.6	)	($	22.8	)	($	62.1	)	($	8.0	)	($	54.1	)
*Operating Statistics*
QEP Energy production volumes
Natural gas (Bcf)		47.9			38.4			9.5			94.2			79.8			14.4
Oil and NGL (MMbbl)		0.9			0.9			—			1.8			1.8			—
Total production (Bcfe)		53.7			43.4			10.3			105.2			90.3			14.9
Average daily production (MMcfe)		590.0			477.0			113.0			581.2			499.0			82.2
QEP Energy average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$	5.44		$	6.89		($	1.45	)	$	5.58		$	6.80		($	1.22	)
Oil and NGL (per bbl)	$	55.87		$	44.44		$	11.43		$	58.69		$	39.05		$	19.64

QEP Energy reported production of 53.7 Bcfe in the second quarter of 2010 compared to 43.4 Bcfe in the 2009 quarter, a 24% increase. Natural gas is QEP Energy’s primary focus. On an energy-equivalent basis, natural gas comprised approximately 89% of QEP Energy second quarter 2010 production. A summary of natural gas-equivalent production by major operating area is shown in the following table:


	3 Months Ended June 30,				6 Months Ended June 30,
	2010	2009	Change		2010	2009	Change
	(in Bcfe)
Midcontinent	27.5	19.8	7.7		53.7	40.8	12.9
Pinedale Anticline	16.5	14.1	2.4		32.0	28.7	3.3
Uinta Basin	5.4	6.0	(0.6	)	10.6	12.3	(1.7	)
Rockies Legacy	4.3	3.5	0.8		8.9	8.5	0.4

Total QEP Energy	53.7	43.4	10.3		105.2	90.3	14.9

QEP Energy production increased 17% in the first half of 2010 compared to a year earlier. In the Midcontinent, production grew 32% to 53.7 Bcfe in the first half of 2010 and represented 51% of the Company’s total production. Ongoing development drilling in the Haynesville formation play in northwest Louisiana and the Woodford Shale play in the Anadarko Basin of western Oklahoma were the main contributors to the production increase. QEP Energy production from the Pinedale Anticline in western Wyoming grew 11% to 32.0 Bcfe in the first half of 2010 as a result of ongoing development drilling. In the Uinta Basin, production decreased 14% to 10.6 Bcfe in the first half of 2010 due to decreased drilling activity. QEP Energy Rockies Legacy 2010 production of 8.9 Bcfe was 0.4 Bcfe higher than a year ago. Rockies Legacy properties include all of the company’s Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin.

Realized prices for natural gas at QEP Energy were lower when compared to the prior year, while realized oil and NGL prices were higher when compared to the prior-year period. In the first half of 2010, the weighted-average realized natural gas price for QEP Energy, including the impact of hedging, was $5.58 per Mcf compared to $6.80 per Mcf for the same period in 2009, an 18% decrease. Realized oil and NGL prices in the first half of 2010 averaged $58.69 per bbl, compared with $39.05 per bbl during the prior year period, a 50% increase. A regional comparison of average realized prices, including hedges, is shown in the following table:


	3 Months Ended June 30,							6 Months Ended June 30,
	2010		2009		Change			2010		2009		Change
*Natural gas (per Mcf)*
Midcontinent	$	6.16	$	7.45	($	1.29	)	$	6.30	$	7.49	($	1.19	)
Rocky Mountains		4.66		6.40		(1.74	)		4.78		6.22		(1.44	)
Volume-weighted average		5.44		6.89		(1.45	)		5.58		6.80		(1.22	)
*Oil and NGL (per bbl)*
Midcontinent	$	49.60	$	45.27	$	4.33		$	55.23	$	40.54	$	14.69
Rocky Mountains		60.42		43.97		16.45			60.98		38.08		22.90
Volume-weighted average		55.87		44.44		11.43			58.69		39.05		19.64

A comparison of net realized average natural gas prices, including the realized losses on basis-only swaps, is shown in the following table:


	3 Months Ended June 30,									6 Months Ended June 30,
	2010			2009			Change			2010			2009			Change
*Natural gas (per Mcf)*
Volume-weighted average (a)	$	5.44		$	6.89		($	1.45	)	$	5.58		$	6.80		($	1.22	)
Realized losses on basis-only swaps (b)		(0.57	)		(0.12	)		(0.45	)		(0.66	)		(0.10	)		(0.56	)

Net realized natural gas price ($ per Mcf)	$	4.87		$	6.77		($	1.90	)	$	4.92		$	6.70		($	1.78	)

(a)	Reported in natural gas sales in the Consolidated Statements of Income.

