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, 2005


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: 019020

PETROQUEST ENERGY, INC.

(Exact name of registrant as specified in its charter)


DELAWARE (State of Incorporation)		72-1440714 (I.R.S. Employer Identification No.)

400 E. Kaliste Saloom Rd., Suite 6000 Lafayette, Louisiana		70508
(Address of principal executive offices)		(Zip code)

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Exchange Act).

Yes þ No 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 October 25, 2005, there were 47,293,490 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,
	2005			2004
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	39,844		$	1,529
Oil and gas revenue receivable		12,521			9,392
Joint interest billing receivable		10,221			3,655
Other current assets		6,990			1,017

Total current assets		69,576			15,593


Oil and gas properties:
Oil and gas properties, full cost method		477,661			363,756
Unevaluated oil and gas properties		39,608			16,380
Accumulated depreciation, depletion and amortization		(198,072	)		(168,453	)

Oil and gas properties, net		319,197			211,683


Other assets, net of accumulated depreciation and amortization of $10,615 and $5,967, respectively		15,204			4,341


Total assets	$	403,977		$	231,617


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable to vendors	$	27,776		$	24,176
Advances from co-owners		8,993			2,265
Hedging liability		30,329			4,536
Oil and gas revenue payable		11,839			2,930
Accrued interest on 10 3/8% Senior Notes		6,016			—
Other accrued liabilities		8,918			6,115

Total current liabilities		93,871			40,022

Bank debt		—			38,500
10 3/8% Senior Notes		148,294			—
Asset retirement obligation		18,338			15,238
Deferred income taxes		13,792			14,606
Long-term hedging liability		4,724			1,974
Other accrued liabilities		227			—

Commitments and contingencies		—			—

Stockholders’ equity:
Common stock, $.001 par value; authorized 75,000 shares; issued and outstanding 47,291 and 44,685 shares, respectively		47			45
Paid-in capital		117,352			112,387
Accumulated other comprehensive loss		(18,841	)		(4,231	)
Retained earnings		26,173			13,076

Total stockholders’ equity		124,731			121,277


Total liabilities and stockholders’ equity	$	403,977		$	231,617

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,
	2005		2004		2005		2004
Revenues:
Oil and gas sales	$	30,859	$	22,516	$	82,508	$	62,084
Interest and other income		522		56		895		187

		31,381		22,572		83,403		62,271


Expenses:
Lease operating expenses		6,601		4,087		15,448		9,593
Production taxes		1,081		300		2,217		1,164
Depreciation, depletion and amortization		10,485		9,701		30,539		26,774
General and administrative		1,571		1,589		5,079		4,716
Accretion of asset retirement obligation		424		210		829		611
Interest expense		3,456		622		9,141		1,968
Derivative expense		—		2		—		2

		23,618		16,511		63,253		44,828


Income from operations		7,763		6,061		20,150		17,443

Income tax expense		2,718		2,121		7,053		6,094


Net income	$	5,045	$	3,940	$	13,097	$	11,349


Earnings per common share:
Basic	$	0.11	$	0.09	$	0.28	$	0.25

Diluted	$	0.10	$	0.08	$	0.27	$	0.25


Weighted average number of common shares:
Basic		47,213		44,631		46,514		44,593

Diluted		48,576		46,905		48,086		46,243

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)


	Nine Months Ended
	September 30,
	2005			2004
Cash flows from operating activities:
Net income	$	13,097		$	11,349
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred tax expense		7,053			6,094
Depreciation, depletion and amortization		30,539			26,774
Accretion of asset retirement obligation		829			611
Amortization of debt issuance costs		1,239			1,232
Compensation expense		213			272
Write-off of debt issuance costs		2,439			—
Amortization of bond discount		65			—
Derivative mark to market		—			(169	)
Changes in working capital accounts:
Accounts receivable		(3,129	)		(1,057	)
Joint interest billing receivable		(6,566	)		(1,296	)
Prepaids and other assets		(6,290	)		(115	)
Accounts payable and accrued liabilities		17,160			7,171
Advances from co-owners		6,728			(1,394	)


Net cash provided by operating activities		63,377			49,472


Cash flows from investing activities:
Investment in gas gathering assets		(9,650	)		—
Investment in oil and gas properties		(124,532	)		(42,360	)


Net cash used in investing activities		(134,182	)		(42,360	)


Cash flows from financing activities:
Proceeds from exercise of options		883			170
Proceeds from bank borrowings		34,500			13,000
Repayment of bank borrowings		(73,000	)		(19,500	)
Proceeds from issuance of 10 3/8% senior notes		148,229			—
Deferred financing costs		(5,543	)		(358	)
Issuance of common stock, net of expenses		4,051			—


Net cash provided by (used in) financing activities		109,120			(6,688	)


Net increase in cash and cash equivalents		38,315			424
Cash and cash equivalents, beginning of period		1,529			779


Cash and cash equivalents, end of period	$	39,844		$	1,203


Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	1,593		$	1,250

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, 2005 and 2004 have been prepared by the Company and were not audited by its independent registered public accounting firm. 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, 2005 and for all reported periods. Certain reclassifications of prior year amounts have been made to conform to the current year presentation. 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, 2004 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 U.S. generally accepted accounting principles have been condensed or omitted. These consolidated financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004.

