UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

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

For the quarterly period ended: September 30, 2004

     For the transition period from:           to:

PETROQUEST ENERGY, INC.

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 [X]      No [  ]

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

Yes [X]      No [  ]

     As of October 25, 2004, there were 44,685,363 shares of the registrant’s common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.

Table of Contents

PETROQUEST ENERGY, INC.

See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

     See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

Note 1 Basis of Presentation

     The consolidated financial information for the three- and nine-month periods ended September 30, 2004 and 2003, respectively, have been prepared by the Company and were not audited by its independent 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, 2004 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, 2003 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 financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.

     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) and PetroQuest Oil & Gas, L.L.C. (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 considered dilutive computed using the treasury stock method.

     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 anti-dilutive options’ exercise prices were between $4.95-$7.65 for the third quarter of 2004 and $3.75-$7.65 for the nine month 2004 period and expire in 2010-2013. Options to purchase 1,197,002 shares of common stock were outstanding during the three- and nine-month periods ended September 30, 2003, 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 anti-dilutive options’ exercise prices were between $2.18-$7.65, respectively, and expire in 2010-2013.

Note 3 Long-Term Debt

     The Company 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 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 re-determinations.

     As of September 30, 2004, the borrowing base under the bank credit facility was $25 million and was subject to monthly reductions of $1.5 million commencing November 1, 2004. At September 30, 2004, the Company had $9 million of borrowings and no letters of credit issued pursuant to the bank credit facility. During October 2004, the Company and the lenders amended the bank credit facility agreement increasing the borrowing base to $38 million and delaying the $1.5 million per month reduction in borrowing base capacity from November to

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December 2004 (see Note 7). The borrowing base reduction increases to $2 million per month for the months of February, March and April 2005. The lenders will determine future monthly reductions in connection with each borrowing base re-determination.

     Outstanding balances on the revolving credit facility bear interest at either the bank’s prime rate 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.

     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, 2004, the Company was in compliance with all of the covenants in the bank credit facility. The bank credit facility matures on May 14, 2006.

     On November 6, 2003, the Company obtained a $20 million subordinated term credit facility from Macquarie Americas Corp. (“Macquarie”). The sub-debt facility carries an interest rate of prime plus 5.5%, is secured by a second mortgage on substantially all of the Company’s oil and gas properties and matures on November 30, 2006. The sub-debt facility is available for advances at any time until December 31, 2004, subject to the restrictive covenants of the sub-debt facility and Macquarie approval. At closing, Macquarie received warrants to purchase 1,250,000 shares of our common stock at an exercise price of $2.30 per share. When cumulative advances under the facility exceeded $5 million, $10 million and $15 million, Macquarie was to receive warrants to purchase an additional 250,000 shares, 500,000 shares and 250,000 shares of our common stock, respectively, at the same exercise price per share. In conjunction with the December 23, 2003 property acquisition, the sub-debt facility was amended and the original warrant was cancelled and reissued at which time all 2,250,000 warrants were issued to Macquarie. The warrants are exercisable at any time through the earlier of 36 months following the repayment in full of the sub-debt facility or 30 days after daily volume weighted average price of our common stock as published by Nasdaq is equal to or greater than, for a period of 30 days, the exercise price multiplied by three. In addition, the Company granted Macquarie piggy-back registration rights with respect to the shares of common stock issuable upon exercise of the warrants. During January 2004, the sub-debt facility, including the note, liens, warrants and all other rights of Macquarie thereunder, was assigned to Macquarie Bank Limited, an affiliate of Macquarie Americas Corp.

     As of September 30, 2004, the Company had $12 million borrowed under the sub-debt facility, which was primarily used to fund the acquisition of properties in the Southeast Carthage Field. The sub-debt facility contains certain restrictive financial and non-financial covenants, including a minimum current ratio of 1.0 to 1.0, a total debt threshold of $45 million and a cumulative minimum production and net operating cash flow threshold, all as defined in the sub-debt facility. During October 2004, the Company amended the sub-debt facility increasing the debt threshold covenant from $45 million to $60 million. The sub-debt facility also requires the Company to establish and maintain commodity hedges covering at least 65% of its proved developed producing reserves through November 2006. As of September 30, 2004, the Company was in compliance with all of the covenants in the sub-debt facility.