(b)	Reported below operating income in the Consolidated Statements of Income.

QEP Energy hedged approximately 79% of second quarter 2010 gas production with fixed-price swaps, and 3% with collars. In the second quarter of 2009, approximately 84% of gas production was hedged with fixed-price swaps. An additional 17% of gas production was subject to basis-only swaps in the 2009 quarter. Gas hedging increased QEP Energy second quarter 2010 gas revenues by $97.5 million and increased second quarter 2009 gas revenues by $171.3 million. Approximately 33% of second quarter 2010 oil production was hedged with fixed-price swaps, and 27% with collars. In second quarter 2009, approximately 35% of oil production was hedged with fixed-price swaps. Oil hedges decreased second quarter 2010 revenues $1.8 million and increased second quarter 2009 revenues $1.3 million. Realized losses on basis-only swaps were $27.4 million in the second quarter of 2010 and $4.6 million in the second quarter of 2009. The net effect of natural gas-basis-only swaps is reported in the Consolidated Statements of Income below operating income. Derivative positions as of June 30, 2010, are summarized in Note 9 to the consolidated financial statements in Item 1 of Part I in this Quarterly Report on Form 10-Q.

QEP Energy hedged approximately 79% of first half 2010 gas production with fixed-price swaps, and 4% with collars. In the first half of 2009, approximately 80% of gas production was hedged with fixed-price swaps. An additional 16% of gas production was subject to basis-only swaps in the 2009 period. Gas hedging increased QEP Energy first half 2010 gas revenues by $143.1 million and increased first half 2009 gas revenues by $311.1 million. Approximately 33% of first half 2010 oil production was hedged with fixed-price swaps, and 27% with collars. In first half 2009, approximately 30% of oil production was hedged with fixed price swaps. Oil hedges decreased revenues $3.8 million in 2010 and increased revenues $5.9 million in 2009. Realized losses on basis-only swaps were $62.1 million in the first half of 2010 and $8.0 million in the first half of 2009.

QEP Energy production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense, allocated interest expense and production taxes) per Mcfe of production decreased 14% to $4.17 per Mcfe in the second quarter of 2010 versus $4.86 per Mcfe in 2009. First half 2010 production costs per Mcfe decreased $0.22 or 5% compared to the 2009 period. QEP Energy production costs are summarized in the following table:


	3 Months Ended June 30,							6 Months Ended June 30,
	2010		2009		Change			2010		2009		Change
	(per Mcfe)
Depreciation, depletion and amortization	$	2.59	$	3.07	($	0.48	)	$	2.61	$	2.73	($	0.12	)
Lease operating expense		0.54		0.74		(0.20	)		0.55		0.74		(0.19	)
General and administrative expense		0.35		0.40		(0.05	)		0.36		0.37		(0.01	)
Allocated interest expense		0.35		0.33		0.02			0.36		0.32		0.04
Production taxes		0.34		0.32		0.02			0.38		0.32		0.06

Total Production Costs	$	4.17	$	4.86	($	0.69	)	$	4.26	$	4.48	($	0.22	)

Production volume-weighted average depreciation, depletion and amortization (DD&A) expense per Mcfe decreased in 2010 due to negative price-related reserve adjustments in the first half of 2009. Lease operating expense per Mcfe decreased as the result of increased production combined with lower operating expense. Growing production from new high-rate, low operating cost wells in northwest Louisiana and declining production from higher-cost areas is lowering average lease operating expense. Allocated interest expense per unit of production increased in the 2010 periods primarily due to higher interest rates and higher debt balances. Production taxes per Mcfe increased in the first half of 2010 as a result of higher natural gas and oil field-level sales prices.

QEP Energy exploration expense decreased $5.7 million or 48% in the first half of 2010 compared to 2009. Abandonment and impairment expense increased $9.4 million, or 125% in 2010 compared to 2009.