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), Pittrans, Inc. (an Oklahoma corporation) and TDC Energy LLC (a single member Louisiana limited liability company).

Note 2 Earnings Per Share

Basic earnings per common share are computed by dividing net income 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 warrants considered dilutive computed using the treasury stock method. A reconciliation between basic and diluted shares outstanding (in thousands) is as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Basic shares outstanding		47,213		44,631		46,514		44,593
Effect of stock options		1,363		1,111		1,304		716
Effect of warrants		—		1,163		268		934

Diluted shares outstanding		48,576		46,905		48,086		46,243

The average market price of the common shares for the quarter ended September 30, 2005 exceeded the exercise price of all options outstanding at the end of the period. Options to purchase 40,000 shares of common stock were outstanding during the nine-month period ended September 30, 2005, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market prices of the common shares during the period. These options’ exercise prices were between $6.79 and $7.65, and expire in 2011 and 2012.

Options to purchase 474,500 and 563,400 shares of common stock were outstanding during the three- and nine-month periods ended September 30, 2004, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market prices of the common shares during the periods. These options’ exercise prices were between $4.95 and $7.65 for the third quarter of 2004 and $3.75 and $7.65 for the nine-month 2004 period and expire in 2010-2013.

Note 3 Long-Term Debt

On May 11, 2005, the Company and PetroQuest Energy, L.L.C. issued $125 million in principal amount of 10 3/8% Senior Notes due 2012 at 98.783% of their face value. On June 17, 2005, the Company and PetroQuest Energy, L.L.C. issued an additional $25 million in principal amount of 10 3/8% Senior Notes due 2012 at 99% of their face value. Collectively, these issuances of 10 3/8% notes are referred to as “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 for the three- and nine-month periods ended September 30, 2005.

After payment of expenses and the initial purchasers’ discounts, the Company received $144.4 million in net proceeds from the issuance of the Notes. Net proceeds were used to repay all outstanding borrowings under the Company’s credit facilities, to fund acquisitions of assets in Oklahoma and to provide capital for future acquisitions and general corporate purposes. The Notes are redeemable beginning on May 15, 2009 at 105.188% of their principal amount and thereafter declining annually to 100% on and after May 15, 2011. In addition, before May 15, 2008, the Company may redeem up to 35% of the aggregate principal amount of the Notes issued with net proceeds from an equity offering at 110.375%. The Notes provide for certain covenants, which include, without limitation, 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, 2005, $6 million had been accrued in connection with the November 15, 2005 interest payment.

The Company entered into a bank credit facility on May 14, 2003. Pursuant to the credit facility agreement, PetroQuest and its subsidiary PetroQuest Energy, L.L.C. (the “Borrower”) have a $75 million revolving credit facility which permits the Borrower to borrow amounts from time to time based on the available borrowing base as determined in the bank credit facility. The bank credit facility is secured by a mortgage on substantially all of the Borrower’s oil and gas properties, a pledge of the membership interest of the Borrower and PetroQuest’s corporate guarantee of the indebtedness of the Borrower. The borrowing base under the bank credit facility is based upon the valuation as of April 1 and October 1 of each year of the Borrower’s mortgaged properties, projected oil and gas prices, and any other factors deemed relevant by the lenders. The Company or the lenders may also request additional borrowing base redeterminations.

During the second quarter of 2005, the Company repaid all outstanding borrowings under the credit facility with a portion of the net proceeds received from the issuance of the Notes. In connection with the issuance of the Notes, the credit facility was amended and as of September 30, 2005, the borrowing base under the bank credit facility was $25 million.

Outstanding balances on the revolving credit facility bear interest at either the prime rate of the bank serving as agent under the facility plus a margin (based on a sliding scale of 0.75% to 1.25% based on borrowing base usage but never less than the Federal Funds Effective Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a sliding scale of 2.0% to 2.5% depending on borrowing base usage). The bank credit facility also allows the Company to use up to $5 million of the borrowing base for letters of credit for fees equal to the applicable margin rate for Eurodollar advances. There were no letters of credit outstanding at September 30, 2005. The bank credit facility matures on May 14, 2006.

