UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark One)

For the quarterly period ended: March 31, 2005

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 þ No o

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

Yes þ No o

      As of May 2, 2005, there were 46,982,088 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.

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PETROQUEST ENERGY, INC.
Consolidated Statements of Income
(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.

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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, 2005 and 2004, 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, 2005 and for all reported periods. Certain reclassifications of prior year amounts have been made to conform to the current year presentation. Results of operations for the interim periods presented are not necessarily indicative of the operating results for the full year or any future periods.

      The balance sheet at December 31, 2004 has been derived from the audited financial statements at that date. Certain information and footnote disclosures normally included in financial statements prepared in accordance with 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, 2004.

      Unless the context otherwise indicates, any references in this Quarterly Report on Form 10-Q to “PetroQuest” or the “Company” refer to PetroQuest Energy, Inc. (Delaware) and its wholly-owned consolidated subsidiaries, PetroQuest Energy, L.L.C. (a single member Louisiana limited liability company), PetroQuest Oil & Gas, L.L.C. (a single member Louisiana limited liability company) and Pittrans, Inc. (an Oklahoma corporation).

Note 2 Earnings Per Share

      Basic earnings per common share are computed by dividing net income by the weighted average number of shares of common stock outstanding during the periods presented. Diluted earnings per common share is determined on a weighted average basis using common shares issued and outstanding adjusted for the effect of stock options and warrants considered dilutive computed using the treasury stock method. A reconciliation between basic and diluted shares outstanding (in thousands) is as follows:

      Options to purchase 90,000 and 607,834 shares of common stock were outstanding during the three month periods ended March 31, 2005 and 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 $6.64 — $7.65 for the first quarter of 2005 and expire in 2011-2015 and $3.75 — $7.65 for the three month 2004 period 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

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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 March 31, 2005, the borrowing base under the bank credit facility was $60 million with $39 million of borrowings and no letters of credit outstanding. In connection with our acquisition of TDC Energy LLC (see Note 8) on April 12, 2005, the borrowing base was increased to $67.5 million and was subject to monthly reductions of $2.5 million commencing in May 2005. After repayment of TDC’s indebtedness with borrowings under the bank credit facility, we had approximately $61 million of borrowings outstanding as of April 12, 2005.

      Outstanding balances on the revolving credit facility bear interest at either the prime rate of the bank serving as agent under the facility plus a margin (based on a sliding scale of 0.75% to 1.25% based on borrowing base usage but never less than the Federal Funds Effective Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a sliding scale of 2.0% to 2.5% depending on borrowing base usage). The bank credit facility also allows the Company to use up to $5 million of the borrowing base for letters of credit for fees equal to the applicable margin rate for Eurodollar advances.

      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, 2005, 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, we obtained a $20 million second lien term credit facility from Macquarie Americas Corp. The 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 facility is available for advances at any time until December 31, 2005, subject to the restrictive covenants of the 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.

      In conjunction with a December 2003 property acquisition, the second lien term facility was amended, the original warrants were cancelled and 2,250,000 warrants were issued to Macquarie. During January 2004, the 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. During February 2005, Macquarie exercised the outstanding warrants utilizing a cashless exercise provision resulting in the issuance of 1,506,466 shares.

      As of March 31, 2005, the Company had $12 million borrowed under the second lien facility. The facility was amended to increase the limit on total debt outstanding, including the bank credit facility, the second lien facility and negative working capital (excluding non-cash amounts with respect to derivatives and asset retirement obligations) to $80 million effective March 31, 2005, and $90 million, effective April 12, 2005. The facility contains certain restrictive financial and non-financial covenants, including a minimum current ratio of 1.0 to 1.0 and a cumulative minimum production and net operating cash flow threshold, all as defined in the facility. The 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, 2005, the Company was in compliance with all of the covenants in the second lien term facility.

Note 4 Asset Retirement Obligation

      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.