The change in unrealized gains and losses on natural gas basis-only swaps increased first half 2010 net income $39.0 million compared to a loss of $102.2 million in the year-earlier period. As of December 31, 2009, all of the Company’s basis-only swaps were paired with fixed-price swaps and re-designated as cash flow hedges. Changes in the fair value of the derivative instruments subsequent to the re-designation were recorded in AOCI. Fair value changes occurring prior to re-designation were recorded in income.

Major QEP Energy Operating Areas

Midcontinent

QEP Energy Midcontinent properties are distributed over a large area, including the Anadarko Basin of Oklahoma and the Texas Panhandle, the Arkoma Basin of Oklahoma and western Arkansas, and the Ark-La-Tex region of Arkansas, Louisiana, and Texas. With the exception of northwest Louisiana, the Granite Wash play in the Texas Panhandle and the Woodford Shale play in western Oklahoma, QEP Energy Midcontinent leasehold interests are fragmented, with no significant concentration of property interests.

QEP Energy has approximately 49,000 net acres of Haynesville Shale lease rights in northwest Louisiana. The depth of the top of the Haynesville Shale ranges from approximately 10,500 feet to 12,500 feet across QEP Energy’s leasehold and is below the Hosston and Cotton Valley formations that QEP Energy has been developing in northwest Louisiana for over a decade. QEP Energy intends to drill or participate in up to 80 horizontal Haynesville Shale wells in 2010. As of June 30, 2010, QEP Energy had seven operated rigs drilling in the project area and operated or had working interests in 656 producing wells in northwest Louisiana compared to 583 at June 30, 2009.

Pinedale Anticline

As of June 30, 2010, QEP Energy has interests in 472 producing wells on the Pinedale Anticline compared to 369 at the end of the second quarter of 2009. Of the 472 producing wells, QEP Energy has working interests in 451 wells and an overriding royalty interest only in an additional 21 wells.

In 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre-density drilling for Lance Pool wells on about 12,700 acres of QEP’s 17,872-acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of QEP core acreage in the field. The Company continues to evaluate development on five-acre density at Pinedale. In January 2008, the WOGCC approved five-acre-density drilling for Lance Pool wells on about 4,200 gross acres of QEP Pinedale leasehold. If five-acre-density development is appropriate for a majority of its leasehold, the Company currently estimates up to 1,400 additional wells will be required to fully develop the Lance Pool on its acreage.

Uinta Basin

As of June 30, 2010, QEP Energy had an operating interest in 2,227 producing wells in the Uinta Basin of eastern Utah, compared to 888 at June 30, 2009. The significant increase in well count was due to the inclusion of QEP Energy acreage within the outside-operated Greater Monument Butte enhanced recovery unit in 2009; resulting in QEP Energy having a very small interest in over 1,300 wells. The majority of Uinta Basin proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs at depths of 5,000 feet to deeper than 18,000 feet. QEP Energy owns interests in over 420,000 gross leasehold acres in the Uinta Basin.

Rockies Legacy

The remainder of QEP Energy Rocky Mountain region leasehold interests, productive wells and proved reserves are distributed over a number of fields and properties managed as the Rockies Legacy division. Most of the properties are located in the Greater Green River Basin of western Wyoming. Planned exploration and development activity for 2010 includes wells in the Green River Basin, the Wyoming portion of the Denver-Julesburg (DJ) Basin and the Williston Basin in North Dakota.

QEP FIELD SERVICES

QEP Field Services, which provides gas-gathering and processing services, reported net income of $24.3 million in the second quarter of 2010 compared to $14.5 million in the same period of 2009. Net income was $47.5 million in the first half of 2010 compared to $25.9 million in the 2009 period. The increase in net income was driven by higher gas-gathering and processing margins. Following is a summary of QEP Field Services financial and operating results:


	3 Months Ended June 30,								6 Months Ended June 30,
	2010			2009		Change			2010			2009			Change
	(in millions)
*Operating Income*
Revenues
NGL sales	$	23.8		$	15.1	$	8.7		$	49.7		$	25.1		$	24.6
Processing		9.0			6.9		2.1			17.3			15.3			2.0
Gathering		38.4			30.9		7.5			74.4			62.9			11.5
Other gathering		7.9			6.5		1.4			18.6			11.1			7.5

