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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-QSB

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2006

OR

Commission File Number 000-19514

Gulfport Energy Corporation

(Exact name of small business issuer specified in its charter)

14313 North May Avenue, Suite 100

Oklahoma City, Oklahoma 73134

(405) 848-8807

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive office)

Check whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer  ¨    Accelerated filer  ¨    Non-accelerated filer  x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

As of August 10, 2006, 33,135,387 shares of common stock were outstanding.

Transitional Small Business Disclosure Format (check one):    Yes  ¨    No  x

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GULFPORT ENERGY CORPORATION

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FORM 10-QSB QUARTERLY REPORT

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GULFPORT ENERGY CORPORATION

BALANCE SHEET

See accompanying notes to financial statements.

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GULFPORT ENERGY CORPORATION

STATEMENTS OF INCOME

(Unaudited)

See accompanying notes to financial statements.

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GULFPORT ENERGY CORPORATION

STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

See accompanying notes to financial statements.

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GULFPORT ENERGY CORPORATION

STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to financial statements.

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GULFPORT ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

These financial statements have been prepared by Gulfport Energy Corporation (the “Company” or “Gulfport”) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission, and reflect all adjustments which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These financial statements should be read in conjunction with the financial statements and the summary of significant accounting policies and notes thereto included in the Company’s most recent annual report on Form 10-KSB. Results for the three month and six month periods ended June 30, 2006 are not necessarily indicative of the results expected for the full year.

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting for Stock-Based Compensation

Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standard No. 123(R), “Share-Based Payment” (“SFAS No. 123(R)”), using the modified prospective transition method. SFAS No. 123(R) requires share-based payments to employees, including grants of employee stock options, to be recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. Under the modified prospective transition method, share-based awards granted or modified on or after January 1, 2006, are recognized as compensation expense over the applicable vesting period. Also, any previously granted awards that are not fully vested as of January 1, 2006 are recognized as compensation expense over the remaining vesting period. No retroactive or cumulative effect adjustments were required upon the Company’s adoption of SFAS No. 123(R) (see Note 10).

Prior to adopting SFAS No. 123(R), the Company accounted for its fixed-plan employee stock options using the intrinsic-value based method prescribed by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB No. 25”), and related interpretations. This method required compensation expense to be recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price.

If the Company had elected the fair value provisions of SFAS No. 123(R) and recognized compensation expense over the vesting period based on the fair value of the stock options granted as of their grant date, the Company’s 2005 net income and net income per share would have differed from the amounts actually reported as shown in the following table.

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2. INSURANCE SETTLEMENT RECEIVABLES

The Company sustained damage to both its Hackberry field located in Cameron Parish, Louisiana and its West Cote Blanche Bay (“WCBB”) field located in St. Mary Parish, Louisiana as a result of Hurricane Rita in September 2005. As of June 30, 2006, the Company had incurred costs of $8,753,000 relating to the damage to the fields and facilities. Of this amount, $250,000 represents insurance deductible amounts that were expensed to lease operating expenses in 2005. During the six months ended June 30, 2006, the Company received $4,475,000 in insurance proceeds related to physical damage which are reflected as investing activity in the statements of cash flows. The remaining $4,028,000 is included in insurance settlement receivables in the accompanying balance sheet at June 30, 2006. Subsequent to June 30, 2006, the Company has received $325,000 in insurance proceeds for physical damage. Based upon consultations with insurance adjustors and a review of the policies, the Company believes this entire amount will be recovered through insurance proceeds.

The Company maintained business interruption insurance to cover lost production revenue in the event of shut-in production. The business interruption insurance began 60 days after the occurrence of the insurable event, subject to a daily limit of $45,000 and had a maximum coverage of 180 days. Coverage began on November 24, 2005 for shut-in production caused by Hurricane Rita. During the three month and six month periods ended June 30, 2006, the Company recognized $614,000 and $3,269,000, respectively, of business interruption insurance proceeds in other income in the statements of income. As of June 30, 2006, the Company had received proceeds of $4,979,000 ($1,710,000 of which was accrued in 2005) related to business interruption for the period of November 24, 2005 to May 1, 2006. Such recoveries are presented as operating cash flows in the statements of cash flows.

3. ACCOUNTS RECEIVABLE – RELATED PARTY

Included in the accompanying June 30, 2006 balance sheet are amounts receivable from affiliates of the Company. These receivables represent amounts billed by the Company for general and administrative functions, such as accounting, human resources, legal, and technical support, performed by Gulfport’s personnel on behalf of the affiliates. As of June 30, 2006, this receivable amount totaled $3,059,000. The Company was reimbursed $2,566,000 and $4,562,000 for the three months and six months ended June 30, 2006, respectively, for general and administrative functions which is reflected as a reduction of general and administrative expenses in the statements of income. For the three months and six months ended June 30, 2005, the Company was reimbursed $1,327,000 and $2,430,000, respectively.

Effective April 1, 2005, the Company entered into an administrative services agreement with Bronco Drilling Company, Inc. (“Bronco”), which was amended on January 1, 2006 and terminated effective April 1, 2006. Under the amended agreement, the Company’s services for Bronco included accounting, human resources, legal and

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technical support. In return for the services rendered by the Company, Bronco paid the Company an annual fee of approximately $150,000, payable in equal monthly installments during the term of the agreement. In addition, Bronco leased approximately 2,500 square feet of office space from the Company for which it paid the Company annual rent of approximately $44,000, payable in equal monthly installments. The services provided to Bronco and the fees for such services could be amended by mutual agreement of the parties. The administrative services agreement had a three-year term, and upon expiration of that term the agreement would continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement was terminable (1) by Bronco at any time with at least 30 days prior written notice to the Company and (2) by either party if the other party was in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. The Company was reimbursed approximately $49,000 in consideration for those services during the six months ended June 30, 2006 and $104,000 and $153,000 for the three and six months ended June 30, 2005, respectively. This amount is reflected as a reduction of general and administrative expenses in the statements of income.

4. PROPERTY AND EQUIPMENT

The major categories of property and equipment and related accumulated depreciation, depletion and amortization as of June 30, 2006 are as follows:

Included in oil and gas properties at June 30, 2006 is the cumulative capitalization of $3,372,000 in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were approximately $177,000 and $419,000 for the three months and six months ended June 30, 2006, respectively, and $70,000 and $160,000 for the three months and six months ended June 30, 2005, respectively.

