Petroquest Energy (PQ) 10-Q 2010 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: June 30, 2010

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: 001-32681

PETROQUEST ENERGY, INC.

(Exact name of registrant as specified in its charter)

DELAWARE	72-1440714
(State of Incorporation)	(I.R.S. Employer Identification No.)
400 E. Kaliste Saloom Rd., Suite 6000
Lafayette, Louisiana	70508
(Address of principal executive offices)	(Zip code)

Registrant’s telephone number, including area code: (337) 232-7028

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.

Yesþ     Noo

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 (§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).

Yeso     Noo

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 definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filero Accelerated filerþ Non-accelerated filero Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yeso     Noþ

As of August 2, 2010, there were 63,196,836 shares of the registrant’s common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.

Table of Contents

	Page No.
Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009		1
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009		2
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009		3
Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2010 and 2009		4
Notes to Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		12
Item 3. Quantitative and Qualitative Disclosures About Market Risk		20
Item 4. Controls and Procedures		21
Part II. Other Information
Item 1. Legal Proceedings		21
Item 1A. Risk Factors		21
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		23
Item 3. Defaults upon Senior Securities		23
Item 4. (Removed and Reserved)		23
Item 5. Other Information		23
Item 6. Exhibits		23
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)

	June 30,			December 31,
	2010			2009
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	57,844		$	20,772
Revenue receivable		13,798			16,457
Joint interest billing receivable		18,902			11,792
Hedging asset		6,482			2,796
Prepaid drilling costs		1,070			2,383
Drilling pipe inventory		16,576			19,297
Other current assets		3,453			1,619
Total current assets		118,125			75,116
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method		1,366,573			1,296,177
Unevaluated oil and gas properties		62,279			108,079
Accumulated depreciation, depletion and amortization		(1,145,600	)		(1,082,381	)
Oil and gas properties, net		283,252			321,875
Gas gathering assets		4,177			4,848
Accumulated depreciation and amortization of gas gathering assets		(1,347	)		(1,198	)
Total property and equipment		286,082			325,525
Long-term receivable		19,029			5,731
Other assets, net of accumulated depreciation and amortization of $9,342 and $8,342, respectively		3,388			4,087
Total assets	$	426,624		$	410,459
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	36,119		$	27,113
Advances from co-owners		3,239			3,662
Oil and gas revenue payable		7,755			7,886
Accrued interest and preferred stock dividend		3,018			3,133
Asset retirement obligation		1,941			4,517
Other accrued liabilities		4,938			4,106
Total current liabilities		57,010			50,417
Bank debt		—			29,000
10 3/8% Senior Notes		149,413			149,267
Asset retirement obligation		16,940			19,399
Other liabilities		364			271
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495 shares		1			1
Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 61,434 and 61,177 shares, respectively		61			61
Paid-in capital		263,505			259,981
Accumulated other comprehensive income		4,071			1,768
Accumulated deficit		(64,741	)		(99,706	)
Total stockholders’ equity		202,897			162,105
Total liabilities and stockholders’ equity	$	426,624		$	410,459

See accompanying Notes to Consolidated Financial Statements.

1

PETROQUEST ENERGY, INC.

Consolidated Statements of Operations

(unaudited)

(Amounts in Thousands, Except Per Share Data)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010		2009			2010			2009
Revenues:
Oil and gas sales	$	41,857	$	55,376		$	89,402		$	114,610
Gas gathering revenue		61		(115	)		130			100
		41,918		55,261			89,532			114,710
Expenses:
Lease operating expenses		9,020		8,373			18,715			19,506
Production taxes		1,599		846			2,947			3,020
Depreciation, depletion and amortization		13,744		18,374			28,728			50,193
Ceiling test writedown		—		—			—			103,582
Gas gathering costs		—		88			11			167
General and administrative		5,816		4,197			10,325			9,022
Accretion of asset retirement obligation		408		472			876			1,124
Interest expense		2,379		3,388			4,189			6,564
		32,966		35,738			65,791			193,178
Gain on legal settlement		—		—			12,400			—
Gain on sale of assets		—		—			—			485
Other income (expense)		94		(2,339	)		11			(5,309	)
Income (loss) from operations		9,046		17,184			36,152			(83,292	)
Income tax expense (benefit)		2,511		8,151			(1,380	)		(26,648	)
Net income (loss)		6,535		9,033			37,532			(56,644	)
Preferred stock dividend		1,287		1,287			2,567			2,567
Net income (loss) available to common stockholders	$	5,248	$	7,746		$	34,965		$	(59,211	)
Earnings per common share:
Basic
Net income (loss) per share	$	0.08	$	0.15		$	0.56		$	(1.20	)
Diluted
Net income (loss) per share	$	0.08	$	0.15		$	0.56		$	(1.20	)
Weighted average number of common shares:
Basic		61,425		49,631			61,335			49,489
Diluted		62,421		50,188			67,356			49,489

See accompanying Notes to Consolidated Financial Statements.

2

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)

	Six Months Ended
	June 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	37,532		$	(56,644	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax benefit		(1,380	)		(26,648	)
Depreciation, depletion and amortization		28,728			50,193
Ceiling test writedown		—			103,582
Non-cash gain on legal settlement		(4,164	)		—
Gain on sale of assets		—			(485	)
Accretion of asset retirement obligation		876			1,124
Inventory impairment		—			861
Share based compensation expense		3,752			3,525
Amortization costs and other		787			748
Payments to settle asset retirement obligations		(5,389	)		(591	)
Changes in working capital accounts:
Revenue receivable		2,659			6,699
Joint interest billing receivable		(7,110	)		12,871
Prepaid drilling and pipe costs		4,034			9,910
Accounts payable and accrued liabilities		8,359			(51,864	)
Advances from co-owners		(423	)		(5,149	)
Other		(1,943	)		(2,638	)
Net cash provided by operating activities		66,318			45,494
Cash flows from (used in) investing activities:
Investment in oil and gas properties		(68,822	)		(30,811	)
Proceeds from sale of unevaluated properties		36,473			—
Proceeds from sale of oil and gas properties		35,000			4,772
Net cash provided by (used in) investing activities		2,651			(26,039	)
Cash flows from (used in) financing activities:
Net payments for share based compensation		(228	)		(234	)
Deferred financing costs		(104	)		(63	)
Net proceeds from common stock offering		—			38,030
Payment of preferred stock dividend		(2,565	)		(2,569	)
Repayment of bank borrowings		(29,000	)		—
Net cash provided by (used in) financing activities		(31,897	)		35,164
Net increase in cash and cash equivalents		37,072			54,619
Cash and cash equivalents, beginning of period		20,772			23,964
Cash and cash equivalents, end of period	$	57,844		$	78,583
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	8,237		$	10,509
Income taxes	$	3		$	—

See accompanying Notes to Consolidated Financial Statements.

