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.

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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.