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

Note 5 New Accounting Standards

      On December 16, 2004, the Financial Accounting Standards Board issued SFAS 123 (revised 2004), “Share Based Payment,” which is a revision of SFAS 123, “Accounting for Stock-Based Compensation.” SFAS 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and amends SFAS 95, “Statement of Cash Flows.” Generally, the approach in SFAS 123(R) is similar to the approach in SFAS 123. However, SFAS 123(R) requires all share based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their estimated fair values. Pro forma disclosure is no longer an alternative. On April 21, 2005, the SEC issued an amendment to rule 4-01(a) of Regulation S-X regarding the compliance date for SFAS 123(R). This amendment changed the effective date to the first fiscal year beginning on or after June 15, 2005. Accordingly, we expect to adopt the standard January 1, 2006.

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

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

      The specific impact of the adoption cannot be predicted at this time because it will depend on the level of share-based payments granted in the future. However, had we adopted SFAS 123(R) in prior periods, the impact would approximate the impact of SFAS 123 as described in Note 7. SFAS 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost to be reflected as a financing cash flow, rather than as an operating cash flow as currently required. We did not recognize any excess tax deductions during the first quarters of 2005 or 2004 in connection with the exercise of stock options.

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

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      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 6 Equity

Other Comprehensive Income and Derivative Instruments

      The following table presents the Company’s comprehensive income for the three month periods ended March 31, 2005 and 2004 (in thousands):

      For the three months ended March 31, 2005 and 2004, the effect of derivative instruments is net of deferred income tax expense of $1,664,000 and $1,073,000, respectively.

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

      Oil and gas sales include reductions related to the settlement of gas hedges of $265,000 and $10,000 and oil hedges of $1,079,000 and $436,000 for the three months ended March 31, 2005 and 2004, respectively. In addition, during the first quarter of 2004 we recognized $9,000 of derivative expense related to an interest rate swap that did not qualify for hedge accounting treatment. This contract expired in November 2004.

      As of March 31, 2005, the Company had entered into the following oil and gas contracts accounted for as cash flow hedges:

      At March 31, 2005, the Company recognized a liability of $11.3 million related to the estimated fair value of these derivative instruments. At March 31, 2005, our derivative instruments were considered effective cash flow hedges. As a result, we do not expect that changes in the fair value of these hedges over the next 12 months will be reflected in our results of operations.

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Note 7 Stock Based Compensation

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

      The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provisions of SFAS No. 123, “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 8 Subsequent Events

      On April 12, 2005, we acquired all of the outstanding membership interests of TDC Energy LLC (“TDC”) an oil and gas exploration company with 12 producing fields and 19 wells in the Gulf of Mexico Shelf. TDC’s oil and gas properties had an estimated 10.5 Bcfe of proved reserves (80% natural gas) as of December 31, 2004, and consist of 84,000 acres with estimated first quarter 2005 production of approximately 8.5 MMcfe per day. Consideration for the acquisition totaled approximately $15.6 million including cash, our common stock and the repayment of approximately $11.5 million in net debt associated with TDC’s operations. In addition, we granted to the members of TDC a net profits interest in the oil and gas produced from the TDC properties; provided, however, that payment of the net profits interest does not commence until after the cumulative production from such properties after April 12, 2005 equals 10 Bcfe.

      On April 19 2005, we entered into four purchase and sale agreements to acquire various assets for an expected net purchase price of approximately $27 million. The assets are located primarily in Pittsburg and Haskell Counties in Oklahoma and include natural gas properties with approximately 6.7 Bcfe of proved reserves (61% proved developed producing and 100% natural gas) as of the effective dates of each of the agreements, and five natural gas gathering systems (representing over 50 total line miles). The assets also include over 8,900 acres of net leasehold in approximately 190 sections of land, and include approximately 400 existing wells with more than 250 identified development drilling locations. We expect to allocate approximately $11.0 million of the purchase price to unevaluated acreage.

      On May 9, 2005, we announced that we had priced a private placement of $125 million in aggregate principal amount of 10.375% Senior Notes due 2012. The notes were priced at 98.783% of their face value to yield 10.625%. The notes will be fully and unconditionally guaranteed by certain of our subsidiaries. We intend to use the net proceeds from the private placement to repay amounts under our existing credit facilities, to fund acquisitions and for general corporate purposes.