The Company is subject to certain restrictive financial and non-financial covenants under the bank credit facility including a minimum current ratio of 1.0 to 1.0, all as defined in the credit facility agreement. The bank credit facility also requires the Borrower to establish and maintain commodity hedges covering at least 50% of its proved developed producing reserves on a rolling twelve-month basis. As of September 30, 2005, the Company was in compliance with all of the covenants in the bank credit facility.

On November 6, 2003, the Company obtained a $20 million second lien term credit facility from Macquarie Americas Corp., which was subsequently assigned to Macquarie Bank Limited (“MBL”). On May 11, 2005, the Company repaid the $12 million of total borrowings outstanding with proceeds from the Notes and terminated this facility. After termination of this facility, however, certain oil and gas hedging contracts with MBL as the counterparty remained in place and are secured by a second mortgage on substantially all of the oil and gas properties of PetroQuest Energy, L.L.C. until the hedges expire or are terminated. During the second quarter of 2005, the Company recognized a charge of $2.3 million related to previously deferred financing costs associated with this facility.

Note 4 Asset Retirement Obligation

The Company accounts for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143 (SFAS 143), “Accounting for Asset Retirement Obligations.” 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 changes to the Company’s asset retirement obligation liability (in thousands):


	Nine Months Ended
	September 30, 2005
Asset retirement obligation at beginning of period	$	16,393
Liabilities incurred during 2005		6,854
Liabilities settled during 2005		—
Accretion expense		829
Revisions in estimated cash flows		(1,913	)

Asset retirement obligation at end of period		22,163
Less: current portion of asset retirement obligation		(3,825	)

Long-term asset retirement obligation	$	18,338

Note 5 New Accounting Standards

In December 2004, the Financial Accounting Standards Board issued SFAS 123 (revised 2004), “Share Based Payment,” which is a revision of SFAS 123, “Accounting for Stock-Based Compensation.” SFAS 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and amends SFAS 95, “Statement of Cash Flows.” Generally, the approach in SFAS 123(R) is similar to the approach in SFAS 123. However, SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their estimated fair values. Pro forma disclosure is no longer an alternative. In April 2005, the SEC issued an amendment to rule 4-01(a) of Regulation S-X regarding the compliance date for SFAS 123(R). This amendment changed the effective date to the first fiscal year beginning on or after June 15, 2005. Accordingly, the Company expects to adopt the standard January 1, 2006.

SFAS 123(R) permits adoption using one of two methods. A “modified prospective” method in which compensation cost is recognized beginning with the effective date using the requirements of SFAS 123(R) for all share-based payments granted after the effective date and the requirements of SFAS 123 for all unvested awards at the effective date related to awards granted prior to the effective date. An alternate method, the “modified retrospective” method, includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

The Company currently accounts for its stock-based compensation plans under the principles prescribed by APB Opinion No. 25. Accordingly, no stock option compensation cost is reflected in net income, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. Accordingly, the adoption of SFAS 123(R) will have a significant impact on our results of operations, but will have no impact on our overall financial position.

The specific impact of the adoption cannot be predicted at this time because it will depend on the level of share-based payments granted in the future. However, had the Company adopted SFAS 123(R) in prior periods, the impact would approximate the impact of SFAS 123 as described in Note 7. SFAS 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost to be reflected as a financing cash flow, rather than as

an operating cash flow as currently required. There were no excess tax deductions recognized during the first nine months of 2005 or 2004 in connection with the exercise of stock options.

In September 2004, the Securities and Exchange Commission adopted Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of SFAS No. 143 by companies following the full cost accounting method. SAB No. 106 indicates that estimated future dismantlement and abandonment costs that are recorded on the balance sheet are to be included in the costs subject to the full cost ceiling limitation. The estimated future cash outflows associated with settling the recorded asset retirement obligations should be excluded from the computation of the present value of estimated future net revenues used in applying the ceiling test. We began applying SAB No. 106 in the first quarter of 2005.

Note 6 Equity

Other Comprehensive Income and Derivative Instruments

The following table presents a recap of the Company’s comprehensive income for the three- and nine-month periods ended September 30, 2005 and 2004 (in thousands):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Net income	$	5,045		$	3,940		$	13,097		$	11,349
Change in fair value of derivative instruments, accounted for as hedges, net of taxes		(13,038	)		(2,631	)		(14,610	)		(5,748	)

Comprehensive income (loss)	$	(7,993	)	$	1,309		$	(1,513	)	$	5,601

For the three months ended September 30, 2005 and 2004, the effect of derivative instruments is net of deferred income tax benefit of $7,021,000 and $1,417,000, respectively. For the nine months ended September 30, 2005 and 2004, the effect of derivative instruments is net of deferred income tax benefit of $7,867,000 and $3,095,000, respectively.

The Company accounts for derivatives in accordance with SFAS 133, as amended. When the conditions 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 to Other Comprehensive Income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the expected event does not occur, or the hedge does not qualify for hedge accounting treatment, changes in the fair value of the derivative are recorded on the income statement.

