UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended: September 30, 2005 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _________________ Commission file number: 1-10671 THE MERIDIAN RESOURCE CORPORATION (Exact name of registrant as specified in its charter) TEXAS 76-0319553 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 1401 ENCLAVE PARKWAY, SUITE 300, HOUSTON, TEXAS 77077 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: 281-597-7000 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 and 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). 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] Number of shares of common stock outstanding at November 4, 2005: 86,765,263 Page 1 of 38 THE MERIDIAN RESOURCE CORPORATION QUARTERLY REPORT ON FORM 10-Q INDEX Page Number ------ PART I - FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Statements of Operations (unaudited) for the Three Months and Nine Months Ended September 30, 2005 and 2004 3 Consolidated Balance Sheets as of September 30, 2005 (unaudited) and December 31, 2004 4 Consolidated Statements of Cash Flows (unaudited) for the Nine Months Ended September 30, 2005 and 2004 6 Consolidated Statements of Stockholders' Equity (unaudited) for the Nine Months Ended September 30, 2005 and 2004 7 Consolidated Statements of Comprehensive Income (Loss) (unaudited) for the Three Months and Nine Months Ended September 30, 2005 and 2004 8 Notes to Consolidated Financial Statements (unaudited) 9 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 18 Item 3. Quantitative and Qualitative Disclosures about Market Risk 29 Item 4. Controls and Procedures 30 PART II - OTHER INFORMATION Item 1. Legal Proceedings 31 Item 6. Exhibits 31 SIGNATURES 32 2 PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (thousands, except per share information) (unaudited) THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ---------------------- ---------------------- 2005 2004 2005 2004 --------- --------- --------- --------- REVENUES: Oil and natural gas $ 36,664 $ 52,951 $ 130,882 $ 149,156 Price risk management activities 60 ---- (400) ---- Interest and other 121 86 510 176 --------- --------- --------- --------- 36,845 53,037 130,992 149,332 --------- --------- --------- --------- OPERATING COSTS AND EXPENSES: Oil and natural gas operating 3,431 3,057 12,223 8,811 Severance and ad valorem taxes 2,189 2,176 6,687 7,005 Depletion and depreciation 19,725 28,387 70,452 77,440 General and administrative 3,961 4,028 13,345 10,723 Hurricane damage repairs 750 ---- 750 ---- Write-down of securities held ---- 195 ---- 195 Accretion expense 272 147 798 414 --------- --------- --------- --------- 30,328 37,990 104,255 104,588 --------- --------- --------- --------- EARNINGS BEFORE INTEREST AND INCOME TAXES 6,517 15,047 26,737 44,744 --------- --------- --------- --------- OTHER EXPENSES: Interest expense 1,194 1,624 3,276 5,594 Debt conversion expense ---- ---- ---- 1,188 --------- --------- --------- --------- 1,194 1,624 3,276 6,782 --------- --------- --------- --------- EARNINGS BEFORE INCOME TAXES 5,323 13,423 23,461 37,962 --------- --------- --------- --------- INCOME TAXES: Current (860) (600) (603) 1,500 Deferred 2,907 5,500 9,633 12,500 --------- --------- --------- --------- 2,047 4,900 9,030 14,000 --------- --------- --------- --------- NET EARNINGS: 3,276 8,523 14,431 23,962 Dividends on preferred stock ---- 737 902 3,144 --------- --------- --------- --------- NET EARNINGS APPLICABLE TO COMMON STOCKHOLDERS $ 3,276 $ 7,786 $ 13,529 $ 20,818 ========= ========= ========= ========= NET EARNINGS PER SHARE: Basic $ 0.04 $ 0.10 $ 0.16 $ 0.30 Diluted $ 0.04 $ 0.09 $ 0.15 $ 0.27 WEIGHTED AVERAGE NUMBER OF COMMON SHARES: Basic 86,683 76,678 83,771 69,690 Diluted 92,134 83,359 89,337 76,852 See notes to consolidated financial statements. 3 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (thousands of dollars) SEPTEMBER 30, DECEMBER 31, 2005 2004 ------------- ------------ (unaudited) ASSETS CURRENT ASSETS: Cash and cash equivalents $ 15,774 $ 24,297 Restricted cash 1,987 891 Accounts receivable, less allowance for doubtful accounts of $240 [2005 and 2004] 16,661 27,763 Prepaid expenses and other 3,675 2,263 Assets from price risk management activities 440 5,705 ---------- ---------- Total current assets 38,537 60,919 ---------- ---------- PROPERTY AND EQUIPMENT: Oil and natural gas properties, full cost method (including $36,596 [2005] and $34,731 [2004] not subject to depletion) 1,482,169 1,377,649 Land 48 478 Equipment and other 6,476 10,039 ---------- ---------- 1,488,693 1,388,166 Less accumulated depletion and depreciation 1,005,693 938,965 ---------- ---------- Total property and equipment, net 483,000 449,201 ---------- ---------- OTHER ASSETS 1,443 2,272 ---------- ---------- TOTAL ASSETS $ 522,980 $ 512,392 ========== ========== See notes to consolidated financial statements. 4 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (continued) (thousands of dollars) SEPTEMBER 30, DECEMBER 31, 2005 2004 ------------- --------- (unaudited) LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable $ 13,333 $ 14,983 Revenues and royalties payable 5,744 8,117 Due to affiliates 2,153 3,866 Notes payable 2,049 870 Accrued liabilities 15,670 21,406 Liabilities from price risk management activities 19,650 8,003 Asset retirement obligations 3,065 1,331 Current income taxes payable ---- 105 --------- --------- Total current liabilities 61,664 58,681 --------- --------- LONG-TERM DEBT 75,129 75,129 --------- --------- OTHER: Deferred income taxes 25,958 22,639 Liabilities from price risk management activities 864 ----- Asset retirement obligations 7,709 8,293 Other 4 20 --------- --------- 34,535 30,952 --------- --------- COMMITMENTS AND CONTINGENCIES (NOTE 5) REDEEMABLE CONVERTIBLE PREFERRED STOCK: Preferred stock, $1.00 par value (1,500,000 shares authorized, None [2005] and 315,886 [2004] shares of Series C Redeemable Convertible Preferred Stock outstanding at stated value) ---- 31,589 --------- --------- STOCKHOLDERS' EQUITY: Common stock, $0.01 par value (200,000,000 shares authorized, 86,748,469 [2005] and 79,215,394 [2004] outstanding) 899 821 Additional paid-in capital 524,175 490,351 Accumulated deficit (159,715) (173,244) Accumulated other comprehensive loss (13,306) (1,574) Unamortized deferred compensation (401) (313) --------- --------- Total stockholders' equity 351,652 316,041 --------- --------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 522,980 $ 512,392 ========= ========= See notes to consolidated financial statements. 5 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (thousands of dollars) (unaudited) NINE MONTHS ENDED SEPTEMBER 30, ------------------------ 2005 2004 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net earnings $ 14,431 $ 23,962 Adjustments to reconcile net earnings to net cash provided by operating activities: Debt conversion expense ---- 1,188 Depletion and depreciation 70,452 77,440 Amortization of other assets 333 1,468 Non-cash compensation 1,460 1,267 Non-cash price risk management activities 400 ---- Write-down of securities held ---- 195 Accretion expense 798 414 Deferred income taxes 9,633 12,500 Changes in assets and liabilities: Restricted cash (1,096) ---- Accounts receivable 11,102 (362) Prepaid expenses and other (1,412) (1,528) Due to affiliates (1,713) 1,614 Accounts payable (1,650) 1,904 Revenues and royalties payable (2,373) (3,935) Accrued liabilities and other (3,933) 10,934 --------- --------- Net cash provided by operating activities 96,432 127,061 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Additions to property and equipment (103,837) (99,899) Proceeds from (settlements on) sale of property (45) (73) --------- --------- Net cash used in investing activities (103,882) (99,972) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Reductions in long-term debt ---- (53,320) Increase in notes payable, net 1,179 1,404 Issuance of stock/exercise of options, net 13 95,009 Repurchase of common stock ---- (49,291) Preferred dividends (2,166) (5,248) Additions to deferred loan costs (99) (16) --------- --------- Net cash used in financing activities (1,073) (11,462) --------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (8,523) 15,627 --------- --------- Cash and cash equivalents at beginning of period 24,297 12,821 --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 15,774 $ 28,448 --------- --------- INFORMATION Non-cash financing activities: Conversion of preferred stock $ (30,625) $ (27,766) Issuance of shares for settlement of accrued liabilities $ (1,716) $ ---- Conversion of convertible subordinated debt $ ---- $ (20,000) See notes to consolidated financial statements. 