3

PETROQUEST ENERGY, INC.

Consolidated Statements of Comprehensive Income

(unaudited)

(Amounts in Thousands)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2010			2009			2010		2009
Net income (loss)	$	6,535		$	9,033		$	37,532	$	(56,644	)
Change in fair value of derivative instruments, accounted for as hedges, net of tax benefit (expense) of $2,508, $8,151, ($1,383) and $2,198, respectively		(4,266	)		(13,846	)		2,303		(3,710	)
Comprehensive income (loss)	$	2,269		$	(4,813	)	$	39,835	$	(60,354	)

See accompanying Notes to Consolidated Financial Statements.

4

PETROQUEST ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 — Basis of Presentation

The consolidated financial information for the three and six month periods ended June 30, 2010 and 2009, respectively, have been prepared by the Company and were not audited by its independent registered public accountants. In the opinion of management, all normal and recurring adjustments have been made to present fairly the financial position, results of operations, and cash flows of the Company at June 30, 2010 and for all reported periods. Results of operations for the interim periods presented are not necessarily indicative of the operating results for the full year or any future periods.

The balance sheet at December 31, 2009 has been derived from the audited financial statements at that date. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted. These consolidated financial statements should be read in conjunction with the audited financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

Unless the context otherwise indicates, any references in this Quarterly Report on Form 10-Q to “PetroQuest” or the “Company” refer to PetroQuest Energy, Inc. (Delaware) and its wholly-owned consolidated subsidiaries, PetroQuest Energy, L.L.C. (a single member Louisiana limited liability company), PetroQuest Oil & Gas, L.L.C. (a single member Louisiana limited liability company), TDC Energy LLC (a single member Louisiana limited liability company) and Pittrans, Inc. (an Oklahoma corporation).

Note 2 — Convertible Preferred Stock

The Company has 1,495,000 shares of 6.875% Series B cumulative convertible perpetual preferred stock (the “Series B Preferred Stock”) outstanding.

The following is a summary of certain terms of the Series B Preferred Stock:

Dividends. The Series B Preferred Stock accumulates dividends at an annual rate of 6.875% for each share of Series B Preferred Stock. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by the Company’s debt agreements, assets are legally available to pay dividends and the Company’s board of directors or an authorized committee of the board declares a dividend payable, the Company pays dividends in cash, every quarter.

Mandatory conversion. On or after October 20, 2010, the Company may, at its option, cause shares of the Series B Preferred Stock to be automatically converted at the applicable conversion rate, but only if the closing sale price of the Company’s common stock for 20 trading days within a period of 30 consecutive trading days ending on the trading day immediately preceding the date the Company gives the conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day.

Conversion rights. Each share of Series B Preferred Stock may be converted at any time, at the option of the holder, into 3.4433 shares of the Company’s common stock (which is based on an initial conversion price of approximately $14.52 per share of common stock, subject to adjustment) plus cash in lieu of fractional shares, subject to the Company’s right to settle all or a portion of any such conversion in cash or shares of the Company’s common stock. If the Company elects to settle all or any portion of its conversion obligation in cash, the conversion value and the number of shares of the Company’s common stock it will deliver upon conversion (if any) will be based upon a 20 trading day averaging period.

Upon any conversion, the holder will not receive any cash payment representing accumulated and unpaid dividends on the Series B Preferred Stock, whether or not in arrears, except in limited circumstances. The conversion rate is equal to $50 divided by the conversion price at the time. The conversion price is subject to adjustment upon the occurrence of certain events. The conversion price on the conversion date and the number of shares of the Company’s common stock, as applicable, to be delivered upon conversion may be adjusted if certain events occur.

5

Note 3 — Earnings Per Share

A reconciliation between basic and diluted earnings (loss) per share computations (in thousands, except per share amounts) is as follows:

	Income			Shares		Per
For the Three Months Ended June 30, 2010	(Numerator)			(Denominator)		Share Amount
Net income available to common stockholders	$	5,248			61,425
Attributable to participating securities		(145	)		—
BASIC EPS	$	5,103			61,425	$	0.08
Effect of dilutive securities:
Stock options		—			381
Restricted stock		145			615
Series B preferred stock		—			—
DILUTED EPS	$	5,248			62,421	$	0.08

	Income			Shares		Per
For the Three Months Ended June 30, 2009	(Numerator)			(Denominator)		Share Amount
Net income available to common stockholders	$	7,746			49,631
Attributable to participating securities		(208	)		—
BASIC EPS	$	7,538			49,631	$	0.15
Effect of dilutive securities:
Stock options		—			202
Restricted stock		208			355
Series B preferred stock		—			—
DILUTED EPS	$	7,746			50,188	$	0.15

	Income			Shares		Per
For the Six Months Ended June 30, 2010	(Numerator)			(Denominator)		Share Amount
Net income available to common stockholders	$	34,965			61,335
Attributable to participating securities		(891	)		—
BASIC EPS	$	34,074			61,335	$	0.56
Effect of dilutive securities:
Stock options		—			375
Restricted stock		891			498
Series B preferred stock		2,567			5,148
DILUTED EPS	$	37,532			67,356	$	0.56

	Loss			Shares		Per
For the Six Months Ended June 30, 2009	(Numerator)			(Denominator)		Share Amount
BASIC EPS
Net loss available to common stockholders	$	(59,211	)		49,489	$	(1.20	)
Effect of dilutive securities:
Stock options		—			—
Restricted stock		—			—
Series B preferred stock		—			—
DILUTED EPS	$	(59,211	)		49,489	$	(1.20	)

6

Common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5,148,000 shares were not included in the computation of diluted earnings per share for the three month periods ended June 30, 2010 and 2009 because the inclusion would have been anti-dilutive. Restricted stock and stock options totaling 514,768 shares and common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5,148,000 shares were not included in the computation of diluted earnings per share for the six-month period ended June 30, 2009 because the inclusion would have been anti-dilutive as a result of the net loss reported for the period.

Options to purchase 2.1 million shares of common stock were outstanding during the three and six month periods ended June 30, 2010 and were not included in the computation of diluted earnings per share because the options’ exercise prices were in excess of the average market price of the common shares. During each of the three and six month periods ended June 30, 2009, options to purchase approximately 1.7 million shares of common stock were outstanding and were not included in the computation of diluted earnings per share because the options’ exercise prices were in excess of the average market price of the common shares.

Note 4 — Common Stock Offering

On June 30, 2009, the Company received approximately $38 million in net proceeds through the public offering of 11.5 million shares of its common stock, which included the issuance of 1.5 million shares pursuant to the underwriters’ over-allotment option.

