e10vq

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: September 30, 2008


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		70508
Lafayette, Louisiana		(Zip code)
(Address of principal executive offices)

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 is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


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

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 November 3, 2008 there were 50,428,695 shares of the registrant’s common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)


	September 30,			December 31,
	2008			2007
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	6,513		$	16,909
Revenue receivable		18,613			22,820
Joint interest billing receivable		24,470			22,936
Prepaid drilling costs		13,551			1,448
Drilling pipe inventory		21,603			—
Hedge asset		13,758			—
Other current assets		3,432			3,984


Total current assets		101,940			68,097

Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method		1,140,595			907,083
Unevaluated oil and gas properties		146,449			80,297
Accumulated depreciation, depletion and amortization		(547,293	)		(432,530	)

Oil and gas properties, net		739,751			554,850
Gas gathering assets		6,967			22,040
Accumulated depreciation and amortization of gas gathering assets		(842	)		(6,640	)


Total property and equipment		745,876			570,250

Other assets, net of accumulated depreciation and amortization of $12,555 and $11,238, respectively		8,248			6,000


Total assets	$	856,064		$	644,347


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	91,558		$	78,273
Advances from co-owners		22,604			12,870
Oil and gas revenue payable		18,215			5,771
Asset retirement obligation		11,407			5,280
Other accrued liabilities		12,944			9,646

Total current liabilities		156,728			111,840

Bank debt		50,000			—
10 3/8% Senior Notes		148,935			148,755
Asset retirement obligation		15,761			12,171
Deferred income taxes		109,460			69,160
Other liabilities		199			104
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 49,284 and 48,414 shares, respectively		49			48
Paid-in capital		213,898			204,979
Accumulated other comprehensive income (loss)		10,615			(435	)
Retained earnings		150,418			97,724

Total stockholders’ equity		374,981			302,317

Total liabilities and stockholders’ equity	$	856,064		$	644,347

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

Consolidated Statements of Income

(unaudited)

(Amounts in Thousands, Except Per Share Data)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Revenues:
Oil and gas sales	$	76,987	$	63,988	$	242,420	$	190,702
Gas gathering revenue and other income		1,442		1,512		5,701		5,566

		78,429		65,500		248,121		196,268


Expenses:
Lease operating expenses		11,721		8,929		31,818		24,185
Production taxes		3,060		1,593		9,489		5,777
Depreciation, depletion and amortization		33,982		31,846		96,109		89,510
Ceiling test writedown		19,380		—		19,380		—
Gas gathering costs		441		894		2,215		3,188
General and administrative		5,720		5,550		18,036		16,054
Accretion of asset retirement obligation		346		238		894		679
Interest expense		1,609		3,542		6,498		11,112

		76,259		52,592		184,439		150,505


Gain on sale of gas gathering assets		26,677		—		26,677		—


Income from operations		28,847		12,908		90,359		45,763

Income tax expense		10,802		4,870		33,810		17,281


Net income		18,045		8,038		56,549		28,482

Preferred stock dividend		1,287		74		3,855		74


Net income available to common stockholders	$	16,758	$	7,964	$	52,694	$	28,408


Earnings per common share:
Basic
Net income per share	$	0.34	$	0.16	$	1.08	$	0.59

Diluted
Net income per share	$	0.32	$	0.16	$	1.01	$	0.57


Weighted average number of common shares:
Basic		49,248		48,284		48,862		48,018

Diluted		55,976		49,778		55,745		49,602

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)


	Nine Months Ended
	September 30,
	2008			2007
Cash flows from operating activities:
Net income	$	56,549		$	28,482
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred tax expense		33,810			17,281
Gain on sale of gas gathering assets		(26,677	)		—
Depreciation, depletion and amortization		96,109			89,510
Ceiling test writedown		19,380			—
Accretion of asset retirement obligation		894			679
Share based compensation expense		7,190			7,656
Amortization expense and other		1,055			883
Payments to settle asset retirement obligations		(16,775	)		(579	)
Changes in working capital accounts:
Revenue receivable		4,207			(2,414	)
Joint interest billing receivable		(1,534	)		365
Prepaid costs and inventory		(33,706	)		2,798
Accounts payable and accrued liabilities		35,884			20,588
Advances from co-owners		9,734			4,665
Other		(201	)		(3,005	)


Net cash provided by operating activities		185,919			166,909


Cash flows from investing activities:
Investment in oil and gas properties		(280,090	)		(176,212	)
Investment in gas gathering assets		(5,653	)		(2,437	)
Proceeds from sale of gas gathering assets, net of expenses		40,105			—
Sale of oil and gas properties and other		1,975			248


Net cash used in investing activities		(243,663	)		(178,401	)


