FORM 10-Q

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: March 31, 2009


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 (Address of principal executive offices)		70508 (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.

Yes þ No o

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).

Yes o No o

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


Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o		Smaller reporting company o

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

Yes o No þ

As of May 1, 2009 there were 50,908,736 shares of the registrant’s common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)


	March 31,			December 31,
	2009			2008
	(Unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	26,484		$	23,964
Revenue receivable		10,777			20,074
Joint interest billing receivable		23,238			24,259
Hedging asset		55,612			40,571
Prepaid drilling costs		7,125			11,523
Drilling pipe inventory		24,520			25,898
Other current assets		3,282			1,530

Total current assets		151,038			147,819

Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method		1,233,703			1,225,304
Unevaluated oil and gas properties		118,730			119,847
Accumulated depreciation, depletion and amortization		(967,410	)		(832,290	)

Oil and gas properties, net		385,023			512,861
Gas gathering assets		4,651			4,644
Accumulated depreciation and amortization of gas gathering assets		(975	)		(900	)

Total property and equipment		388,699			516,605

Other assets, net of accumulated depreciation and amortization of $6,750 and $6,237, respectively		6,426			5,825


Total assets	$	546,163		$	670,249


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	36,136		$	70,643
Advances from co-owners		2,744			5,349
Oil and gas revenue payable		10,665			15,305
Accrued interest and preferred stock dividend		7,202			3,696
Asset retirement obligation		7,651			8,590
Other accrued liabilities		3,584			4,094

Total current liabilities		67,982			107,677

Bank debt		130,000			130,000
10 3/8% Senior Notes		149,062			148,998
Asset retirement obligation		16,117			17,043
Deferred income taxes		—			28,845
Other liabilities		199			199
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 49,411 and 49,319 shares, respectively		49			49
Paid-in capital		218,390			216,253
Accumulated other comprehensive income		35,696			25,560
Accumulated deficit		(71,333	)		(4,376	)

Total stockholders’ equity		182,803			237,487

Total liabilities and stockholders’ equity	$	546,163		$	670,249

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

Consolidated Statements of Operations

(unaudited)
(Amounts in Thousands, Except Per Share Data)


	Three Months Ended
	March 31,
	2009			2008
Revenues:
Oil and gas sales	$	59,234		$	74,819
Gas gathering revenue		215			1,731

		59,449			76,550


Expenses:
Lease operating expenses		11,133			10,197
Production taxes		2,174			2,891
Depreciation, depletion and amortization		31,819			30,098
Ceiling test writedown		103,582			—
Gas gathering costs		79			948
General and administrative		4,825			5,167
Accretion of asset retirement obligation		652			247
Interest expense		3,176			2,499

		157,440			52,047


Gain on sale of assets		485			—
Other income (expense)		(2,970	)		216


Income (loss) from operations		(100,476	)		24,719

Income tax expense (benefit)		(34,799	)		9,275


Net income (loss)		(65,677	)		15,444

Preferred stock dividend		1,280			1,283


Net income (loss) available to common stockholders	$	(66,957	)	$	14,161


Earnings per common share:
Basic
Net income (loss) per share	$	(1.36	)	$	0.29

Diluted
Net income (loss) per share	$	(1.36	)	$	0.28


Weighted average number of common shares:
Basic		49,346			48,479
Diluted		49,346			55,362

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)


	Three Months Ended
	March 31,
	2009			2008
Cash flows from operating activities:
Net income (loss)	$	(65,677	)	$	15,444
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense (benefit)		(34,799	)		9,275
Depreciation, depletion and amortization		31,819			30,098
Ceiling test writedown		103,582			—
Gain on sale of assets		(485	)		—
Accretion of asset retirement obligation		652			247
Amortization of debt issuance costs		307			251
Amortization of bond discount		64			58
Inventory impairment		825			—
Share based compensation expense		2,180			2,332
Payments to settle asset retirement obligations		(46	)		(746	)
Changes in working capital accounts:
Revenue receivable		9,297			(8,517	)
Joint interest billing receivable		1,021			1,487
Accounts payable and accrued liabilities		(28,321	)		(7,720	)
Advances from co-owners		(2,605	)		(341	)
Other		3,168			(5,554	)


Net cash provided by operating activities		20,982			36,314


Cash flows from investing activities:
Investment in oil and gas properties		(17,805	)		(84,290	)
Investment in gas gathering assets		(7	)		(2,349	)
Proceeds from sale of oil and gas properties		711			1,890


Net cash used in investing activities		(17,101	)		(84,749	)


Cash flows from financing activities:
Net proceeds from (payments for) share based compensation		(42	)		208
Deferred financing costs		(35	)		(35	)
Payment of preferred stock dividend		(1,284	)		(1,585	)
Repayment of bank borrowings		—			(5,000	)
Proceeds from bank borrowings		—			50,000


Net cash provided by (used in) financing activities		(1,361	)		43,588


Net increase (decrease) in cash and cash equivalents		2,520			(4,847	)

Cash and cash equivalents, beginning of period		23,964			16,909


Cash and cash equivalents, end of period	$	26,484		$	12,062


Supplemental disclosure of cash flow information:
Cash paid during the period for:

Interest	$	1,324		$	297


Income taxes	$	—		$	—

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 Basis of Presentation

The consolidated financial information for the three-month periods ended March 31, 2009 and 2008, 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 March 31, 2009 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, 2008 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, 2008.