Note 5 — Long-Term Debt

The Company and PetroQuest Energy, L.L.C. have outstanding $150 million of 10 3/8% Senior Notes that are due in 2012 (the “Notes”). At June 30, 2010, the estimated fair value of the Notes was $151.9 million, based upon a market quote provided by an independent broker. The Notes have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on May 15 and November 15. At June 30, 2010, $1.9 million had been accrued in connection with the November 15, 2010 interest payment and the Company was in compliance with all of the covenants contained in the Notes.

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Calyon New York Branch, Bank of America, N.A., Wells Fargo Bank, N.A., and Whitney National Bank. The Credit Agreement provides the Company with a $300 million revolving credit facility that permits borrowings based on the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows the Company to use up to $25 million of the borrowing base for letters of credit. The Credit Agreement matures on February 10, 2012; provided, however, if on or prior to such date the Company prepays or refinances, subject to certain conditions, the Notes, the maturity date will be extended to October 2, 2013. As of June 30, 2010, the Company had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1 and July 1 of each year. The borrowing base, which was based upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1, 2010, is $100 million effective March 22, 2010. The next borrowing base redetermination is scheduled to occur by September 30, 2010. The Company or the lenders may request two additional borrowing base redeterminations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.

The indenture governing the Notes also limits the Company’s ability to incur indebtedness under the Credit Agreement. Under the indenture, the Company cannot incur additional secured indebtedness under the Credit Agreement if at the time of such incurrence, the total amount of indebtedness under the Credit Agreement is in excess of the greater of (i) $75 million and (ii) 20% of its ACTNA (as defined in the indenture). That calculation is based primarily on the valuation of the Company’s estimated reserves of oil and natural gas using the trailing 12 month average commodity pricing methodology as of the prior year-end. As of June 30, 2010, the indenture limits the Company’s borrowings under the Credit Agreement to $75 million.

7

The Credit Agreement is secured by a first priority lien on substantially all of the assets of the Company and its subsidiaries, including a lien on all equipment and at least 85% of the aggregate total value of the Company’s oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 1.625% to 2.625% depending on borrowing base usage) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 2.5% to 3.5% depending on borrowing base usage). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%. For the purposes of the definition of alternative base rate only, the adjusted LIBO rate is equal to the rate at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office of JPMorgan Chase Bank, N.A. in immediately available funds in the London interbank market. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company pays commitment fees of 0.5%.

The Company and its subsidiaries are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of 3.0 to 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. As of June 30, 2010, the Company was in compliance with all of the covenants contained in the Credit Agreement.

Note 6 — Asset Retirement Obligation

The Company accounts for asset retirement obligations in accordance with ASC Topic 410-20, which requires recording the fair value of an asset retirement obligation associated with tangible long-lived assets in the period incurred. Asset retirement obligations associated with long-lived assets included within the scope of ASC Topic 410-20 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. The Company has legal obligations to plug, abandon and dismantle existing wells and facilities that it has acquired and constructed.

The following table describes all changes to the Company’s asset retirement obligation liability (in thousands):

Asset retirement obligation at January 1, 2010	$	23,916
Liabilities settled		(6,478	)
Accretion expense		876
Revisions in estimated cash flows		567
Asset retirement obligation at June 30, 2010		18,881
Less: current portion of asset retirement obligation		(1,941	)
Long-term asset retirement obligation	$	16,940

Liabilities settled during the six months ended June 30, 2010 included two offshore fields that were completely decommissioned and the liability for an additional offshore platform that was transferred to a third party related to a farmout.

Note 7 — Share Based Compensation

The Company accounts for share-based compensation in accordance with ASC Topic 718. Share-based compensation expense is reflected as a component of the Company’s general and administrative expense. A detail of share-based compensation for the periods ended June 30, 2010 and 2009 is as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Stock options:
Incentive Stock Options	$	197	$	146	$	432	$	440
Non-Qualified Stock Options		502		448		1,074		1,117
Restricted stock		1,071		751		2,246		1,968
Share based compensation	$	1,770	$	1,345	$	3,752	$	3,525

8

Note 8 — Ceiling Test

The Company uses the full cost method to account for its oil and gas properties. Accordingly, the costs to acquire, explore for and develop oil and gas properties are capitalized. Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, including the effects of cash flow hedges in place, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to ceiling test write down of oil and gas properties in the quarter in which the excess occurs.

As a result of lower prices at March 31, 2009, and the associated negative impact on certain of the Company’s proved reserves and estimated future net cash flows, the Company recognized a ceiling test write-down of $103.6 million at March 31, 2009.

Note 9 — Derivative Instruments

The Company seeks to reduce its exposure to commodity price volatility by hedging a portion of its production through commodity derivative instruments. The Company accounts for commodity derivatives in accordance with ASC Topic 815. When the conditions for hedge accounting specified in ASC Topic 815 are met, the Company may designate its commodity derivatives as cash flow hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative would be recorded in the income statement as derivative income or expense. At June 30, 2010, the Company’s outstanding derivative instruments were considered effective cash flow hedges.

Oil and gas sales include additions related to the settlement of gas hedges of $4,756,000 and $22,441,000 and oil hedges of zero and $1,470,000 for the three months ended June 30, 2010 and 2009, respectively. For the six-month periods ended June 30, 2010 and 2009, oil and gas sales include additions related to the settlement of gas hedges of $6,287,000 and $36,419,000 and oil hedges of zero and $3,515,000, respectively.

As of June 30, 2010, the Company had entered into the following gas contracts accounted for as cash flow hedges:

	Instrument		Weighted
Production Period	Type	Daily Volumes	Average Price
Natural Gas:
July-December 2010	Costless Collar	40,000 Mmbtu	$	5.62 – 6.27

At June 30, 2010, the Company recognized a net asset of approximately $6.5 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of June 30, 2010, the Company would realize a $4.1 million gain, net of taxes, as an increase in gas sales during the next 12 months. These gains are expected to be reclassified based on the schedule of gas volumes stipulated in the derivative contracts.

All of the Company’s derivative instruments at June 30, 2010 were designated as hedging instruments under ASC Topic 815. The following tables reflect the fair value of the Company’s derivative instruments in the consolidated financial statements (in thousands):

Effect of Derivative Instruments on the Consolidated Balance Sheet at June 30, 2010:

	Asset Derivatives
	Balance Sheet
Instrument	Location	Fair Value
Commodity Derivatives	Hedging asset	$	6,482

Effect of Derivative Instruments on the Consolidated Balance Sheet at December 31, 2009:

Instrument	Location	Fair Value
Commodity Derivatives	Hedging asset	$	2,796

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Effect of Derivative Instruments on the Consolidated Statement of Operations for the three months ended June 30, 2010 and 2009:

	Amount of Loss			Location of	Amount of Gain
	Recognized in Other			Gain Reclassified	Reclassified into
Instrument	Comprehensive Income			into Income	Income
Commodity Derivatives at June 30, 2010	$	(4,266	)	Oil and gas sales	$	4,756
Commodity Derivatives at June 30, 2009	$	(13,846	)	Oil and gas sales	$	23,911

Effect of Derivative Instruments on the Consolidated Statement of Operations for the six months ended June 30, 2010 and 2009:

	Amount of Income (Loss)			Location of	Amount of Gain
	Recognized in Other			Gain Reclassified	Reclassified into
Instrument	Comprehensive Income			into Income	Income
Commodity Derivatives at June 30, 2010	$	2,303		Oil and gas sales	$	6,287
Commodity Derivatives at June 30, 2009	$	(3,710	)	Oil and gas sales	$	39,934

As defined in ASC Topic 820, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC Topic 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:

• Level 1: valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority;

• Level 2: valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability;

• Level 3: valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority.