Cash flows from financing activities:
Net proceeds from (payments for) share based compensation		1,634			(63	)
Deferred financing costs		(132	)		(73	)
Proceeds from preferred stock offering		—			65,000
Costs of preferred stock offering		—			(3,453	)
Payment of preferred stock dividend		(4,154	)		—
Repayment of bank borrowings		(78,000	)		(70,000	)
Proceeds from bank borrowings		128,000			23,000


Net cash provided by financing activities		47,348			14,411


Net (decrease) increase in cash and cash equivalents		(10,396	)		2,919

Cash and cash equivalents, beginning of period		16,909			4,795


Cash and cash equivalents, end of period	$	6,513		$	7,714


Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	9,499		$	11,283

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- and nine-month periods ended September 30, 2008 and 2007, respectively, has been prepared by the Company and was 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 September 30, 2008 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, 2007 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, 2007.

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 September and October 2007, the Company completed the public offering of an aggregate 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. 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.

The Series B Preferred Stock accumulates dividends at an annual rate of 6.875% for each share of Series B Preferred Stock. 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 will pay dividends in cash, every quarter. At September 30, 2008, the Company had accrued $1,075,324 in connection with the dividend payment made on October 15, 2008.

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 per share computations (in thousands, except per share amounts) is as follows:


	Income		Shares		Per
For the Three Months Ended September 30, 2008	(Numerator)		(Denominator)		Share Amount
BASIC EPS

Net income available to common stockholders	$	16,758		49,248	$	0.34

Effect of dilutive securities:
Stock options		—		983
Restricted stock		—		597
Series B preferred stock		1,287		5,148


DILUTED EPS	$	18,045		55,976	$	0.32


	Income		Shares		Per
For the Three Months Ended September 30, 2007	(Numerator)		(Denominator)		Share Amount
BASIC EPS

Net income available to common stockholders	$	7,964		48,284	$	0.16

Effect of dilutive securities:
Stock options		—		966
Restricted stock		—		528


DILUTED EPS	$	7,964		49,778	$	0.16


	Income		Shares		Per
For the Nine Months Ended September 30, 2008	(Numerator)		(Denominator)		Share Amount
BASIC EPS

Net income available to common stockholders	$	52,694		48,862	$	1.08

Effect of dilutive securities:
Stock options		—		1,111
Restricted stock		—		624
Series B preferred stock		3,855		5,148


DILUTED EPS	$	56,549		55,745	$	1.01


	Income		Shares		Per
For the Nine Months Ended September 30, 2007	(Numerator)		(Denominator)		Share Amount
BASIC EPS

Net income available to common stockholders	$	28,408		48,018	$	0.59

Effect of dilutive securities:
Stock options		—		1,090
Restricted stock		—		494


DILUTED EPS	$	28,408		49,602	$	0.57

Diluted earnings per share during the three and nine months ended September 30, 2008 did not include 539,309 shares and 827,515 shares, respectively, of restricted stock and stock options because their inclusion would have been anti-dilutive. For the three and nine months ended September 30, 2007, diluted earnings per share did not include 1,135,307 shares and 1,293,029 shares, respectively, of restricted stock and stock options since their inclusion would have been anti-dilutive. Additionally, diluted earnings per share for the three and nine months ended September 30, 2007 did not include the assumed conversion of the Series B Preferred Stock as the effect of assuming conversion was anti-dilutive.

Note 4 Long-Term Debt

During 2005, the Company and its wholly-owned subsidiary, 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 constituted less than 3% of the Company’s consolidated assets and revenues at and for the three and nine months ended September 30, 2008.

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 September 30, 2008, $5.8 million was accrued in connection with the November 15, 2008 interest payment and the Company was in compliance with all of the covenants under the Notes.

On November 18, 2005, the Company and PetroQuest Energy, L.L.C. (the “Borrower”) entered into the Second Amended and Restated Credit Agreement (the “Prior Credit Agreement”), which provided for a $100 million revolving credit facility with an available borrowing base of $95 million. As of September 30, 2008, there were $50 million in borrowings outstanding and, except as set forth below, the Company was in compliance with all of the covenants under the Prior Credit Agreement. On September 30, 2008, the required lenders under the Prior Credit Agreement waived, from September 30, 2008 until November 30, 2008, the requirement that the Company comply with the financial covenant contained in the Prior Credit Agreement relating to the minimum ratio of consolidated current assets to consolidated current liabilities.

On October 2, 2008, the Company and the Borrower replaced the credit facility under the Prior Credit Agreement when they entered into the Credit Agreement (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.