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

During 2007, the Company completed the public offering of 1,495,000 shares of its 6.875% Series B cumulative convertible perpetual preferred stock (the “Series B Preferred Stock”). The net proceeds received from the offering totaled $70.7 million and were primarily used to repay outstanding borrowings under the Company’s credit facility. 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.

Note 3 Earnings Per Share

Basic earnings per common share is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding during the periods presented. Diluted earnings per common share is determined on a weighted average basis using common shares issued and outstanding adjusted for the effect of stock options and restricted stock considered dilutive computed using the treasury stock method.

Diluted earnings per share also considers the effect of the Series B Preferred Stock by applying the “if converted” method. Under this method, the dividends applicable to the Series B Preferred Stock are added to the numerator and the Series B Preferred Stock is assumed to have been converted to common shares in the denominator. In applying the “if converted” method for the Series B Preferred Stock, conversion is not assumed in computing diluted earnings per share if the effect would be anti-dilutive.

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


	Loss			Shares		Per
For the Three Months Ended March 31, 2009	(Numerator)			(Denominator)		Share Amount
BASIC EPS

Net loss available to common stockholders	$	(66,957	)		49,346	$	(1.36	)

Effect of dilutive securities:
Stock options		—			—
Restricted stock		—			—
Series B preferred stock		—			—


DILUTED EPS	$	(66,957	)		49,346	$	(1.36	)


	Income		Shares		Per
For the Three Months Ended March 31, 2008	(Numerator)		(Denominator)		Share Amount
BASIC EPS

Net income available to common stockholders	$	14,161		48,479	$	0.29

Effect of dilutive securities:
Stock options		—		1,033
Restricted stock		—		702
Series B preferred stock		1,283		5,148


DILUTED EPS	$	15,444		55,362	$	0.28

Restricted stock and stock options totaling 501,994 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 three month period ended March 31, 2009 because the inclusion would have been anti-dilutive as a result of the net loss reported for the period. In addition, options to purchase 1,652,232 shares of common stock were outstanding during the three months ended March 31, 2009 that would not have been 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. Options to purchase 401,935 shares of common stock were outstanding during the three-month period ended March 31, 2008, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares.

Note 4 Long-Term Debt

During 2005, the Company and PetroQuest Energy, L.L.C. issued $150 million in principal amount of 10 3/8% Senior Notes due 2012 (the “Notes”). The Notes are guaranteed by the significant subsidiaries of the Company and PetroQuest Energy, L.L.C. The aggregate assets and revenues of subsidiaries not guaranteeing the Notes constitute less than 3% of the Company’s consolidated assets and revenues.

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 March 31, 2009, $5.8 million had been accrued in connection with the May 15, 2009 interest payment and the Company was in compliance with all of the covenants contained in the Notes.

On October 2, 2008, the Company and PetroQuest Energy, L.L.C. (the “Borrower”) entered into the 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 March 31, 2009 the Company had $130 million of 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 as of January 1 and July 1 of each year of the reserves attributable to the Company’s oil and gas properties. The current borrowing base, which was based upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1, 2009, is $130 million. The next borrowing base redetermination is scheduled to occur by September 30, 2009. If the borrowing base is further reduced, the Company would be obligated to repay the amount by which its aggregate credit exposure under the Credit Agreement may exceed the revised borrowing base within forty-five days after the revised borrowing base is determined. 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 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 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 prior year-end commodity prices. Based upon the level of borrowings outstanding at March 31, 2009, the Company is currently not able to incur new indebtedness under the Credit Agreement. While the indenture limits the amount of new indebtedness that may be incurred under the Credit Agreement, it does not restrict the amount of indebtedness that may be outstanding under the Credit Agreement. Therefore, even though the amount of indebtedness under the Credit Agreement at March 31, 2009 exceeds the limit described above, the Company is not required by the indenture to reduce the amount currently outstanding. If the Company reduces the borrowings currently outstanding under the Credit Agreement, the indenture may limit the amounts that could be re-borrowed thereunder, in accordance with the limit described above, even though such re-borrowings would be permitted under the Credit Agreement.

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, a minimum liquidity of $10 million 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 March 31, 2009, the Company was in compliance with all of the covenants contained in the Credit Agreement.

Note 5 Asset Retirement Obligation

In June 2001, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards No. 143 (SFAS 143), “Accounting for Asset Retirement Obligations,” which requires recording the fair value of an asset retirement obligation associated with tangible long-lived assets in the period incurred.

Retirement obligations associated with long-lived assets included within the scope of SFAS 143 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, 2009	$	25,633
Liabilities incurred during 2009		4
Liabilities settled during 2009		(46	)
Accretion expense		652
Revisions in estimated cash flows		(2,475	)


Asset retirement obligation at March 31, 2009		23,768
Less: current portion of asset retirement obligation		(7,651	)

Long-term asset retirement obligation	$	16,117

In general, the costs of oilfield related services and materials have declined since December 31, 2008 as a result of the sharp decline in commodity prices and the corresponding decline in the demand for these services. During the first quarter of 2009, the Company recorded a $2.5 million downward revision to its asset retirement obligation to reflect the estimated decline in abandonment costs since December 31, 2008.