The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company’s derivative instruments at June 30, 2010 were in the form of costless collars based on NYMEX pricing. The fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.

The following table summarizes the valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of June 30, 2010 and December 31, 2009 (in thousands):

	Fair Value Measurements Using
	Quoted Prices		Significant Other		Significant
	in Active		Observable		Unobservable
Instrument	Markets (Level 1)		Inputs (Level 2)		Inputs (Level 3)
Commodity Derivatives:
At June 30, 2010	$	—	$	6,482	$	—
At December 31, 2009	$	—	$	2,796	$	—

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Note 10 — Woodford Shale Joint Development Agreement

In May 2010, PetroQuest Energy, L.L.C. entered into a joint development agreement with WSGP Gas Producing LLC (WSGP), a subsidiary of NextEra Energy Resources, LLC, whereby WSGP acquired 50% of the Company’s Woodford proved undeveloped reserves as well as the right to earn 50% of the Company’s undeveloped Woodford acreage position through a two phase drilling program. The Company received $57.4 million in cash at closing, net of $2.6 million in fees incurred in relation to the transaction, and recorded a long-term receivable for an additional $14 million to be received on November 30, 2011. The Company recorded the total consideration of approximately $71 million as an adjustment to capitalized costs with no gain or loss recognized. If certain production performance metrics are achieved, the Company will receive an additional $14 million during the drilling program. Additionally, WSGP will fund a share of the future drilling costs under a drilling program.

Note 11 — Gain on Legal Settlement and Other Expense

In January 2010, the Company recorded a gain relative to a $9 million cash settlement received from a lawsuit that was originally filed by the Company in 2008 relating to disputed interests in certain oil and gas assets purchased in 2007. The gain was reduced by approximately $0.8 million of costs incurred by the Company directly related to the settlement. In addition to the cash proceeds received, the Company was assigned additional working interests in certain producing properties. The Company recorded an additional $4.2 million gain representing the estimated fair market value of those interests on the effective date of the settlement.

Other expense during the three and six month periods ended June 30, 2009 included approximately $2.4 million and $4.6 million, respectively, related to payments made in connection with a drilling rig contract. Because this rig was not utilized, there were no corresponding assets to record in connection with the fixed payments required, regardless of actual rig usage. Therefore, the costs were recorded as a component of other expense. This contract expired during July 2009.

Note 12 — Income Taxes

The Company typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of the ceiling test write-downs recognized during 2008 and 2009, the Company has incurred a cumulative three-year loss. As a result of this cumulative loss and the impact it has on the determination of the recoverability of deferred tax assets through future earnings, the Company established a valuation allowance for a portion of the deferred tax asset. The Company reduced the valuation allowance by $15 million during the first half of 2010, the impact of which is included in the Company’s effective tax rate. The valuation allowance was $9.6 million as of June 30, 2010.

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

Overview

PetroQuest Energy, Inc. is an independent oil and gas company engaged in the exploration, development, acquisition and production of oil and gas reserves in the Arkoma Basin, East Texas, South Louisiana and the shallow waters of the Gulf of Mexico shelf. We seek to grow our production, proved reserves, cash flow and earnings at low finding and development costs through a balanced mix of exploration, development and acquisition activities. From the commencement of our operations in 1985 through 2002, we were focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During 2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower risk onshore properties. As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk profile, we refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift capital to higher probability of success onshore wells and mitigate the risks associated with individual wells by expanding our drilling program across multiple basins.

Utilizing the cash flow generated by our higher margin Gulf Coast Basin assets, we have successfully diversified into onshore, longer life assets, including the Woodford and Fayetteville shales in Oklahoma and Arkansas and the Southeast Carthage field in Texas. Beginning in 2003, with our acquisition of the Southeast Carthage Field, through 2009, we have invested approximately $650 million into growing our longer life assets. During the six year period ended December 31, 2009, we have more than doubled our estimated proved reserves to 179 MMcfe and realized a 97% drilling success rate on 551 gross wells drilled. We have continued to focus our efforts on properties we control. We currently operate approximately 75% of our total estimated proved reserves and manage the drilling and completion activities on an additional 15% of such reserves. We have grown our production to 80.6 MMcfe per day for the quarter ended June 30, 2010. At June 30, 2010, 82% of our estimated proved reserves and 54% of our second quarter 2010 production were derived from our longer life assets.

During late 2008, in response to declining commodity prices and the global financial crisis, we shifted our focus from increasing production and reserves to building liquidity and strengthening our balance sheet. As a result of our significant operational control over our drilling prospects, we were able to reduce our capital expenditures, including capitalized interest and overhead, by 83% from $357.8 million in 2008 to $59.1 million in 2009. In addition, we reduced our lease operating expenses, production taxes and general and administrative costs, by a combined 23% from 2008 to 2009. Finally, in June 2009 we completed a public offering of 11.5 million shares of our common stock, receiving net proceeds of approximately $38 million. As a result of these and other liquidity building efforts, we have repaid $130 million of borrowings outstanding under our bank credit facility since August 2009. As of June 30, 2010, we had no borrowings outstanding under this facility.

Having achieved our 2009 goals of building liquidity and strengthening our balance sheet, in 2010 we have refocused on the key elements of our business strategy with the goal of growing our reserves and production in a fiscally prudent manner. To that end, in May 2010, we entered into a joint development agreement with WSGP Gas Producing LLC (WSGP), a subsidiary of NextEra Energy Resources, LLC, whereby WSGP acquired 50% of our Woodford proved undeveloped reserves as well as the right to earn 50% of our undeveloped Woodford acreage position through a two phase drilling program. We received $57.4 million in cash at closing, net of $2.6 million in transaction fees, and will receive an additional $14 million on November 30, 2011. If certain production performance metrics are achieved, we will receive an additional $14 million during the drilling program. Additionally, WSGP will fund a share of our future drilling costs under a drilling program. The additional capital provided by this agreement will allow us to accelerate the pace of our development of the Woodford Shale and pursue opportunities in other basins.