The borrowing base under the Credit Agreement is based primarily 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 initial borrowing base is fixed at $150 million until the first borrowing base re-determination, which is scheduled to occur by March 31, 2009. The Company or the lenders may request two additional borrowing base re-determinations each year. As of October 2, 2008, the Company had $62 million outstanding and no letters of credit issued pursuant to 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 0.0% to 0.75% depending on borrowing base usage) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.25% depending on borrowing base usage). However, for the first six months of the Credit Agreement, the margin will be 0.5% for ABR loans and 2.0% for Eurodollar loans. The alternate base rate is equal to the higher of the JPMorgan Chase prime rate or the Federal Funds Effective Rate plus 0.5% per annum, and 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 Borrower) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit will be charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees.

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, 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 October 2, 2008, 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, 2008	$	17,451
Liabilities incurred during 2008		9,225
Liabilities settled during 2008		(17,360	)
Accretion expense		894
Revisions in estimated cash flows		16,958


Asset retirement obligation at September 30, 2008		27,168
Less: current portion of asset retirement obligation		(11,407	)

Long-term asset retirement obligation	$	15,761

Periodically, the Company revises its estimates regarding abandonment of its properties to consider changes in scope, timing and cost. During 2008, the Company revised its cost estimates to abandon several of its Gulf of Mexico properties.

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 three- and nine-month periods ended September 30, 2008 and 2007 is as follows (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Stock options:
Incentive Stock Options	$	349	$	255	$	1,020	$	943
Non-Qualified Stock Options		752		484		1,983		1,396
Restricted stock		1,418		1,431		4,187		5,317

Share based compensation	$	2,519	$	2,170	$	7,190	$	7,656

During the three- and nine-month periods ended September 30, 2008, the Company recorded income tax benefits of $0.8 million and $2.3 million, respectively, related to share based compensation expense recognized during those periods. The three- and nine-month periods ended September 30, 2007 include income tax benefits of $0.7 million and $2.5 million, respectively, related to share based compensation. 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 Derivative Instruments

The Company accounts for derivatives in accordance with SFAS 133, as amended. When the conditions for hedge accounting specified in SFAS 133 are met, the Company may designate these derivatives as 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 are recorded in the income statement as derivative income or expense. At September 30, 2008, 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 ($3,925,000) and $4,366,000 and oil hedges of ($1,567,000) and ($77,200) for the three months ended September 30, 2008 and 2007, respectively. For the nine-month periods ended September 30, 2008 and 2007, oil and gas sales include additions (reductions) related to the settlement of gas hedges of ($11,538,000) and $8,207,000 and oil hedges of ($4,504,000) and $155,000, respectively.

The Credit Agreement requires that the counterparties to the Company’s 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 the Company’s existing hedge contracts are JPMorgan and Calyon, both of which are lenders under the Credit Agreement. To the extent the Company enters into additional hedge contracts, it expects that certain lenders under the Credit Agreement would serve as counterparties. As of September 30, 2008, 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:
October-December 2008	Costless Collar	42,500 Mmbtu	$8.32 — 10.52
2009	Costless Collar	20,000 Mmbtu	$9.50 — 12.94
Crude Oil:
October-December 2008	Costless Collar	900 Bbls	$86.67 — 126.49
2009	Costless Collar	400 Bbls	$100.00 — 168.50

At September 30, 2008, the Company recognized an asset of $16.8 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of September 30, 2008, the Company would realize an $8.7 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 production of oil and gas associated with the derivative contracts.

Note 8 Sale of Gas Gathering Assets

On July 31, 2008, the Company sold the majority of its gas gathering assets located in Oklahoma for $41.3 million and recorded a $26.7 million gain, subject to certain normal post-closing adjustments. The net proceeds from the sale were used to repay a portion of the borrowings outstanding under the Prior Credit Agreement. The following table summarizes the operating data attributable to the gas gathering systems sold (in thousands):


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008		2007			2008		2007
Gas gathering revenue	$	1,195	$	1,065		$	4,899	$	4,164
Expenses:
Gas gathering costs		434		894			2,159		3,188
Depreciation expense		282		692			1,924		2,058

Income (loss) from operations	$	479	$	(521	)	$	816	$	(1,082	)

Note 9 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, 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.

At September 30, 2008, the Company computed the estimated future net cash flows from its proved oil and gas reserves, discounted at 10%, using average quarter end prices of $6.04 per Mcfe and $101.12 per barrel. Approximately 91% of the Company’s proved reserves are natural gas. Due to the low market price for gas at September 30, 2008, the Company’s capitalized costs exceeded the full cost ceiling by $19.4 million. As a result, the Company recorded a $19.4 million non-cash ceiling test writedown of its oil and gas properties at September 30, 2008.