A reconciliation of the asset retirement obligation for the six months ended June 30, 2006, is as follows:

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5. OTHER ASSETS

Other assets consist of the following as of June 30, 2006:

Tatex Thailand II, LLC

During 2005, the Company purchased a 23.5% ownership interest in Tatex Thailand II, LLC (“Tatex”) at a cost of $2,400,000. The remaining interests in Tatex are owned by other entities controlled by Wexford Capital LLC, an affiliate of Gulfport. Tatex, a non-public entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering three million acres which includes the Phu Horm field. During the three months and six months ended June 30, 2006, Gulfport paid $41,000 and $439,000, respectively, in cash calls, bringing its total investment in Tatex (including previous cash calls) to $2,941,000.

Windsor Bakken, LLC

During 2005, the Company purchased a 20% ownership interest in Windsor Bakken, LLC (“Bakken”). The remaining interests in Bakken are owned by other entities controlled by Wexford Capital LLC, an affiliate of Gulfport. In 2005 and 2006, Bakken acquired leases on undeveloped acreage in the Williston Basin areas of western North Dakota and Eastern Montana. As of June 30, 2006, Gulfport’s net investment in Bakken is $2,367,000.

6. LONG-TERM DEBT

A break down of long-term debt as of June 30, 2006 is as follows:

Maturities of long-term debt as of June 30, 2006 are as follows:

(1) The Company maintained a line of credit with Bank of Oklahoma, under which the Company could borrow up to $2,300,000. Amounts borrowed under the line bore interest at the JP Morgan Chase prime rate plus 1%, with payments of interest on outstanding balances due monthly. Any principal amounts borrowed under the line were due on July 1, 2005. This line of credit expired under its own terms on July 1, 2005.

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On March 11, 2005, Gulfport entered into a three-year secured reducing credit agreement providing for a $30.0 million revolving credit facility with Bank of America, N.A. Borrowings under the revolving credit facility are subject to a borrowing base limitation, which was initially set at $18.0 million, subject to adjustment. On November 1, 2005, the amount available under the borrowing base limitation was increased to $23.0 million and was redetermined without change on May 30, 2006. The credit facility has a term of three years and all principal amounts of revolving loans outstanding under the credit facility, together with all accrued and unpaid interest and fees, will be due and payable on March 11, 2008. The Company makes quarterly interest payments on amounts borrowed under the facility. Amounts borrowed under the credit facility bear interest at Bank of America Prime plus 0.25% (8.50% at June 30, 2006). The Company’s obligations under the credit facility are collateralized by a lien on substantially all of the Company’s assets. The credit facility contains certain affirmative and negative covenants, including, but not limited to, the following financial covenants: (a) the ratio of current assets to current liabilities may not be less than 1.00 to 1.00; (b) the ratio of funded debt to EBITDAX (net income before deductions for taxes, excluding unrealized gains and losses related to trading securities and commodity hedges, plus depreciation, depletion, amortization and interest expense, plus exploration costs deducted in determining net income under full cost accounting) for a twelve month period may not be greater than 2.00 to 1.00; and (c) the ratio of EBITDAX to interest expense for a twelve month period may not be less than 3.00 to 1.00. The Company was in compliance with all covenants at June 30, 2006. As of June 30, 2006, approximately $15 million was outstanding under this credit facility, which is included in long-term debt, net of current maturities on the accompanying balance sheet. The Company has used and expects to continue to use the proceeds of borrowings under the credit facility for the exploration of oil and natural gas properties and other capital expenditures, acquisition opportunities, repair of damaged facilities and for other general corporate purposes.

(2) The building loans include $54,000 related to a building in Lafayette, Louisiana, purchased in 1996 to be used as the Company’s Louisiana headquarters. This loan matures in February 2008 and bears interest at the rate of 5.75% per annum.

In addition, in June 2004 the Company purchased the office building it occupies in Oklahoma City, Oklahoma, for $3,700,000. One loan associated with this building matured in March 2006 and bore interest at the rate of 6% per annum, while the other loan matures in June 2011 and bears interest at the rate of 6.5% per annum. All building loans require monthly interest and principal payments and are collateralized by the respective land and buildings.

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7. EARNINGS PER SHARE

A reconciliation of the components of basic and diluted net income per common share is presented in the table below:

Options to purchase 200,000 shares at $11.20 per share, 40,000 shares at $12.17 per share, and 57,000 restricted shares were excluded from the calculation of dilutive earnings per share for the three month and six month periods ended June 30, 2006 because they were anti-dilutive. There were no potential shares of common stock that were considered anti-dilutive during the three month or six month periods ended June 30, 2005.

8. COMMITMENTS AND CONTINGENCIES

Plugging and Abandonment Funds

In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2007, the Company can access the trust for use in plugging and abandonment charges associated with the property. As of June 30, 2006, the plugging and abandonment trust totaled approximately $2,929,000, including interest received during 2006 of approximately $51,000. The Company has plugged 231 wells at WCBB since it began its plugging program in 1997, which management believes fulfills its minimum plugging obligation through 2007.

Oil Royalty Payments

The Louisiana State Mineral Board (“LSMB”) is disputing Gulfport’s royalty payments to the State of Louisiana resulting from the sale of oil under fixed price contracts. The LSMB maintains that Gulfport paid approximately $1,400,000 less in royalties under the fixed price contracts than the royalties Gulfport would have had to pay had it sold the oil at prevailing market rates. Gulfport has denied any liability to the LSMB for underpayment of royalties and has maintained that it was entitled to enter into the fixed price contracts with unrelated third parties and pay royalties based upon the sales proceeds from those contracts. In May 2006, Gulfport offered to settle the claim for $180,000 which has been accrued in accounts payable and accrued liabilities in the

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accompanying balance sheet. The LSMB rejected the offer, but continues to participate in discussions to resolve this dispute. Gulfport continues to believe that the dispute will be satisfactorily resolved, either through settlement, litigation or arbitration.

9. COMMON STOCK OPTIONS, RESTRICTED STOCK, WARRANTS, AND CHANGES IN CAPITALIZATION

Options

During the first quarter of 2006, the Company granted a total of 40,000 options for the purchase of shares of the Company’s common stock. The exercise price per share of these options is $12.17. The options vest in equal monthly installments over a three-year period and expire ten years after the date of grant.

On April 20, 2006, the Company amended and restated the 2005 Stock Incentive Plan (the “Plan”) to include (a) Incentive Stock Options, (b) Nonstatutory Stock Options, (c) Restricted Awards (Restricted Stock and Restricted Stock Units), (d) Performance Awards and (e) Stock Appreciation Rights; and to increase the maximum aggregate amount of common stock that may be issued under the Plan from 1,904,606 shares to 3,000,000 shares, including the 627,337 shares underlying options granted to employees under the Company’s 1999 Stock Option Plan.