6 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY NINE MONTHS ENDED SEPTEMBER 30, 2005 AND 2004 (in thousands) (unaudited) Common Stock Additional ------------------------ Paid-In Accumulated Shares Par Value Capital Deficit --------- --------- --------- --------- Balance, December 31, 2003 61,725 $ 644 $ 394,177 $(202,492) Issuance of rights to common stock ----- 3 1,388 ----- Company's 401(k) plan contribution 44 ----- 275 ----- Exercise of stock options 25 ----- 120 ----- Compensation expense ----- ----- ----- ----- Accum. other comprehensive loss ----- ----- ----- ----- Write-down of securities held ----- ----- ----- ----- Issuance for conversion of pref stock 6,484 65 27,701 ----- Issuance for conversion of sub debt 4,209 42 21,146 ----- Issuance of shares frm stock offering 13,800 138 94,476 ----- Repurchase of common stock ----- ----- ----- ----- Retirement of treasury stock (09/04) (7,082) (71) (49,220) ----- Preferred dividends ----- ----- ----- (3,144) Net earnings ----- ----- ----- 23,962 --------- --------- --------- --------- Balance, September 30, 2004 79,205 $ 821 $ 490,063 $(181,674) ========= ========= ========= ========= Balance, December 31, 2004 79,215 $ 821 $ 490,351 $(173,244) Issuance of rights to common stock ----- 3 1,365 ----- Company's 401(k) plan contribution 36 ----- 180 ----- Exercise of stock options 49 ----- 163 ----- Compensation expense ----- ----- ----- ----- Accum. other comprehensive income ----- ----- ----- ----- Issuance for conversion of pref stock 7,099 71 30,554 ----- Issuance cost - 2004 stock offering ----- ----- (150) ----- Issuance of shares as compensation 349 4 1,712 ----- Preferred dividends ----- ----- ----- (902) Net earnings ----- ----- ----- 14,431 --------- --------- --------- --------- Balance, September 30, 2005 86,748 $ 899 $ 524,175 $(159,715) ========= ========= ========= ========= Accumulated Other Unamortized Treasury Stock Comprehensive Deferred ------------------------ Loss Compensation Shares Cost Total --------- --------- --------- --------- --------- Balance, December 31, 2003 $ (7,704) $ (290) ----- $ ----- $ 184,335 Issuance of rights to common stock ----- (1,391) ----- ----- ----- Company's 401(k) plan contribution ----- ----- ----- ----- 275 Exercise of stock options ----- ----- ----- ----- 120 Compensation expense ----- 1,267 ----- ----- 1,267 Accum. other comprehensive loss (2,027) ----- ----- ----- (2,027) Write-down of securities held 185 ----- ----- ----- 185 Issuance for conversion of pref stock ----- ----- ----- ----- 27,766 Issuance for conversion of sub debt ----- ----- ----- ----- 21,188 Issuance of shares frm stock offering ----- ----- ----- ----- 94,614 Repurchase of common stock ----- ----- (7,082) (49,291) (49,291) Retirement of treasury stock (09/04) ----- ----- 7,082 49,291 ----- Preferred dividends ----- ----- ----- ----- (3,144) Net earnings ----- ----- ----- ----- 23,962 --------- --------- --------- --------- --------- Balance, September 30, 2004 $ (9,546) $ (414) ----- $ ----- $ 299,250 ========= ========= ========= ========= ========= Balance, December 31, 2004 $ (1,574) $ (313) ----- $ ----- $ 316,041 Issuance of rights to common stock ----- (1,368) ----- ----- ----- Company's 401(k) plan contribution ----- ----- ----- ----- 180 Exercise of stock options ----- ----- ----- ----- 163 Compensation expense ----- 1,280 ----- ----- 1,280 Accum. other comprehensive income (11,732) ----- ----- ----- (11,732) Issuance for conversion of pref stock ----- ----- ----- ----- 30,625 Issuance cost - 2004 stock offering ----- ----- ----- ----- (150) Issuance of shares as compensation ----- ----- ----- ----- 1,716 Preferred dividends ----- ----- ----- ----- (902) Net earnings ----- ----- ----- ----- 14,431 --------- --------- --------- --------- --------- Balance, September 30, 2005 $ (13,306) $ (401) ----- $ ----- $ 351,652 ========= ========= ========= ========= ========= See notes to consolidated financial statements. 7 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (thousands of dollars) (unaudited) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2005 2004 2005 2004 -------- -------- -------- -------- Net earnings applicable to common stockholders $ 3,276 $ 7,786 $ 13,529 $ 20,818 Other comprehensive income (loss), net of tax, for unrealized losses from hedging activities: Unrealized holding gains (losses) arising during period (1) (14,076) (4,218) (20,481) (10,298) Reclassification adjustments on settlement of contracts (2) 4,314 3,161 8,749 8,271 -------- -------- -------- -------- (9,762) (1,057) (11,732) (2,027) -------- -------- -------- -------- Total comprehensive income (loss) $ (6,486) $ 6,729 $ 1,797 $ 18,791 ======== ======== ======== ======== (1) net of income tax (expense) benefit $ 7,579 $ 2,271 $ 11,028 $ 5,545 (2) net of income tax expense $ (2,323) $ (1,702) $ (4,711) $ (4,453) See notes to consolidated financial statements. 8 THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited) 1. BASIS OF PRESENTATION The consolidated financial statements reflect the accounts of The Meridian Resource Corporation and its subsidiaries (the "Company" or "Meridian") after elimination of all significant intercompany transactions and balances. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2004, as filed with the Securities and Exchange Commission. The financial statements included herein as of September 30, 2005, and for the three month and nine month periods ended September 30, 2005 and 2004, are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of financial position and of the results for the interim periods presented. Certain minor reclassifications of prior period statements have been made to conform to current reporting practices. The results of operations for interim periods are not necessarily indicative of results to be expected for a full year. 2. ACCRUED LIABILITIES Below is the detail of our accrued liabilities on our balance sheets as of September 30, 2005 and December 31, 2004 (thousands of dollars): SEPTEMBER 30, DECEMBER 31, 2005 2004 ------- ------------ Capital Expenditures $10,178 $12,662 Bonuses 1,510 3,355 Dividends ---- 1,346 Other 3,982 4,043 ------- ------- TOTAL $15,670 $21,406 ======= ======= 3. DEBT CREDIT FACILITY. On December 23, 2004, the Company amended its existing credit facility to provide for a four-year $200 million senior secured credit facility (the "Credit Facility") with Fortis Capital Corp., as administrative agent, sole lead arranger and bookrunner; Comerica Bank as syndication agent; and Union Bank of California as documentation agent. Bank of Nova Scotia, Allied Irish Banks p.l.c., RZB Finance LLC and Standard Bank PLC completed the syndication group. The initial borrowing base under the Credit Facility is $130 million and it was reaffirmed by the syndication group effective as of November 1, 2005, and continuing until the next scheduled redetermination date. As of September 30, 2005, outstanding borrowings under the Credit Facility totaled $75.1 million. The Credit Facility is subject to semi-annual borrowing base redeterminations on April 30 and October 31 of each year. In