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Item 2.

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

Overview

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

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

Recent Events

      On April 12, 2005, we acquired all of the outstanding membership interests of TDC Energy LLC (“TDC”) an oil and gas exploration company with 12 producing fields and 19 wells in the Gulf of Mexico Shelf. TDC’s oil and gas properties had an estimated 10.5 Bcfe of proved reserves (80% natural gas) as of December 31, 2004, and consist of 84,000 acres with estimated first quarter 2005 production of approximately 8.5 MMcfe per day. Consideration for the acquisition totaled approximately $15.6 million including cash, our common stock and the repayment of approximately $11.5 million in net debt associated with TDC’s operations. In addition, we granted to the members of TDC a net profits interest in the oil and gas produced from the TDC properties; provided, however, that payment of the net profits interest does not commence until after the cumulative production from such properties after April 12, 2005 equals 10 Bcfe.

      On April 19, 2005, we entered into four purchase and sale agreements to acquire various assets for an expected net purchase price of approximately $27 million. The assets are located primarily in Pittsburg and Haskell Counties in Oklahoma and include natural gas properties with approximately 6.7 Bcfe of proved reserves (61% proved developed producing and 100% natural gas) as of the effective dates of each of the agreements, and five natural gas gathering systems (representing over 50 total line miles). The assets also include over 8,900 acres of net leasehold in approximately 190 sections of land, and include approximately 400 existing wells with more than 250 identified development drilling locations. We expect to allocate approximately $11.0 million of the purchase price to unevaluated acreage.

      On May 9, 2005, we announced that we had priced a private placement of $125 million in aggregate principal amount of 10.375% Senior Notes due 2012. The notes were priced at 98.783% of their face value to yield 10.625%. The notes will be fully and unconditionally guaranteed by certain of our subsidiaries. We intend to use the net proceeds from the private placement to repay amounts under our existing credit facilities, to fund acquisitions and for general corporate purposes.

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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 units-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 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

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adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” See Note 4 in the Notes to Consolidated Financial Statements for a further discussion of this accounting standard.

Reserve Estimates

      Our estimates of proved oil and gas reserves constitute quantities that we are reasonably certain of recovering in future years. These estimates, however, represent projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such oil and gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variance may be material.

Derivative Instruments

      The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. At inception, all of our commodity derivative instruments represent hedges of the price of future oil and gas production. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded to Other Comprehensive Income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the expected event does not occur, changes in the fair value of the derivative are recorded on the income statement.

      Our hedges are specifically referenced to the NYMEX index prices we receive for our Gulf Coast Basin production. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX index prices and the posted prices we receive from our Gulf Coast Basin production. Through this analysis, we are able to determine if a high correlation exists between the prices received for our Gulf Coast Basin production and the indexed prices at which the hedges will be settled. At March 31, 2005, our derivative instruments were considered effective cash flow hedges.

      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. These historical results are not necessarily indicative of results to be expected in future periods.

The above sales and average sales prices include reductions to revenue related to the settlement of gas hedges of $265,000 and $10,000 and oil hedge settlements of $1,079,000 and $436,000 for the three months ended March 31, 2005 and 2004, respectively.

Net income totaled $4,187,000 and $3,172,000 for the quarters ended March 31, 2005 and 2004, respectively. The increase in net income during the 2005 period was primarily attributable to the following:

Production. Oil production during the first quarter of 2005 increased 2% from the quarter ended March 31, 2004, while natural gas production in 2005 increased 4% from the first quarter of 2004. The increase in production as compared to 2004 was primarily the result of our 97% and 100% drilling success rates during 2004 and the first quarter of 2005, respectively, offset by normal production declines and continued downtime at our Main Pass 74 Field. We expect that production for the second quarter of 2005 will increase from first quarter 2005 levels due to continued drilling success and production from the acquisitions closed during April 2005.