Note 6 Share Based Compensation

The Company accounts for share-based compensation in accordance with SFAS 123 (revised 2004) “Share Based Payment” (“SFAS 123(R)”). 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 March 31, 2009 and 2008 is as follows (in thousands):


	Three Months Ended
	March 31,
	2009		2008
Stock options:
Incentive Stock Options	$	294	$	349
Non-Qualified Stock Options		669		534
Restricted stock		1,217		1,449

Share based compensation	$	2,180	$	2,332

During each of the three-month periods ended March 31, 2009 and 2008, the Company recorded income tax benefits of $0.7 million related to share based compensation expense recognized during those periods. Any excess tax benefits from the vesting of restricted stock and the exercise of stock options will not be recognized in paid-in capital until the Company is in a current tax paying position. Presently, all of the Company’s income taxes are deferred and the Company has substantial net operating losses available to carryover to future periods. Accordingly, no excess tax benefits have been recognized for any periods presented.

Note 7 Ceiling Test

The Company uses the full cost method to account for its oil and natural gas operations. Accordingly, the costs to acquire, explore for and develop oil and natural 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.

The prices of oil and natural gas have declined significantly since June 2008. At March 31, 2009, the prices used in computing the estimated future net cash flows from the Company’s proved reserves, including the effect of hedges in place at March 31, 2009, averaged $3.87 per Mcfe and $52.34 per barrel. As a result of lower prices and their 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 during the three months ended March 31, 2009. The Company’s cash flow hedges in place at March 31, 2009 reduced the ceiling test write-down by approximately $72 million.

Note 8 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 SFAS 133, as amended. When the conditions for hedge accounting specified in SFAS 133 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 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 March 31, 2009, the Company’s outstanding derivative instruments were considered effective cash flow hedges.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $13,978,000 and $174,000 and oil hedges of $2,045,000 and ($816,000) for the three months ended March 31, 2009 and 2008, respectively.

As of March 31, 2009, the Company had entered into the following oil and gas contracts accounted for as cash flow hedges:


	Instrument		Weighted
Production Period	Type	Daily Volumes	Average Price
Natural Gas:
April–June 2009	Swap	20,000 Mmbtu	$	5.62
April-December 2009	Swap	17,500 Mmbtu	$	6.15
July–December 2009	Swap	10,000 Mmbtu	$	5.34
April–December 2009	Costless Collar	30,000 Mmbtu	$	8.75 – 11.38
2010	Costless Collar	10,000 Mmbtu	$	6.00 – 7.15
Crude Oil:
April-December 2009	Costless Collar	400 Bbls	$	100.00 – 168.50

All of the Company’s derivative instruments at March 31, 2009 were designated as hedging instruments under SFAS 133. The following tables reflect the fair value of the Company’s derivative instruments in the consolidated financial statements as of March 31, 2009 (in thousands):

Effect of Derivative Instruments on the Consolidated Balance Sheet

Asset Derivatives

Liability Derivatives

Balance Sheet

Instrument

Location

Fair Value

Location

Fair Value

Commodity Derivatives

Hedging asset

55,612

N/A

—

Other assets

1,048

N/A

56,660

Effect of Derivative Instruments on the Consolidated Statement of Operations

Amount of Gain

Location of

Amount of Gain

Recognized in Other

Gain Reclassified

Reclassified into

Instrument

Comprehensive Income

into Income

Income

Commodity Derivatives

10,136

Oil and gas sales

16,023

Based on estimated future commodity prices as of March 31, 2009, the Company would realize a $35 million gain, net of taxes, as an increase in oil and gas sales during the next 12 months. These gains are expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contracts.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosure about fair value measurements. The Company adopted SFAS No. 157 on January 1, 2008. As defined in SFAS No. 157, 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. SFAS 157 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.

With the adoption of SFAS 157, the Company classified its commodity derivatives based upon the data used to determine fair value. The Company’s derivative instruments at March 31, 2009 were in the form of swaps and 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 March 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

—

56,660

—

Note 9 Other Expense

Other expense during the first quarter of 2009 includes $2.3 million related to payments made in connection with a drilling rig contract. As a result of the significant decline in natural gas prices, the Company elected to idle this drilling rig during the first quarter of 2009. Because there are no corresponding assets to record in connection with the fixed payments required, regardless of actual rig usage, under this contract, the costs are recorded as a component of other expense. This contract expires during July 2009.

Note 10 New Accounting Standards

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations,” and establishes principles and requirements for the recognition and measurement by an acquirer in its financial statements of the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree. The statement also establishes principles and requirements for the recognition and measurement of the goodwill acquired in the business combination or the gain from a bargain purchase and for information disclosed in its financial statements. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures about derivative and hedging activities, and is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company adopted SFAS No. 161 on January 1, 2009 with no impact on its financial position or results of operations.