Oil and gas sales include reductions related to gas hedges of $1,563,000 and $119,000 and oil hedges of $1,688,000 and $1,295,000 for the three months ended September 30, 2005 and 2004, respectively. Oil and gas sales include reductions related to gas hedges of $2,641,000 and $486,000 and oil hedges of $4,029,000 and $2,468,000 for the nine months ended September 30, 2005 and 2004, respectively. In addition, during the second quarter of 2004, the Company recognized $2,000 in derivative expense related to an interest rate swap that did not qualify for hedge accounting treatment. This contract expired in November 2004.

As of September 30, 2005, 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:
2005	Swap	10,750 Mmbtu	$	6.04
Fourth Quarter 2005	Costless Collar	10,500 Mmbtu	$	5.36 - 10.66
2006	Swap	5,500 Mmbtu	$	4.33
January — June 2006	Costless Collar	6,500 Mmbtu	$	5.42 - 10.46
July — December 2006	Costless Collar	4,000 Mmbtu	$	6.00 - 11.21

Crude Oil:
Fourth Quarter 2005	Costless Collar	900 Bbls	$	32.78 - 48.04
First Quarter 2006	Costless Collar	600 Bbls	$	37.67 - 57.37
April — December 2006	Costless Collar	200 Bbls	$	23.00-26.40

At September 30, 2005, the Company recognized a liability of $35.1 million representing the estimated fair value of these derivative instruments. The Company expects to reclassify approximately $19.7 million of deferred losses, net of taxes, on derivatives from accumulated comprehensive loss to oil and gas sales during the next 12 months. These losses are expected to be reclassified as the oil and gas volumes underlying the derivative contracts are produced and sold. At September 30, 2005, the Company’s derivative instruments were considered effective cash flow hedges.

Note 7 Stock Based Compensation

The Company accounts for its stock-based compensation plans under the principles prescribed by the Accounting Principles Board’s Opinion No. 25, “Accounting for Stock Issued to Employees.”

The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123 pursuant to the disclosure requirements of SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” (in thousands, except per share data):


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Net income	$	5,045		$	3,940		$	13,097		$	11,349
Stock-based compensation:
Add expense included in reported results, net of tax		—			—			22			177
Deduct fair value based method, net of tax		(155	)		(247	)		(486	)		(917	)

Pro forma net income	$	4,890		$	3,693		$	12,633		$	10,609


Earnings per common share:
Basic — as reported	$	0.11		$	0.09		$	0.28		$	0.25
Basic — pro forma	$	0.10		$	0.08		$	0.27		$	0.24
Diluted — as reported	$	0.10		$	0.08		$	0.27		$	0.25
Diluted — pro forma	$	0.10		$	0.08		$	0.26		$	0.23

Note 8 Acquisitions

On April 12, 2005, the Company acquired all of the outstanding membership interests of TDC Energy Inc. (“TDC”) an oil and gas exploration company with 12 producing fields and 19 wells in the Gulf of Mexico shelf. TDC’s oil and gas properties had an estimated 10.5 Bcfe of proved reserves (80% natural gas) as of December 31, 2004. Consideration for the acquisition included cash, our common stock and the repayment of approximately $11.5 million in net debt associated with TDC’s operations.

On May 11, 2005, the Company closed two of four purchase and sale agreements relating to gas properties and gas gathering systems located in Oklahoma for an aggregate purchase price of $5.9 million. On July 1, 2005, the remaining two purchase and sale agreements were closed for an adjusted purchase price of $23.2 million. On July 13, 2005, the Company acquired additional working interests in producing properties located in Oklahoma. This acquisition increased interests that were previously acquired by a proportionate 20% for an adjusted purchase price of approximately $3.6 million. Approximately $12 million of the combined purchase price of these assets was allocated to unevaluated property.


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 with operations in the Gulf Coast Basin, Texas and Oklahoma. We seek to increase our proved reserves, production, cash flow and earnings at low finding and development costs through a balanced mix of exploration, development and acquisition activities. We were successful in 2004 in improving our operating and financial results compared to the prior year. From 2003 to 2004, we increased proved reserves by 22%, production by 47%, cash flow from operating activities by 106% and net income by 349%.

From the commencement of our operations in 1985 through 2002, we focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow Gulf of Mexico shelf. Beginning in 2003, we began diversifying our reserves and production with longer life onshore properties in Texas and Oklahoma, and we enhanced our risk management policies by reducing our average working interest in projects, shifting capital to higher probability onshore wells and reducing the risks associated with individual wells by expanding our drilling program. In particular, in 2003 we acquired properties in the Southeast Carthage Field in East Texas with 29 Bcfe of proved reserves. In 2004, we entered the Arkoma Basin in Oklahoma by building an acreage position, drilling wells and acquiring 10.5 Bcfe of proved reserves. During 2005 we increased our presence in the Arkoma Basin in Oklahoma through multiple acquisition transactions. To complement these transactions, we added personnel with expertise and knowledge specific to these regions dedicated to evaluating and exploiting these properties. At September 30, 2005, approximately 51% of our estimated proved reserves were located outside of the Gulf Coast Basin, as compared to 45% at December 31, 2004.