Note 4 New Accounting Standards

     In June 2001, the Financial Accounting Standards Board 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 Company adopted SFAS 143 effective January 1, 2003. The net difference between the Company’s previously depleted abandonment costs and the amounts estimated under SFAS 143, after taxes, totaled a gain of

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$849,000, which was recognized as a cumulative effect of a change in accounting principle. The gain was due to the effect on the historical depletion as a result of the retirement obligation being recorded at fair value.

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

     In January 2003, the Financial Accounting Standards Board issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), which requires companies to evaluate variable interest entities to determine whether to apply the consolidation provisions of FIN 46 to those entities. The consolidation provisions of FIN 46, if applicable, would apply to variable interest entities created after January 31, 2003 immediately, and to variable interest entities created before February 1, 2003 in the Company’s interim period that began on October 1, 2003. The Company believes that it has no interests in these types of entities, and adopted this standard effective January 1, 2004 with no effect on the financial statements.

Note 5 Equity

Other Comprehensive Income and Derivative Instruments

     The following table presents the Company’s comprehensive income for the three- and nine-month periods ended September 30, 2004 and 2003 (in thousands):

     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. For the three months ended September 30, 2004 and 2003, the effect of derivative financial instruments is net of deferred income tax (benefit) expense of ($1,417,000) and $287,000, respectively. For the nine months ended September 30, 2004 and 2003, the effect of derivative financial instruments is net of deferred income tax (benefit) expense of ($3,095,000) and $536,000, respectively.

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     Oil and gas sales include reductions related to gas hedges of $119,000 and $171,000 and oil hedges of $1,295,000 and $412,000 for the three months ended September 30, 2004 and 2003, respectively. Oil and gas sales include reductions related to gas hedges of $486,000 and $2,440,000 and oil hedges of $2,468,000 and $1,423,000 for the nine months ended September 30, 2004 and 2003, respectively. The Company recognized $2,000 and ($586,000) in derivative expense (benefit) related to ineffective derivative instruments for the three months ended September 30, 2004 and 2003, respectively. The Company recognized $2,000 and $1,163,000 in derivative expense for the nine months ended September 30, 2004 and 2003, respectively, as a result of the settlement of ineffective derivatives.

     As of September 30, 2004, the Company had entered into the following oil and gas contracts accounted for as cash flow hedges:

     At September 30, 2004, the Company recognized a liability of $10,405,000 related to the estimated fair value of these derivative instruments.

     The Company currently has an interest rate swap covering $5 million of its floating rate debt. The swap, which expires in November 2004, has a fixed interest rate of 5.665%. The swap is stated at its estimated fair value and is marked-to-market through derivative expense on the income statement. As of September 30, 2004, the estimated fair value of the open interest rate swap was a liability of $49,000.

Note 6 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.”

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     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, “Accounting for Stock Based Compensation” pursuant to the disclosure requirements of SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure” (in thousands, except per share data):

Note 7 Subsequent Event

     During October 2004, the Company acquired interests in natural gas properties located in the Arkoma Basin of Oklahoma for approximately $13.5 million. The Company expects to allocate approximately $2 million of the purchase price to unevaluated acreage. The purchase was financed with borrowings under the Company’s bank credit facility, the borrowing base of which was increased from $25 million to $38 million (see Note 3).

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Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

     PetroQuest Energy, Inc. is an independent oil and gas company engaged in the exploration, development, acquisition and operation of oil and gas properties onshore and offshore in the Gulf Coast Region, East Texas and the Arkoma Basin of Oklahoma. The Company and its predecessors have been active in the Gulf Coast Region since 1986, which gives the Company extensive geophysical, technical and operational expertise in this area.