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, which from the commencement of operations in 1985 through 2002, was 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 accelerated our penetration into longer life basins in Oklahoma, Arkansas and Texas through significantly increased and successful drilling activity and selective acquisitions. Specific asset diversification activities include the 2003 acquisition of proved reserves and acreage in the Southeast Carthage Field in East Texas. In 2004, we entered the Arkoma Basin in Oklahoma by building an acreage position, drilling wells and acquiring proved reserves. During 2005 and 2006, we acquired additional acreage in Oklahoma and Texas, initiated an expanded drilling program in these areas, opened an exploration office in Tulsa, Oklahoma and divested several mature, high-cost Gulf of Mexico fields. During 2007, we acquired a leasehold position in Arkansas and continued to robustly drill in Oklahoma and Texas. During 2008, we significantly increased our acreage position in Oklahoma and increased the pace of drilling operations in our longer life basins as we invested $260.4 million in Oklahoma, Arkansas and Texas.

In response to the impact that the decline in commodity prices has had on our cash flow, the deteriorated condition of the financial markets caused by the global financial crisis and our future expectations for commodity prices, production rates and capital costs, we have shifted our focus during 2009 from increasing production and reserves to building liquidity and strengthening our balance sheet. As a result, our expected 2009 drilling capital expenditures, which include capitalized interest and overhead, are expected to range between $60 million and $90 million, with only approximately $50 million of that amount fully committed to be spent. This budget is significantly reduced as compared to our actual 2008 drilling capital expenditures, including capitalized interest and overhead, of approximately $296 million. As discussed in more detail below, we expect that our production volumes for 2009 will generally approximate those achieved in 2008. While our first quarter 2009 production was a Company quarterly record, as a result of the reduction in capital spending we expect that production volumes for the remainder of 2009 will decline as compared to first quarter volumes.

We plan to fund our drilling capital expenditures with cash flow from operations. 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 2009 capital budget to stay under our projected cash flow from operations, with a goal of building liquidity and strengthening our balance sheet.

Critical Accounting Policies

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.

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.

The prices of oil and natural gas have declined significantly since June 2008. At March 31, 2009, we computed the estimated future net cash flows from our proved oil and gas reserves, discounted at 10%, using average quarter-end prices, including hedges, of $3.87 per Mcfe and $52.34 per barrel. Due to the low market prices at March 31, 2009, our capitalized costs exceeded the full cost ceiling, resulting in a $103.6 million non-cash ceiling test write-down of our oil and gas properties. Our cash flow hedges in place at March 31, 2009 reduced the ceiling test write-down by approximately $72 million.

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 additional 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.

Reserve Estimates

Our estimates of proved oil and gas reserves constitute quantities that we are reasonably certain of recovering in future years from known reservoirs under existing economic and operating conditions. 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.

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 March 31, 2009, 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.

New Accounting Standards

In March 2008, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133” (“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures about derivative and hedging activities, and is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted SFAS No. 161 on January 1, 2009 with no impact to our financial position or results of operations.

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
	March 31,
	2009		2008
Production:
Oil (Bbls)		174,811		193,776
Gas (Mcf)		9,047,214		6,727,828
Total Production (Mcfe)		10,096,080		7,890,484

Sales:
Total oil sales	$	9,279,283	$	18,229,840
Total gas sales		49,954,858		56,589,465

Total oil and gas sales	$	59,234,141	$	74,819,305


Average sales prices:
Oil (per Bbl)	$	53.08	$	94.08
Gas (per Mcf)		5.52		8.41
Per Mcfe		5.87		9.48

The above sales and average sales prices include additions (reductions) related to the settlement of gas hedges of $13,978,000 and $174,000 and the settlement of oil hedges of $2,045,000 and ($816,000) for the three months ended March 31, 2009 and 2008, respectively.

Net income (loss) available to common stockholders totaled ($66,957,000) and $14,161,000 for the quarters ended March 31, 2009 and 2008, respectively. The decrease during the 2009 period was primarily attributable to the following:

Production. Oil production during the first three months of 2009 decreased 10% from 2008 primarily due to normal production declines at our Ship Shoal 72 and Turtle Bayou Fields, which produce approximately half of our total oil production. Partially offsetting these declines was an increase due to the inception of production at our Pelican Point Field in May 2008, which accounted for approximately 12% of our total oil production during the 2009 period.

Gas production during the first quarter of 2009 increased 34% from the comparable period in 2008. The increase in gas production was primarily the result of our drilling success during 2008 in our longer life basins, where the production is primarily natural gas, as well as discoveries at our Pelican Point and Kent Bayou fields in south Louisiana. Overall, production during the first quarter of 2009 was 28% higher than the 2008 period.

We have achieved company records for production in each of the last five years. As a result of low commodity prices, we have reduced our 2009 drilling activities. Even though our 2009 capital expenditures budget will be significantly less than our spending in 2008, we expect that production in 2009 will generally approximate 2008 volumes. However, as a result of the reduction in capital spending, production volumes for the remainder of 2009 are expected to decline from first quarter 2009 volumes.