Note 10 New Accounting Standards

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 expects to adopt SFAS No. 161 beginning January 1, 2009, and is currently evaluating the impact, if any, SFAS No. 161 will have on its financial position or results of operations.

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 February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure certain financial instruments and certain other items at fair value. The Company adopted SFAS No. 159 on January 1, 2008 and elected not to account for any other assets or liabilities at fair value and thus the adoption had no impact to its financial statements.

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. The adoption did not have an effect on the Company’s financial position or results of operations.

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 the fair values. The Company’s derivative instruments at September 30, 2008 were in the form of costless collars. The fair value of these derivatives is derived from quotes provided by the counterparties to the contracts. Although the Company believes the quotes are indicative of the approximate price at which the counterparty would be willing to settle such contracts as of the measurement date and there is observable market data underlying the quotes, there is not sufficient corroborating market evidence to support classifying these instruments as Level 2. As a result, the Company designates its commodity derivatives as Level 3 in the fair value hierarchy.

The following table summarizes the valuation of the Company’s instruments subject to fair value measurement on a recurring basis as of September 30, 2008 (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

—

16,849

The following table sets forth a reconciliation of changes in the fair value of the Company’s commodity derivative asset (liability) classified as Level 3 in the fair value hierarchy (in thousands):


	Three Months Ended			Nine Months Ended
	September 30, 2008			September 30, 2008
Balance at beginning of period	$	(44,012	)	$	(691	)
Total gains or losses (realized or unrealized):
Included in earnings		(5,492	)		(16,042	)
Included in other comprehensive income		60,861			17,540
Purchases, issuances and settlements		5,492			16,042
Transfers in and out of Level 3		—			—

Balance at end of period	$	16,849		$	16,849

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 included 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 continued to diversify into longer life regions by acquiring unevaluated leasehold interests in Arkansas. Drilling operations targeting the Fayetteville Shale began on this acreage in September 2007. In addition, robust drilling activity continued in Oklahoma and Texas as we drilled 61 gross wells in these regions during 2007, realizing a 93% success rate.

Our 2007 results marked the fourth consecutive year we achieved annual company records for production, estimated proved reserves, cash flow from operating activities and net income. Our record results over the last four years reflect our consistent drilling success and correlate directly with the implementation of our asset diversification strategy during 2003. Comparing 2007 results with those in 2003, we have grown production by 226% and proved reserves by 88%.

At September 30, 2008, 67% of our estimated proved reserves were located in our longer life basins as compared to 61% at December 31, 2007. Approximately 53% of our third quarter 2008 production volumes were derived from our longer-life properties as compared to 33% during the fourth quarter of 2007.

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 oil and gas properties, whether or not being amortized currently, 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.

At September 30, 2008, we computed the estimated future net cash flows from our proved oil and gas reserves, discounted at 10%, using average quarter end prices of $6.04 per Mcfe and $101.12 per barrel. Approximately 91% of our proved reserves are natural gas. Due to the low market price for gas at September 30, 2008, our capitalized costs exceeded the full cost ceiling by $19.4 million. As a result, we recorded a $19.4 million non-cash ceiling test writedown of our oil and gas properties at September 30, 2008. 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 substantially, 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. 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, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. 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 quality of available data, engineering and geological interpretation and 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, all of which may in fact vary considerably from actual results. 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. For these reasons, estimates of the economically recoverable quantities of expected oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. 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. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variance may be material.

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 September 30, 2008, our derivative instruments were considered effective cash flow hedges.

Estimating the fair value of hedging derivatives requires complex calculations incorporating estimates of future prices, discount rates and price movements. As a result, we obtain the fair value of our commodity derivatives from the counterparties to those contracts. Because the counterparties are market makers, they are able to provide us with an approximate price at which they would be willing to settle such contracts as of the given date. We believe the values provided by our counterparties represent an accurate estimate of the fair value of the contracts.

New Accounting Standards

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. We expect to adopt SFAS No. 161 beginning January 1, 2009, and are currently evaluating the impact, if any, SFAS No. 161 will have on our financial position or results of operations.

In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure certain financial instruments and certain other items at fair value. We adopted SFAS No. 159 on January 1, 2008 and elected not to account for any other assets or liabilities at fair value. As a result, the adoption had no impact to our financial statements.

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. We adopted SFAS No. 157 on January 1, 2008 (see Note 10).