Restricted Stock

On May 16, 2006, the Company issued 57,000 shares of restricted common stock of the Company. These shares vest in equal monthly installments over a three-year period.

Exercise of Warrants

During the first quarter of 2006, the holders of warrants issued in 2002 in conjunction with a private placement offering exercised their warrants resulting in 12,171 net shares of the Company’s common stock issued. No proceeds were received by the Company related to the exercise of these warrants. The Company had 90,800 warrants outstanding at June 30, 2006 which can be converted into 305,210 shares of common stock at current exercise price of $1.19 per share.

Sale of Common Stock

In April of 2006, the Company closed a public offering of 6,050,000 shares of common stock at a price of $14.00 per share. All shares were sold by the Company’s selling stockholders and the Company did not receive any proceeds. The offering included a total of up to 907,500 shares to be purchased pursuant to the underwriter’s over-allotment option granted by the selling stockholders. On May 8, 2006, the underwriters exercised their over-allotment option for 790,000 shares. The Company used the net proceeds of approximately $10,452,000, after the underwriting discount and before offering expenses, to repay outstanding borrowings under its credit facility with Bank of America.

10. STOCK-BASED COMPENSATION

As discussed in Note 1, on January 1, 2006, the Company changed its method of accounting for share-based compensation from the APB No. 25 intrinsic-value accounting method to the fair value recognition provisions of SFAS No. 123(R). During the three month and six month periods ended June 30, 2006, the Company’s stock-based compensation expense was $202,000 and $368,000, respectively, of which the Company capitalized $55,000 and $88,000, respectively, which reduced basic and diluted earnings per share $.01 each for the six months ended June 30, 2006. Options and restricted common stock are reported as equity instruments and their fair value is amortized to expense using the straight line method over the vesting period. The shares of stock issued once the options are exercised will be authorized but unissued common stock. During the three months and six months ended June 30, 2006, the Company capitalized $55,000 and $88,000, respectively, of its stock-based compensation pursuant to the full cost method of accounting for oil and natural gas properties.

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The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model that uses the assumptions noted in the following table. Expected volatilities are based on the historical volatility of the market price of Gulfport’s common stock over a period of time ending on the grant date. Based upon historical experience of the Company, the expected term of options granted is equal to the vesting period. The risk-free rate for periods within the contractual life of the option is based on the U.S Treasury yield curve in effect at the time of the grant. The Plan provides that all options must have an exercise price not less than the fair value of the Company’s common stock on the date of the grant.

The following table provides information relating to outstanding stock options for the six months ended June 30, 2006:

The Company has not declared dividends and does not intend to do so in the foreseeable future, and thus did not use a dividend yield. In each case, the actual value that will be realized, if any, depends on the future performance of the common stock and overall stock market conditions. There is no assurance that the value an optionee actually realizes will be at or near the value estimated using the Black-Scholes model.

The fair value of restricted common stock awards is based on the closing price of the Company’s common stock on date of the grant. The Company issued 57,000 restricted shares of common stock in May 2006 with a fair value of $756,000, which will be recorded as compensation expense over the three year vesting period of the restricted shares.

A summary of the status of stock options and related activity for the six month period ended June 30, 2006 is presented below:

Unrecognized compensation expense as of June 30, 2006 related to outstanding stock options and restricted shares was $2,612,000. The expense is expected to be recognized over a weighted-average period of 1.89 years.

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11. OTHER COMPREHENSIVE INCOME

Other comprehensive income for the three months and six months ended June 30, 2006 is as follows:

12. ACCOUNTING STANDARDS YET TO BE ADOPTED

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments,” which amends FASB Statements No. 133 and 140. SFAS No. 155 clarifies certain issues relating to embedded derivatives and beneficial interests in securitized financial assets. The provisions of SFAS 155 are effective for all financial instruments acquired or issued after fiscal years beginning after September 15, 2006. We are currently assessing the impact that the adoption of SFAS 155 will have on our financial statements.

In June 2006, the FASB issued FASB Interpretation Number 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.” This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This Interpretation is effective for fiscal years beginning after December 15, 2006. The Company is currently assessing the effect of this Interpretation on its financial statements.

13. FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Oil Price Hedging Activities

The Company established an oil price-hedging program in August 2005. The Company seeks to reduce its exposure to unfavorable changes in oil prices, which are subject to significant and often volatile fluctuation, by taking receive-fixed positions in price swap contracts. The Company pays the counterparty the excess of the oil market price over the fixed price and will receive the excess of the fixed price over the market price as defined in each contract. These contracts allow the Company to predict with greater certainty the effective oil prices to be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. As of June 30, 2006, price swap contracts were in place to hedge 270,000 barrels (“Bbls”) of estimated future production during the remainder of 2006 at $64.05 per barrel.

The Company’s price swap contracts are tied to commodity prices on the New York Mercantile Exchange (“NYMEX”). The Company receives the fixed price amount stated in the contract and pays to its counterparty the current market price for oil as listed on the NYMEX West Texas Index (WTI). However, due to the geographic location of the Company’s assets and the cost of transporting oil to another market, the amount that the Company receives when it actually sells its oil differs from the index price. The difference between oil prices on the NYMEX WTI and average price received by the Company during the month for its oil is referred to as a basis differential.

The following table summarizes the estimated volumes, fixed prices, fixed-price sales and fair value attributable to the price swap contracts as of June 30, 2006.

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The estimates of fair value of the price swap contracts are computed based on the difference between the prices provided by the price swap contracts and forward market prices as of the specified date, as adjusted for basis differentials. Forward market prices for oil are dependent upon supply and demand factors in such forward market and are subject to significant volatility. The fair value estimates shown above are subject to change as forward market prices and basis change.

All price swap contracts have been executed in connection with the Company’s oil price hedging program. The differential between the fixed price and the floating price for each contract settlement period multiplied by the associated contract volume is the contract profit or loss. For price swap contracts qualifying as cash flow hedges pursuant to SFAS 133, the realized contract profit or loss is included in oil sales in the period for which the underlying production was hedged. For the three and six months ended June 30, 2006, there were net realized losses of $850,000 under price swap contracts, which included $47,000 of gains that had previously been deferred within other comprehensive income and are further discussed in the subsequent paragraph.