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Critical Accounting Policies

Reserve Estimates

Our estimates of proved oil and gas reserves constitute those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. At the end of each year, our proved reserves are estimated by independent petroleum engineers in accordance with guidelines established by the SEC. These estimates, however, represent projections based on geologic and engineering data. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quantity and quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves may be later determined to be uneconomic. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such oil and gas properties.

On December 29, 2008, the SEC issued a revision to Staff Accounting Bulletin 113 (“SAB 113”) which established guidelines related to modernizing accounting and disclosure requirements for oil and natural gas companies. The revised disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The revised rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The revised disclosure requirements also require companies to report the independence and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates. A significant change to the rules involves the pricing at which reserves are measured. The revised rules utilize a 12-month average price using beginning of the month pricing during the 12-month period prior to the ending date of the balance sheet to report oil and natural gas reserves rather than period-end prices. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization. The revised rules were effective for reserve estimation at December 31, 2009 with first reporting for calendar year companies in their 2009 annual reports.

Full Cost Method of Accounting

We use the full cost method of accounting for our investments in oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing oil and natural gas are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include the costs of drilling exploratory wells, including those in progress and geological and geophysical service costs in exploration activities. Development costs include the costs of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of proved oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.

The costs associated with unevaluated properties are not initially included in the amortization base and primarily relate to ongoing exploration activities, unevaluated leasehold acreage and delay rentals, seismic data and capitalized interest. These costs are either transferred to the amortization base with the costs of drilling the related well or are assessed quarterly for possible impairment or reduction in value.

We compute the provision for depletion of oil and gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. In addition to costs associated with evaluated properties, the amortization base includes estimated future development costs related to non-producing reserves. Our depletion expense is affected by the estimates of future development costs, unevaluated costs and proved reserves, and changes in these estimates could have an impact on our future earnings.

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We capitalize certain internal costs that are directly identified with acquisition, exploration and development activities. The capitalized internal costs include salaries, employee benefits, costs of consulting services and other related expenses and do not include costs related to production, general corporate overhead or similar activities. We also capitalize a portion of the interest costs incurred on our debt. Capitalized interest is calculated using the amount of our unevaluated property and our effective borrowing rate.

Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to write-down of oil and gas properties in the quarter in which the excess occurs.

Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If oil or gas prices decline, even for only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of oil and gas properties could occur in the future.

Future Abandonment Costs

Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the timing of estimated costs, the impact of future inflation on current cost estimates and the political and regulatory environment.

Derivative Instruments

The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. At inception, all of our commodity derivative instruments represent hedges of the price of future oil and gas production. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income or expense.

Our hedges are specifically referenced to NYMEX prices. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX prices at which the hedges will be settled. At June 30, 2010, our derivative instruments were considered effective cash flow hedges.

Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX prices, discount rates and price movements. As a result, we obtain the fair value of our commodity derivatives using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. Our fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of our default risk for derivative liabilities.

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Results of Operations

The following table sets forth certain information with respect to our oil and gas operations for the periods noted. These historical results are not necessarily indicative of results to be expected in future periods.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Production:
Oil (Bbls)		154,285		138,788		298,926		313,599
Gas (Mcf)		6,406,710		7,728,284		13,266,573		16,775,499
Total Production (Mcfe)		7,332,420		8,561,012		15,060,129		18,657,093
Sales:
Total oil sales	$	11,910,281	$	9,424,297	$	23,287,394	$	18,703,580
Total gas sales		29,946,896		45,951,367		66,114,527		95,906,225
Total oil and gas sales	$	41,857,177	$	55,375,664	$	89,401,921	$	114,609,805
Average sales prices:
Oil (per Bbl)	$	77.20	$	67.90	$	77.90	$	59.64
Gas (per Mcf)		4.67		5.95		4.98		5.72
Per Mcfe		5.71		6.47		5.94		6.14

The above sales and average sales prices include additions related to the settlement of gas hedges of $4,756,000 and $22,441,000 and the settlement of oil hedges of zero and $1,470,000 for the three months ended June 30, 2010 and 2009, respectively. The above sales and average sales prices include additions related to the settlement of gas hedges of $6,287,000 and $36,419,000 and the settlement of oil hedges of zero and $3,515,000 for the six months ended June 30, 2010 and 2009, respectively.

Net income available to common stockholders totaled $5,248,000 and $7,746,000 for the quarters ended June 30, 2010 and 2009, respectively, while net income (loss) available to common stockholders for the six-month periods ended June 30, 2010 and 2009 totaled $34,965,000 and ($59,211,000), respectively. The primary fluctuations were as follows:

Production Production decreased 19% in the first half of 2010, as compared to the 2009 period, as a result of reduced capital spending during 2009. In addition, during the second quarter of 2010, we experienced unanticipated shut-ins at our Ship Shoal 72 and Main Pass 74 fields due to facility maintenance and third party pipeline repairs. Production at Ship Shoal 72 has been fully restored while production at Main Pass 74 is currently partially restored but is anticipated to be fully restored during August 2010. Because our capital expenditure budget for 2010 is significantly increased as compared to our budget for 2009, we expect quarterly production growth during the remainder of 2010. However, we expect total 2010 production to be slightly lower than volumes produced during 2009.

Gas production during the three and six month periods ended June 30, 2010 decreased 17% and 21%, respectively, from the comparable periods in 2009. The decrease in gas production was primarily the result of reduced capital spending during 2009 and normal production declines in Oklahoma, where initial production rates are higher than the sustained rates over the life of the wells, combined with the unanticipated shut-ins at Ship Shoal Block 72 and Main Pass Block 74.

Oil production during the three month period ended June 30, 2010 increased 11% from the 2009 period due to the restoration of production at our Ship Shoal 225 field after repairs and a recompletion following Hurricanes Katrina and Rita. Oil production decreased 5% during the six month period ended June 30, 2010 from the comparable 2009 period, primarily due to reduced capital spending during 2009 and normal production declines.

Prices Including the effects of our hedges, average gas prices per Mcf for the three and six month periods ended June 30, 2010 were $4.67 and $4.98, respectively, as compared to $5.95 and $5.72 for the respective 2009 periods. Average oil prices per Bbl for the three and six months ended June 30, 2010 were $77.20 and $77.90, respectively, as compared to $67.90 and $59.64, respectively, for the 2009 periods. Stated on an Mcfe basis, unit prices received during the quarter and six months ended June 30, 2010 were 12% and 3% lower than the prices received during the comparable 2009 periods.

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Revenue Including the effects of hedges, oil and gas sales during the quarter and six months ended June 30, 2010 decreased 24% and 22% to $41,857,000 and $89,402,000, respectively, as compared to oil and gas sales of $55,376,000 and $114,610,000 during the 2009 periods. The decreased revenue during 2010 was primarily the result of lower production and a decrease in hedge settlements realized during the first half of 2010 as compared to 2009. As a result of the impact of the settlements of our higher valued 2009 hedge positions on 2009 oil and gas sales as compared to the expected impact of our 2010 hedge positions, we expect oil and gas revenue to decline during 2010 as compared to 2009.

