Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-QSB

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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 shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

As of May 12, 2006, 32,972,706 shares of common stock were outstanding.

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

Table of Contents

GULFPORT ENERGY CORPORATION

TABLE OF CONTENTS

FORM 10-QSB QUARTERLY REPORT

2

Table of Contents

Item 1. Financial Statements

March 31, 2006 and 2005

Forming a part of Form 10-QSB Quarterly Report to the

Securities and Exchange Commission

3

Table of Contents

GULFPORT ENERGY CORPORATION

BALANCE SHEET

See accompanying notes to financial statements.

4

Table of Contents

GULFPORT ENERGY CORPORATION

STATEMENTS OF INCOME

(Unaudited)

See accompanying notes to financial statements.

5

Table of Contents

GULFPORT ENERGY CORPORATION

STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

See accompanying notes to financial statements.

6

Table of Contents

GULFPORT ENERGY CORPORATION

STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to financial statements.

7

Table of Contents

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 period ended March 31, 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).

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.

8

Table of Contents

2. INSURANCE SETTLEMENT RECEIVABLES

The Company sustained damage to both its Hackberry field located in Cameron Parish, Louisiana and its WCBB field located in St. Mary Parish, Louisiana as a result of Hurricane Rita in September 2005. As of March 31, 2006, the Company had incurred costs of $6,085,000 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. As of March 31, 2006, the Company had received $1,000,000 in insurance proceeds related to physical damage which are reflected as investing activity in the statements of cash flows. The remaining $4,835,000 is included in insurance settlement receivables in the accompanying balance sheet at March 31, 2006. The Company has received $1,200,000 in insurance proceeds for physical damage subsequent to March 31, 2006. Based upon consultations with insurance adjustors and review of 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 an 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 period ended March 31, 2006, the Company accrued $2,655,000 of business interruption insurance proceeds in other income in the statements of income. As of March 31, 2006, the Company had received aggregate proceeds of $2,587,000 ($1,710,000 of which was accrued in 2005) related to business interruption for the period of November 24, 2005 to March 31, 2006. Such recoveries are presented as operating cash flows in the statements of cash flows. A balance of $1,778,000 is included in insurance settlement receivables in the accompanying balance sheet at March 31, 2006.

3. ACCOUNTS RECEIVABLE – RELATED PARTY

Included in the accompanying March 31, 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 March 31, 2006, this receivable amount totaled $3,930,000.

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. In return for the services rendered by the Company, Bronco pays the Company an annual fee of approximately $150,000 payable in equal monthly installments during the term of the agreement. In addition, Bronco leases approximately 2,500 square feet of office space from the Company for which it pays the Company annual rent of approximately $44,000 payable in equal monthly installments. The services being provided to Bronco and the fees for such services can be amended by mutual agreement of the parties. The administrative services agreement has a three-year term, and upon

9

Table of Contents

expiration of that term, the agreement will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement is 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 is 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 three months ended March 31, 2006. 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 March 31, 2006 are as follows:

Included in oil and gas properties at March 31, 2006 is the cumulative capitalization of $3,194,000 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 $242,000 for the three months ended March 31, 2006.

A reconciliation of the asset retirement obligation for the three months ended March 31, 2006, is as follows:

10

Table of Contents

5. OTHER ASSETS

Other assets consist of the following as of March 31, 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 3 million acres which includes the Phu Horm Field. During the three months ended March 31, 2006, Gulfport paid $398,000 in cash calls, bringing its total investment in Tatex to $2,900,000.

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 March 31, 2006, Gulfport’s net investment in Bakken was $2,254,000.

6. LONG-TERM DEBT

A break down of long-term debt as of March 31, 2006 is as follows:

11

Table of Contents

Revolving Line of Credit

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.

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. 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 against the credit facility bear interest at Bank of America prime plus 0.25% (7.75% at March 31, 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 March 31, 2006. As of March 31, 2006, the Company had borrowed $14.5 million against the 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 gas properties and other capital expenditures, acquisition opportunities, repair of damaged facilities, and for other general corporate purposes.

Building Loans

The building loans include $62,000 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.

12

Table of Contents

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 and 40,000 shares at $12.17 per share were excluded from the calculation of dilutive earnings per share for the three months ended March 31, 2006 because they were anti-dilutive. There were no potential shares of common stock that were considered anti-dilutive during the three-month period ended March 31, 2005.

8. COMMITMENTS AND CONTINGENCIES

Plugging and Abandonment Funds

In connection with the acquisition of the remaining 50% interest in the West Cote Blanche Bay (“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 March 31, 2006, the plugging and abandonment trust totaled approximately $2,904,000, including interest received during 2006 of approximately $26,000. The Company has plugged 206 wells at WCBB since it began its plugging program in 1997, which management believes fulfills its minimum plugging obligation through March 31, 2006.