addition to the scheduled semi-annual borrowing base redeterminations, the lenders or the Company have the right to redetermine the borrowing base at any time, provided that no party can request more than one such redetermination between the regularly scheduled borrowing base redeterminations. Obligations under the Credit Facility are secured by pledges of outstanding capital stock of the Company's subsidiaries and by a first priority lien on not less than 75% (95% in the case of an event of default) of its 9 present value of proved oil and gas properties. In addition, the Company is required to deliver to the lenders and maintain satisfactory title opinions covering not less than 70% of the present value of proved oil and gas properties. The Credit Facility also contains other restrictive covenants, including, among other items, maintenance of certain financial ratios, restrictions on cash dividends on Common Stock and under certain circumstances Preferred Stock, limitations on the redemption of Preferred Stock and an unqualified audit report on the Company's consolidated financial statements, with which the Company is in compliance. Under the Credit Facility, the Company may secure either (i) (a) an alternative base rate loan that bears interest at a rate per annum equal to the greater of the administrative agent's prime rate; or (b) federal funds-based rate plus -1/2 of 1%, plus an additional 0.5% to 1.25% depending on the ratio of the aggregate outstanding loans and letters of credit to the borrowing base or; (ii) a Eurodollar base rate loan that bears interest, generally, at a rate per annum equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.25%, depending on the ratio of the aggregate outstanding loans and letters of credit to the borrowing base. At September 30, 2005, the three-month LIBOR interest rate was 4.065%. The Credit Facility also provides for commitment fees of 0.375% calculated on the difference between the borrowing base and the aggregate outstanding loans under the Credit Facility. 4. 8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK A private placement of $66.9 million of 8.5% redeemable convertible preferred stock was completed during May 2002. The preferred stock was convertible into shares of the Company's Common Stock at a conversion price of $4.45 per share. Dividends were payable semi-annually in cash or additional preferred stock. At the option of the Company, one-third of the preferred shares could be forced to convert to Common Stock if the closing price of the Company's Common Stock exceeded 150% of the conversion price for 30 out of 40 consecutive trading days on the New York Stock Exchange. The preferred stock was subject to redemption at the option of the Company after March 2005, and mandatory redemption on March 31, 2009. During the first six months of 2005, the Company completed the conversion of all of the remaining outstanding shares of preferred stock to Common Stock, with $31.6 million of stated value being converted into approximately 7.1 million shares of the Company's Common Stock. 5. COMMITMENTS AND CONTINGENCIES LITIGATION. H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a claim against Meridian for damages "estimated to exceed several million dollars" for Meridian's alleged gross negligence and willful misconduct under certain agreements concerning certain wells and property in the S.W. Holmwood and E. Lake Charles Prospects in Calcasieu Parish of Louisiana, as a result of Meridian's satisfying a prior adverse judgment in favor of Amoco Production Company. Meridian has filed an answer denying Hawkins' claims and asserted a counterclaim for attorney's fees, court costs and other expenses, and for declaratory relief that Meridian is entitled to retain the amounts that it had been paid by Hawkins. The Company has not provided any amount for this matter in its financial statements at September 30, 2005. ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with numerous other oil companies) in various similar lawsuits concerning several fields in which the Company has had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs' lands from alleged contamination and otherwise from the defendants' oil and gas operations. The Company has not provided any amount for these matters in the financial statements at September 30, 2005. 10 LITIGATION INVOLVING INSURABLE ISSUES. There are no other material legal proceedings which exceed our insurance limits to which Meridian or any of its subsidiaries is a party or to which any of its property is subject, other than ordinary and routine litigation incidental to the business of producing and exploring for crude oil and natural gas. 6. STOCKHOLDERS' EQUITY COMMON STOCK. In August 2004, the Company completed a public offering of 13,800,000 shares of Common Stock at a price of $7.25 per share. The total proceeds of the offering, net of issuance costs, received by the Company were approximately $94.6 million. The Company repurchased all of the 7,082,030 shares of its Common Stock that were beneficially owned by Shell Oil Company for $49.3 million and a portion of the remaining proceeds of that equity offering was used to repay borrowings under the Company's senior secured credit agreement, which resulted in an increase in funds available to the Company to accelerate planned capital expenditures for drilling activities and related pipeline construction. The repurchased 7,082,030 shares of Common Stock that were held in Treasury Stock were retired as of September 30, 2004. As previously noted, during the nine months ended September 30, 2004, 6.5 million shares of Common Stock were issued for the conversion of the 8.5% Redeemable Convertible Preferred Stock and 4.2 million shares of Common Stock was issued for the early retirement of the 9 -1/2% Convertible Subordinated Notes. During the the first nine months of 2005, the Company completed the conversion of all of the remaining outstanding shares of the 8.5% Redeemable Convertible Preferred Stock with the issuance of approximately 7.1 million shares of the Company's Common Stock. 11 7. EARNINGS PER SHARE (in thousands, except per share) The following tables set forth the computation of basic and diluted net earnings per share: THREE MONTHS ENDED SEPTEMBER 30, 2005 2004 -------- ------- Numerator: Net earnings applicable to common stockholders $ 3,276 $ 7,786 Plus income impact of assumed conversions: Preferred stock dividends N/A N/A ------- ------- Net earnings applicable to common stockholders plus assumed conversions $ 3,276 $ 7,786 ------- ------- Denominator: Denominator for basic earnings per share - weighted-average shares outstanding 86,683 76,678 Effect of potentially dilutive common shares: Warrants 4,820 4,839 Employee and director stock options 631 1,842 Redeemable preferred stock N/A N/A ------- ------- Denominator for diluted earnings per share - weighted-average shares outstanding and assumed conversions 92,134 83,359 ======= ====== Basic earnings per share $ 0.04 $ 0.10 ======= ====== Diluted earnings per share $ 0.04 $ 0.09 ======= ====== NINE MONTHS ENDED SEPTEMBER 30, 2005 2004 -------- ------- Numerator: Net earnings applicable to common stockholders $13,529 $20,818 Plus income impact of assumed conversions: Preferred stock dividends N/A N/A Interest on convertible subordinated notes ----- 270 ------- ------- Net earnings applicable to common stockholders plus assumed conversions $13,529 $21,088 ------- ------- Denominator: Denominator for basic earnings per share - weighted-average shares outstanding 83,771 69,690 Effect of potentially dilutive common shares: Warrants 4,701 4,439 Employee and director stock options 865 1,584 Convertible subordinated notes ----- 1,139 Redeemable preferred stock N/A N/A ------- ------- Denominator for diluted earnings per share - weighted-average shares outstanding and assumed conversions 89,337 76,852 ======= ====== Basic earnings per share $ 0.16 $ 0.30 ======= ====== Diluted earnings per share $ 0.15 $ 0.27 ======= ====== 12 8. OIL AND NATURAL GAS HEDGING ACTIVITIES The Company addresses market risk by selecting instruments with value fluctuations which correlate strongly with the underlying commodity being hedged. The Company enters into derivative contracts to hedge the price risks associated with a portion of anticipated future oil and gas production. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at or prior to expiration or are exchanged for physical delivery contracts. The Company does not obtain collateral to support the agreements, but monitors the financial viability of counter-parties and believes its credit risk is minimal on these transactions. In the event of nonperformance by the counter-party, the Company would be exposed to price risk. The Company has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. The Company's results of operations and operating cash flows are impacted by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, the Company has entered into various derivative contracts. These contracts allow the Company to predict with greater certainty the effective oil and natural gas prices to be received for hedged production. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, these derivative instruments continue to be highly effective in achieving the risk management objectives for which they were intended. These contracts have been designated as cash flow hedges as provided by Statement of Financial Accounting Standards ("SFAS") 133 and any changes in fair value are recorded in other comprehensive income until earnings are affected by the variability in cash flows of the designated hedged item. Any changes in fair value resulting from the ineffectiveness of the hedge are reported in the consolidated statement of operations as a component of revenues. The Company recognized a gain related to hedge ineffectiveness of approximately $0.1 million during the three months and a loss of approximately $0.4 million during the nine months ended September 30, 2005, and none during the three and nine months ended September 30, 2004. The estimated September 30, 2005 fair value of the Company's oil and natural gas derivatives was a net unrealized loss of $20.5 million ($13.3 million net of tax) which is recorded in Accumulated Other Comprehensive Loss on the Company's consolidated balance sheet. Based upon September 30, 2005 oil and natural gas commodity prices, approximately $19.7 million of the loss deferred in other comprehensive income could potentially lower gross revenues over the next twelve months. The derivative contracts expire at various dates through July 31, 2007. Net settlements under these derivative contracts reduced oil and natural gas revenues by $5,517,000 and $4,863,000 for the three months ended September 30, 2005 and 2004, respectively, and by $12,340,000 and $12,724,000 for the nine months ended September 30, 2005 and 2004, respectively, as a result of hedging transactions. The Notional Amount is equal to the total net volumetric hedge position of the Company during the periods presented. The positions effectively hedge approximately 26% of the proved developed natural gas production and 28% of the proved developed oil production during the respective terms of the derivative contracts. The fair values of the hedges are based on the difference between the strike price and the New York Mercantile Exchange future prices for the applicable trading months. The fair value of the hedging agreements is recorded on our consolidated balance sheet as separately identified assets or liabilities, except for $451 thousand included in Other Assets. The estimated fair value of our hedging agreements as of September 30, 2005, is provided below: 13 Swap / Floor Ceiling Fair Value Notional Price Price Sept 30, 2005 Type Amount ($ per unit) ($ per unit) (in thousands) ------ --------- ------------ ------------ -------------- NATURAL GAS (MMBTU) Oct 2005 Swap 350,000 $ 6.34 N/A $ (2,646) Oct 2005 Collar 350,000 $ 6.50 $ 7.90 (2,102) Nov 2005 - Mar 2006 Collar 2,980,000 $ 7.50 $ 11.25 (10,381) Apr 2006 - Oct 2006 Collar 1,130,000 $ 8.00 $ 14.50 (47) -------- Total Natural Gas (15,176) -------- CRUDE OIL (BBLS) Oct 2005 - Jul 2006 Collar 173,000 $ 37.50 $ 47.50 (3,356) Oct 2005 - Jul 2006 Collar 33,000 $ 40.00 $ 50.00 (571) Aug 2006 - Jul 2007 Collar 168,000 $ 50.00 $ 74.00 (521) -------- Total Crude Oil (4,448) -------- $(19,624) ======== As of September 30, 2005, the Company had designated a natural gas hedge related to the first 380,000 Mmbtu produced and sold from its Biloxi Marshlands ("BML") project area during September 2005. As previously announced, Hurricane Katrina caused a production disruption during September 2005 in the Company's BML project area, whereby all of the Company's natural gas production was curtailed during the hedge period. Since the Company was unable to deliver natural gas, a hedging loss of approximately $1.1 million was deferred until production was re-established in October 2005, as per the Financial Accounting Standards Board's ("FASB") SFAS 133 Implementation Issue No. G3. 9. STOCK-BASED COMPENSATION SFAS 123, "Accounting for Stock-Based Compensation," as amended by SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure," established accounting and disclosure requirements using a fair value-based method of accounting for stock-based employee compensation plans. As provided for under SFAS 123, there has been no amount of compensation expense recognized for the Company's stock option plans. The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board ("APB") Opinion 25, "Accounting for Stock Issued to Employees." Compensation expense is recorded for restricted stock awards over the requisite vesting periods based upon the market value on the date of the grant. No stock-based compensation expense was recorded in the three or nine month periods ended September 30, 2005 and 2004. The following is a reconciliation of reported earnings and earnings per share as if the Company used the fair value method of accounting for stock-based compensation. Fair value is calculated using the Black-Scholes option-pricing model. 14 (In thousands, except per share data) Three Months Ended September 30, ------------------------------------- 2005 2004 --------- --------- Net earnings applicable to common stockholders as reported $ 3,276 $ 7,786 Stock-based compensation (expense) benefit determined under fair value method for all awards, net of tax (64) (66) --------- --------- Net earnings applicable to common stockholders pro forma $ 3,212 $ 7,720 ========= ========= Basic earnings per share: As reported $ 0.04 $ 0.10 Pro forma $ 0.04 $ 0.10 Diluted earnings per share: As reported $ 0.04 $ 0.09 Pro forma $ 0.04 $ 0.09 (In thousands, except per share data) Nine Months Ended September 30, ------------------------------------- 2005 2004 --------- --------- Net earnings applicable to common stockholders as reported $ 13,529 $ 20,818 Stock-based compensation expense determined under fair value method for all awards, net of tax (162) (74) --------- --------- Net earnings applicable to common stockholders pro forma $ 13,367 $ 20,744 ========= ========= Basic earnings per share: As reported $ 0.16 $ 0.30 Pro forma $ 0.16 $ 0.30 Diluted earnings per share: As reported $ 0.15 $ 0.27 Pro forma $ 0.15 $ 0.27 In December 2004, the FASB issued SFAS No. 123R which is a replacement statement to SFAS No. 123 entitled "Share-Based Payment." This statement also amends SFAS No. 95 "Statement of Cash Flows". This statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise's equity instruments or that may be settled by the issuance of such equity instruments. The statement would eliminate the ability to account for share-based compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued to Employees," and generally would require instead that such transactions be accounted for using a fair-value-based method. This statement will be effective for the Company for interim periods beginning after December 15, 2005. The impact on the results of operations would be similar to the pro forma disclosures made above. 