The Company’s oil production was shut-in during the fourth quarter of 2005 and for a portion of the first quarter of 2006 due to Hurricane Rita’s impact on the Company’s facilities. In accordance with SFAS 133 Derivative Implementation Group Issue Number G3, certain extenuating circumstances that impact the timing of the forecasted transaction and are outside the control or influence of the Company permit the gain or loss related to the cash flow hedge being reported in accumulated other comprehensive income until the forecasted transaction is recognized in earnings. As a result, all fourth quarter 2005 and first quarter 2006 contract profits and losses (net gain of $114,000 and $77,000, respectively) remained in accumulated other comprehensive income at March 31, 2006. During the second quarter of 2006, production was restored and the Company recognized gains of $47,000 in the second quarter of 2006. The remaining deferred gain of $144,000 will be recognized as oil is produced during the third quarter of 2006.

For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS 133, changes in fair value are recognized in other comprehensive income until the hedged item is recognized in earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. During the three months and six months ended June 30, 2006, losses of $119,000 and $163,000, respectively, were recognized into earnings resulting from hedge ineffectiveness.

Contracts that do not qualify as cash flow hedges are adjusted to fair value through income. There were no contracts which did not qualify as cash flow hedges as of June 30, 2006.

Based upon market prices at June 30, 2006, the estimated amount of unrealized losses for price swap contracts shown as adjustments to other comprehensive income that are expected to be reclassified into earnings as actual contract cash settlements are realized within the next six months is $2,867,000.

As part of the agreement with the counterparty, the Company has established a deposit account to cover margin calls if required. At June 30, 2006, the account totaled $2,500,000; however, should the Company’s liability for the cash flow hedges continue to increase, further cash calls may be required.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes thereto included in our Annual Report on Form 10-KSB and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-QSB.

Disclosure Regarding Forward-Looking Statements

This Form 10-QSB includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical facts included in this Form 10-QSB that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, general economic, market or business conditions; the opportunities (or lack thereof) that may be presented to and pursued by us; competitive actions by other oil and natural gas companies; changes in laws or regulations; hurricanes and other natural disasters and other factors, including those listed in the “Risk Factors” section of our Annual Report on Form 10-KSB, many of which are beyond our control. Consequently, all of the forward-looking statements made in this Form 10-QSB are qualified by these cautionary statements, and we cannot assure you that the actual results or developments anticipated by us will be realized or, even if realized, that they will have the expected consequences to or effects on us, our business or operations. We have no intention, and disclaim any obligation, to update or revise any forward looking statements, whether as a result of new information, future results or otherwise.

Overview

We are an independent oil and natural gas exploration and production company with our principal properties located along the Louisiana Gulf Coast. Our operations are concentrated in two fields: West Cote Blanche Bay, or WCBB, and the Hackberry fields. We seek to achieve reserve and production growth and increase our cash flow through our annual drilling programs.

The WCBB field lies approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (79.4% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.4% non-operated working interest (30.0% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres.

The East Hackberry field is located along the western shore of Lake Calcasieu in Louisiana, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 79% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. The interest includes two separate lease blocks, the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. The two lease blocks together contain 3,147 acres.

The West Hackberry field is located on land and is five miles West of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 87.5% NRI) in 592 acres within the West Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy’s Strategic Petroleum Reserves.

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Recent Developments

Current Production. During the three months ended June 30, 2006, our net production was 215,093 barrels of oil and 100,120 thousand cubit feet of gas “Mcf,” or 231,779 BOE, as compared to 64,321 barrels of oil and 92,025 Mcf of gas, or 79,659 BOE, for the three months ended March 31, 2006. Our total net production averaged approximately 4,326 BOE per day during July 2006 compared to 2,467 BOE per day for the same period in 2005, which represents an 75% increase.

WCBB. On September 24, 2005, the tidal surge from Hurricane Rita caused damage to our WCBB facilities. Although we lost more than 150 days of production, our main tank batteries, which handled approximately 70% of our production before Hurricane Rita, became operational during the first quarter of 2006. We currently have a majority of the production from the wells that were producing prior to Hurricane Rita back on-line and anticipate being fully operational at WCBB by the end of September 2006. We began returning wells to production during the first quarter of 2006, and as of August 7, 2006, 46 of the 57 active wells in the field prior to Hurricane Rita had been returned to production. The remaining 11 wells that were producing prior to Hurricane Rita and accounted for an aggregate of only approximately 120 BOE per day net to us, are expected to be back on-line by the end of September 2006.

In July 2006, we drilled an 11,763 foot, higher risk, higher return exploratory gas target in our WCBB field. The well, while structurally high, did not find the anticipated sand. However, we currently believe the objective sand may still be a viable objective. Accordingly, we may attempt to access the target sand by drilling a side-track from the original well. The cost of the well to date is approximately $5.8 million. We will continue to periodically drill our higher risk, higher return exploratory wells but do not anticipate drilling another deep test well until next year.

Through August 10, 2006, we have drilled a total of 18 developmental wells and one higher risk, higher return exploratory well in our WCBB field, for 19 total wells drilled this year. Of the 19 wells drilled this year, 14 have been completed and are producing, three were not commercial and two are still waiting to be completed. One well waiting on completion has 86 feet of apparent net pay and the other has 270 feet of apparent net pay. The total of 356 feet of apparent net pay is contained in 15 zones. Excluding the deep gas test, the 18 wells drilled in 2006 have had an estimated average cost per well of $1.1 million. We currently have two drilling rigs at WCBB drilling two additional wells and plan to drill eight additional wells at WCBB for a total of 29 wells at WCBB during 2006. At WCBB, our net production averaged 3,923 BOE per day during July 2006 compared to 2,014 BOE per day for the same period in 2005 which represents a 95% increase. On September 20, 2005, prior to Hurricane Rita, aggregate net production at WCBB was 2,204 Boe. On August 8, 2006, net production at WCBB was approximately 4,082 BOE.

East Hackberry Field. On September 20, 2005, prior to shutting-in our 11 producing East Hackberry wells in preparation for Hurricane Rita, aggregate net production was approximately 299 BOE per day. Production was re-established from six of these wells in November 2005. Due to damage to certain of our production facilities caused by Hurricane Rita, five wells in our State Lease 50 Block remain shut-in. Prior to being shut-in, these five wells had aggregate production of approximately 50 BOE per day. We budgeted $8.0 million to replace and upgrade certain of our East Hackberry facilities in connection with our 2006 drilling program. As of June 30, 2006, we had spent approximately $800,000. We intend to put the five remaining shut-in wells back on line when these facilities are completed. At East Hackberry, our net production averaged 200 BOE per day during July 2006 compared to 63 BOE per day for the same period in 2005. On August 8, 2006, net production at East Hackberry was 147 BOE.