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. Gulfport is currently in discussions with the LSMB to resolve this dispute and believes it will be satisfactorily resolved in the Company’s favor.

9. COMMON STOCK OPTIONS AND WARRANTS

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.

13

Table of Contents

Subsequent to March 31, 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 which 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.

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 has 90,800 warrants outstanding at March 31, 2006 which can be converted to 305,210 shares of common stock with a current exercise price of $1.19 per share.

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 first three months of 2006, the Company’s stock-based compensation expense was $166,000. These options 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 by unissued common stock. During the three months ended March 31, 2006, the Company capitalized $33,000 of its stock-based compensation pursuant to the full cost method of accounting for oil and gas properties.

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. 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 at March 31, 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.

14

Table of Contents

A summary of the status of stock options and related activity for the three month period ended March 31, 2006 is presented below:

A summary of the Company’s unvested stock options as of March 31, 2006, and changes during the three months then ended, is presented below.

Unrecognized compensation expense as of March 31, 2006 related to outstanding stock options was $2,059,000. The expense is expected to be recognized over a weighted-average period of 1.96 years.

11. 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.

12. 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 March 31, 2006, price swap contracts were in place to hedge 405,000 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

15

Table of Contents

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 March 31, 2006.

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 months ended March 31, 2006, there were no realized gains under price swap contracts.

The Company’s oil production was shut-in during fourth quarter 2005 and for a portion of first quarter 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) remain in accumulated other comprehensive income at March 31, 2006. This amount will be recognized when the production is restored and reported in earnings. The Company believes that the forecasted oil production will occur beginning in the second quarter 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 ended March 31, 2006, losses of $45,000 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 March 31, 2006.

Based upon market prices at March 31, 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 nine months is $1,759,000.

As part of the agreement with the counterparty, the Company has established a deposit account to cover margin calls if required. At March 31, 2006, the account totaled approximately $700,000; however, should the Company’s liability for the cash flow hedges continue to increase, further cash calls may be required.

16

Table of Contents

13. SUBSEQUENT EVENTS

On April 27, 2006, Gulfport entered into an underwriting agreement relating to the offer and sale by the selling stockholders of 6,050,000 shares of the Company’s common stock. The Company granted the underwriters an option, exercisable for 30 days from the date of the underwriting agreement, to purchase up to an aggregate of 907,500 additional shares of common stock solely to cover overallotments, if any, made in connection with the offering. The price per share to the underwriters was $13.23, and the underwriters initially offered the shares to the public at $14.00 per share. The offering of the shares was made under a Registration Statement on Form S-3 (File No. 333-133109) filed on April 7, 2006, as amended by Amendment No. 1 to the Registration Statement, filed on April 21, 2006, and Amendment No. 2 to the Registration Statement, filed on April 27, 2006, including a prospectus dated April 28, 2006. The sale of the shares by the selling stockholders was completed on May 3, 2006. The Company did not receive any of the proceeds from the sale of shares by the selling stockholders. On May 8, 2006, the underwriters exercised their overallotment option for 790,000 shares, and that sale closed on May 10, 2006. The Company used the net proceeds of $10,452,000, after the underwriting discount and before offering expenses, from the exercise of the overallotment option to repay outstanding borrowings under its credit facility with Bank of America.

17

Table of Contents

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% 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.

18

Table of Contents

Recent Developments

WCBB. On September 24, 2005, the tidal surge from Hurricane Rita caused damage to our WCBB facilities. We lost more than 150 days of production, but our main tank batteries, which handled approximately 70% of our production before Hurricane Rita, again became operational during the first quarter of 2006. We anticipate that the balance of our production facilities at WCBB will be brought on line within the next 90 days. We began returning wells to production during the first quarter of 2006, and as of May 15, 2006, 27 of the 57 active wells in the field prior to Hurricane Rita had been returned to production. We continue to reactivate our remaining shut-in WCBB wells and have recently begun producing from thirteen new wells that were drilled after Hurricane Rita but had not been completed due to the damage to our facilities caused by that storm. In addition, we have one new WCBB well that we expect to bring on line within the next ten days and three WCBB wells that we expect to bring on line early in the third quarter of 2006.

To date in 2006, we have drilled twelve new wells and production casing has been run on ten of these wells, with six of those wells now producing and four wells waiting on completion. The remaining two wells drilled to date in 2006 were shallow dry holes, including one exploratory well that was drilled to satisfy our drilling commitment to hold non-productive leasehold interests within the WCBB field. We are currently drilling our 13th 2006 well and within a week will begin drilling our 14th and 15th wells including a deeper, exploratory 11,600’ well.