Recent Events

On May 11, 2005, we issued $125 million in principal amount of 10 3/8% Senior Notes due 2012 at 98.783% of their face value. On June 17, 2005, we issued an additional $25 million in principal amount of 10 3/8% Senior Notes due 2012 at 99% of their face value. Collectively, the issuances of 10 3/8% notes are referred to herein as “the Notes.” Net proceeds from the issuance of the Notes totaled $144.4 million and were used to repay all of our debt outstanding under the credit facilities, to fund acquisitions of assets in Oklahoma and to provide capital for future acquisitions and general corporate purposes.

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 relate to unevaluated leasehold acreage and delay rentals, exploratory wells in progress, 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 and dismantlement, restoration and abandonment costs, net of estimated salvage values. 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 the 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. Declines in prices or reserves could result in a future write-down of oil and gas properties.

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

Future Abandonment Costs

Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology 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 consultants 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 to Other Comprehensive Income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the expected event does not occur, or the hedge does not qualify for hedge accounting treatment, changes in the fair value of the derivative are recorded on the income statement.

Our hedges are specifically referenced to the NYMEX index prices we receive for our Gulf Coast Basin production. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, we analyze the correlation between NYMEX index prices and the posted prices we receive from our Gulf Coast Basin production. Through this analysis, we are able to determine if a high correlation exists between the prices received for our Gulf Coast Basin production and the NYMEX prices at which the hedges will be settled. At September 30, 2005, 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 choose to 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 a literal market value, or what they would be willing to settle such contracts for as of the given date.

Results of Operations

The following table (unaudited) sets forth certain operating information with respect to our oil and gas operations for the periods noted:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Production:
Oil (Bbls)		138,013		218,906		536,568		643,437
Gas (Mcf)		3,046,211		2,481,218		8,547,834		6,803,269
Total Production (Mcfe)		3,874,289		3,794,654		11,767,242		10,663,891

Sales:
Total oil sales	$	6,711,423	$	8,013,842	$	24,331,122	$	22,324,568
Total gas sales		24,147,980		14,502,074		58,176,498		39,759,829

Average sales prices:
Oil (per Bbl)	$	48.63	$	36.61	$	45.35	$	34.70
Gas (per Mcf)		7.93		5.84		6.81		5.84
Per Mcfe		7.97		5.93		7.01		5.82

The above sales and average sales prices include reductions related to gas hedges of $1,563,000 and $119,000 and oil hedges of $1,688,000 and $1,295,000 for the three months ended September 30, 2005 and 2004, respectively. The above sales and average sales prices include reductions related to gas hedges of $2,641,000 and $486,000 and oil hedges of $4,029,000 and $2,468,000 for the nine months ended September 30, 2005 and 2004, respectively.

Net income totaled $5,045,000 and $3,940,000 for the quarters ended September 30, 2005 and 2004, respectively. Net income totaled $13,097,000 and $11,349,000 for the nine months ended September 30, 2005 and 2004, respectively. The results are attributable to the following components:

Production. Oil production in 2005 declined 37% and 17% from the quarter and nine months ended September 30, 2004, respectively. Natural gas production in 2005 increased 23% and 26% over the quarter and nine months ended September 30, 2004, respectively. On an Mcfe basis, production for the quarter and nine months ended September

30, 2005 increased 2% and 10% over the respective 2004 periods. During the first nine months of 2005, 73% of our total production was natural gas as compared to 64% during the 2004 period. This shift towards natural gas is the result of our expanded operations in Texas and Oklahoma where the production is primarily natural gas.

The increase in current year production compared to 2004 was due to our recent acquisitions and the success of our expanded drilling program. Offsetting our production gains were the shut-in of all of our Gulf Coast Basin fields for a portion of the third quarter of 2005 as a result of Hurricanes Katrina and Rita and the continued shut-in of our Main Pass 74 field due to third-party pipeline damage from Hurricane Ivan in 2004. Our production during the fourth quarter of 2005 will be negatively impacted by hurricane damage to third-party downstream assets.

Prices. Including the effects of our hedges, average oil prices per barrel for the quarter and nine months ended September 30, 2005 were $48.63 and $45.35, as compared to $36.61 and $34.70, respectively, for the same periods in 2004. Average gas prices per Mcf were $7.93 and $6.81 for the quarter and nine months ended September 30, 2005, respectively, as compared to $5.84 for both the quarter and nine month periods in 2004. Stated on an Mcfe basis, unit prices received during the quarter and nine months ended September 30, 2005 were 34% and 20% higher, respectively, than the prices received during the comparable 2004 periods.