     The Company’s business strategy is to increase production, cash flow and reserves through a balanced mix of exploration, development and acquisition activities. During 2003, the Company began a process of diversifying its primarily Gulf Coast Region asset base in order to increase its exposure to longer life reserves and production. Approximately 39% of the Company’s proved reserves at September 30, 2004 were located outside of the Gulf Coast Region and for the nine months ended September 30, 2004, 14% of the Company’s production was derived from properties located outside of the Gulf Coast. At September 30, 2004, the Company operated approximately 60% of its proved reserves and production for the first nine months of 2004 was 36% oil and 64% natural gas.

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 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 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

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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. The accounting for future abandonment costs changed on January 1, 2003, with the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” See New Accounting Standards in the Notes to Consolidated Financial Statements for a further discussion of this accounting standard.

Reserve Estimates

     Our estimates of oil and gas reserves are, by necessity, 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 due to being highly effective 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, changes in the fair value of the derivative are recorded on the income statement.

     Estimating the fair values of hedging derivatives requires complex calculations incorporating estimates of future prices, discount rates and price movements. Instead, we choose to obtain the fair value of our commodity derivatives from the counter parties to those contracts. Since the counter parties 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.

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Results of Operations

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

The above sales and average sales prices include reductions to revenue related to gas hedge settlements of $119,000 and $171,000 and oil hedge settlements of $1,295,000 and $412,000 for the three months ended September 30, 2004 and 2003, respectively. The above sales and average sales prices include reductions to revenue from gas hedge settlements of $486,000 and $2,440,000 and oil hedge settlements of $2,468,000 and $1,423,000 for the nine months ended September 30, 2004 and 2003, respectively.

Net income totaled $3,940,000 and $229,000 for the quarters ended September 30, 2004 and 2003, respectively. Net income totaled $11,349,000 and $1,524,000 for the nine months ended September 30, 2004 and 2003, respectively. The increase in net income was primarily attributable to the following:

Production. Oil production in 2004 increased 32% and 10% from the quarter and nine months ended September 30, 2003, respectively. Natural gas production in 2004 increased 141% and 95% over the quarter and nine months ended September 30, 2003, respectively. On a Mcfe basis, production for the quarter and nine months ended September 30, 2004 increased 87% and 53% over the 2003 periods, respectively. The increase in production as compared to 2003 was the result of our current year drilling success and our acquisition of producing properties in the Southeast Carthage Field in December 2003.

Prices. Average oil prices per Bbl for the quarter and nine months ended September 30, 2004 were $36.61 and $34.70, as compared to $27.36 and $28.76, respectively, for the same periods in 2003. Average gas prices per Mcf were $5.84 for both the quarter and nine months ended September 30, 2004, as compared to $5.09 and $5.23, respectively, for the same periods in 2003. Stated on a Mcfe basis, unit prices received during the quarter and nine months ended September 30, 2004 were 23% and 16% higher, respectively, than the prices received during the comparable 2003 periods.

Revenue. Oil and gas sales during the quarter and nine months ended September 30, 2004 increased 130% to $22,516,000 and 77% to $62,084,000 as compared to sales of $9,800,000 and $35,014,000, respectively, for the 2003 periods. Higher production volumes and commodity prices generated the increased revenue during the 2004 periods.

Expenses. Lease operating expenses for the quarter and nine months ended September 30, 2004 increased to $4,087,000 and $9,593,000 as compared to $2,235,000 and $7,501,000, respectively, for the same periods in 2003. On a Mcfe basis, lease operating expenses for the three and nine month periods of 2004 totaled $1.08 and $0.90 as compared to $1.10 and $1.07, respectively, for the same periods during 2003. The per unit decreases are primarily due to the increased production from new fields with lower operating expenses and a higher percentage of gas production in the current year.

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General and administrative expenses during the third quarter and nine months ended September 30, 2004 totaled $1,589,000 and $4,716,000 as compared to expenses of $1,171,000 and $3,519,000, respectively, during the 2003 periods. The increases are primarily due to increased salaries, bonus accrual and compensation expense attributable to stock issued as long-term incentive compensation. The Company capitalized $1,210,000 and $3,449,000 of general and administrative costs during the quarter and nine months ended September 30, 2004 as compared to $974,000 and $2,869,000, respectively, in the 2003 periods.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the third quarter of 2004 totaled $2.52 per Mcfe as compared to $3.00 per Mcfe for the same period in 2003. The DD&A rate on oil and gas properties for the nine months ended September 30, 2004 was $2.48 per Mcfe compared to $2.89 per Mcfe for the respective 2003 period. The decrease from 2003 is due primarily to the acquisition of the Southeast Carthage Field during December 2003 at a lower per unit cost than our historical depletion rate and our drilling success during the current year.