10. ASSET RETIREMENT OBLIGATIONS On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations." This statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. The fair value of asset 15 retirement obligation liabilities has been calculated using an expected present value technique. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in the Company's asset retirement obligations fair value estimate since a reasonable estimate could not be made. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. This standard requires the Company to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. The following table describes the change in the Company's asset retirement obligations for the nine months ended September 30, 2005, and for the year ended December 31, 2004 (thousands of dollars): Asset retirement obligation at December 31, 2003 $ 4,102 Additional retirement obligations recorded in 2004 1,051 Settlements during 2004 (972) Revisions to estimates during 2004 4,842 Accretion expense for 2004 601 -------- Asset retirement obligation at December 31, 2004 9,624 Additional retirement obligations recorded in 2005 760 Settlements during 2005 (182) Revisions to estimates during 2005 (226) Accretion expense for 2005 798 -------- Asset retirement obligation at September 30, 2005 $ 10,774 ======== 11. NEW ACCOUNTING PRONOUNCEMENTS In December 2004, the FASB issued SFAS No. 123R which is a replacement statement to SFAS No. 123 entitled "Share-Based Payment." This statement also amends SFAS No. 95, "Statement of Cash Flows." This statement addresses the accounting for share-based payment transactions in which an enterprise receives employee services in exchange for (a) equity instruments of the enterprise or (b) liabilities that are based on the fair value of the enterprise's equity instruments or that may be settled by the issuance of such equity instruments. The statement would eliminate the ability to account for share-based compensation transactions using APB Opinion No. 25, "Accounting for Stock Issued to Employees," and generally would require instead that such transactions be accounted for using a fair-value-based method. This statement will be effective for the Company for interim periods beginning after December 15, 2005. The impact on the results of operations would be similar to the pro forma disclosures presented in Note 9. In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, "Accounting for Conditional Asset Retirement Obligations." This interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB No. 143, "Accounting for Asset Retirement Obligations." A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN No. 47 states that a Company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN No. 47 is effective for fiscal years ending after December 15, 2005. This interpretation does not have any impact to the Company's financial position, results of operations or cash flows. In May 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections -- a replacement of APB No. 20 and FASB No. 3." In order to enhance financial reporting consistency between periods, SFAS No. 154 modifies the requirements for the accounting and reporting of the direct effects of changes in 16 accounting principles. Under APB No. 20, the cumulative effect of voluntary changes in accounting principle was recognized in Net Income in the period of the change. Unlike the treatment previously prescribed by APB No. 20, retrospective application is now required, unless it is not practical to determine the specific effects in each period or the cumulative effect. If the period specific effects cannot be determined, it is required that the new accounting principle must be retrospectively applied in the earliest period possible to the balance sheet accounts and a corresponding adjustment be made to the opening balance of retained earnings or another equity account. If the cumulative effect cannot be determined, it is necessary to apply the new accounting principles prospectively at the earliest practical date. If it is not feasible to retrospectively apply the change in principle, the reason that this is not possible and the method used to report the change are required to be disclosed. The statement also provides that changes in accounting for depreciation, depletion or amortization should be treated as changes in accounting estimate inseparable from a change in an accounting principle and that disclosure of the preferability of the change is required. SFAS No. 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005. 17 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following is a discussion of The Meridian Resource Corporation and its subsidiaries' ("Meridian" or the "Company") financial operations for the three and nine months ended September 30, 2005 and 2004. The Company's consolidated financial statements included in this report, as well as our Annual Report on Form 10-K for the year ended December 31, 2004 (and the notes attached thereto), should be read in conjunction with this discussion. GENERAL. Management believes the Company's financial condition and operations are on sound footing as evidenced by the following: o Average daily production is currently approximately 73.2 Mmcfe/d, or approximately 105% of the pre-Hurricane Katrina level with more to be added in the near term; o Positive earnings have been maintained in the face of extremely difficult conditions during the third quarter; o Solid cash flows and liquidity, combined with low debt ratios maintain financial flexibility; o And a balanced inventory of exploration plays continues to allow the Company to grow production. Meridian ended 2004 and entered 2005 with greater than normal production declines related primarily to three of the Company's larger producing wells being shut in for workover and operational issues, compounded by a series of exploration dry holes drilled in an effort to extend the Company's Biloxi Marshlands prospect area beyond the geological and geographical limits of the traditional shallower Cris I sand section. Immediate actions were taken to address the production issues and the trend began to reverse during the second quarter as a result of several exploration successes in two of the Company's primary regions of exploration and development--Turtle Bayou/Ramos Complex area with discoveries at Turtle Island, Turtle Cove, Bayou Chene, Northwest Bayou Chene, Bayou Black and Turtle Shell; and in Biloxi Marshlands project area with new discoveries in the northeast quadrant at String of Pearls and in the extreme southwest quadrant at Bayou Gentilly. The exploration program remained intact with the identification of a series of offsets to the new discoveries with the necessary cash flows available to implement the Company's capital spending program during the balance of the third and fourth quarters of 2005. Poised to move forward with the second-half drilling program, the Company was confronted with major hurdles that began with Hurricane Dennis during June 2005 which left workover operations 1,000 feet shy of the target depth and days away from the potential of returning production to the Biloxi Marshlands 1-2 well at its prior rate or 7.5 Mmcfe/d (3.5 Mmcfe/d net). The hurdles culminated with the complete destruction of almost all of the Company's production facilities in the Biloxi Marshlands project area as the eye of Hurricane Katrina passed directly over the area. What followed in late August 2005 was a series of some of the greatest challenges in the history of the Gulf Coast and Meridian--the devastation of Hurricanes Katrina and Rita. Beginning August 28, 2005, the Company shut in all production in all effected areas in anticipation of Hurricane Katrina and removed all personnel from the field. With the support and assistance of its senior bank group, the Company's unutilized borrowing capacity ($55 million) allowed it to meet the challenges head on, to manage the problems of people, equipment, boats, barges, quarters, production equipment, and fabrication. Meridian began to restore lost production only forty-five (45) days after operations were initiated, beginning first with the return of production to the Company's Biloxi Marshlands Facility #1, followed by the reinstatement at the Biloxi Marshlands Facilities #2, #3 and #4, the successful recompletion operations at the SL 16049 well in the Ramos Complex and the addition of the Bayou Chene and Northwest Bayou Chene discoveries, with more to come following completion of pipeline and production facilities at Turtle Shell, Bayou Black, String of Pearls, Hornets Nest, and Bayou Gentilly. At present, without the addition of the above wells or full compression at all of the Biloxi facilities, the Company is currently producing 105% of pre-Katrina production levels. 