Prices. Including the effects of our hedges, average oil prices per barrel for the quarter ended March 31, 2009 were $53.08, as compared to $94.08 for the 2008 period. Average gas prices per Mcf for the quarter ended March 31, 2009 were $5.52, as compared to $8.41 for the 2008 period. Stated on an Mcfe basis, unit prices received during the quarter ended March 31, 2009 were 38% lower than the prices received during the comparable 2008 period.

Revenue. Including the effects of hedges, oil and gas sales during the quarter ended March 31, 2009 decreased 21% to $59,234,000, as compared to oil and gas sales of $74,819,000 during the 2008 period. The decrease in sales during the 2009 period was the result of lower commodity prices, offset in part by higher production. We believe that based on current economic conditions, it is possible that commodity prices, particularly prices for natural gas, could decline further during 2009. Further declines in commodity prices would negatively impact our 2009 oil and gas sales.

Expenses. Lease operating expenses for the three month period ended March 31, 2009 increased to $11,133,000 as compared to $10,197,000 during the 2008 period. Per unit operating expenses totaled $1.10 per Mcfe during the three-month period of 2009 as compared to $1.29 per Mcfe during the 2008 period.

The increase in lease operating expenses was primarily due to the inception of operations at several new fields, including Pelican Point, Kent Bayou and Fayetteville in Arkansas. We believe the costs of services and materials in the markets in which we operate will decline during 2009 as the demand for such materials and services weakens as a result of the substantial decline in commodity prices and the overall condition of the oil and gas industry and the global economy. Operating expenses during the first quarter of 2009 were 13% lower than fourth quarter 2008 operating expenses.

Production taxes during the quarter ended March 31, 2009 totaled $2,174,000 as compared to $2,891,000 during the 2008 period. Our production taxes are primarily based on the value of the oil and gas we produce. The decrease in 2009 production taxes is primarily due to the impact of lower commodity prices realized for the production from our Oklahoma, Arkansas and Texas properties. Offsetting this decrease was a 7% increase in the Louisiana gas severance tax rate effective July 1, 2008.

General and administrative expenses during the quarter ended March 31, 2009 decreased 7% to $4,825,000 as compared to expenses of $5,167,000 during the comparable 2008 period. We capitalized $2,032,000 of general and administrative costs during the three-month period ended March 31, 2009 and $2,349,000 during the comparable 2008 period. Overall, we expect that general and administrative costs during 2009 will continue to be less than 2008 amounts.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the quarter ended March 31, 2009 totaled $31,538,000, or $3.12 per Mcfe, as compared to $29,057,000, or $3.68 per Mcfe, during the 2008 period. The decline in our DD&A per Mcfe was the result of the ceiling test write-down of a substantial portion of our proved oil and gas properties during 2008 as a result of lower commodity prices, offset in part by the negative impact of lower commodity prices on our proved reserves at March 31, 2009. Assuming commodity prices remain at current levels, we would expect our DD&A per Mcfe for the remainder of 2009 to decline from first quarter 2009 levels.

The prices of oil and natural gas used in computing our estimated proved reserves at March 31, 2009 had a negative impact on our proved reserves from certain of our longer-life properties and reduced the estimated discounted cash flow from our proved reserves. As a result, we recorded a non-cash ceiling test write-down of our oil and gas properties as of March 31, 2009 totaling $103,582,000. See Note 7, “Ceiling Test” for further discussion of the ceiling test.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $3,176,000 during the quarter ended March 31, 2009 as compared to $2,499,000 during the 2008 period. We capitalized $2,029,000 of interest during the first quarter of 2009 and $2,290,000 during the 2008 period.

Other expense during the first quarter of 2009 includes $2,250,000 related to payments made in connection with a drilling rig contract. As a result of the significant decline in natural gas prices, we elected to idle this drilling rig during the first quarter of 2009. Because there are no corresponding assets to record in connection with the fixed payments required, regardless of actual rig usage, under this contract, the costs are recorded as a component of other expense. This contract expires during July 2009. Assuming natural gas prices remain at or below current levels, we would expect other expense during the second quarter of 2009 to approximate first quarter amounts, as we do not anticipate using this drilling rig based on the current economic environment.

Income tax expense (benefit) during the quarter ended March 31, 2009 totaled ($34,799,000) as compared to $9,275,000 during the 2008 period. The decrease during the 2009 period is the result of the impact of the ceiling test write-down recognized during the first quarter of 2009. 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. However, as a result of the ceiling test write-downs realized during 2008, we have incurred an aggregate loss during the three year period ended December 31, 2008. 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 have established a valuation allowance of $2.5 million at March 31, 2009 for a portion of the deferred tax benefit derived from the net loss incurred during the first quarter of 2009. Accordingly, our effective tax rate for the first quarter of 2009 was lower than the 2008 period.

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 and sales of assets. At March 31, 2009, we had a working capital surplus of $83.1 million compared to a surplus of $40.1 million at December 31, 2008.