West Hackberry Field. At West Hackberry, our net production averaged 67 BOE per day during July 2006 compared to 47 BOE per day for the same period in 2005. On August 8, 2006, our net production at West Hackberry was 67 barrels of oil.

Insurance Coverage. We sustained damage to both our Hackberry field located in Cameron Parish, Louisiana and our WCBB field located in St. Mary Parish, Louisiana as a result of Hurricane Rita in September 2005. As of June 30, 2006, we had incurred costs of $8,753,000 relating to the damage to these fields and facilities. Of this

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amount, $250,000 represents insurance deductible amounts that were expensed to lease operating expenses in 2005. During the six months ended June 30, 2006, we received $4,475,000 in insurance proceeds related to physical damage which is reflected in cash flows from investing activities as a reduction to oil and gas property additions in our statements of cash flows. The remaining $4,028,000 is included in insurance settlement receivables in the accompanying balance sheet at June 30, 2006. Subsequent to June 30, 2006, we have received $325,000 in insurance proceeds for physical damage. Based upon consultations with insurance adjustors and a review of the policies, we believe the entire $3,703,000 balance of the insurance settlement receivable will be recovered through insurance proceeds.

We also maintained business interruption insurance to cover lost production revenue in the event of shut-in production. The business interruption insurance began 60 days after the occurrence of the insurable event, subject to a daily limit of $45,000 and had a maximum coverage of 180 days. Coverage began on November 24, 2005 for shut-in production caused by Hurricane Rita. During the six-month period ended June 30, 2006, we recognized $3,269,000 of business interruption insurance proceeds in other income in the statements of income. As of June 30, 2006, we had received proceeds of $4,979,000 ($1,710,000 of which was accrued in 2005) related to business interruption for the period of November 24, 2005 to May 1, 2006. Such recoveries are presented as operating cash flows in the statements of cash flows.

Effective May 24, 2006, we renewed our platform and business interruption insurance. Due to the large increases in premiums, we reduced the amount of platform insurance coverage from $12.1 million to a total of $3.0 million in coverage. During repairs of our facilities, we attempted to rebuild our facilities to better enable them to withstand a similar hurricane with less damage. Additionally, our new policy now provides for $7.5 million of business interruption insurance coverage for a period of 45 days which begins after a waiting period of 90 days after the date of a qualifying event. Collectively, these coverages have a self insured retention of $1.0 million.

RESULTS OF OPERATIONS

Comparison of the Three Months Ended June 30, 2006 and 2005

We reported net income of $7,059,000 for the three months ended June 30, 2006, compared to $3,010,000 for the three months ended June 30, 2005. The improvement in net income primarily reflects a 48% increase in the average oil price received to $64.37 per barrel for the three months ended June 30, 2006 from $43.38 per barrel for same period in 2005 and a 25% increase in net production to 231,779 BOE for the three months ended June 30, 2006 from 185,425 BOE for the same period in 2005.

Oil and Gas Revenues. For the three months ended June 30, 2006, we reported oil and gas revenues of $14,349,000, compared to revenues of $7,816,000 during the same period in 2005. This increase in revenues is primarily attributable to a 48% increase in the average oil price received to $64.37 per barrel for the three months ended June 30, 2006 from $43.38 per barrel for same period in 2005 and a 25% increase in net production to 231,779 BOE for the three months ended June 30, 2006 from 185,425 BOE for the same period in 2005. This increase in oil and gas production was primarily the result of production from new wells brought on line subsequent to the 2005 period as a result of both our 2005 and 2006 drilling programs.

The following table summarizes our oil and natural gas production and related pricing for the three months ended June 30, 2006 and 2005:

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Lease Operating Expenses. Lease operating expenses not including production taxes increased to $2,255,000 for the three months ended June 30, 2006 from $1,961,000 for the same period in 2005. This increase was mainly due to increases in the general costs of supplies and labor in our operating area along the Louisiana Gulf Coast.

Production Taxes. Production taxes increased to $1,921,000 for the three months ended June 30, 2006 from $1,029,000 for the same period in 2005. This increase was directly related to an 84% increase in oil and gas revenues as a result of the 47% improvement in the price received per BOE as well as a 25% increase in production for the three months ended June 30, 2006 compared to the same period in 2005.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased to $2,743,000 for the three months ended June 30, 2006, and consisted of $2,648,000 in depletion on oil and natural gas properties and $95,000 in depreciation of other property and equipment. This compares to total depreciation, depletion and amortization expense of $1,452,000 for the three months ended June 30, 2005. This increase was due primarily to an increase in our oil and natural gas property costs associated with our 2006 drilling program and an increase in our oil and gas production for the period.

General and Administrative Expenses. Net general and administrative expenses increased to $513,000 for the three months ended June 30, 2006 from $311,000 for the same period in 2005. This increase was due primarily to $202,000 of compensation expense recognized as a result of the implementation of SFAS No. 123(R), “Share Based Payment” and an increase in franchise tax expenses for the three months ended June 30, 2006 compared to the same period in 2005.

Accretion Expense. Accretion expense increased to $149,000 for the three month period ended June 30, 2006 from $117,000 for the same period in 2005, due to a larger obligation at the beginning of 2006 as compared to the beginning of 2005, resulting from the addition of future abandonment obligations on new wells drilled during 2005.

Interest Expense. Ordinary interest expense increased to $397,000 for the three months ended June 30, 2006 from $63,000 for the same period in 2005 due to an increase in average debt outstanding. At June 30, 2006, total debt outstanding under our facility with Bank of America was $15,048,000. At June 30, 2005, there was no debt outstanding under this facility.

Interest Expense – Preferred Stock. During the three months ended June 30, 2005, we incurred interest expense on preferred stock classified as a liability under SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“SFAS 150”). During 2005, we redeemed all of the remaining outstanding shares of our Series A preferred stock. As a result, we incurred no interest expense relating to preferred stock during the three months ended June 30, 2006 as compared to $272,000 in interest expense incurred during the same period in 2005.

Income Taxes. As of June 30, 2006, we had a net operating loss carry forward of approximately $100.1 million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At June 30, 2006, a valuation allowance of $38.0 million had been provided for deferred tax assets. We had no income tax expense due to a change in the valuation allowance for deferred income taxes for the three months ended June 30, 2006.