18 To all who served to assist us in this effort, we are and will be forever grateful. These include our entire staff and contract personnel, especially the operations and production group, field staff experiencing first-hand their own personal losses, but who, after protecting their families, immediately (within hours and days of the storm's passing) returned to the field to bring our production back on stream. Our thanks also go to all of our service companies and suppliers of equipment, services, supplies and fabrication, and construction facilities. The financial restructuring the Company completed over the past several years allowed the Company to continue its plans for growth in spite of the fact that approximately 50% of the Company's existing production was shut-in for a significant portion of the third quarter of 2005. The Company's debt position remained low and the Company was able to realize a larger percentage of the commodity price increases experienced during the quarter as a result of expiration of the lower oil and gas hedge position. During the course of the first nine months of 2005, Meridian's exploration drilling activities were focused on extending the Biloxi Marshlands exploration play with the acquisition of the final 140 square miles of 3-D seismic data in the southwestern quadrant of its 400,000-acre option/lease acreage position and the drilling of extension wells to test and analyze the limits of the aerial extent of the play for the timely exercise of our lease options during December 2005. These activities focused on developing exploration concepts beyond the traditional Cris I type targets, with the objective of extending our understanding of all hydrocarbon indicators or signatures within the play and to the extreme limits of all areas within the proprietary 3-D survey. We were successful in establishing new production from new sands in the northeast quadrant of the acreage with the discovery of the String of Pearls Deltaic prospect well and then to the extreme southwest region of its acreage with the discovery of the Bayou Gentilly prospect in the pressured Cris I section. As a result, additional prospective acreage was identified and acquired for future drilling operations now scheduled for the remainder of 2005 and 2006. Information gained from the Company's drilling activities and newly acquired and reprocessed 3-D seismic data in the region has resulted in an increased knowledge base for future drilling. Prior to the interruptions in drilling and production caused by Hurricanes Katrina and Rita, we had scheduled the drilling of five additional wells in the area near the String of Pearls prospect well beginning with the Gato del Sol prospect. Although delayed, it is anticipated that we will resume drilling activities in the region upon the return of the Company's drilling rig during the fourth quarter 2005, with expectations to continue to drill one well per month in the Biloxi Marshlands project area through 2006. In addition, the Company has completed the development of its deeper prospects and anticipates beginning to drill the first such prospect during the first quarter 2006. Multiple stacked pay sands with three-way and four-way closures have been identified using the Company's reprocessed data applications confirming the existence of closures and sand respectively in several of the targeted objectives. Potential unrisked reserves range between 250 Bcfe and 750 Bcfe from two of the three proposed wells. Since inception of the Biloxi Marshlands project area, Meridian has expended approximately $184 million in the Biloxi Marshlands project area on lease options, leases, 3-D seismic acquisitions and processing, exploration drilling and completion activities, pipelines and production facilities. We have drilled 35 wells, completing 21 wells for a success rate of approximately 60% in multiple sand sections including the Deltaic, Cris I, both pressured and nonpressured, and Rob L sands. We have received a return of our investment of approximately $191 million and currently are producing approximately 31.8 Mmcfe/d (net) or 90% of pre-storm levels from the Biloxi Marshlands project area, not including 19 production from the String of Pearls, Hornets Nest and Bayou Gentilly wells and without full rate deliveries at all other facilities because full compression has not been reinstated to date. In general, production in Biloxi has outperformed predictions at locations with larger reservoirs and generally met expectations or disappointed expectations at smaller reservoir locations. The Company continues to increase its knowledge in the area as additional wells are drilled and placed on production in the region with expectations to improve our success ratios as we continue to exploit the area's reserves. The Company believes that no one has as much experience or knowledge about drilling in this region based on the newly acquired technical data and information in our exclusive possession. As a result, we believe that we have an advantage over our competition in the region for development of future opportunities after the exercise of our lease options in December 2005. We will be the only exploration company with the fully processed and merged proprietary 3-D data over the entire acreage position without seismic gaps in the data. In addition to the activities in our Biloxi Marshlands play, we began the drilling of our Turtle Bayou/Ramos Complex area patterned after our previously discovered Thornwell field and the Biloxi Marshlands models of lower risk, multiple-well exploration in areas where reserves have either been overlooked or bypassed by others in the area. During 2005, we successfully drilled and completed 6 wells with 2 dry holes. The most recent discovery was the Company's Turtle Shell prospect which was recently tested up to a rate of 4 Mmcfe/d with no water, beyond which point it was unnecessary to produce additional gas into the atmosphere prior to turning the well to production upon completion of pipeline tie-ins. Operations in this area were affected by the hurricanes but not to the same extent experienced in Biloxi Marshlands. While we were delayed with our operations and production because of shutting in producing wells and mobilizing people and drilling/workover rigs to safe harbor prior to the storms arrival, we have completed the drilling of the Turtle Shell prospect well and the successful recompletion of the SL16049 well, returning the well to production at a rate of approximately 5.1 Mmcfe/d (net). With the addition of the SL 16049 well and the addition of the Bayou Chene discoveries, current production post Hurricanes Katrina and Rita from the Turtle Bayou/Ramos Complex wells net to the Company has reached 29.2 Mmcfe/d (net), or 155% of