Total Revenues		79.1			59.4		19.7			160.0			114.4			45.6

Operating expenses
Processing		3.0			2.6		0.4			6.0			5.2			0.8
Processing plant shrinkage		7.5			5.3		2.2			17.9			11.8			6.1
Gathering		8.7			8.3		0.4			18.6			18.8			(0.2	)
General and administrative		7.2			6.9		0.3			14.0			10.7			3.3
Production and other taxes		1.0			1.1		(0.1	)		2.1			2.0			0.1
Depreciation, depletion and amortization		11.9			11.0		0.9			23.7			21.9			1.8

Total Operating Expenses		39.3			35.2		4.1			82.3			70.4			11.9
Net (loss) from asset sales		(0.3	)		—		(0.3	)		(1.1	)		(0.2	)		(0.9	)

Operating Income	$	39.5		$	24.2	$	15.3		$	76.6		$	43.8		$	32.8

*Operating Statistics*
Natural gas processing volumes
NGL sales (MMgal)		26.7			24.8		1.9			51.5			46.2			5.3
NGL sales price (per gal)	$	0.89		$	0.61	$	0.28		$	0.96		$	0.54		$	0.42
Fee-based processing volumes (recast) (in millions of MMBtu)
For unaffiliated customers		30.4			19.1		11.3			58.5			45.9			12.6
For affiliated customers		26.7			23.0		3.7			52.3			48.7			3.6

Total Fee-Based Processing Volumes		57.1			42.1		15.0			110.8			94.6			16.2

Fee-based processing (per MMBtu)	$	0.16		$	0.16	$	—		$	0.16		$	0.16		$	—
Natural gas gathering volumes (recast) (in millions of MMBtu)
For unaffiliated customers		65.2			78.3		(13.1	)		135.7			160.0			(24.3	)
For affiliated customers		49.0			25.8		23.2			92.2			54.1			38.1

Total Gas Gathering Volumes		114.2			104.1		10.1			227.9			214.1			13.8

Gas gathering revenue (per MMBtu)	$	0.34		$	0.30	$	0.04		$	0.33		$	0.29		$	0.04

Gathering margin (gathering revenue minus gathering operating and maintenance expense) increased 29% in the second quarter to $37.6 million in 2010 compared to $29.1 million in 2009. Gathering margins in the first half of 2010 increased 35% to $74.4 million compared to $55.2 million in 2009. Gathering volumes increased 10.1 million MMBtu, or 10% to 114.2 million MMBtu in the second quarter of 2010 and increased 13.8 million MMBtu in the first half of 2010 compared with the 2009 periods.

Processing margin (processing revenue minus plant operating and maintenance expense, which includes processing plant-shrinkage) for the second quarter of 2010 increased 59% to $22.3 million compared to $14.1 million in 2009 and increased 84% to $43.1 million in the first half of 2010 compared to $23.4 million in the 2009 period. Fee-based gas-processing volumes increased 36% in the second quarter of 2010 to 57.1 million MMBtu and increased 17% to 110.8 million MMBtu in the first half of 2010 compared to 94.6 million MMBtu in the 2009 period. In the second quarter of 2010, fee-based gas processing revenues increased 31% or $2.1 million compared to the year ago quarter and 15% or $2.2 million in the first half of 2010 compared to the first half of 2009. The frac spread from keep-whole processing increased 66% or $6.5 million in the second quarter of 2010 compared to the 2009 quarter and 139% in the first half of 2010 compared to the first half of 2009.

Approximately 77% of QEP Field Services’ net operating revenue from processing and gathering contracts (revenue minus processing plant-shrinkage) in the second quarter 2010 was derived from fee-based contracts, down from 82% in 2009.

Depreciation expense grew $0.9 million or 8% in the second quarter of 2010 compared with the 2009 quarter as a result of plant additions.

QEP MARKETING

QEP Marketing net income was $0.5 million in the second quarter of 2010, a decrease of 38% compared to $0.8 million in 2009 and decreased $4.6 million in the first half of 2010 compared to 2009 as a result of lower marketing margins. First half revenues from unaffiliated customers were $315.5 million in 2010 compared to $197.6 million in 2009, a 60% increase. The weighted-average natural gas sales price increased 38% in the first half of 2010 to $4.38 per MMBtu, compared to $3.18 per MMBtu in the 2009 period.