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				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Production:
Oil (Bbls)		137,929		243,048		504,509		889,521
Gas (Mcf)		7,214,427		6,621,226		21,322,903		18,257,387
Total Production (Mcfe)		8,042,001		8,079,514		24,349,957		23,594,513

Sales:
Total oil sales	$	15,695,498	$	18,793,535	$	53,362,415	$	59,892,329
Total gas sales		61,291,924		45,194,457		189,057,801		130,809,880


Total oil and gas sales	$	76,987,422	$	63,987,992	$	242,420,216	$	190,702,209


Average sales prices:
Oil (per Bbl)	$	113.79	$	77.32	$	105.77	$	67.33
Gas (per Mcf)		8.50		6.83		8.87		7.16
Per Mcfe		9.57		7.92		9.96		8.08

The above sales and average sales prices include additions (reductions) to revenue related to the settlement of gas hedges of ($3,925,000) and $4,366,000 and the settlement of oil hedges of ($1,567,000) and ($77,200) for the three months ended September 30, 2008 and 2007, respectively. The above sales and average sales prices include additions (reductions) to revenue related to the settlement of gas hedges of ($11,538,000) and $8,207,000 and the settlement of oil hedges of ($4,504,000) and $155,000 for the nine-month periods ended September 30, 2008 and 2007, respectively.

Net income available to common stockholders totaled $16,758,000 and $7,964,000 for the quarters ended September 30, 2008 and 2007, respectively, while net income available to common stockholders for the nine-month periods ended September 30, 2008 and 2007 totaled $52,694,000 and $28,408,000, respectively. The increase during the 2008 periods was primarily attributable to the following:

Production. During September 2008, the majority of our Gulf Coast Basin properties were impacted by Hurricanes Gustav and Ike and we estimate that approximately 1.2 Bcfe, which would have been produced during the third quarter of 2008, was shut-in and deferred as a result of the storms. Oil production during the three- and nine-month periods ended September 30, 2008 decreased 43% from the comparable 2007 periods primarily due to normal production declines at our Ship Shoal 72 and Turtle Bayou Fields, which produce approximately half of our total oil production, as well as the impact from the hurricanes. Currently, production from the majority of our Gulf Coast Basin properties has been restored.

During late 2007, we began drilling operations on our Arkansas acreage. As a result of production from this new basin and our continued expansion into our longer life basins, where the production is primarily natural gas, our gas production during the three- and nine-month periods ended September 30, 2008 increased 9% and 17%,

respectively, from the comparable 2007 periods. The increase in gas production during the 2008 periods was partially offset by the downtime we experienced during September as a result of the hurricanes. Overall, production during the first nine months of 2008 was 3% higher than the 2007 period.

As a result of the restoration of the majority of our Gulf Coast Basin production and new production from our ongoing operations, we expect that production during the fourth quarter of 2008 will be higher than volumes produced during the third quarter of 2008. We currently have approximately 5% of our total production shut-in as a result of Hurricanes Gustav and Ike. We expect this production to be restored throughout the remainder of 2008 and the first quarter of 2009.

Prices. Including the effects of our hedges, average oil prices per barrel for the quarter and nine months ended September 30, 2008 were $113.79 and $105.77, respectively, as compared to $77.32 and $67.33, respectively, for the 2007 periods. Average gas prices per Mcf were $8.50 and $8.87 for the quarter and nine months ended September 30, 2008, respectively, as compared to $6.83 and $7.16 for the respective 2007 periods. Stated on an Mcfe basis, unit prices received during the quarter and nine months ended September 30, 2008 were 21% and 23% higher, respectively, than the prices received during the comparable 2007 periods. Since September 30, 2008, oil and gas prices have declined. See “Liquidity and Capital Resources” below for a discussion of the impact of oil and gas prices on our revenues, cash flow and bank credit facility.

Revenue. Oil and gas sales during the quarter and nine months ended September 30, 2008 increased 20% and 27% to $76,987,000 and $242,420,000, respectively, as compared to oil and gas sales of $63,988,000 and $190,702,000 for the 2007 periods. The increased revenue during the 2008 periods was primarily the result of higher pricing and increased gas production.

Expenses. Lease operating expenses for the three- and nine-month periods ended September 30, 2008 increased to $11,721,000 and $31,818,000, respectively, as compared to $8,929,000 and $24,185,000 during the 2007 periods. On a unit of production basis, operating expenses totaled $1.46 and $1.31 per Mcfe during the three- and nine-month periods of 2008, respectively, as compared to $1.11 and $1.03 per Mcfe during the 2007 periods.

Overall, the cost of materials, transportation, fuel and other services increased during 2008 as compared to 2007. Additionally, our operating expenses on a per unit basis during the 2008 periods were negatively impacted by the 1.2 Bcfe of production that was deferred as a result of the hurricanes. For 2009, the costs of services and materials in the markets in which we operate could decline as the demand for such materials and services may weaken as a result of the recent decline in commodity prices and the overall outlook for the global economy.

