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: March 31, 2004
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.

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 April 30, 2004, there were 44,570,693 shares of the registrant’s common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.

Table of Contents

PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)

See accompanying Notes to Consolidated Financial Statements.

1

PETROQUEST ENERGY, INC.
Consolidated Statements of Operations
(unaudited)
(Amounts in Thousands, Except Per Share Data)

See accompanying Notes to Consolidated Financial Statements.

2

PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited)
(Amounts in Thousands)

See accompanying Notes to Consolidated Financial Statements.

3

PETROQUEST ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

Note 1 Basis of Presentation

     The consolidated financial information for the three-month periods ended March 31, 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 March 31, 2004 and for all reported periods. Results of operations for the interim periods presented are not necessarily indicative of the operating results for the full year or any future periods.

     The balance sheet at December 31, 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).

     Certain reclassifications of prior year amounts have been made to conform with the current year presentation.

Note 2 Earnings Per Share

     Basic earnings per common share was computed by dividing net income by the weighted average number of shares of common stock outstanding during the relevant periods. 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 607,834 shares of common stock were outstanding during the three-month period ended March 31, 2004, 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 $3.75-$7.65 and expire in 2010-2013. Options to purchase 1,325,587 shares of common stock were outstanding during the three-month period ended March 31, 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 period. These options’ exercise prices were between $3.13-$7.65 and expire in 2011-2012.

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 which permits the Borrower to borrow amounts from time to time based on its 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. As of March 31, 2004, the borrowing base under the bank credit facility was $21.2 million and is subject to monthly reductions of $1.25 million commencing July 1, 2004. At March 31, 2004, the Company had $14 milllion of borrowings and no letters of credit issued pursuant to the bank credit facility. The banks will determine future monthly reductions in connection with each borrowing base redetermination.

4

     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. At May 3, 2004, the Company had $13 million of borrowings and no letters of credit issued pursuant to the bank credit facility.

     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 March 31, 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.

     As of March 31, 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, as amended, 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. 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 March 31, 2004, the Company was in compliance with all of the covenants in the sub-debt facility.

     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.

Note 4 New Accounting Standards

     In June 2001, the Financial Accounting Standards Board issued 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 adopted SFAS 143 effective January 1, 2003. The net difference between the Company’s previously recorded abandonment liability and the amounts estimated under SFAS 143, after taxes, totaled a gain of $849,000, which has been recognized as a cumulative effect of a change in accounting principle. The gain is due to the effect on the historical depletion as a result of the retirement obligation being recorded at fair value.

     The Company has legal obligations to plug, abandon and dismantle existing wells and facilities that it has acquired and constructed during its existence.

5

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

     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.

Note 5 Equity

Other Comprehensive Income and Derivative Instruments

     The following table presents a recap of the Company’s comprehensive income for the three-month periods ended March 31, 2004 and 2003 (in thousands):

     The Company accounts for derivatives in accordance with Statement of Financial Accounting Standards No. 133, as amended (SFAS 133). When the conditions specified in SFAS 133 are met, the Company may designate these derivatives as hedges. For the three months ended March 31, 2004 and 2003, the effect of derivative financial instruments is net of deferred income tax benefit of $1,073,000 and $279,000, respectively.

     Oil and gas sales include reductions related to gas hedges of $10,000 and $1,644,000 and oil hedges of $436,000 and $725,000 for the three months ended March 31, 2004 and 2003, respectively. The Company recognized $59,000 and $35,000 in derivative expense for the three months ended March 31, 2004 and 2003, respectively, as a result of the settlement of derivatives.

6

     As of March 31, 2004, the Company had entered into the following oil and gas contracts accounted for as cash flow hedges:

     At March 31, 2004 the Company recognized a liability of $4,628,000 related to 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 fair value and is marked-to-market through derivative expense on the Company’s income statement. As of March 31, 2004, the fair value of the open interest rate swap was a liability of $169,000.

7

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.” 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. 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 Acquisition of Assets

     On December 23, 2003, the Company acquired an interest in the Southeast Carthage Field in East Texas for approximately $23.4 million. The Company allocated approximately $1.2 million of the purchase price to unevaluated acreage. At December 31, 2003, the Company’s independent reservoir engineering firm attributed 29 Bcfe of proved reserves net to the Company’s interest in this field.

8

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 and the East Texas area. The Company and its predecessors have been active in this area 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 exploration, development and acquisition of properties located in the Gulf Coast Region, as well as finding additional opportunities in areas with longer reserve lives. At March 31, 2004, the Company operated approximately 75% of all of its proved reserves. For the three months ended March 31, 2004, approximately 33% of the Company’s equivalent production was oil and 67% was 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 and 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, 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.

9

     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 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, the fair value of the derivative is 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.

10

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 related to gas hedges of $10,000 and $1,644,000 and oil hedges of $436,000 and $725,000 for the three months ended March 31, 2004 and 2003, respectively.

Net income totaled $3,172,000 and $2,993,000 for the quarters ended March 31, 2004 and 2003, respectively. The results are attributable to the following components:

Production. Oil production in 2004 decreased 24% from the first quarter ended March 31, 2003. Natural gas production in 2004 increased 35% over the first quarter ended March 31, 2003. On a Mcfe basis, production for the quarter ended March 31, 2004 increased 7% over the same period in 2003. The increase in current year production as compared to 2003 was due to our drilling success during the second half of 2003 as well as our acquisition of the Southeast Carthage Field in East Texas during December 2003.