Comparison of the Six Months Ended June 30, 2006 and 2005

We reported net income of $9,887,000 for the six months ended June 30, 2006, compared to $4,940,000 for the six months ended June 30, 2005. This increase in net income was due primarily to a 50% increase in the average oil price received to $63.53 per barrel for the six months ended June 30, 2006 from $42.42 per barrel for same period in 2005 and business interruption insurance recoveries of $3,269,000 due to Hurricane Rita partially offset by a 11% decrease in net production to 311,438 BOE for the six months ended June 30, 2006 from 350,015 BOE for the same period in 2005.

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Oil and Gas Revenues. For the six months ended June 30, 2006, we reported oil and gas revenues of $18,798,000, compared to oil and gas revenues of $14,624,000 during the same period in 2005. This increase in revenues is attributable to a 50% increase in the average oil price received to $63.53 per barrel for the six months ended June 30, 2006 from $42.42 per barrel for same period in 2005 offset partially by a 11% decrease in production for the six months ended June 30, 2006 to 311,438 BOE from 350,015 BOE for the same period in 2005. This decrease in oil and gas production was primarily the result of unexpected, additional delays we have experienced in repairing the WCBB facilities damaged by Hurricane Rita and delays in construction of the East Hackberry production facilities. These delays were caused by shortages in oilfield equipment and personnel in the coastal region of the Gulf of Mexico.

The following table summarizes our oil and natural gas production and related pricing for the six months ended June 30, 2006 and 2005:

Lease Operating Expenses. Lease operating expenses not including production taxes decreased to $3,606,000 for the six months ended June 30, 2006 from $4,027,000 for the same period in 2005. This decrease was mainly due to a reduction of our variable operating expenses incurred as a result of the impact of Hurricane Rita, which was partially offset by the fuel and field electricity costs and other additional lease operating expenses attributable to our interest in the Marquiss field. We acquired our interest in the Marquiss field in February 2005. Accordingly, there is a full six months of lease operating expenses included in the six months ended June 30, 2006.

Production Taxes. Production taxes increased to $2,486,000 for the six months ended June 30, 2006 from $1,834,000 for the same period in 2005. This increase was directly related to a 29% increase in oil and gas revenues as a result of the 44% improvement in the price received per BOE partially offset by an 11% decline in production for the six months ended June 30, 2006 compared to the same period last year.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased to $3,736,000 for the six months ended June 30, 2006, and consisted of $3,549,000 in depletion on oil and natural gas properties and $187,000 in depreciation of other property and equipment. This compares to total depreciation, depletion and amortization expense of $2,752,000 for the six months ended June 30, 2005. This increase was due primarily to an increase in our oil and natural gas property costs associated with our 2006 drilling program.

General and Administrative Expenses. Net general and administrative expenses increased to $1,514,000 for the six months ended June 30, 2006 from $695,000 for the same period in 2005. This increase was due primarily to increases in legal expenses, the costs of our engineering estimates, the filing fee associated with our NASDAQ listing, the $368,000 effect of the implementation of SFAS No. 123(R), “Share Based Payment” and general increases in payroll costs and related benefits. These increases were partially offset by increases in general administrative reimbursements from our affiliates.

Accretion Expense. Accretion expense increased $65,000 to $298,000 for the six month period ended June 30, 2006 from $233,000 for the same period in 2005, due to a larger obligation at the beginning of 2006 compared to the beginning of 2005, resulting from the addition of future abandonment obligations on new wells drilled during 2005.

Interest Expense. Ordinary interest expense increased to $668,000 for the six months ended June 30, 2006 from $121,000 for the same period in 2005 due to an increase in average debt outstanding. At June 30, 2006, total debt outstanding under our facility with Bank of America was $15,048,000. At June 30, 2005, there was no debt outstanding under this facility.

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Interest Expense – Preferred Stock. During the six months ended June 30, 2005, we incurred interest expense on preferred stock classified as a liability under SFAS No. 150. During 2005, we redeemed all of our remaining outstanding shares of the Series A preferred stock. As a result, we incurred no interest expense relating to preferred stock during the six months ended June 30, 2006 as compared to $272,000 in interest expense incurred during the same period in 2005.

Income Taxes. As of June 30, 2006, we had a net operating loss carry forward of approximately $100.1 million, in addition to numerous temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not be realized. At June 30, 2006, a valuation allowance of $38.0 million had been provided for deferred tax assets. We had no income tax expense due to a change in the valuation allowance for deferred income taxes for the six months ended June 30, 2006.

Liquidity and Capital Resources

Overview. Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, the issuance of equity securities, borrowings under our bank and other credit facilities and, from time to time, the sale of oil and natural gas properties. Due to damage and business interruption resulting from Hurricane Rita during the fourth quarter of 2005 and the six months ended June 30, 2006, recoveries under our insurance coverages have also provided a significant source of funds. Our ability to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or oil and gas production.

Net cash flow provided by operating activities was $12,354,000 for the six months ended June 30, 2006, compared to net cash flow provided by operating activities of $10,099,000 for the same period in 2005. This increase was primarily the result of an increase in cash receipts from our oil and gas purchasers due to higher prices received for oil production, partially offset by increase in cash paid for lease operating expenses and production taxes.

Net cash used in investing activities for the six months ended June 30, 2006 was $25,233,000 compared to $17,976,000 for the same period in 2005. During the six months ended June 30, 2006, we spent $23,142,000 in additions to oil and natural gas properties, of which $12,020,000 was spent on our 2006 drilling program, $3,722,000 was spent on expenses attributable to the wells drilled during 2005, $1,598,000 was spent on additions to oil and natural gas properties due to the hurricane net of insurance proceeds, $3,617,000 spent on new compressors for WCBB with the remainder attributable mainly to plugging and abandonment costs, capitalized general and administrative expenses and recompletions. Cash used in investing activities also included $439,000 of additional investments in Tatex Thailand II and $1,339,000 of additional investments in Windsor Bakken LLC. We used cash from operations, insurance recoveries and borrowings under our credit facility to fund our investing activities.

Net cash provided by financing activities for the six months ended June 30, 2006 was $17,738,000 compared to $8,828,000 for the same period in 2005. The 2006 amount provided by financing activities is attributable to draws of $18,500,000 on our credit facility with Bank of America and proceeds from the issuance of common stock and exercise of options of $9,990,000. During the six months ended June 30, 2006, we received net proceeds of $10.4 million from the sale of shares as a result of the underwriters exercise of their over-allotment option in connection with our May 2006 underwritten public offering. These net proceeds were used to pay down existing debt under our credit facility. The $8,828,000 provided by financing activities during the six months ended June 30, 2005 is attributable to net cash proceeds of approximately $23,207,000 from the issuance of common stock in two private placements and upon the exercise of the outstanding warrants, offset by the approximately $14,278,000 used to redeem 14,278 shares of the 14,292 outstanding shares of our Series A preferred stock.