During the third quarter of 2005, our hedges reduced the average prices we received for gas by $0.51 per Mcfe and for oil by $12.23 per barrel. For the first nine months of 2005, our hedges reduced our average realized prices by $0.31 per Mcfe and $7.50 per barrel. Hedges reduced our average realized prices by $0.05 per Mcfe and $5.91 per barrel during the third quarter of 2004 and by $0.07 per Mcfe and $3.84 per barrel for the nine-month period of 2004.

Revenue. Oil and gas sales during the quarter and nine months ended September 30, 2005 increased to $30,859,000 and $82,508,000 as compared to sales of $22,516,000 and $62,084,000, respectively, during the 2004 periods. The increase in revenue was the result of higher production volumes and average realized commodity prices during the 2005 periods.

Interest and other income for the quarter and nine months ended September 30, 2005 totaled $522,000 and $895,000, respectively, as compared to $56,000 and $187,000 during the 2004 periods. The increase in 2005 periods is primarily due to interest income earned on remaining cash proceeds from the Notes.

Expenses. Lease operating expenses for the quarter and nine months ended September 30, 2005 increased to $6,601,000 and $15,448,000 as compared to $4,087,000 and $9,593,000, respectively, for the same periods in 2004. On an Mcfe basis, lease operating expenses for the quarter and nine months ended September 30, 2005 totaled $1.70 and $1.31 as compared to $1.08 and $0.90, respectively, for the 2004 periods.

Lease operating costs during the third quarter of 2005 included approximately $700,000 of costs associated with well workovers and platform painting and approximately $64,000 of minor repair work from Hurricane Katrina. Overall, operating costs during 2005 were higher due to an increase in the number of producing wells we participate in and higher oil field service costs, such as labor, transportation and materials. We expect to incur increased operating costs during the fourth quarter of 2005 as we repair minor damages sustained during the recent hurricanes. Our insurance coverage provides for a $275,000 deductible to be met for each named storm.

Production taxes totaled $1,081,000 and $2,217,000 during the quarter and nine months ended September 30, 2005, respectively, as compared to $300,000 and $1,164,000 during the 2004 periods. The increase is primarily due to increased commodity prices, increased production from our Oklahoma and onshore Texas properties and an increase in the Louisiana severance tax rate effective July 1, 2005.

General and administrative expenses during the quarter and nine months ended September 30, 2005 totaled $1,571,000 and $5,079,000 as compared to $1,589,000 and $4,716,000, respectively, during the 2004 periods. The Company capitalized $1,161,000 and $3,464,000 of general and administrative costs during the quarter and nine months ended September 30, 2005 as compared to $1,210,000 and $3,449,000, respectively, in the comparable 2004 periods.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the quarter and nine months ended September 30, 2005 totaled $10,025,000, or $2.59 per Mcfe, and $29,811,000 or $2.53 per Mcfe. DD&A expense on oil and gas properties for the respective 2004 periods totaled $9,567,000, or $2.52 per Mcfe, and $26,434,000, or $2.48 per Mcfe. The increase in our DD&A expense per Mcfe is primarily due to increased costs to

drill for, develop and acquire oil and gas reserves. As a result of the supply and demand imbalance of oil and gas properties, equipment and services caused by high commodity prices, relative to historical averages, we expect this trend to continue.

Interest expense, net of amounts capitalized on unevaluated properties, increased to $3,456,000 and $9,141,000, respectively, during the quarter and nine months ended September 30, 2005 as compared to $622,000 and $1,968,000 during the same periods in 2004. The increase in interest expense is the result of higher debt levels associated with the Notes, as well as a charge during 2005 of $2,439,000 related to previously deferred financing costs which were written off in connection with the repayment of amounts outstanding under our credit facilities. We capitalized $924,000 and $235,000 of interest during the quarters ended September 30, 2005 and 2004, respectively. We capitalized $1,676,000 and $619,000 of interest during the nine months ended September 30, 2005 and 2004, respectively. Capitalized interest for the 2005 periods increased because of higher interest payments associated with our increased debt, as well as the growth in our unevaluated oil and gas properties, which was primarily the result of 2005 acquisitions and exploratory wells in progress at September 30, 2005. As a result of higher debt levels associated with the Notes, we expect interest expense for the remainder of 2005 to exceed amounts recognized during 2004.

Income tax expense of $2,718,000 and $7,053,000 was recognized during the quarter and nine months ended September 30, 2005, respectively, as compared to $2,121,000 and $6,094,000 during the same periods of 2004. The change is the result of fluctuations in the operating profit during the current year. We provide for income taxes at a statutory rate of 35%.