Production taxes during the quarter and nine months ended September 30, 2008 totaled $3,060,000 and $9,489,000, respectively, as compared to $1,593,000 and $5,777,000 during the 2007 periods. The increase in 2008 production taxes is primarily due to higher prices and increased production from our Oklahoma, Arkansas and Texas properties. Additionally, there was a 7% increase in the Louisiana gas severance tax rate effective July 1, 2008.

General and administrative expenses during the quarter and nine months ended September 30, 2008 totaled $5,720,000 and $18,036,000, respectively, as compared to expenses of $5,550,000 and $16,054,000 during the comparable 2007 periods. Included in general and administrative expenses for the periods ended September 30, 2008 and 2007 was share-based compensation expense relative to SFAS 123(R) as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2008		2007		2008		2007
Stock options:
Incentive Stock Options	$	349,000	$	255,000	$	1,020,000	$	943,000
Non-Qualified Stock Options		752,000		484,000		1,983,000		1,396,000
Restricted stock		1,418,000		1,431,000		4,187,000		5,317,000

Share-based compensation	$	2,519,000	$	2,170,000	$	7,190,000	$	7,656,000

Excluding share-based compensation, general and administrative expense during the third quarter of 2008 decreased by 5% and increased by 29% for the nine month period ended September 30, 2008 as compared to the 2007 periods. Employee-related costs associated with the 23% increase in our staffing since September 2007 represented the majority of the increase in general and administrative costs for the nine month 2008 period, as compared to 2007. We expect that general and administrative expenses for the fourth quarter of 2008 will be comparable to the third quarter of 2008.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the quarter and nine months ended September 30, 2008 totaled $33,420,000, or $4.16 per Mcfe, and $93,408,000, or $3.84 per Mcfe, respectively, as compared to $30,935,000, or $3.83 per Mcfe, and $86,861,000, or $3.68 per Mcfe, respectively, during the 2007 periods. The prices of oil and natural gas declined significantly during the third quarter of 2008. Because 91% of our proved reserves are natural gas, the decline in the price of natural gas at September 30, 2008 had a negative impact on our proved reserves from certain of our longer-life properties. As a result of the negative price-related reserve revisions, we experienced an increase to our DD&A for the third quarter of 2008 and recorded a non-cash ceiling test writedown of our oil and gas properties totaling $19,380,000. See Note 9, “Ceiling Test” for further discussion of the ceiling test.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $1,609,000 and $6,498,000, respectively, during the quarter and nine months ended September 30, 2008 as compared to $3,542,000 and $11,112,000 during the 2007 periods. We capitalized $3,190,000 and $7,991,000 of interest during the three- and nine-month periods of 2008 and $1,674,000 and $4,437,000 during the respective 2007 periods. The increase in the capitalized portion of our interest cost during the 2008 periods is due to the increase in our unevaluated properties, which is primarily the result of leasehold acquisitions in our longer-life basins.

Income tax expense during the quarter and nine-month periods ended September 30, 2008 totaled $10,802,000 and $33,810,000, respectively, as compared to $4,870,000 and $17,281,000 during the respective 2007 periods. The increase is primarily the result of the increased operating profit, including the gain on the sale of our gas gathering assets, in the 2008 periods as compared to 2007. We 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.

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 September 30, 2008, we had a working capital deficit of $54.8 million compared to a deficit of $43.7 million at December 31, 2007. On October 2, 2008, we entered into a new $300 million credit facility with an initial borrowing base of $150 million. We believe that our working capital balance should be viewed in conjunction with availability of borrowings under our bank credit facility when measuring liquidity. At October 2, 2008, we had $88 million of borrowings available under our new bank credit facility.

The increase in our working capital deficit at September 30, 2008 was attributable to several factors including the increase in our revenue payable liability, which is a function of higher production at September 30, 2008 as compared to December 31, 2007. Our advances from co-owners and accounts payable to vendors were also higher at September 30, 2008 as a result of the increase in operational activity ongoing at September 30, 2008. Offsetting the increases in these liabilities were increases in prepaid drilling costs and drilling pipe inventory, primarily for near-term drilling operations, and the increase of our hedging asset, which is 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. 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 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. 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 from operations increased from $166,909,000 during the nine months ended September 30, 2007 to $185,919,000 during the 2008 period. The increase was primarily attributable to higher production and realized prices during the 2008 period.

Source of Capital: Debt

During 2005, we issued $150 million in principal amount of our 10 3/8% Senior Notes (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 September 30, 2008, $5.8 million had been accrued in connection with the November 15, 2008 interest payment and we were in compliance with all of the covenants under the Notes.