Issuance of Equity. On May 3, 2006, certain of our stockholders sold 6,050,000 shares of our common stock in an underwritten public offering at an offering price to the public of $14.00 per share. In connection with the offering, we granted the underwriters a 30-day option to purchase additional shares of our common stock to cover over-allotments, if any. On May 8, 2006, the underwriters exercised their option with respect to 790,000 shares. We

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received net proceeds of $10.4 million from the sale of these shares on May 10, 2006 after deducting the underwriting discount and before offering expenses. These net proceeds were used to pay down existing debt under our credit facility.

Credit Facility. On March 11, 2005, we entered into a three-year secured reducing credit agreement providing for a $30.0 million revolving credit facility with Bank of America, N.A. Borrowings under the revolving credit facility are subject to a borrowing base limitation that- was initially set at $18.0 million, subject to adjustment. On November 1, 2005, the amount available under the borrowing base limitation was increased to $23.0 million. On May 30, 2006, the lender completed a re-determination of our borrowing base and the availability continues to be $23.0 million. The credit facility has a term of three years and all principal amounts of revolving loans outstanding under the credit facility, together with all accrued and unpaid interest and fees will be due and payable on March 11, 2008. Amounts borrowed under the credit facility bear interest at Bank of America prime plus 0.25% (8.50% at June 30, 2006). Our obligations under the credit facility are collateralized by a lien on substantially all of our assets. We have used and expect to continue to use the proceeds of borrowings under the credit facility for the exploration of oil and natural gas properties and other capital expenditures, acquisition opportunities, repair of damaged facilities and for other general corporate purposes. On May 11, 2006, we repaid $10.4 million of the outstanding indebtedness under the agreement with proceeds from the sale of our common stock pursuant to the exercise of the over-allotment option. As of June 30, 2006, $15.0 million was outstanding under this credit facility.

Building Loans. We have three loans associated with two of our buildings. One loan, in the original principal amount of $99,000, related to a building in Lafayette, Louisiana, that we purchased in 1996 to be used as our Louisiana headquarters. This loan matures in February 2008 and bears interest at the rate of 5.75% per annum. In addition, in June 2004 we purchased the office building we occupy in Oklahoma City, Oklahoma for $3,700,000. One of the two loans associated with this building, with an original principal amount of $389,000, matured in March 2006 and bore interest at a rate of 6% per annum. The other loan associated with this building, with an original principal amount of $3,000,000, matures in June 2011 and bears interest at a rate of 6.5% per annum. All building loans require monthly interest and principal payments and are collateralized by the respective land and buildings.

Capital Expenditures. Our primary capital commitments over the past several years have related to the development of our proved reserves and obligations under our credit facilities and Series A preferred stock, which is no longer outstanding. Our recent capital commitments have related to repairs to damage caused to our facilities by the hurricane.

Our strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing reserves and (2) explore other acquisition opportunities. We have upgraded our infrastructure and our existing facilities to increase operating efficiencies and volume capacities and lower lease operating expenses. We believe these upgrades will also enable our facilities to withstand future hurricanes with less damage. Additionally, we completed the reprocessing of 3-D seismic data in our principal property, WCBB. The reprocessed data will enable our geophysicists to continue to generate new prospects and enhance existing prospects in the intermediate zones in the field, thus creating a portfolio of new drilling opportunities.

In our December 31, 2005 reserve report, 79% of our net reserves were categorized as proved undeveloped. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or utilize third parties to accomplish those activities.

Our inventory of prospects includes approximately 119 wells at WCBB. The drilling schedule used in our December 31, 2005 reserve report anticipates that all of those wells will be drilled by 2015. During 2006, we intend to drill 29 wells, recomplete 18 existing wells at our WCBB field and complete six wells that we drilled in 2005 for an estimated aggregate cost of $42.0 million. As of August 3, 2006, we had drilled 18 developmental wells and one higher risk, higher return exploratory well in WCBB for a total of 19 wells in 2006 at an estimated cost to date of $25.6 million. Of the 19 wells drilled this year, 14 have been completed and are producing, three were not commercial and two are waiting to be completed. We also plan to spend approximately $6.0 million during 2006 for facilities at WCBB, including the purchase of three new compressors.

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During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry for a total cost of approximately $5.0 million. Given that previous drilling activities at the East Hackberry field were undertaken without the benefit of modern seismic information, we believe that the newly acquired 3-D seismic data will enhance our probability of drilling success. We are evaluating the newly processed 3-D seismic data to identify additional drilling locations. Late in the third quarter of 2006, we plan to move one rig from WCBB to East Hackberry State Lease 50 to begin a six-well drilling program. These wells will target measured depths of approximately 13,000 feet using directional drilling techniques. Although we had originally budgeted $12.5 million for these wells, due to the delays in our production facilities and the resulting delays in start dates for our Hackberry drilling program, we currently believe we will only spend approximately $5.0 million in 2006 for these new drills. The 3-D seismic data also suggests the possibility of deep gas production and, as a result, we intend to drill a deep wildcat well during 2007 for a total anticipated well cost of approximately $4.0 million. If productive, multiple offset locations could be drilled. We budgeted approximately $8.0 million during 2006 for new facilities and upgrades to existing facilities to support our proposed East Hackberry drilling program, and during the six months ended June 30, 2006 we have spent $800,000.

To mitigate the effects of commodity price fluctuations, we have entered into price swap contracts to hedge 45,000 barrels of production per month from WCBB during 2006 with a fixed price of $64.05 per barrel. As part of the agreement with our counterparty, we have established a deposit account to cover margin calls if required. Under these arrangements, the counterparty may require us to post cash collateral approximately equal to the difference between the agreed contract price of $64.05 per barrel and a defined market price multiplied by the remaining barrels of oil under the open contracts. At June 30, 2006, the account totaled approximately $2,500,000; however, should our liability for the cash flow hedges continue to increase, further cash calls may be required.

We intend to acquire from a related party a 25% interest in 115,000 acres in the Canadian Oil Sands for approximately $8.0 million. The leases are in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of other existing oil sands projects. Thus, there is some infrastructure already in place. Current plans contemplate commencing construction of a 10,000 barrel per day steam assisted gravity drainage facility as soon as 2008.