The twelve wells we have drilled at WCBB to date in 2006 include six deep wells, two intermediate depth wells and four shallow wells. The deep wells, with total depths ranging from 8,850 to 10,147 feet, have approximately 509 feet of apparent net pay, the intermediate wells, with total depths ranging from 5,000 to 7,500 feet, have approximately 188 feet of apparent net pay and two of the shallow wells, at depths of less than 3,000 feet, have 40 feet of apparent net pay.

On September 20, 2005, prior to Hurricane Rita, aggregate net production at WCBB was 2,204 Boe. During the period March 20, 2006 through March 30, 2006, aggregate net production ranged from 1,754 Boe to 3,032 Boe per day. Aggregate net production from WCBB during the first quarter of 2006 was 48.0 Mboe. On May 9, 2006, net production at WCBB was 2,695 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, and during the period March 20, 2006 through March 30, 2006, aggregate net production from these wells ranged from approximately 181 Boe to 219 Boe per day. 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 have budgeted $8.0 million to replace and upgrade certain of our East Hackberry facilities in connection with our 2006 drilling program and intend to put the five remaining shut-in wells back on line when these facilities are completed. Aggregate net production from the East Hackberry field during the first quarter of 2006 was 14.6 Mboe. On May 9, 2006, net production at East Hackberry was 125 Boe.

West Hackberry Field. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 24 are shut-in and one has been converted to a saltwater disposal well. The remaining eight wells have been plugged and abandoned. Aggregate net production from the West Hackberry field during the first quarter of 2006 was 7 Mboe. On May 9, 2006, net production at West Hackberry was 79 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 March 31, 2006, we had incurred costs of $6,085,000 relating to the damage to these fields and facilities. Of this amount, $250,000 represents insurance deductible amounts that were expensed to lease operating expenses in 2005. During the three months ended March 31, 2006, we received $1,000,000 in insurance proceeds related to physical damage which is reflected in cash flows from investing activities in our statements of cash flows. The remaining $4,835,000 is included in insurance settlement receivables in the accompanying balance sheet at March 31, 2006. Subsequent to March 31, 2006, we have received $1,200,000 in insurance proceeds for physical damage. Based upon consultations with insurance adjustors and a review of the policies, we believe the entire balance of the insurance settlement receivables 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 an 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 period ended March 31, 2006, we accrued $2,655,000 of business interruption insurance proceeds in other income in the statements of income. As of March 31, 2006, we had received proceeds of $2,587,000 ($1,710,000 of which was accrued in 2005) related to business interruption for the period of November 24, 2005 to March 31, 2006. Such recoveries are presented as operating cash flows in the statements of cash flows. A balance of $1,778,000 is included in insurance settlement receivables in the accompanying balance sheet at March 31, 2006.

RESULTS OF OPERATIONS

Comparison of the Three Months Ended March 31, 2006 and 2005

We reported net income of $2,828,000 for the three months ended March 31, 2006, as compared to $1,930,000 for the three months ended March 31, 2005. This increase in net income was due to business interruption insurance recoveries of $2,655,000 and decreases in lease operating and depreciation, depletion and amortization expenses, partially offset by a decrease in production and related income due to Hurricane Rita.

Oil and Gas Revenues. For the three months ended March 31, 2006, we reported oil and gas revenues of $4,450,000, compared to revenues of $6,807,000 during the same period in 2005. This decrease in revenues is attributable to a 58% decrease in barrels of oil produced and sold to 64,000 barrels of oil for the three months ended March 31, 2006 from 154,000 barrels of oil for the same period in 2005. This decrease in oil production was due to damage to our WCBB facilities from Hurricane Rita in September

19

Table of Contents

2005. The impact of the decrease was partially offset by a 47% increase in the average oil price received for the three months ended March 31, 2006 to $60.74 per barrel from $41.41 per barrel for the same period in 2005.

The following table summarizes our oil and natural gas production and related pricing for the three months ended March 31, 2006 and 2005:

Lease Operating Expenses. Lease operating expenses not including production taxes decreased to $1,352,000 for the three months ended March 31, 2006 from $2,065,000 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 which we acquired in February 2005.