On November 18, 2005, we and PetroQuest Energy, L.L.C. (the “Borrower”) entered into the Second Amended and Restated Credit Agreement (the “Prior Credit Agreement”), which provided for a $100 million revolving credit facility with an available borrowing base of $95 million. As of September 30, 2008, there were $50 million in borrowings outstanding and, except as set forth below, we were in compliance with all of the covenants under the Prior Credit Agreement. On September 30, 2008, the required lenders under the Prior Credit Agreement waived, from September 30, 2008 until November 30, 2008, the requirement that we comply with the financial covenant contained in the Prior Credit Agreement relating to the minimum ratio of consolidated current assets to consolidated current liabilities.

On October 2, 2008, we replaced the credit facility under the Prior Credit Agreement when we entered into the Credit Agreement (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.

The borrowing base under the Credit Agreement is based primarily upon the valuation as of January 1 and July 1 of each year of the reserves attributable to our oil and gas properties. The initial borrowing base is fixed at $150 million until the first borrowing base re-determination, which is scheduled to occur by March 31, 2009. We or the lenders may request two additional borrowing base re-determinations each year. As of November 3, 2008, we had $90 million outstanding under and no letters of credit issued pursuant to the Credit Agreement.

The Credit Agreement is secured by a first priority lien on substantially all of our assets and 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 0.0% to 0.75% depending on borrowing base usage) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.25% depending on borrowing base usage). However, for the first six months of the Credit Agreement, the margin will be 0.5% for ABR loans and 2.0% for Eurodollar loans. Outstanding letters of credit will be charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees.

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, 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 October 2, 2008, we were in compliance with all of the covenants contained in the Credit Agreement.

Source of Capital: Divestitures

We do not budget for 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 capital to be reinvested in higher rate of return projects or in projects that have longer estimated lives. On July 31, 2008, we sold the majority of our gas gathering systems located in Oklahoma for $41.3 million and recorded a $26.7 million gain, subject to normal post-closing adjustments. The net proceeds from the sale were used to repay a portion of the borrowings outstanding under the Prior Credit Agreement in order to provide increased liquidity to execute our capital program. There can be no assurance that we will be able to sell any of our assets in the future.

Source of Capital: Issuance of Securities

We have approximately $125 million remaining under an effective universal shelf registration statement relating to the potential public offer and sale of any combination of debt securities, common stock, preferred stock, depositary shares, and warrants. The registration statement does not provide any assurance that we will or could sell any such securities.

Use of Capital: Exploration and Development

We continue our strategic focus of funding our drilling expenditures primarily with cash flow from operations. In response to the recent 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 the remainder of 2008 by deferring several projects that we operate. Our 2008 capital budget, which excludes acquisitions and capitalized interest and general and administrative costs, is expected to range between $250 million and $260 million, of which $208 million was incurred during the first nine months of 2008. Based on our outlook of commodity prices and production, we believe that we will be able to fund the remainder of our planned 2008 exploration and development activities with cash on hand, cash flow from operations and available bank borrowings under our recently expanded credit facility.

We are currently developing our capital expenditure budget for 2009, which is expected to be less than our 2008 capital program. Because we operate the majority of our proved reserves, we are able to control the timing on a substantial portion of our capital investments. As a result of this flexibility, we expect to be able to tailor our 2009 capital budget to stay within our projected cash flow from operations based upon our expectations of commodity prices, production 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 require additional financings, which may include borrowings under our credit facility, 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.

Use of Capital: Acquisitions

While we do not budget for acquisitions, during 2008 we were active in evaluating opportunities that fit our specific acquisition profile. In Texas, we acquired an additional 50% interest and control of operations in our Weekley Prospect for approximately $20 million. In Oklahoma, we closed several leasehold transactions for a combined cost of approximately $38.6 million. These acquisition costs were funded through borrowings under our credit facility and a majority of the acreage is considered unevaluated at September 30, 2008. As a result of lower commodity prices and the resulting impact to our cash flow from operations and liquidity, we expect to significantly reduce our leasing and acquisition activities for the remainder of 2008 and 2009.

We expect to fund future acquisitions primarily with borrowings under our bank credit facility and cash flow from operations, but may also issue additional equity or debt securities either directly or in connection with an acquisition. There can be no assurance that acquisition funds may be available on terms acceptable to us, if at all.

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 continued price declines since September 30, 2008, declines in the values of our properties that have resulted in and may in the future result in additional ceiling test writedowns, 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 2008, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $6.4 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 quarter and nine month periods ended September 30, 2008, we paid $5,492,000 and $16,042,000, respectively, to the counterparties to our derivative instruments 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 September 30, 2008, 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:
October-December 2008	Costless Collar	42,500 Mmbtu	$8.32 — 10.52
2009	Costless Collar	20,000 Mmbtu	$9.50 — 12.94
Crude Oil:
October-December 2008	Costless Collar	900 Bbls	$86.67 — 126.49
2009	Costless Collar	400 Bbls	$100.00 — 168.50

At September 30, 2008, we recognized an asset of $16.8 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of September 30, 2008, we would realize a $8.7 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 production of oil and gas associated with the derivative contracts.