Expenses Lease operating expenses for the three month period ended June 30, 2010 increased to $9,020,000 as compared to $8,373,000 during the 2009 period primarily as a result of unanticipated maintenance costs. Per unit lease operating expenses totaled $1.23 per Mcfe during the three month period ended June 30, 2010 as compared to $0.98 per Mcfe during the 2009 period. Lease operating expenses for the six month period ended June 30, 2010 decreased to $18,715,000 as compared to $19,506,000 during the 2009 period. Per unit lease operating expenses totaled $1.24 per Mcfe during the six month period ended June 30, 2010 as compared to $1.05 per Mcfe during the 2009 period. Although per unit lease operating expenses increased, absolute lease operating expenses during the first six months of 2010 decreased as compared to the 2009 period primarily due to the overall reduction in produced volumes, as well as lower insurance costs. We expect that lease operating expenses during 2010 will generally approximate lease operating expenses during 2009.

Production taxes during the quarter and six months ended June 30, 2010 totaled $1,599,000 and $2,947,000, respectively, as compared to $846,000 and $3,020,000 during the 2009 periods. Production taxes during the second quarter of 2009 included approximately $570,000 of production tax refunds for several Oklahoma horizontal wells.

General and administrative expenses during the quarter and six months ended June 30, 2010 totaled $5,816,000 and $10,325,000, respectively, as compared to expenses of $4,197,000 and $9,022,000 during the 2009 periods. Included in general and administrative expenses was share-based compensation expense related to ASC Topic 718, as follows (in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2010		2009		2010		2009
Stock options:
Incentive Stock Options	$	197	$	146	$	432	$	440
Non-Qualified Stock Options		502		448		1,074		1,117
Restricted stock		1,071		751		2,246		1,968
Share based compensation	$	1,770	$	1,345	$	3,752	$	3,525

We capitalized $3,802,000 and $6,526,000 of general and administrative costs during the three and six month periods ended June 30, 2010 and $2,195,000 and $4,227,000 of such costs during the comparable 2009 periods. We expect that 2010 general and administrative expenses will be higher than 2009 expenses due to increased employee related costs including increased staffing necessary to accelerate our Woodford Shale development pursuant to the Woodford Shale joint development agreement.

The price of natural gas used in computing our estimated proved reserves at March 31, 2009 had a negative impact on our estimated proved reserves from certain of our longer-life properties and reduced the estimated future net cash flows from our estimated proved reserves. As a result, we recorded a non-cash ceiling test write-down of our oil and gas properties during the first quarter of 2009 totaling $103,582,000. No such write-down was recorded during the first half of 2010.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three and six months ended June 30, 2010 totaled $13,483,000, or $1.84 per Mcfe, and $28,219,000, or $1.87 per Mcfe, respectively, as compared to $18,087,000, or $2.11 per Mcfe, and $49,625,000, or $2.66 per Mcfe, during the comparable 2009 periods. The decline in our DD&A per Mcfe was primarily the result of the ceiling test write-downs of a substantial portion of our proved oil and gas properties during 2009 as a result of lower commodity prices, the impact of the joint development agreement, as well as reserve additions during 2010 from our Woodford operations. We expect DD&A per Mcfe for the remainder of 2010 to generally approximate the second quarter of 2010 rate.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $2,379,000 and $4,189,000 during the quarter and six months ended June 30, 2010 as compared to $3,388,000 and $6,564,000 during the 2009 periods. We capitalized $2,083,000 and $4,723,000 of interest during three and six month periods of 2010 and $2,208,000 and $4,237,000 during the 2009 periods. We have reduced the outstanding borrowings under our bank credit facility from $130 million at June 30, 2009 to zero at June 30, 2010. As a result, we anticipate interest expense to be lower in 2010.

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In January 2010, we recorded a gain relative to a $9,000,000 cash settlement received from a lawsuit filed by us in 2008 relating to disputed interests in certain oil and gas assets purchased in 2007. The gain was reduced by $775,000 of costs incurred by us directly related to the settlement. In addition to the cash proceeds received, we were assigned additional working interests in certain producing properties. We recorded an additional $4,164,000 gain representing the estimated fair market value of those interests on the effective date of the settlement.

Other expense during the second quarter and six months of 2009 included $2,396,000 and $4,646,000, respectively, related to payments made in connection with a drilling rig contract. Because we elected to idle this drilling rig, there were no corresponding assets to record in connection with the fixed payments required under this contract, regardless of actual rig usage. As a result, the costs were recorded as a component of other expense. This contract expired during July 2009.

Income tax expense (benefit) during the quarter and six months ended June 30, 2010 totaled $2,511,000 and ($1,380,000), respectively, as compared to $8,151,000 and ($26,648,000) during the comparable 2009 periods. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.

As a result of the ceiling test write-downs recognized during 2008 and 2009, we have incurred a cumulative three-year loss. As a result of this cumulative loss and the impact it has on the determination of the recoverability of deferred tax assets through future earnings, we established a valuation allowance for a portion of the deferred tax asset. We reduced the valuation allowance by $14,989,000 during the first half of 2010, the impact of which is included in our effective tax rate. The valuation allowance was $9,624,000 as of June 30, 2010. Our effective tax rate in future periods will be impacted by future adjustments to the valuation allowance.

Liquidity and Capital Resources

We have financed our acquisition, exploration and development activities to date principally through cash flow from operations, bank borrowings, private and public offerings of equity and debt securities, joint development agreements and sales of assets. At June 30, 2010, we had a working capital surplus of $61.1 million compared to a surplus of $24.7 million at December 31, 2009. The increase was primarily due to the cash received from the Woodford Shale joint development agreement.

Prices for oil and natural gas are subject to many factors beyond our control such as weather, the overall condition of the global financial markets and economies, relatively minor changes in the outlook of supply and demand, and the actions of OPEC. Oil and natural gas prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. Lower prices and/or lower production may decrease revenues, cash flows and the borrowing base under the bank credit facility, thus reducing the amount of financial resources available to meet our capital requirements. Lower prices and reduced cash flow may also make it difficult to incur debt, including under our bank credit facility, because of the restrictive covenants in the indenture governing the Notes. See “Source of Capital: Debt” below. Our ability to comply with the covenants in our debt agreements is dependent upon the success of our exploration and development program and upon factors beyond our control, such as oil and natural gas prices.

Source of Capital: Operations

Net cash flow from operations increased from $45,494,000 during the six months ended June 30, 2009 to $66,318,000 during the 2010 period. The increase in operating cash flow during 2010 was primarily attributable to the timing of payments made in 2009 to reduce our accounts payable to vendors and the cash received during the first quarter of 2010 in connection with a legal settlement. Partially offsetting these increases was an increase to our joint interest billing receivables, which is a result of the increase in drilling activity.