Interest expense, net of amounts capitalized on unevaluated prospects, totaled $622,000 and $1,968,000, respectively, during the quarter and nine months ended September 30, 2004 as compared to $30,000 and $283,000 during the respective 2003 periods. The increase in interest costs is primarily due to borrowings made in December 2003 to fund the acquisition of properties in the Carthage Field. We capitalized $235,000 and $111,000 of interest during the quarters ended September 30, 2004 and 2003, respectively. We capitalized $619,000 and $343,000 of interest during the nine months ended September 30, 2004 and 2003, respectively.

Derivative expense (benefit) during the quarter and nine months ended September 30, 2004 totaled $2,000 as compared to ($586,000) and $1,163,000 during the comparable 2003 periods. These fluctuations are primarily due to the expiration of one of our interest rate swaps that was recorded as derivative expense. In addition, during 2003 we had one gas derivative marked-to-market on the income statement because the derivative was deemed ineffective.

Income tax expense of $2,121,000 and $6,094,000 was recognized during the quarter and nine months ended September 30, 2004, respectively, as compared to expense of $123,000 and $364,000 during the same periods of 2003. The change is a 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 exploration and development activities to date principally through cash flow from operations, bank borrowings, private and public offerings of common stock and sales of properties.

Source of Capital: Operations

Net cash flow from operating activities increased from $17,382,000 during the nine months ended September 30, 2003 to $49,472,000 for the same period in 2004. This increase resulted primarily from the increased production and realized commodity prices during the current year. Our working capital deficit at September 30, 2004 totaled ($25,577,000) versus a deficit of ($15,299,000) at December 31, 2003. The increased working capital deficit is the result of increased capital expenditures during 2004 and the corresponding timing of accounts payable related to exploration and development costs, as well as the increase in our hedging liability, which is the result of the increase in estimated future commodity prices. We believe that our working capital balance should be viewed in conjunction with availability of borrowings under our bank credit facilities when measuring liquidity.

Source of Capital: Debt

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-

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determinations. As of September 30, 2004, the borrowing base under the bank credit facility was $25 million and was subject to monthly reductions of $1.5 million commencing November 1, 2004.

At September 30, 2004, we had $9 million of borrowings and no letters of credit issued pursuant to the bank credit facility. During October 2004, the Company and the lenders amended the bank credit facility agreement increasing the borrowing base to $38 million and delaying the $1.5 million per month reduction in borrowing base capacity from November to December 2004. The borrowing base reduction increases to $2 million per month for the months of February, March and April 2005. In addition, during October 2004 the Company acquired interests in natural gas properties in Oklahoma for approximately $13.5 million. This acquisition was financed with proceeds from the recently increased borrowing base. The bank will determine future monthly reductions in connection with each borrowing base re-determination.

Outstanding balances on the revolving credit facility bear interest at either the bank’s prime rate 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.

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, 2004, we were in compliance with all of the covenants in the bank credit facility. The bank credit facility matures on May 14, 2006.