Production Taxes. Production taxes decreased to $565,000 for the three months ended March 31, 2006 from $805,000 for the same period in 2005. This decrease was directly related to a decrease in production and related oil and gas revenues as a result of the impact of Hurricane Rita.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased to $993,000 for the three months ended March 31, 2006, and consisted of $901,000 in depletion on oil and natural gas properties and $92,000 in depreciation of other property and equipment. This compares to total depreciation, depletion and amortization expense of $1,300,000 for the three months ended March 31, 2005. This decrease was due primarily to a decrease in our production due to Hurricane Rita, partially offset by an increase in our oil and natural gas property costs associated with our 2005 and 2006 drilling programs.

General and Administrative Expenses. Net general and administrative expenses increased to $1,002,000 for the three months ended March 31, 2006 from $384,000 for the same period in 2005. This increase was due primarily to increases in legal expenses, the costs of our engineering estimates, our NASDAQ filing fee, the 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 $32,000 to $149,000 for the three months ended March 31, 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 $270,000 for the three months ended March 31, 2006 from $58,000 for the same period in 2005 due to an increase in average debt outstanding. At March 31, 2006, total debt outstanding under our facility with Bank of America was $14.5 million. At March 31, 2005, there was no debt outstanding under this facility.

Interest Expense – Preferred Stock. During the three months ended March 31, 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 the Series A preferred stock. As a result, we incurred no interest expense relating to preferred stock during the three months ended March 31, 2006 as compared to $272,000 in interest expense incurred during the same period in 2005.

20

Table of Contents

Income Taxes. As of March 31, 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 March 31, 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 March 31, 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. Our ability to access any of these sources of funds can be significantly impacted by unexpected decreases in oil and natural gas prices.

Net cash flow provided by operating activities was $2,428,000 for the three months ended March 31, 2006, as compared to net cash flow provided by operating activities of $3,451,000 for the same period in 2005. This decrease was primarily the result of a decrease in cash received from oil and natural gas production, partially offset by a reduction in cash paid for lease operating expenses and production taxes.

Net cash used in investing activities for the three months ended March 31, 2006 was $9,935,000 as compared to $8,191,000 for the same period in 2005. During the three months ended March 31, 2006, we spent $9,369,000 in additions to oil and natural gas properties, of which $4,417,000 was spent on our 2006 drilling program, $2,391,000 was spent on expenses attributable to the wells drilled during 2005, $1,149,000 was spent on additions to oil and natural gas properties due to the hurricane with the remainder attributable mainly to capitalized general and administrative expenses. 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 three months ended March 31, 2006 was $7,232,000 as compared to $9,024,000 for the same period in 2005. The 2006 amount provided by financing activities is attributable to draws of $7,500,000 on our credit facility with Bank of America. The $9,024,000 provided by financing activities during the three months ended March 31, 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 $14,133,000 used to redeem our outstanding shares of 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 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, which we used to pay down outstanding 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 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. 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% (7.75% at March 31, 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 gas properties and other

21

Table of Contents

capital expenditures, acquisition opportunities, repair of damaged facilities and for other general corporate purposes. As of March 31, 2006, $14.5 million was outstanding under this credit facility. 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.

Building Loans. We had three loans associated with two of our buildings. One loan, in the original principal amount of $99,000, relates 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 outstanding Series A preferred stock.

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. 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 120 PUD 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 22 wells, recomplete 18 existing wells at our WCBB field and complete six wells that we drilled in 2005 for an estimated aggregate cost of $33.2 million. As of May 4, 2006, we had drilled twelve new wells in 2006 and production casing has been run on ten of these wells, with six of these wells non producing and four wells waiting on completion. The remaining two wells were shallow dry holes. We also plan to spend approximately $6.0 million during 2006 for facilities at WCBB, including the purchase of five new compressors.

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. We currently intend to drill six wells during 2006 at East Hackberry to measured depths of approximately 13,000 feet using directional drilling techniques. We have budgeted $12.5 million for these wells. 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 have budgeted approximately $8.0 million during 2006 for new facilities and upgrades to existing facilities to support our proposed East Hackberry drilling program.

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 March 31, 2006, the account totaled approximately $700,000; however, should our liability for the cash flow hedges continue to increase, further cash calls may be required.

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 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

22

Table of Contents

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 March 31, 2006, the plugging and abandonment trust totaled approximately $2,904,000, including interest received during 2006 of approximately $26,000. We have plugged 206 wells at WCBB since we began our plugging program in 1997, which management believes fulfills its minimum plugging obligation through March 31, 2006. 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 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 our adoption of SFAS No. 123(R). During the first three months of 2006, our stock-based compensation expense was $166,000.

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.

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 March 31, 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 March 31, 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.

23

Table of Contents

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

None.

ITEM 5. OTHER INFORMATION

(a) None

(b) None

ITEM 6. EXHIBITS

24

Table of Contents

25

Table of Contents

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.

26