CONSOLIDATED RESULTS BELOW OPERATING INCOME

Separation costs

Interest expense

Interest expense rose 28% in the second quarter of 2010 and 26% in the first half of 2010 and compared to a year ago due primarily to the Company issuing $300.0 million of notes at a 6.8% interest rate in August 2009 and using the proceeds to repay lower cost variable rate bank debt.

Realized and unrealized gain (loss) on basis-only swaps

In the past, the Company has used basis-only swaps to manage the risk of widening basis differentials. Basis-only swaps do not qualify for hedge accounting. As of December 31, 2009, all of the Company’s basis-only swaps were paired with fixed-price swaps and re-designated as cash flow hedges. Fair value changes occurring prior to re-designation were recorded in income. Changes in the fair value of the derivative instruments subsequent to the re-designation were recorded in AOCI. Realized losses on settlements of basis-only swaps amounted to $27.4 million in the second quarter of 2010 and $4.6 million in the second quarter of 2009. Unrealized gains on basis-only swaps amounted to $27.4 million in the second quarter of 2010 compared to losses of $27.8 million in 2009. Realized losses on settlements of basis-only swaps totaled $62.1 million in the first half of 2010 and $8.0 million in 2009. Unrealized gains were $62.1 million in the first half of 2010 compared to losses of $162.7 million in 2009.

Income taxes

The effective combined federal and state income tax rate was 36.8% in the first half of 2010 compared with 36.3% in the 2009 period.

LIQUIDITY AND CAPITAL RESOURCES

Operating Activities

Net cash provided from continuing operating activities decreased 17% in the first half of 2010 compared to the first half of 2009 due to lower noncash adjustments to net income. Noncash adjustments to net income consist primarily of depreciation, depletion and amortization; noncash unrealized gains and losses on basis-only swaps and changes in deferred income taxes. Cash sources from operating assets and liabilities were lower in 2010 primarily due to reductions in accounts receivable in the first half of 2009. Net cash provided from continuing operating activities is presented below:


	6 Months Ended June 30,
	2010			2009		Change
	(in millions)
Income from continuing operations	$	148.2		$	47.9	$	100.3
Noncash adjustments to net income		377.1			472.4		(95.3	)
Changes in operating assets and liabilities		(57.2	)		45.3		(102.5	)

Net cash provided from continuing operating activities	$	468.1		$	565.6	($	97.5	)

Investing Activities

A comparison of capital expenditures of continuing operations for the first half of 2010 and 2009 plus a forecast for calendar year 2010 are presented below:


	6 Months Ended June 30,					Forecast 12 Months Ended
	2010		2009			December 31, 2010
	(in millions)
QEP Energy	$	518.9	$	508.9		$	1,041.1
QEP Field Services		137.1		55.4			300.0
QEP Marketing and other		0.1		0.5			1.2

Total cash capital expenditures of continuing operations		656.1		564.8			1,342.3
Change in accruals		30.7		(118.2	)		—

Total accrued capital expenditures of continuing operations	$	686.8	$	446.6		$	1,342.3

Financing Activities

In the first half of 2010, net cash used in investing activities of $598.5 million exceeded net cash provided by operating activities of $468.1 million by $130.4 million. Long-term debt (including the current portion of long-term debt) decreased by $102.0 million from year-end 2009 primarily as a result of the $250.0 million equity contribution by Questar associated with the Spin-off. At June 30, 2010, long-term debt consisted of $98.0 million outstanding under QEP’s revolving credit facility and $1,148.8 million in notes, which included $150.0 million of notes that mature in March 2011. All intercompany loans between Questar and QEP, which have been historically reported as notes payable on the Condensed Consolidated Balance Sheets, were repaid on June 30, 2010, in conjunction with the Spin-off. At June 30, 2010, combined short-term and long-term debt was 30% and equity was 70% of total capital.