On November 6, 2003, we obtained a $20 million subordinated term credit facility from Macquarie. The sub-debt facility carries an interest rate of prime plus 5.5%, is secured by a second mortgage on substantially all of our oil and gas properties and matures November 30, 2006. The sub-debt facility is available for advances at any time until December 31, 2004, subject to the restrictive covenants of the sub-debt facility and Macquarie approval. At closing, Macquarie received warrants to purchase 1,250,000 shares of our common stock at an exercise price of $2.30 per share. When cumulative advances under the sub-debt facility exceeded $5 million, $10 million and $15 million, Macquarie was to receive warrants to purchase an additional 250,000 shares, 500,000 shares and 250,000 shares of our common stock, respectively, at the same exercise price per share. In conjunction with the December 23, 2003 property acquisition, the sub-debt facility was amended and the original warrant was cancelled and reissued at which time all 2,250,000 warrants were issued to Macquarie. The warrants are exercisable at any time through the earlier of 36 months following the repayment in full of the sub-debt facility or 30 days after daily volume weighted average price of our common stock as published by Nasdaq is equal to or greater than, for a period of 30 days, the exercise price multiplied by three. In addition, we granted Macquarie piggy-back registration rights with respect to the shares of common stock issuable upon exercise of the warrants. During January 2004, the sub-debt facility, including the note, liens, warrants and all other rights of Macquarie thereunder, was assigned to Macquarie Bank Limited, an affiliate of Macquarie Americas Corp.

As of September 30, 2004, we had $12 million borrowed under the sub-debt facility, which was primarily used to fund our acquisition of properties in the Southeast Carthage Field. The sub-debt facility contains certain restrictive financial and non-financial covenants, including a minimum current ratio of 1.0 to 1.0, a total debt threshold of $45 million and a cumulative minimum production and net operating cash flow threshold, all as defined in the sub-debt facility. During October 2004, the Company amended the sub-debt facility increasing the debt threshold covenant from $45 million to $60 million. The sub-debt facility also requires us to establish and maintain commodity hedges covering at least 65% of our proved developed producing reserves through November 2006. As of September 30, 2004, we were in compliance with all of the covenants in the sub-debt facility.

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. 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.

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Source of Capital: Issuance of Equity Securities

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 2004 will require significant capital. Our 2004 capital budget, excluding acquisitions, is approximately $60 million of which $41 million had been incurred by September 30, 2004. Acquisition costs during the first nine months of 2004 totaled approximately $4 million. Our capital budget has increased during 2004 as a result of higher production levels and commodity prices, which has increased our cash flow from operations from our original estimates.

We have recently completed the drilling of our Chianti and Shiraz prospects and six wells in our Oklahoma area, and are drilling our Jambalaya prospect and wells in our Oklahoma area and Southeast Carthage Field. In addition, during October 2004, we acquired additional interests in natural gas properties in Oklahoma for $13.5 million.

Our management believes that cash flows from operations and available bank borrowings will be sufficient to fund the remainder of our planned 2004 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.

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 Discussions 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. We believe that our business operations are not exposed to significant market risks relating to foreign currency exchange risk.

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Our revenues are derived from the sale of our crude oil and natural gas production. Based on projected sales volumes for the remaining three months of 2004, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $2 million impact on our revenues.

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, 2004, we had entered into the following oil and gas contracts accounted for as cash flow hedges:

At September 30, 2004, the Company recognized a liability of $10,405,000 related to these derivative instruments.

We currently have an interest rate swap covering $5 million of our floating rate debt. The swap, which expires in November 2004, has a fixed interest rate of 5.665%. The swap is stated at its estimated fair value and is marked-to-market through derivative expense in our income statement. As of September 30, 2004, the estimated fair value of the open interest rate swap was a liability of $49,000.

The Company also evaluated the potential effect that near term changes may have on the Company’s credit facilities. Debt outstanding under the credit facilities is subject to a floating interest rate and represents 100% of the Company’s total debt as of September 30, 2004. Based upon an analysis, utilizing the actual interest rate in effect and balances outstanding as of September 30, 2004 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 remaining three months of 2004 is approximately $38,000.

Item 4. CONTROLS AND PROCEDURES

As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective, in all material respects, with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Securities and Exchange Commission’s rules and forms, of information required to be disclosed by the issuer in the reports that it files or submits under the

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

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Part II

Item 1. LEGAL PROCEEDINGS

          NONE.

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

          NONE.

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 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 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 Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	PETROQUEST ENERGY, INC.
Date: October 29, 2004	By:	/s/ Michael O. Aldridge
		Michael O. Aldridge
		Senior Vice President, Chief Financial Officer and Treasurer (Authorized Officer and Principal Financial and Accounting Officer)

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EXHIBIT INDEX

          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 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 Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002