During October 2008, we entered into the following gas contract accounted for as a cash flow hedge:

Instrument

Production Period

Type

Daily Volumes

Price

Natural Gas:

2009

Swap

10,000 Mmbtu

7.46

Debt outstanding under our bank credit facility is subject to a floating interest rate and represents 25% of our total debt as of September 30, 2008. Based upon an analysis, utilizing the actual interest rate in effect and balances outstanding as of September 30, 2008, 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 2008 and 2009 is approximately $0.6 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.

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 a substantial and 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, which have declined since September 30, 2008. 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 are subject to large fluctuations in response to a variety of other factors beyond our control.

These factors include:

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

	•		market uncertainty;

	•		the level of consumer product demand;

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

	•		the condition of the United States and worldwide economies;

	•		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.

At various times, excess domestic and imported supplies have depressed oil and natural gas prices. We cannot predict future oil and natural gas prices and such prices may decline. Declines 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 may also reduce the amount of oil and natural gas that we can produce economically and require us to record ceiling test write-downs when prices decline. 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.

We may not be able to obtain adequate financing to execute our operating strategy.

Our ability to execute our operating strategy is highly dependent on our having access to capital. We have historically addressed our long-term liquidity needs through the use of bank credit facilities, second lien term credit facilities, the issuance of equity and debt securities, the use of proceeds from the sale of assets and the use of cash provided by operating activities. We will continue to examine the following alternative sources of long-term capital:

	•		borrowings from banks or other lenders;

	•		the issuance of debt securities;

	•		the sale of common stock, preferred stock or other equity securities;

	•		joint venture financing; and

	•		production payments.

The availability of these sources of capital will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices, which have declined since September 30, 2008, our credit ratings, interest rates, market perceptions of us or the oil and gas industry, our market value and operating performance. We may be unable to execute our operating strategy if we cannot obtain capital from these sources.

Lower oil and natural gas prices may cause us to record additional 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, 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 stockholders’ equity. As a result of the decline in prices, at September 30, 2008, we recorded a ceiling test write-down of $19.4 million. The risk that we will be required to write down the carrying value of oil and natural 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.

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 September 30, 2008, the aggregate amount of our outstanding indebtedness was $199 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 our 10 3/8% senior notes due 2012, which we refer to as our 10 3/8% 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 our 10 3/8% 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 our 10 3/8% notes alone, 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 are at variable rates of interest, which, if interest rates increase, could result in higher interest expense;

	•		we 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 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.

We may incur debt from time to time under our bank credit facility. The borrowing base limitation under our bank credit facility is periodically redetermined and upon such redetermination, we could be forced to repay a portion of our bank debt. We may not have sufficient funds to make such repayments.

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 our 10 3/8% 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 our 10 3/8% 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.

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 September 30, 2008.


					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
July 1 - July 31, 2008		1,904	$	20.87		—		—
August 1 - August 31, 2008		3,426		17.99		—		—
September 1 - September 30, 2008		—				—		—


(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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

NONE

Item 5. OTHER INFORMATION

NONE

Item 6. EXHIBITS

Exhibit 10.1, Credit Agreement dated as of October 2, 2008, among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., JPMorgan Chase Bank, N.A., Calyon New York Branch, Bank of America, N.A., Wells Fargo Bank, N.A., and Whitney National Bank (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on October 6, 2008).

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.


	Page No.
Part I. Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007		1

Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2008 and 2007		2

Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2008 and 2007		3

Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2008 and 2007		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		24

Item 3. Defaults upon Senior Securities		24

Item 4. Submission of Matters to a Vote of Security Holders		24

Item 5. Other Information		24

Item 6. Exhibits		24
EXHIBIT 31.1
EXHIBIT 31.2
EXHIBIT 32.1
EXHIBIT 32.2



	PETROQUEST ENERGY, INC.

Date: November 6, 2008	/s/	W. Todd Zehnder

		W. Todd Zehnder
		Executive Vice President, Chief
		Financial Officer and Treasurer
		(Authorized Officer and Principal
		Financial Officer)



/s/ W. Todd Zehnder

W. Todd Zehnder
Chief Financial Officer
November 6, 2008

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/s/ Charles T. Goodson Charles T. Goodson
	Chief Executive Officer
	November 6, 2008



/s/ Charles T. Goodson Charles T. Goodson
Chief Executive Officer
November 6, 2008



/s/ W. Todd Zehnder W. Todd Zehnder
Chief Financial Officer
November 6, 2008