The increase in our working capital at March 31, 2009 was primarily attributable to our significantly reduced capital expenditures during the first quarter of 2009. With the reduced level of capital spending, we were able to strengthen our working capital through building our cash balance and using available cash flow to reduce short-term liabilities, primarily our accounts payable to vendors. In addition, our working capital surplus grew during the first quarter of 2009 as a result of the increase in the value of our hedging asset, which is primarily a function of lower estimated future commodity prices.

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. Natural gas and oil prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow and raise additional capital. Our borrowing base 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 natural gas and oil 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 natural gas and oil prices.

Source of Capital: Operations

Net cash flow provided by operating activities decreased from $36,314,000 during the quarter ended March 31, 2008 to $20,982,000 during the 2009 period. The decrease in operating cash flow was primarily attributable to the impact of lower commodity prices on our operations. In addition, during the 2009 period we used a substantial portion of our cash flow to reduce our accounts payable to vendors.

Source of Capital: Debt

During 2005, we issued $150 million in principal amount of 10 3/8% Senior Notes due 2012 (the “Notes”). 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 March 31, 2009, $5.8 million had been accrued in connection with the May 15, 2009 interest payment and we were in compliance with all of the covenants under the Notes.

On October 2, 2008, we entered into the 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 for the use of 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. As of March 31, 2009 we had $130 million of 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 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 properties as of January 1, 2009, is $130 million. The next borrowing base redetermination is scheduled to occur by September 30, 2009. If the borrowing base is further reduced, we would be obligated to repay the amount by which our aggregate credit exposure under the Credit Agreement may exceed the revised borrowing base within forty-five days after the revised borrowing base is determined. We 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 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 prior year-end commodity prices. Based upon the level of borrowings outstanding at March 31, 2009, we are currently not able to incur new indebtedness under the Credit Agreement. While the indenture limits the amount of new indebtedness that may be incurred under the Credit Agreement, it does not restrict the amount of indebtedness that may be outstanding under the Credit Agreement. Therefore, even though the amount of indebtedness under the Credit Agreement at March 31, 2009 exceeds the limit described above, we are not required by the indenture to reduce the amount currently outstanding. If we reduce the borrowings currently outstanding under the Credit Agreement, the indenture may limit the amounts that could be re-borrowed thereunder, in accordance with the limit described above, even though such re-borrowings would be permitted under the Credit Agreement.

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, a minimum liquidity of $10 million 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 March 31, 2009, we were in compliance with all of the covenants contained in the Credit Agreement.

Source of Capital: Issuance of Securities

During April 2009, we filed a universal shelf registration statement to replace our previous registration statement, which was scheduled to expire in April 2009. The replacement registration statement, once declared effective by the SEC, will allow 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: 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. In May 2009, we sold certain of our East Texas oil and gas properties for approximately $4.3 million. During the quarter ended March 31, 2009, we sold a portion of our unevaluated leasehold acreage for $0.7 million. In 2008, we sold the majority of our gas gathering systems located in Oklahoma for $44.4 million. There can be no assurance that we will be able to sell any of our assets in the future.

Use of Capital: Exploration and Development

In response to the decline in commodity prices and the deteriorated condition of the capital markets caused by the global financial crisis, we have reduced our capital expenditure budget for 2009, as compared to 2008. Our 2009 capital budget, which includes capitalized interest and general and administrative costs, is expected to range between $60 million and $90 million, of which approximately $10 million was incurred during the first quarter of 2009. Approximately $50 million of our 2009 budget is committed to be spent. We plan to continue our strategic focus of funding our drilling expenditures with cash flow from operations. 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 2009 capital budget to stay below our projected cash flow from operations, with a goal of building liquidity and strengthening our balance sheet, based upon our expectations of commodity prices, production rates and capital costs.

However, if commodity prices continue to decline or if actual production or costs vary significantly from our expectations, our 2009 exploration and development activities could be reduced further or could require additional financings, which may include sales of equity or debt securities, sales of properties or assets or joint venture arrangements with industry partners. As a result of the current condition of the financial markets, we cannot assure you that such additional financings will be available on acceptable terms, if at all. If we are unable to obtain additional financing, we could be forced to further delay, reduce our participation in or even abandon some of our exploration and development opportunities or be forced to sell some of our assets on an untimely or unfavorable basis.

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 significant price decline since June 2008, the deteriorating 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, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, 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 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.

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: interest rates and commodity prices. 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 2009, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $3.6 million impact on our revenues.

We periodically 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 quarters ended March 31, 2009 and 2008, we received from (paid to) the counterparties to our derivative instruments $16,023,000 and ($642,000), 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 JP Morgan and Calyon, both of which 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 March 31, 2009, we had entered into the following oil and gas contracts accounted for as cash flow hedges:

Instrument

Weighted

Production Period

Type

Daily Volumes

Average Price

Natural Gas:

April–June 2009

Swap

20,000 Mmbtu

5.62

April–December 2009

Swap

17,500 Mmbtu

6.15

July–December 2009

Swap

10,000 Mmbtu

5.34

April–December 2009

Costless Collar

30,000 Mmbtu

8.75 – 11.38

2010

Costless Collar

10,000 Mmbtu

6.00 – 7.15

Crude Oil:

April–December 2009

Costless Collar

400 Bbls

$100.00 – 168.50

At March 31, 2009, we recognized an asset of approximately $56.7 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of March 31, 2009, we would realize a $35 million gain, net of taxes, as an increase to oil and gas sales during the next 12 months. These gains are expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contracts.