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 common stock and debt securities and sales of properties.

Source of Capital: Operations

Net cash flow from operations increased from $49,472,000 during the nine months ended September 30, 2004 to $63,377,000 for the same period in 2005. This increase resulted primarily from the increased production and realized commodity prices during the current year.

At September 30, 2005, we had a working capital deficit of $24,295,000 versus a deficit of $24,429,000 at December 31, 2004. The increase in our current assets at September 30, 2005 was primarily due to an increased cash position from the remaining net proceeds received from the issuance of the Notes. The increase in current assets was offset by an increase in our current liabilities, primarily due to an increase in the current portion of the estimated fair value of our derivative instruments, a result of higher estimated future commodity prices, and an accrual for the November 2005 interest payment on the Notes. In general, our accounts receivable and accounts payable at September 30, 2005 increased as a result of higher capital expenditures, production and commodity prices realized during 2005. We believe that our working capital balance should be viewed in conjunction with availability of borrowings under our bank credit facility when measuring liquidity.

Source of Capital: Debt

After payment of expenses and the initial purchasers’ discounts, we received $144.4 million in net proceeds from the issuance of the Notes. Net proceeds were used to repay all outstanding borrowings under our credit facilities, to fund acquisitions and to provide capital for future acquisitions and general corporate purposes. The Notes are redeemable at our option beginning on May 15, 2009 at 105.188% of their principal amount and thereafter declining annually to 100% on and after May 15, 2011. In addition, before May 15, 2008, we may redeem up to 35% of the aggregate principal amount of the Notes issued with net proceeds from an equity offering at 110.375%. The Notes provide for certain covenants, which include, without limitation, 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, 2005, $6 million had been accrued in connection with the November 15, 2005 interest payment. As of September 30, 2005, we were in compliance with all of the covenants under the Notes.

We entered into a bank credit facility on May 14, 2003. Pursuant to the credit facility agreement, PetroQuest and our subsidiary PetroQuest Energy, L.L.C. (the “Borrower”) have a $75 million revolving credit facility that permits us to borrow amounts from time to time based on the available borrowing base as determined in the bank credit facility. The bank credit facility is secured by a mortgage on substantially all of the Borrower’s oil and gas properties, a pledge of the membership interest of the Borrower and PetroQuest’s corporate guarantee of the indebtedness of the Borrower. The borrowing base under the bank credit facility is based upon the valuation as of April 1 and October 1 of each year of the Borrower’s mortgaged properties, projected oil and gas prices, and any other factors deemed relevant by the lenders. We, or the lenders, may request additional borrowing base re-determinations.

During the second quarter of 2005, we repaid all outstanding borrowings under the credit facility with proceeds received from the issuance of the Notes. In connection with the issuance of the Notes, the credit facility was amended and as of September 30, 2005, the borrowing base under the bank credit facility was $25 million.

Outstanding balances on the revolving credit facility bear interest at either the prime rate of the bank serving as agent under the facility plus a margin (based on a sliding scale of 0.75% to 1.25% based on borrowing base usage but never less than the Federal Funds Effective Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a sliding scale of 2.0% to 2.5% depending on borrowing base usage). The bank credit facility also allows us to use up to $5 million of the borrowing base for letters of credit for fees equal to the applicable margin rate for Eurodollar advances. There were no letters of credit outstanding at September 30, 2005. The bank credit facility matures on May 14, 2006.

We are subject to certain restrictive financial and non-financial covenants under the bank credit facility including a minimum current ratio of 1.0 to 1.0, all as defined in the credit facility agreement. The bank credit facility also requires the Borrower to establish and maintain commodity hedges covering at least 50% of its proved developed producing reserves on a rolling twelve-month basis. As of September 30, 2005, we were in compliance with all of the covenants in the bank credit facility.

On November 6, 2003, we obtained a $20 million second lien term credit facility from Macquarie Americas Corp., which was subsequently assigned to Macquarie Bank Limited (“MBL”). On May 11, 2005, we repaid the $12 million of total borrowings outstanding with proceeds from the Notes and terminated this facility. After termination of this facility, however, certain oil and gas hedging contracts with MBL as the counterparty remained in place and are secured by a second mortgage on substantially all of the oil and gas properties of PetroQuest Energy, L.L.C. until the hedges expire or are terminated.

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. Reduced cash flow may also make it difficult to incur debt, other than under our bank credit facility, because of the restrictive covenants in the indenture for the Notes. Although we do not anticipate debt covenant violations, our ability to comply with 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: Issuance of Equity Securities

During April 2005, we issued 646,226 shares of our common stock in connection with our acquisition of TDC Energy, Inc.