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Source of Capital: Debt

We have outstanding $150 million of our 10 3/8% Senior Notes that are due in 2012 (the “Notes”), which have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on May 15 and November 15. At June 30, 2010, $1.9 million had been accrued in connection with the November 15, 2010 interest payment and we were in compliance with all of the covenants under the Notes.

We have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Calyon New York Branch, Bank of America, N.A., Wells Fargo Bank, N.A., and Whitney National Bank. The Credit Agreement provides for a $300 million revolving credit facility that permits borrowings based on the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows us to use up to $25 million of the borrowing base for letters of credit. The Credit Agreement matures on February 10, 2012; provided, however, if on or prior to such date we prepay or refinance, subject to certain conditions, the Notes, the maturity date will be extended to October 2, 2013. We had no borrowings outstanding as of June 30, 2010 under (and no letters of credit issued pursuant to) the Credit Agreement.

The borrowing base under the Credit Agreement is based upon the valuation as of January 1 and July 1 of each year of the reserves attributable to our oil and gas properties. The current borrowing base, which was based upon the valuation of the reserves attributable to our oil and gas property as of January 1, 2010, is $100 million effective March 22, 2010. The next borrowing base redetermination is scheduled to occur by September 30, 2010. We or the lenders may request two additional borrowing base redeterminations each year. Each time the borrowing base is to be redetermined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.

The indenture governing the Notes also limits our ability to incur indebtedness under the Credit Agreement. Under the indenture, we will not be able to incur additional secured indebtedness under the Credit Agreement if at the time of such incurrence, the total amount of indebtedness under the Credit Agreement is in excess of the greater of (i) $75 million and (ii) 20% of our ACTNA (as defined in the indenture). That calculation is based primarily on the valuation of our estimated reserves of oil and natural gas using the trailing 12 month average commodity pricing methodology as of the prior year-end. As of June 30, 2010, the indenture limits our borrowings under the Credit Agreement to $75 million.

The Credit Agreement is secured by a first priority lien on substantially all of our assets, including a lien on all equipment and at least 85% of the aggregate total value of our oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 1.625% to 2.625% depending on borrowing base usage) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 2.5% to 3.5% depending on borrowing base usage). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%. For the purposes of the definition of alternative base rate only, the adjusted LIBO rate is equal to the rate at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office of JPMorgan Chase Bank, N.A. in immediately available funds in the London interbank market. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by us) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, we pay commitment fees of 0.5%.

We are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of 3.0 to 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. As of June 30, 2010, we were in compliance with all of the covenants contained in the Credit Agreement.

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Source of Capital: Issuance of Securities

On June 30, 2009, we received net proceeds of approximately $38 million through the public offering of 11.5 million shares of our common stock, which included the issuance of 1.5 million shares pursuant to the underwriters’ over-allotment option.

During July 2009, a new shelf registration statement was declared effective and allows us to publicly offer and sell up to $200 million of any combination of debt securities, shares of common and preferred stock, depositary shares and warrants. The registration statement does not provide any assurance that we will or could sell any such securities.

Source of Capital: Joint Ventures

In May 2010, we entered into a joint development agreement with WSGP, a subsidiary of NextEra Energy Resources, LLC, whereby WSGP acquired 50% of our Woodford proved undeveloped reserves as well as the right to earn 50% of our undeveloped Woodford acreage position through a two phase drilling program. We received $57.4 million in cash at closing, net of $2.6 million in transaction fees, and will receive an additional $14 million on November 30, 2011. If certain production performance metrics are achieved, we will receive an additional $14 million during the drilling program. Additionally, WSGP will fund a share of our future drilling costs under a drilling program. The additional capital provided by this agreement will allow us to accelerate the pace of our development of the Woodford Shale and pursue opportunities in other basins.

Source of Capital: Divestitures

We do not budget property divestitures; however, we are continually evaluating our property base to determine if there are assets in our portfolio that no longer meet our strategic objectives. From time to time we may divest certain non-strategic assets in order to provide liquidity to strengthen our balance sheet or capital to be reinvested in higher rate of return projects. We cannot assure you that we will be able to sell any of our assets in the future.

Use of Capital: Exploration and Development

Our 2010 capital budget, which includes capitalized interest and general and administrative costs, is expected to range between $100 million and $110 million, of which approximately $69 million was spent to develop oil and gas properties during the first half of 2010. This represents a significant increase from the capital spending in 2009. Because we operate the majority of our proved reserves, we expect to be able to control the timing of a substantial portion of our capital investments. As a result of this flexibility, we plan to actively manage our 2010 capital budget to stay within our projected cash flow from operations, based upon our expectations of commodity prices, production rates and capital costs.

However, if commodity prices decline or if actual production or costs vary significantly from our expectations, our 2010 exploration and development activities could be reduced or could be financed through a combination of cash on hand or borrowings under the credit facility.

Disclosure Regarding Forward Looking Statements

This Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices and the significantly depressed natural gas prices since the middle of June 2008, the uncertain economic conditions in the United States and globally, declines in the values of our properties that have resulted and may in the future result in additional ceiling test write-downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters, including the impact of the oil spill in the Gulf of Mexico on our present and future operations, and the operating hazards attendant to the oil and gas business. In particular, careful consideration should be given to cautionary statements made in the various reports the Company has filed with the Securities and Exchange Commission. The Company undertakes no duty to update or revise these forward-looking statements.

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When used in this Form 10-Q, the words, “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Form 10-Q.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We experience market risks primarily in two areas: commodity prices and interest rates. Because our properties are located within the United States, we do not believe that our business operations are exposed to significant foreign currency exchange risks.

Our revenues are derived from the sale of our crude oil and natural gas production. Based on projected sales volumes for the remainder of 2010, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $6.5 million impact on our revenues.

We seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparties to the hedge, the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this difference multiplied by the quantity hedged. During the quarter and six month periods ended June 30, 2010 we received from the counterparties to our derivative instruments $4,756,000 and $6,287,000, respectively, in connection with net hedge settlements.

We are required to pay the difference between the floating price and the fixed price (when the floating price exceeds the fixed price) regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge.

Our Credit Agreement requires that the counterparties to our hedge contracts be lenders under the Credit Agreement or, if not a lender under the Credit Agreement, rated A/A2 or higher by S&P or Moody’s. Currently, the counterparties to our existing hedge contracts are lenders under the Credit Agreement. To the extent we enter into additional hedge contracts, we would expect that certain of the lenders under the Credit Agreement would serve as counterparties.