Prices. Average oil prices per barrel for the first quarter of 2005 and 2004 were $43.40 and $32.52, respectively. Average gas prices per Mcf were $6.14 for the quarter ended March, 31, 2005, as compared to $5.70 for the 2004 period. Stated on an Mcfe basis, unit prices received during the quarter ended March 31, 2005 were 16% higher than the prices received during the comparable 2004 period.

Revenue. Oil and gas sales during the first quarter of 2005 increased 20% to $21,672,000 as compared to sales of $18,133,000 for the 2004 period. Higher commodity prices and production volumes generated the increased revenue during the 2005 period.

Expenses. Lease operating expenses for the 2005 quarter increased 43% to $3,882,000 as compared to $2,722,000 for the 2004 quarter. On an Mcfe basis, lease operating expenses for the three month period of 2005 totaled $1.16 as compared to $0.84 for the 2004 period. Operating costs were higher in the 2005 period due to the increase in the number of producing wells we participate in and higher oil field service costs. We expect this trend in increased operating expenses to continue into 2005.

Production taxes during the first quarter of 2005 totaled $374,000 as compared to $444,000 during the 2004 period. The decline in production taxes is the result of lower production rates from our onshore Louisiana properties during the current period.

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General and administrative expenses during the first quarter of 2005 totaled $1,689,000 as compared to expenses of $1,294,000 during the 2004 period. The increase is primarily due to a 14% increase in staffing since March 31, 2004 necessary to support our increased operational activity. The Company capitalized $1,100,000 and $993,000 of general and administrative costs during the quarters ended March 31, 2005 and 2004, respectively.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the first quarter of 2005 totaled $8,092,000 or $2.42 per Mcfe as compared to $7,843,000 or $2.43 per Mcfe for the same period in 2004.

Interest expense, net of amounts capitalized on unevaluated prospects, totaled $962,000 and $681,000 during the quarters ended March 31, 2005 and 2004, respectively. The increase in interest costs is primarily due to borrowings to finance the acquisition of properties during 2004. We capitalized $267,000 and $179,000 of interest during the quarters ended March 31, 2005 and 2004, respectively. We expect that our interest costs will be higher in the second quarter of 2005 due to borrowings to fund our April 2005 acquisitions.

Income tax expense totaled $2,254,000 and $1,708,000 during the quarters ended March 31, 2005 and 2004, respectively. 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 $10,454,000 during the first quarter of 2004 to $11,439,000 for the 2005 period. This increase resulted primarily from increased commodity prices and production during the 2005 quarter. Our working capital deficit at March 31, 2005 totaled ($26,391,000) versus a deficit of ($24,429,000) at December 31, 2004. 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-determinations.

As of March 31, 2005, the borrowing base under the bank credit facility was $60 million. In connection with our acquisition of TDC on April 12, 2005, the borrowing base was increased to $67.5 million and was subject to monthly reductions of $2.5 million commencing in May 2005.

At March 31, 2005, we had $39 million of borrowings and no letters of credit issued pursuant to the bank credit facility. After repayment of TDC’s indebtedness with borrowings under the bank credit facility, we had approximately $61 million of borrowings outstanding on April 12, 2005.

Outstanding balances on the revolving credit facility bear interest at either the prime rate of the bank serving as legal agent under the facility plus a margin (based on a sliding scale of 0.75% to 1.25% based on borrowing base usage but never less than the Federal Funds Effective Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a sliding scale of 2.0% to 2.5% depending on borrowing base usage). The bank credit facility also allows us to use up to $5 million of the borrowing base for letters of credit for fees equal to the applicable margin rate for Eurodollar advances.

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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, 2005, 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 second lien term credit facility from Macquarie. The second lien 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 facility is available for advances at any time until December 31, 2005, subject to the restrictive covenants of the 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.

In conjunction with a December 2003 property acquisition, the facility was amended, the original warrants were cancelled and 2,250,000 warrants were issued to Macquarie. During January 2004, the second lien 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. During February 2005, Macquarie exercised the outstanding warrants utilizing a cashless exercise provision resulting in the issuance of 1,506,466 shares.