Prices. The average oil price per Bbl for the quarter ended March 31, 2004 was $32.52, as compared to $30.81 for the same period in 2003. The average gas price per Mcf was $5.70 for the quarter ended March 31, 2004, as compared to $5.55 for the same period in 2003. Stated on a Mcfe basis, unit prices received during the first quarter ended March 31, 2004 were 5% higher than the prices received during the comparable 2003 period.

Revenue. Oil and gas sales during the first quarter ended March 31, 2004 increased to $18,133,000 as compared to sales of $16,154,000 for the same period in 2003. The increases in production volumes and average realized commodity prices resulted in the increase in revenue for the three months ended March 31, 2004.

Expenses. Lease operating expenses for the quarter ended March 31, 2004 decreased to $2,722,000 as compared to $2,762,000 for the same period in 2003. On a Mcfe basis, lease operating expenses for the quarter ended March 31, 2004 decreased to $0.84 as compared to $0.92 for the same period during 2003. The decrease is primarily due to the increased production that is primarily generated from newer fields with lower operating expenses and a higher percentage of gas production in the current year.

General and administrative expenses during the first quarter ended March 31, 2004 totaled $1,294,000 as compared to expenses of $1,223,000 during the 2003 period. The Company capitalized $993,000 of general and administrative costs during the quarter ended March 31, 2004 as compared to $978,000 in the comparable 2003 period. We have recognized $57,000 and $86,000 of non-cash compensation expense during the quarters ended March 31, 2004 and 2003, respectively.

Depreciation, depletion and amortization (“DD&A”) expense for the quarter ended March 31, 2004 decreased 6%, from the comparable 2003 period. On a Mcfe basis, which reflects the changes in production, the DD&A rate for the first quarter of 2004 was $2.46 per Mcfe as compared to $2.81 per Mcfe for the same period in 2003. The

11

decrease in 2004 as compared to 2003 is due primarily to the acquisition of the Southeast Carthage Field in East Texas during December 2003 and our drilling success over the last nine months.

Interest expense, net of amounts capitalized on unevaluated prospects, increased $658,000 during the first quarter ended March 31, 2004 as compared to the same period in 2003. The increase is the result of the sub-debt facility consummated during 2003, which has a higher effective interest rate than our historical borrowings. We capitalized $179,000 and $124,000 of interest during the three months ended March 31, 2004 and 2003, respectively.

Derivative expense decreased $26,000 during the first quarter ended March 31, 2004 as compared to the same period in 2003. This fluctuation is primarily due to the expiration of one of our interest rate swaps that was recorded as derivative expense.

Income tax expense of $1,708,000 was recognized during the quarter ended March 31, 2004, as compared to expense of $1,155,000 during the same period 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 operations increased from $6,688,000 during the three months ended March 31, 2003 to $10,220,000 for the same period in 2004. This increase resulted primarily from the increased production and realized commodity prices during the current year. The working capital deficit was reduced from $(15.3) million at December 31, 2003 to $(10.5) million at March 31, 2004. This decrease was caused primarily by all of our debt being currently classified as long-term whereas there was a current portion at December 31, 2003.

Source of Capital: Debt

We entered into a new 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 which permits us to borrow amounts from time to time based on our 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 also request additional borrowing base redeterminations. As of March 31, 2004, the borrowing base under the bank credit facility was $21.2 million and is subject to monthly reductions of $1.25 million commencing July 1, 2004. The bank will determine future monthly reductions in connection with each borrowing base redetermination.

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. At May 3, 2004, we had $13 million of borrowings and no letters of credit issued pursuant to the bank credit facility.

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 March 31, 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

12

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.

As of March 31, 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, as amended, 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. The sub-debt facility also requires us to establish and maintain commodity hedges covering at least 65% of its proved developed producing reserves through November 2006. As of March 31, 2004, we were in compliance with all of the covenants in the sub-debt facility.

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.

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.

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

We have an exploration and development program budget for the year 2004 that will require significant capital. Our capital budget for capital for new projects in 2004 is approximately $45-50 million of which $9 million had been incurred by March 31, 2004. We have completed the drilling of our Andouille, Eagle #2 and Tasso prospects and two wells in the Southeast Carthage Field, and will soon spud our Roux and Beignet prospects along with another well in the Southeast Carthage Field. Our management believes that cash flows from operations will be sufficient to fund 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,

13

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.

Our revenues are derived from the sale of our crude oil and natural gas production. Based on projected annual sales volumes for the remaining nine months of 2004, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $6 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 March 31, 2004, we had entered into the following oil and gas contracts accounted for as cash flow hedges:

At March 31, 2004, the Company recognized a liability of $4,628,000 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 fair value and is marked-to-market

14

through derivative expense in our income statement. As of March 31, 2004, the fair value of the open interest rate swap was a liability of $169,000.

The Company also evaluated the potential effect that reasonably possible 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 March 31, 2004. Based upon an analysis, utilizing the actual interest rate in effect and balances outstanding as of March 31, 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 nine months of 2004 is approximately $125,000.

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 (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 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.

15

Part II

NONE.

NONE.

NONE.

NONE.

NONE.

(a) 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

(b) Reports on Form 8-K:

On January 8, 2004, the Company filed a current report on Form 8-K regarding its drilling activities and fourth quarter 2003 production guidance.

On January 28, 2004, the Company filed a current report on Form 8-K regarding the addition of a director to its Board of Directors.

On February 19, 2004, the Company filed a current report on Form 8-K regarding its 2004 fourth quarter and year-end results.

16

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: May 7, 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)

17