Debt outstanding under our bank credit facility is subject to a floating interest rate and represents 47% of our total debt as of March 31, 2009. Based upon an analysis, utilizing the actual interest rate in effect and balances outstanding as of March 31, 2009, and assuming a 10% increase in interest rates and no changes in the amount of debt outstanding, the potential effect on interest expense for the remainder of 2009 is approximately $0.3 million.

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 have declined substantially since June 30, 2008. An extended decline in the prices of oil and natural gas would likely have a material adverse effect on our financial condition.

Our revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties depend to a large degree on prevailing oil and natural gas prices. 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 oil and natural gas have declined substantially since June 30, 2008 and remain 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;

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

	•		political instability in the Middle East and elsewhere;

	•		the price 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 my 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 and results of operations.

The current financial crisis and deteriorating economic conditions may have material adverse impacts on our business and financial condition that we currently cannot predict.

As widely reported, economic conditions in the United States and globally have been deteriorating. Financial markets in the United States, Europe and Asia have been experiencing a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in security prices, severely diminished liquidity and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of various financial institutions and an unprecedented level of intervention from the United States federal government and other governments. Unemployment has risen while business and consumer confidence have declined and there are fears of a prolonged recession. Although we cannot predict the impacts on us of the deteriorating economic conditions, they could materially adversely affect our business and financial condition.

For example:

	•		the demand for oil and natural gas may decline due to the deteriorating economic conditions which could negatively impact the revenues, margins and profitability of our oil and natural gas business;

	•		we may be unable to obtain adequate funding under our bank credit facility due to reductions in our borrowing base as a result of a redetermination due to lower oil and gas prices, limitations imposed by the indenture governing our 10 3/8% Senior Notes due 2012 (the “Notes”) on our ability to incur indebtedness or lending counterparties being unwilling or unable to meet their funding obligations;

	•		the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;

	•		our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration and/or development of our reserves; or

	•		our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.

We have a substantial amount of indebtedness, which may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt.

As of March 31, 2009, the aggregate amount of our outstanding indebtedness, net of available cash on hand, was $252.6 million, which could have important consequences for you, including the following:

	•		it may be more difficult for us to satisfy our obligations with respect to the Notes, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the indenture governing the Notes and the agreements governing such other indebtedness;

	•		the covenants contained in our debt agreements limit our ability to borrow money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations;

	•		we will need to use a substantial portion of our cash flows to pay principal and interest on our debt, approximately $15.6 million per year for interest on the Notes alone, and to pay quarterly dividends, if declared by our Board of Directors, on our Series B Preferred Stock, approximately $5.1 million per year, which will reduce the amount of money we have for operations, capital expenditures, expansion, acquisitions or general corporate or other business activities;

	•		the amount of our interest expense may increase because certain of our borrowings in the future may be at variable rates of interest, which, if interest rates increase, could result in higher interest expense;

	•		we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;

	•		we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially extended or further declines in oil and natural gas prices; and our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

In addition, we may be unable to obtain adequate funding under our bank credit facility because (i) our borrowing base under our current revolving credit facility may decrease as the result of a redetermination, reducing it due to lower oil or natural gas prices, operating difficulties, declines in reserves, lending requirements or regulations, or for any other reason in our lenders’ discretion, (ii) limitations imposed by the indenture governing the Notes on our ability to incur indebtedness or (iii) our lending counterparties may be unwilling or unable to meet their funding obligations. If our revised borrowing base, which is scheduled to be re-determined by September 30, 2009, is less than $130 million, we will be obligated to repay the amount by which our aggregate credit exposure under our bank credit facility may exceed the revised borrowing base within forty-five days after the revised borrowing base is determined.

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 ACNTA (as defined in the indenture). Based upon the level of borrowings outstanding as of March 31, 2009, we are not able to incur new indebtedness under the Credit Agreement. In addition, if we reduce the borrowings currently outstanding under the Credit Agreement, the indenture may limit the amounts that may be re-borrowed thereunder, in connection with the limit described above, even though such re-borrowings would be permitted under the Credit Agreement.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt, including the Notes and meet our other obligations. If we do not have enough money to service our debt, we may be required to refinance all or part of our existing debt, including the Notes, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all.

Lower oil and natural gas prices may cause us to record ceiling test write-downs.

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. As a result of the decline in commodity prices, we recognized $103.6 million and $266.2 million in ceiling test write-downs during the first quarter of 2009 and the year ended December 31, 2008, respectively. We may recognize additional write-downs if commodity prices continue to decline or if we experience substantial downward adjustments to our estimated proved reserves.

Item 6. EXHIBITS

Exhibit 10.1, Amended Executive Employment Agreement dated effective as of December 31, 2008, between Charles T. Goodson and the Company (incorporated herein by reference to Exhibit 10.1 to Current Report on Form 8-K filed January 6, 2009).