On June 30, 2010, in conjunction with the Spin-off, QEP amended its existing revolving credit agreement. Among other things, the amendment increased the amount of commitments from $800.0 million to $1.0 billion, increased commitment fees, increased the applicable margin used in calculating interest rates and added financial covenants that limit the amount of funded indebtedness the Company may incur. In addition, QEP entered into a new $500.0 million, 364-day term loan agreement (Term Loan) with substantially the same initial pricing and terms as its revolving credit agreement. The Term Loan can be extended for an additional 364-day period upon request by the Company. The Term Loan agreement contains provisions that increase the applicable margin in determining the interest rate and require the Company to pay additional fees to the lenders if the Term Loan is outstanding in excess of specified time periods. At July 26, 2010, QEP had $120.0 million outstanding under its revolving credit facility and $3.8 million of letters of credit issued.

As a result of the change in ownership of QEP and the subsequent change in ratings of the Company’s notes to below investment grade (see Debt Ratings, below), the notes’ indenture required the Company to offer to purchase all of outstanding notes ($1,150.0 million principal amount) at a price of either par or 101% of par plus accrued, unpaid interest. The Company sent offers to purchase to note holders on July 9, 2010, and the offer will expire on August 6, 2010, unless extended. Any notes properly tendered to the Company are expected to be purchased on August 11, 2010. The combination of availability under the revolving credit agreement and the Term Loan will provide adequate liquidity to purchase all of the notes if they are tendered.

Debt Ratings

On July 2, 2010, Moody’s Investors Service reduced QEP’s long-term debt rating to Ba1 and Standard & Poor’s reduced its rating of QEP’s long-term debt to BB+.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

QEP’s primary market-risk exposure arises from changes in the market price for natural gas, oil and NGL, and volatility in interest rates. QEP Marketing has long-term contracts for pipeline capacity and is obligated to pay for transportation services with no guarantee that it will be able to fully utilize the contractual capacity of these transportation commitments.

Commodity-Price Risk Management

QEP’s subsidiaries use commodity-price derivative instruments in the normal course of business to reduce the risk of adverse commodity-price movements. However, these same arrangements typically limit future gains from favorable price movements. Derivative contracts are currently in place for a significant share of QEP Energy-owned gas and oil production and a portion of QEP Marketing gas-marketing transactions.

As of June 30, 2010, QEP held commodity-price hedging contracts covering about 325.4 million MMBtu of natural gas and 1.9 million barrels of oil. A year earlier, the QEP hedging contracts covered 426.5 million MMBtu of natural gas, 1.6 million barrels of oil and natural gas basis-only swaps on an additional 83.2 Bcf. Changes in the fair value of derivative contracts from December 31, 2009 to June 30, 2010, are presented below:


	Cash flow Hedges			Basis-only Swaps			Total
	(in millions)
Net fair value of gas- and oil-derivative contracts outstanding at Dec. 31, 2009	$	138.5		($	239.4	)	($	100.9	)
Contracts settled		(141.7	)		62.1			(79.6	)
Change in gas and oil prices on futures markets		375.4			—			375.4
Contracts added		0.4			—			0.4

Net fair value of gas- and oil-derivative contracts outstanding at June 30, 2010	$	372.6		($	177.3	)	$	195.3

A table of the net fair value of gas- and oil-derivative contracts as of June 30, 2010, is shown below. Most of the fixed-priced swaps will settle in the next 12 months and the fair value of cash-flow hedges will be reclassified from Accumulated Other Comprehensive Income to the Consolidated Statements of Income:


	Cash flow Hedges		Basis-only Swaps			Total
	(in millions)
Contracts maturing by June 30, 2011	$	228.9	($	118.4	)	$	110.5
Contracts maturing between July 1, 2011 and June 30, 2012		86.2		(58.9	)		27.3
Contracts maturing between July 1, 2012 and June 30, 2013		38.4		—			38.4
Contracts maturing between July 1, 2013 and June 30, 2014		19.1		—			19.1

Net fair value of gas- and oil-derivative contracts outstanding at June 30, 2010	$	372.6	($	177.3	)	$	195.3

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


	June 30, 2010		December 31, 2009
	(in millions)
Net fair value - asset (liability)	$	195.3	($100.9	)
Fair value if market prices of gas and oil and basis differentials decline by 10%		359.2	174.2
Fair value if market prices of gas and oil and basis differentials increase by 10%		19.2	(375.8	)

Interest-Rate Risk Management

As of June 30, 2010, QEP had $1,148.8 million of fixed-rate long-term debt and $98.0 million of variable-rate long-term debt.