pre-storm production levels. These rates do not include the Turtle Shell prospect well which is expected to be on line and producing within 30 days. We have identified multiple additional prospects in this new area of exploration and are currently drilling the Company's Bayou Lawrence prospect at approximately 8,300 feet measured depth ("MD") with a target depth of 10,900 feet MD. Depending on the Company's continued success, it has identified a minimum of 3-8 additional prospects in this area and will continue exploration activities to develop other similar leads in the immediate area. Other activities during the past nine months include the previously reported joint venture participation in the East Texas Woodbine play, further extending the Company's seismic-based exploration strategy to areas that we believe will not only add to our reserve base but lengthen our overall reserve life ratios. Since acquiring the acreage positions in conjunction with our partner, we have added additional acreage under identified prospects and have permitted three drilling locations as we await two rigs that have been contracted to drill the first two wells, with one rig anticipated to remain and drill additional follow-on wells based on results. Depending on the Company's success in the area, we have budgeted the drilling of up to nine wells for the remainder of 2005 and 2006. Meridian continues to expand its domestic exploration program to insure a balance of higher rate wells delivering earlier cash flows typically found in its core area of the Gulf Coast region of south Louisiana and southeast Texas with longer lived conventional and unconventional plays that provide the Company with a longer lived reserve base and multiple-well development opportunities where the earlier cash flows can be deployed to add steady growth in reserves over the long term. We are pleased with our initial efforts in this area and look forward to continued success in this extension of the Company's business plan. INDUSTRY CONDITIONS. Revenues, profitability and future growth rates of Meridian are substantially dependent upon prevailing prices for oil and natural gas. Oil and natural gas prices have been extremely volatile in recent years and are affected by many factors outside of our control. Our average oil price (after adjustments for hedging activities) for the three months ended September 30, 2005, was $43.92 per barrel compared to $30.26 per barrel for the three months ended September 30, 2004, and $31.14 per barrel for the three months ended June 30, 2005. Our average natural gas price (after adjustments for hedging activities) for the three months ended September 30, 2005, was $7.32 per Mcf compared to $5.58 per Mcf for the three months ended September 30, 2004, and $6.63 per Mcf for the three months ended June 30, 2005. Fluctuations in prevailing prices for oil and natural gas have several important consequences to us, including affecting the level of cash flow received from our producing properties, the timing of exploration of certain prospects and our access to capital markets, which could impact our revenues, profitability and ability to maintain or increase our exploration and development program. 20 CRITICAL ACCOUNTING POLICIES AND ESTIMATES. The Company's discussion and analysis of its financial condition and results of operation are based upon consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted and adopted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. See the Company's Annual Report on Form 10-K for the year ended December 31, 2004, for further discussion. 21 RESULTS OF OPERATIONS THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2004 OPERATING REVENUES. Third quarter 2005 oil and natural gas revenues, which include oil and natural gas hedging activities (see Note 8 of Notes to Consolidated Financial Statements), decreased $16.3 million (31%) as compared to third quarter 2004 revenues due to a 48% decrease in production volumes primarily due to natural production declines and hurricane-related losses (see "General" above), partially offset by a 34% increase in average commodity prices on a natural gas equivalent basis. Our average daily production decreased from 105.1 Mmcfe during the third quarter of 2004 to 54.5 Mmcfe for the third quarter of 2005. Oil and natural gas production volume totaled 5,010 Mmcfe for the third quarter of 2005, compared to 9,671 Mmcfe for the comparable period of 2004. The following table summarizes the Company's operating revenues, production volumes and average sales prices for the three months ended September 30, 2005 and 2004: THREE MONTHS ENDED SEPTEMBER 30, INCREASE 2005 2004 (DECREASE) ------- ------- ------- Production Volumes: Oil (Mbbl) 203 320 (37%) Natural gas (MMcf) 3,790 7,753 (51%) Mmcfe 5,010 9,671 (48%) Average Sales Prices: Oil (per Bbl) $ 43.92 $ 30.26 45% Natural gas (per Mcf) $ 7.32 $ 5.58 31% Mmcfe $ 7.32 $ 5.48 34% Operating Revenues (000's): Oil $ 8,916 $ 9,683 (8%) Natural gas 27,748 43,268 (36%) ------- ------- Total Operating Revenues $36,664 $52,951 (31%) ======= ======= OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis increased $0.3 million (12%) to $3.4 million during the third quarter of 2005, compared to $3.1 million in 2004. On a unit basis, lease operating expenses increased $0.36 per Mcfe to $0.68 per Mcfe for the third quarter of 2005 from $0.32 per Mcfe for the third quarter of 2004. The increase in per unit cost is a reflection of lower production volumes between the two periods, as explained above. SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes totaled $2.2 million for both the third quarter of 2005 and 2004. A decrease in oil and natural gas production was offset by an increase in oil prices and a higher natural gas tax rate. Meridian's oil and natural gas production is primarily from Louisiana, and is therefore subject to Louisiana severance tax. The severance tax rates for Louisiana are 12.5% of gross oil revenues and were $0.252 per Mcf for natural gas, an increase from $0.208 per Mcf for the third quarter of 2004. On an equivalent unit of production basis, severance and ad valorem taxes increased to $0.44 per Mcfe from $0.23 per Mcfe for the comparable three-month period. 22 DEPLETION AND DEPRECIATION. Depletion and depreciation expense decreased $8.7 million during the third quarter of 2005 to $19.7 million. This was primarily the result of the decrease in oil and natural gas production, partially offset by an increase in the depletion rate as compared to the 2004 period. The Company revised its earlier reserve estimates associated the Thibodaux #3 well in the Ramos field based on the well's performance, resulting in a higher depletion and depreciation rate coupled with the addition of costs related to unsuccessful wells drilled during 2005. On a unit basis, depletion and depreciation expense increased by $1.00 per Mcfe, to $3.94 per Mcfe for the three months ended September 30, 2005, compared to $2.94 per Mcfe for the same period in 2004. GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense was essentially flat, between the corresponding periods. On an equivalent unit of production basis, general and administrative expenses increased to $0.79 per Mcfe for the third quarter of 2005 compared to $0.42 per Mcfe for the comparable 2004 period. The increase in per unit cost is a reflection of lower production volumes between the two periods, as explained above. HURRICANE DAMAGE REPAIRS. This expense of $750 thousand is related to damages incurred from hurricanes Katrina and Rita, primarily related to the Company's insurance deductible. INTEREST EXPENSE. Interest expense decreased $0.4 million (26%), to $1.2 million for the third quarter of 2005 in comparison to the third quarter of 2004. The decrease is primarily a result of the reduction in long-term debt. NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2004 OPERATING REVENUES. Oil and natural gas revenues during the nine months ended September 30, 2005, decreased $18.3 million (12%) as compared to the revenues for the nine months ended September 30, 2004, due to a 28% decrease in production volumes primarily from natural production declines and partially from the effects of hurricanes (see "General" above), partially offset by a 21% increase in average commodity prices on a natural gas equivalent basis. Our average daily production decreased from 99.5 Mmcfe during the first nine months of 2004 to 72.2 Mmcfe for the first nine months of 2005. Oil and natural gas production volume totaled 19,706 Mmcfe for the first nine months of 2005, compared to 27,269 Mmcfe for the comparable period of 2004. 