As of June 30, 2010, we had entered into the following gas contracts accounted for as cash flow hedges:

	Instrument		Weighted
Production Period	Type	Daily Volumes	Average Price
Natural Gas:
July-December 2010	Costless Collar	40,000 Mmbtu	$	5.62 – 6.27

At June 30, 2010, we recognized a net asset of approximately $6.5 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of June 30, 2010, we would realize a $4.1 million gain, net of taxes, as an increase to gas sales during the next 12 months. These gains are expected to be reclassified based on the schedule of gas volumes stipulated in the derivative contracts.

Although we presently have no borrowings outstanding under our bank credit facility, future borrowings under such facility would be subject to a floating interest rate. An increase in interest rates could impact our interest expense to the extent of any future borrowings under our bank credit facility.

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Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, completed an evaluation of the effectiveness of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded:

i. that the Company’s disclosure controls and procedures are designed to ensure (a) that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (b) that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure; and

ii. that the Company’s disclosure controls and procedures are effective.

Notwithstanding the foregoing, there can be no assurance that the Company’s disclosure controls and procedures will detect or uncover all failures of persons within the Company and its consolidated subsidiaries to disclose material information otherwise required to be set forth in the Company’s periodic reports. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.

Changes in Internal Controls

There have been no changes in the Company’s internal controls over financial reporting during the period covered by this report that have materially affected, or that are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II

Item 1. LEGAL PROCEEDINGS

NONE.

Item 1A. RISK FACTORS

Oil and natural gas prices are volatile, and natural gas prices have been significantly depressed since the middle of 2008. An extended decline in the prices of oil and natural gas would likely have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.

Our future financial condition, revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties depend primarily on the prices we receive for our oil and natural gas production. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon oil and natural gas prices. Prices for natural gas have been significantly depressed since the middle of 2008 and future oil and natural gas prices are subject to large fluctuations in response to a variety of factors beyond our control.

These factors include:

• relatively minor changes in the supply of or the demand for oil and natural gas;

• the condition of the United States and worldwide economies;

• market uncertainty;

• the level of consumer product demand;

• weather conditions in the United States, such as hurricanes;

• the actions of the Organization of Petroleum Exporting Countries;

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• domestic and foreign governmental regulation and taxes, including price controls adopted by the Federal Energy Regulatory Commission;

• political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America;

• the price and level of foreign imports of oil and natural gas; and

• the price and availability of alternate fuel sources.

We cannot predict future oil and natural gas prices and such prices may decline further. An extended decline in oil and natural gas prices may adversely affect our financial condition, liquidity, ability to meet our financial obligations and results of operations. Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and has required and may require us to record additional ceiling test write-downs. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices. Our sales are not made pursuant to long-term fixed price contracts.

To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.

Lower oil and natural gas prices may cause us to record ceiling test write-downs, which could negatively impact our results of operations.

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date. During 2009, we recognized $156.1 million in ceiling test write-downs as a result of the decline in commodity prices.

We review the net capitalized costs of our properties quarterly, using, effective for fiscal periods ending on or after December 31, 2009, a single price based on the beginning of the month average of oil and natural gas prices for the prior 12 months. We also assess investments in unproved properties periodically to determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. We may experience further ceiling test write-downs or other impairments in the future. In addition, any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.

A drilling moratorium in the U.S. Gulf of Mexico, or other regulatory initiatives in response to the current oil spill in the Gulf of Mexico, could adversely affect our business.

As has been widely reported, on April 20, 2010, a fire and explosion occurred onboard the semisubmersible drilling rig Deepwater Horizon, leading to the oil spill currently affecting the Gulf of Mexico. In response to this incident, the Minerals Management Service (now known as the Bureau of Ocean Energy Management, Regulation and Enforcement, or the BOE) of the U.S. Department of the Interior issued a notice on May 30, 2010 implementing a six-month moratorium on certain drilling activities in the U.S. Gulf of Mexico. Implementation of the moratorium was blocked by a U.S. district court, which was subsequently affirmed on appeal, but on July 12, 2010, the BOE issued a new moratorium that applies to deep-water drilling operations that use subsea blowout preventers or surface blowout preventers on floating facilities. The new moratorium will last until November 30, 2010, or until such earlier time that the BOE determines that deep-water drilling operations can proceed safely. The BOE is also expected to issue new safety and environmental guidelines or regulations for drilling in the U.S. Gulf of Mexico, and potentially in other geographic regions, and may take other steps, affecting both onshore and offshore operations, that could increase the costs of exploration and production, reduce the area of operations and result in permitting delays. This incident could also result in drilling suspensions or other regulatory initiatives in other areas of the U.S. and/or at a state level. In addition, bills have been, and may continue to be, introduced in Congress to increase or eliminate certain liability limitations for oil spills under federal law (such as H.R. 3534 which was passed by the House of Representatives on July 30, 2010 and eliminates the cap on damage from spills at offshore facilities that are recoverable under the Oil Pollution Act of 1990). Although it is difficult to predict the ultimate impact of the moratorium or any new guidelines, regulations or legislation, a prolonged suspension of drilling activity in the U.S. Gulf of Mexico and other areas, new regulations, increased insurance costs or decreased insurance availability, and increased liability for companies operating in this sector could adversely affect our operations in the U.S. Gulf of Mexico and elsewhere.

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

The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended June 30, 2010.

					Total Number of
					Shares		Maximum Number (or
					Purchased as		Approximate Dollar
					Part of Publicly		Value) of Shares that
	Total Number of		Average Price		Announced		May be Purchased Under
	Shares Purchased (1)		Paid Per Share		Plan or Program		the Plans or Programs
April 1 - April 30, 2010		—	$	—		—		—
May 1 - May 31, 2010		2,315		6.28		—		—
June 1 - June 30, 2010		391		6.46		—		—

(1) All shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards.

Item 3. DEFAULTS UPON SENIOR SECURITIES

NONE.

Item 4. (REMOVED AND RESERVED)

Item 5. OTHER INFORMATION

NONE.

Item 6. EXHIBITS

Exhibit 10.1, PetroQuest Energy, Inc. Annual Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 13, 2010).

Exhibit 10.2, Joint Development Agreement dated May 17, 2010, among PetroQuest Energy, L.L.C., a Louisiana limited liability company, WSGP Gas Producing, LLC, a Delaware limited liability company, and NextEra Energy Gas Producing, LLC, a Delaware limited liability company.

Exhibit 10.3, PetroQuest Energy, Inc. Annual Incentive Plan, as amended and restated (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 8, 2010).

Exhibit 31.1, Certification of Chief Executive Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.

Exhibit 31.2, Certification of Chief Financial Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.

Exhibit 32.1, Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2, Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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SIGNATURE

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.

	PETROQUEST ENERGY, INC.
Date: August 5, 2010	/s/ J. Bond Clement
	J. Bond Clement
	Executive Vice President, Chief Financial Officer and Treasurer (Authorized Officer and Principal Financial Officer)

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