We have an effective universal shelf registration statement relating to the potential public offer and sale by PetroQuest of any combination of debt securities, common stock, preferred stock, depositary shares, and warrants from time to time or when financing needs arise. The registration statement does not provide assurance that we will or could sell any such securities.

Use of Capital: Exploration and Development

Our exploration and development budget for the fourth quarter of 2005 is approximately $50 million, excluding acquisitions, capitalized interest and general and administrative costs. Through September 30, 2005, capital expenditures excluding acquisitions, capitalized interest and general and administrative costs totaled approximately $78 million.

Based upon our outlook on commodity prices and production, we believe that cash on hand, cash flow from operations and borrowings available under our credit facility will be sufficient to fund the remainder of our planned 2005 exploration and development activities. In the future, our exploration and development activities could require additional financings, which may include sales of additional equity or debt securities, additional bank borrowings, sales of properties, or joint venture arrangements with industry partners. 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 delay 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

We do not budget for acquisitions; however, we are continually evaluating opportunities that fit our specific acquisition profile. We expect to fund future acquisitions primarily with cash on hand, cash flow from operations and borrowings under our credit facility, but we 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.

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 the Company’s estimate of the sufficiency of its existing capital sources, its 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 and in projecting future rates of production, the timing of development expenditures and drilling of wells, 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 the 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

Historically, we have experienced market risks primarily in two areas: commodity prices and interest rates. We believe that our business operations are not exposed to significant market risks relating to foreign currency exchange risk because all of our operations are conducted within the United States.

Our revenues are derived from the sale of our crude oil and natural gas production. Based on projected annual sales volumes for the fourth quarter of 2005, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $3.3 million impact on our revenues, inclusive of hedging.

In a typical hedge transaction, we will have the right to receive from the counterparts 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 counterparts this difference multiplied by the

quantity hedged. 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.

As of September 30, 2005, 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:
2005	Swap	10,750 Mmbtu	$	6.04
Fourth Quarter 2005	Costless Collar	10,500 Mmbtu	$	5.36-10.66
2006	Swap	5,500 Mmbtu	$	4.33
January — June 2006	Costless Collar	6,500 Mmbtu	$	5.42-10.46
July — December 2006	Costless Collar	4,000 Mmbtu	$	6.00-11.21

Crude Oil:
Fourth Quarter 2005	Costless Collar	900 Bbls	$	32.78-48.04
First Quarter 2006	Costless Collar	600 Bbls	$	37.67-57.37
April — December 2006	Costless Collar	200 Bbls	$	23.00-26.40

At September 30, 2005, the Company recognized a liability of $35.1 million representing the estimated fair value of these derivative instruments. In addition, during the third quarter of 2004, we recognized $2,000 of derivative expense related to an interest rate swap that did not qualify for hedge accounting treatment. This contract expired in November 2004.

During the second quarter of 2005, we repaid all of our variable rate bank debt using proceeds from the issuance of fixed rate senior notes. Because 100% of our debt outstanding at September 30, 2005 was subject to a fixed rate, we did not have any exposure to rising interest rates at September 30, 2005.

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, carried out 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 the following:

	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.


			Page No.
Part I.	Financial Information

	Item 1.	Financial Statements

		Consolidated Balance Sheets as of
		September 30, 2005 and December 31, 2004		1

		Consolidated Statements of Income for the
		Three and Nine Months Ended September 30, 2005 and 2004		2

		Consolidated Statements of Cash Flows for the
		Nine Months Ended September 30, 2005 and 2004		3

		Notes to Consolidated Financial Statements		4

	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		10

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		16

	Item 4.	Controls and Procedures		17

Part II.	Other Information

	Item 1.	Legal Proceedings		18

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		18

	Item 3.	Defaults upon Senior Securities		18

	Item 4.	Submission of Matters to a Vote of Security Holders		18

	Item 5.	Other Information		18

	Item 6.	Exhibits		18
Certification of CEO pursuant to Rule 13a-14a/15d-14a
Certification of CFO pursuant to Rule 13a-14a/15d-14a
Certification Pursuant to Section 906
Certification Pursuant to Section 906


	PETROQUEST ENERGY, INC.

Date: October 28, 2005	By:	/s/ Michael O. Aldridge

		Michael O. Aldridge
		Senior Vice President, Chief
		Financial Officer and Treasurer
		(Authorized Officer and Principal
		Financial and Accounting Officer)


/s/ Charles T. Goodson
Charles T. Goodson
Chief Executive Officer
October 28, 2005


/s/ Michael O. Aldridge
Michael O. Aldridge
Chief Financial Officer
October 28, 2005


/s/Charles T. Goodson
Charles T. Goodson
Chief Executive Officer
October 28, 2005

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1.		I have reviewed this Form 10-Q of PetroQuest Energy, Inc.;

2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.		The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


*		Filed herewith


*		Filed herewith