As of March 31, 2005 we had $12 million borrowed under the second lien facility. The facility was amended to increase the limit on total debt outstanding, including the bank credit facility, the second lien facility and negative working capital (excluding non-cash amounts with respect to derivatives and asset retirement obligations) to $80 million effective March 31, 2005, and $90 million, effective April 12, 2005. The facility contains certain restrictive financial and non-financial covenants, including a minimum current ratio of 1.0 to 1.0 and a cumulative minimum production and net operating cash flow threshold, all as defined in the facility. The 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 March 31, 2005 we were in compliance with all of the covenants in the second lien term 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.

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 2005 will require significant capital. Our 2005 capital budget, excluding acquisitions, is $85 million to $95 million of which approximately $23 million had been incurred by March 31, 2005.

Based upon our outlook on commodity prices and production, we believe that cash flows from operations and available bank borrowings will be sufficient to fund the remainder of our planned 2005 exploration and development activities. In the future, our exploration and development activities could require additional financings, which may include sales of additional equity or debt securities, additional bank borrowings, sales of properties, or joint venture arrangements with industry partners. We cannot assure you that such additional financings will be available on acceptable terms, if at all. If we are unable to obtain additional financing, we could be forced to delay or even abandon some of our exploration and development opportunities or be forced to sell some of our assets on an untimely or unfavorable basis.

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Use of Capital: Acquisitions

We do not budget for acquisitions; however, we are continually evaluating opportunities that fit our specific acquisition profile. We expect to fund future acquisitions primarily with cash flow from operations and borrowings under our credit facilities, but may also issue additional equity or debt securities either directly or in connection with an acquisition. There can be no assurance that acquisition funds may be available on terms acceptable to us.

Disclosure Regarding Forward Looking Statements

This Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are the Company’s estimate of the sufficiency of its existing capital sources, its ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions and in projecting future rates of production, the timing of development expenditures and drilling of wells, and the operating hazards attendant to the oil and gas business. In particular, careful consideration should be given to cautionary statements made in the various reports the Company has filed with the Securities and Exchange Commission. The Company undertakes no duty to update or revise these forward-looking statements.

When used in the Form 10-Q, the words, “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Form 10-Q.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We experience market risks primarily in two areas: interest rates and commodity prices. Because our properties are located within the United States, we do not believe that our business operations are exposed to significant foreign currency exchange risks.

Our revenues are derived from the sale of our crude oil and natural gas production. Based on projected sales volumes for the remainder of 2005, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $13 million impact on our revenues.

In a typical hedge transaction, we will have the right to receive from the counterparties to the hedge, the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this difference multiplied by the quantity hedged. 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.

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As of March 31, 2005 we had entered into the following oil and gas contracts accounted for as cash flow hedges:

At March 31, 2005, the Company recognized a liability of $11.3 million related to the estimated fair value of these derivative instruments. In addition, during the first quarter of 2004, we recognized $9,000 of derivative expense related to an interest rate swap that did not qualify for hedge accounting treatment. This contract expired in November 2004.

Recent Hedging Activity:

      On April 1, 2005, we entered into the following oil and gas contracts accounted for as cash flow hedges:

      On April 12, 2005, in connection with our acquisition of TDC, we assumed the following gas hedging contracts which we expect to account for as cash flow hedges:

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 March 31, 2005. Based upon an analysis, utilizing the actual interest rate in effect and balances outstanding as of March 31, 2005 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 quarters of 2005 is approximately $300,000.

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Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

      As of the end of the period covered by this report, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, carried out an evaluation of the effectiveness of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded:

	i.	that the Company’s disclosure controls and procedures are designed to ensure (a) that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (b) that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure; and
	ii.	that the Company’s disclosure controls and procedures are effective.

Changes in Internal Controls

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

Part II

         Exhibit 31.1, Certification of Chief Executive Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.

         Exhibit 31.2, Certification of Chief Financial Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.

         Exhibit 32.1, Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

         Exhibit 32.2, Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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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: May 9, 2005	/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