Forward-Looking Statements

This quarterly report may contain or incorporate by reference information that includes or is based upon “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. In particular, these include statements relating to future actions, prospective services or products, future performance or results of current and anticipated services or products, exploration efforts, expenses, the outcome of contingencies such as legal proceedings, trends in operations and financial results.

Any or all forward-looking statements may turn out to be wrong. 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. Among factors that could cause actual results to differ materially are:

•

the risk factors discussed in Part I, Item 1A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009;

•

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

•

changes in industry trends;

•

changes in laws or regulations; and

•

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

QEP undertakes no obligation to publicly correct or update the forward-looking statements in this quarterly report, in other documents, or on the Web site to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

ITEM 4. CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures.

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the 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) as of June 30, 2010. Based on such evaluation, such officers have concluded that, as of June 30, 2010, the Company’s disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company, including its consolidated subsidiaries, required to be included in the Company’s reports filed or submitted under the Exchange Act. The Company’s Chief Executive Officer and Chief Financial Officer also concluded that the controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management including its principal executive and financial officers or persons performing similar functions as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Controls.

There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter ended June 30, 2010, 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

QEP is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on the Company’s financial position, results of operations or cash flows. A liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Disclosures are provided for contingencies reasonably likely to occur which would have a material adverse effect on the Company’s financial position, results of operations or cash flows. Some of the claims involve highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined.

Environmental Claims

In United States of America v. QEP Field Services Co., Civil No. 208CV167, filed on February 29, 2008, in Utah Federal District Court, the U.S. Environmental Protection Agency (EPA) alleges that QEP Field Services violated the federal Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. EPA further alleges that the facilities are located within the original boundaries of the former Uncompahgre Indian Reservation and are therefore within “Indian Country.” EPA asserts primary CAA jurisdiction over “Indian Country” where state CAA programs do not apply. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for QEP Field Services’ facilities render them “major sources” of emissions for criteria and hazardous air pollutants. Categorization of the facilities as “major sources” affects the particular regulatory program applicable to those facilities. EPA claims that QEP Field Services failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations for testing and reporting, among other things. QEP Field Services contends that its facilities have pollution controls installed that reduce their actual air emissions below major source thresholds, rendering them subject to the requirements of different regulatory provisions than those asserted by EPA. QEP Field Services intends to vigorously defend against the EPA’s claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying Utah’s CAA program or EPA’s prior practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all reasonably possible outcomes; however, management believes the Company has accrued a reasonable loss contingency that is an immaterial amount, for the anticipated most likely outcome.

The Ute Indian Tribe has intervened as a co-plaintiff in this CAA enforcement action, but has been constrained by the court’s intervention order to claims based on questions of law and fact common to the government’s CAA claims. The Tribe alleges claims against QEP Field Services based on tort and public nuisance and seeks injunctive relief and monetary damages. QEP Field Services has filed a motion to dismiss the Tribe’s multiple, amended complaints in intervention for lacking commonality with the government’s claims. As a result, the Tribe has threatened to cancel its comprehensive January 2005, Surface Use and Access Concession Agreement (SUA) with QEP and its current and former affiliates and to deny future access to QEP and its current and former affiliates in carrying out development and operations. The parties have tendered cross-claims of breach under the SUA and have triggered an informal resolution process likely leading to arbitration separate from the pending CAA litigation. QEP will vigorously defend its rights under the SUA.

ITEM 6. EXHIBITS.

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


Exhibit No.		Exhibits
12		Ratio of Earnings to Fixed Charges

31.1		Certification signed by C. 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		Certification signed by C. 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.

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)

July 30, 2010		/s/ C. B. Stanley
		C. B. Stanley,
		President and Chief Executive Officer

July 30, 2010		/s/ Richard J. Doleshek
		Richard J. Doleshek,
		Executive Vice President,
		Chief Financial Officer and Treasurer


Exhibit No.		Exhibits
12		Ratio of Earnings to Fixed Charges

31.1		Certification signed by C. 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		Certification signed by C. 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.

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