We believe that our cash on hand, insurance proceeds as described above under “Recent Developments—Insurance Coverage,” cash flow from operations, and borrowings under our credit facility will be sufficient to fund our capital expenditures for the remainder of 2006.

Commitments

In connection with the acquisition of the remaining 50% interest in WCBB, we assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2007, we can access the trust for use in plugging and abandonment charges associated with the property. As of June 30, 2006, the plugging and abandonment trust totaled approximately $2,929,000, including interest received during 2006 of approximately $51,000. We have plugged 231 wells at WCBB since we began our plugging program in 1997, which management believes fulfills its minimum plugging obligation through 2007. In addition, we have letters of credit totaling $200,000 secured by certificates of deposit being held for plugging costs in the East Hackberry field. Once specific wells are plugged and abandoned, the $200,000 will be returned to us.

New Accounting Pronouncements

SFAS No. 123

Effective January 1, 2006, we adopted SFAS No. 123(R), using the modified prospective transition method. SFAS No. 123(R) requires share-based payments to employees, including grants of employee stock options, to be recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. Under the modified prospective transition method, share-based awards granted or modified on or after January 1, 2006, are recognized as compensation expense over the applicable vesting period. Also, any previously granted awards that are not fully vested as of January 1, 2006 are recognized as compensation expense over the remaining vesting period. No retroactive or cumulative effect adjustments were required upon our adoption of SFAS No. 123(R). During the first six months of 2006, our stock-based compensation expense was $368,000.

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SFAS No. 155

In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments,” which amends FASB Statements No. 133 and 140. SFAS No. 155 clarifies certain issues relating to embedded derivatives and beneficial interests in securitized financial assets. The provisions of SFAS 155 are effective for all financial instruments acquired or issued after fiscal years beginning after September 15, 2006. We are currently assessing the impact that the adoption of SFAS 155 will have on our financial statements.

FIN 48

In June 2006, the FASB issued FASB Interpretation Number 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109.” This Interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” This Interpretation is effective for fiscal years beginning after December 15, 2006. We are currently assessing the effect of this Interpretation on our financial statements.

ITEM 3. CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures. Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information we are required to disclose in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to our management, including the Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.

As of June 30, 2006, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of June 30, 2006, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Louisiana State Mineral Board is disputing our royalty payments to the State of Louisiana resulting from the sale of oil under fixed price contracts. The Board maintains that we paid approximately $1,400,000 less in royalties under the fixed price contracts than the royalties we would have had to pay had we sold the oil at prevailing market rates. We have denied any liability to the Board for underpayment of royalties and have maintained that we were entitled to enter into the fixed price contracts with unrelated third parties and pay royalties based upon the sales proceeds from those contracts. In May 2006, we offered to settle the claim for $180,000. The Board rejected the offer, but continues to participate in discussions to resolve this dispute. We continue to believe that the dispute will be satisfactorily resolved, either through settlement, litigation, or arbitration.

We have been named as a defendant in various lawsuits related to our business. The ultimate resolution of these matters is not expected to have a material adverse effect on our financial condition or results of operations for the periods presented in the financial statements.

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

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On April 20, 2006, our board of directors nominated seven persons to serve on our board of directors and adopted our Amended and Restated 2005 Stock Incentive Plan. On April 20, 2006, in accordance with Delaware law and our bylaws, the holders of a majority of the outstanding shares of our common stock executed a written consent (1) electing the seven director nominees, Mike Liddell, James D. Palm, Robert E. Brooks, David L. Houston, Mickey Liddell, Dan Noles and Phillip G. Lancaster, to hold office until the next annual meeting or until their successors are duly elected and qualified or until each such director’s earlier resignation or removal; and (2) approving the Amended and Restated 2005 Stock Incentive Plan. The written consent of common stockholders was executed by stockholders holding over 66% of the shares of common stock eligible to vote. The election of the directors did not become effective and no new options or other awards were permitted to be issued under the Amended and Restated 2005 Stock Incentive Plan until May 16, 2006.

The Amended and Restated 2005 Stock Incentive Plan provides a means by which eligible recipients may be granted one or more of the following awards: (1) Incentive Stock Options, (2) Nonstatutory Stock Options, (3) Restricted Awards (Restricted Stock and Restricted Stock Units) (4) Performance Awards and (5) Stock Appreciation Rights. The maximum aggregate amount of our common stock which may be issued upon exercise of all awards under the Amended and Restated 2005 Stock Incentive Plan, including incentive stock options, may not exceed 3,000,000 shares, subject to certain adjustments, less 627,337 shares, the total number of shares underlying options granted to employees prior to the adoption of this plan and outstanding on the effective date under our 1999 Stock Option Plan.

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ITEM 5. OTHER INFORMATION

(a) Termination of Administrative Services Agreement

Effective April 1, 2006, Bronco Drilling Company, Inc. terminated our administrative services agreement. Under this agreement, we provided certain services to Bronco, including accounting, human resources, legal and technical support services. In return for these services, Bronco payed us an annual fee of approximately $414,000. In addition, Bronco leased approximately 1,200 square feet of office space from us for our headquarters located in Oklahoma City, Oklahoma for which Bronco paid us annual rent of $20,880. In January 2006, Bronco reduced the level of administrative services being provided by us and increased its office space to approximately 2,500 square feet. As a result, Bronco’s annual fee for administrative services was reduced to approximately $150,000 and its annual rental was increased to approximately $44,000.

Resignation and Appointment of Director

Phillip G. Lancaster has notified us of his intention to become the Chief Executive Officer of one of our affiliates. The Nasdaq rules require that a majority of our board of directors consist of independent directors, after certain transition period, and that the audit committee of our board of directors be comprised of three independent directors. As a result, effective August 15, 2006, Phillip G. Lancaster resigned from his positions as a member of our board of directors and a member of the audit and compensation committees of our board of directors. To fill the resulting vacancies, effective August 15, 2006, our board of directors have appointed Scott Streller to serve on our board of directors and on the audit and compensation committees of our board of directors. There are no agreements or understandings pursuant to which Mr. Streller was appointed as a member of our board of directors. After giving effect to this change, the audit committee of our board of directors consists of three independent directors, David L. Houston, Robert E. Brooks and Mr. Streller and the compensation committee of our board of directors consists of two non-employee and outside directors within the meanings of Rule 16b-3 promulgated under the Securities Exchange Act of 1934, as amended and Section 163(m) of the Internal Revenue Code, respectively, Mr. Houston and Mr. Streller.

(b) None.

ITEM 6. EXHIBITS

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SIGNATURES

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

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