Exhibit 10.2, Amended Executive Employment Agreement dated effective as of December 31, 2008, between W. Todd Zehnder and the Company (incorporated herein by reference to Exhibit 10.2 to Current Report on Form 8-K filed January 6, 2009).

Exhibit 10.3, Amended Executive Employment Agreement dated effective as of December 31, 2008, between Arthur M. Mixon, III and the Company (incorporated herein by reference to Exhibit 10.3 to Current Report on Form 8-K filed January 6, 2009).

Exhibit 10.4, Amended Executive Employment Agreement dated effective as of December 31, 2008, between Daniel G. Fournerat and the Company (incorporated herein by reference to Exhibit 10.4 to Current Report on Form 8-K filed January 6, 2009).

Exhibit 10.5, Amended Executive Employment Agreement dated effective as of December 31, 2008, between Stephen H. Green and the Company (incorporated herein by reference to Exhibit 10.5 to Current Report on Form 8-K filed January 6, 2009).

Exhibit 10.6, Form of Amended Termination Agreement between the Company and each of its executive officers, including Charles T. Goodson, W. Todd Zehnder, Arthur M. Mixon, III, Daniel G. Fournerat and Stephen H. Green (incorporated herein by reference to Exhibit 10.6 to Current Report on Form 8-K filed January 6, 2009).

Exhibit 10.7, First Amendment to the PetroQuest Energy, Inc. Annual Cash Bonus Plan (incorporated herein by reference to Exhibit 10.7 to Current Report on Form 8-K filed January 6, 2009).

Exhibit 10.8, Form of Incentive Stock Option Agreement for executive officers (including Charles T. Goodson, W. Todd Zehnder, Arthur M. Mixon, III, Daniel G. Fournerat, Stephen H. Green, Mark K. Stover, Dalton F. Smith III and J. Bond Clement) under the PetroQuest Energy, Inc. 1998 Incentive Plan, as amended and restated effective May 14, 2008 (the “Incentive Plan”) (incorporated herein by reference to Exhibit 10.2 to Annual Report on Form 10-K filed February 27, 2009).

Exhibit 10.9, Form of Nonstatutory Stock Option Agreement under the Incentive Plan (incorporated herein by reference to Exhibit 10.3 to Annual Report on Form 10-K filed February 27, 2009).

Exhibit 10.10, Form of Restricted Stock Agreement for executive officers (including Charles T. Goodson, W. Todd Zehnder, Arthur M. Mixon, III, Daniel G. Fournerat, Stephen H. Green, Mark K. Stover, Dalton F. Smith III and J. Bond Clement) under the Incentive Plan (incorporated herein by reference to Exhibit 10.4 to Annual Report on Form 10-K filed February 27, 2009).

Exhibit 10.11, Amended Executive Employment Agreement dated effective as of December 31, 2008, between Mark K. Stover and the Company (incorporated herein by reference to Exhibit 10.20 to Annual Report on Form 10-K filed February 27, 2009).

Exhibit 10.12, Amended Executive Employment Agreement dated effective as of December 31, 2008, between Dalton F. Smith III and the Company (incorporated herein by reference to Exhibit 10.20 to Annual Report on Form 10-K filed February 27, 2009).

Exhibit 10.13, Amended Executive Employment Agreement dated effective as of December 31, 2008, between J. Bond Clement and the Company (incorporated herein by reference to Exhibit 10.21 to Annual Report on Form 10-K filed February 27, 2009).

Exhibit 10.14, First Amendment to Credit Agreement dated as of March 24, 2009, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Calyon New York Branch, Bank of America, N.A., Wells Fargo Bank, N.A. and Whitney National Bank (incorporated herein by reference to Exhibit 10.1 to Current Report on Form 8-K filed March 24, 2009).


	Page No.
Part I. Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008		1

Consolidated Statements of Operations for the Three Months Ended March 31, 2009 and 2008		2

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2009 and 2008		3

Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2009 and 2008		4

Notes to Consolidated Financial Statements		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		11

Item 3. Quantitative and Qualitative Disclosures About Market Risk		18

Item 4. Controls and Procedures		19

Part II. Other Information

Item 1. Legal Proceedings		20

Item 1A. Risk Factors		20

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		23

Item 3. Defaults upon Senior Securities		23

Item 4. Submission of Matters to a Vote of Security Holders		23

Item 5. Other Information		23

Item 6. Exhibits		24

EX-31.1
EX-31.2
EX-32.1
EX-32.2


					Total Number of
					Shares Purchased		Maximum Number (or
					as Part of		Approximate Dollar
					Publicly		Value) of Shares that May
	Total Number of		Average Price		Announced Plan		be Purchased Under the
	Shares Purchased (1)		Paid Per Share		or Program		Plans or Programs
January 1 – January 31, 2009		—	$	—		—		—
February 1 – February 28, 2009		10,012		3.24		—		—
March 1 – March 31, 2009		12,068		2.28		—		—


	PETROQUEST ENERGY, INC.
Date: May 6, 2009	/s/ W. Todd Zehnder
	W. Todd Zehnder
	Executive Vice President, Chief Financial Officer and Treasurer (Authorized Officer and Principal Financial Officer)

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


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.