23 The following table summarizes the Company's operating revenues, production volumes and average sales prices for the nine months ended September 30, 2005 and 2004: NINE MONTHS ENDED SEPTEMBER 30, INCREASE 2005 2004 (DECREASE) -------- --------- ---------- Production Volumes: Oil (Mbbl) 680 977 (30%) Natural gas (MMcf) 15,623 21,409 (27%) Mmcfe 19,706 27,269 (28%) Average Sales Prices: Oil (per Bbl) $ 36.03 $ 27.61 30% Natural gas (per Mcf) $ 6.81 $ 5.71 19% Mmcfe $ 6.64 $ 5.47 21% Operating Revenues (000's): Oil $ 24,519 $ 26,957 (9%) Natural gas 106,363 122,199 (13%) -------- --------- Total Operating Revenues $130,882 $149,156 (12%) ======== ========= OPERATING EXPENSES. Oil and natural gas operating expenses on an aggregate basis increased $3.4 million (39%) to $12.2 million during the first nine months of 2005, compared to $8.8 million in 2004. On a unit basis, lease operating expenses increased $0.30 per Mcfe to $0.62 per Mcfe for the first nine months of 2005 from $0.32 per Mcfe for the first nine months of 2004. Oil and gas operating expenses increased due to additional operating expenses associated with the increase in wells and facilities in the Biloxi Marshlands project area, and to increased workover-related expenses of approximately $1.8 million, primarily at Weeks Island, Ramos and various offshore fields. SEVERANCE AND AD VALOREM TAXES. Severance and ad valorem taxes decreased $0.3 million (5%) to $6.7 million for the first nine months of 2005, compared to $7.0 million during the same period in 2004 primarily because of a decrease in oil and natural gas production, partially offset by an increase in oil prices and a higher natural gas tax rate. Meridian's oil and natural gas production is primarily from Louisiana, and is therefore subject to Louisiana severance tax. The severance tax rates for Louisiana are 12.5% of gross oil revenues and were $0.252 per Mcf (effective July 1, 2005) for natural gas. For the first six months of 2005 and the last six months of 2004, the rate was $0.208 per Mcf for natural gas, an increase from $0.171 per Mcf for the first half of 2004. On an equivalent unit of production basis, severance and ad valorem taxes increased to $0.34 per Mcfe from $0.26 per Mcfe for the comparable nine-month period. DEPLETION AND DEPRECIATION. Depletion and depreciation expense decreased $6.9 million (9%) during the first nine months of 2005 to $70.5 million, from $77.4 million for the same period of 2004. This was primarily the result of the decline in oil and natural gas production, partially offset by an increase in the depletion rate as compared to the 2004 period. During the second quarter of 2005, the Company suspended operations to re-drill a well on its North Turtle Bayou prospect after unsuccessful attempts to reestablish production from the well. During the third quarter of 2005, the Company re-evaluated the Thibodaux #1 well in the Ramos field based on the well's performance. As a result, the Company revised its earlier reserve estimates associated with these wells resulting in a higher depletion and depreciation rate coupled with the addition of costs related to unsuccessful wells drilled during 2005. On a unit basis, depletion and depreciation expense increased by $0.74 per Mcfe, to $3.58 per Mcfe for the nine months ended September 30, 2005, compared to $2.84 per Mcfe for the same period in 2004. 24 GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased $2.6 million to $13.3 million compared to $10.7 million for 2004. The increase was primarily the result of increased professional services, accounting fees and increased operating activities. On an equivalent unit of production basis, general and administrative expenses increased $0.29 per Mcfe to $0.68 per Mcfe for the first nine months of 2005 compared to $0.39 per Mcfe for the comparable 2004 period. HURRICANE DAMAGE REPAIRS. This expense of $750 thousand is related to damages incurred from hurricanes Katrina and Rita, primarily related to the Company's insurance deductible. INTEREST EXPENSE. Interest expense decreased $2.3 million (41%), to $3.3 million for the first nine months of 2005 in comparison to the first nine months of 2004. The decrease is a result of the reduction in long-term debt. LIQUIDITY AND CAPITAL RESOURCES WORKING CAPITAL. During the first nine months of 2005, Meridian's capital expenditures were internally financed with cash from operations. As of September 30, 2005, the Company had a cash balance of $15.8 million and a working capital deficit of $23.1 million. This deficit was made up primarily of a $19.6 million net current liability associated with price risk management activities which will be offset by future revenues. Management's strategy is to grow the Company by taking advantage of the strong asset base built over the years and to add reserves through the drill bit while maintaining a disciplined approach to costs. Where appropriate, the Company will allocate excess cash above capital expenditures to reduce leverage. CASH FLOWS. Net cash provided by operating activities was $96.4 million for the nine months ended September 30, 2005, as compared to $127.1 million for the same period in 2004. The decrease of $30.6 million was primarily due to a reduction in revenues from oil and natural gas of $18.3 million and a reduction in accrued expenses in the first nine months of 2005 from the first nine months of 2004. Net cash used in investing activities was $103.9 million during the nine months ended September 30, 2005, versus $100.0 million in the first nine months of 2004. The increase in capital expenditures of $3.9 million was primarily associated with drilling and related activities in the Biloxi Marshlands project area and the greater Ramos Complex. Cash flows used in financing activities during the first nine months of 2005 were $1.1 million, compared to cash used in financing activities of $11.5 million during the first nine months of 2004. This reduction in cash used in financing activities was primarily due to reduced preferred stock dividends coupled with the reduction in debt repayments. With the preferred stock conversions in 2005, the Company will see an annual $2.6 million reduction of dividend payments. CREDIT FACILITY. On December 23, 2004, the Company amended its existing credit facility to provide for a four-year $200 million senior secured credit facility (the "Credit Facility") with Fortis Capital Corp., as administrative agent, sole lead arranger and bookrunner; Comerica Bank as syndication agent; and Union Bank of California as documentation agent. Bank of Nova Scotia, Allied Irish Banks p.l.c., RZB Finance LLC and Standard Bank PLC completed the syndication group. The initial borrowing base under the Credit Facility is $130 million and it has been reaffirmed by the syndication group effective November 1, 2005. As of September 30, 2005, outstanding borrowings under the Credit Facility totaled $75.1 million. The Credit Facility is subject to semi-annual borrowing base redeterminations on April 30 and October 31 of each year. In addition to the scheduled semi-annual borrowing base redeterminations, the lenders or the Company, have the right to redetermine the borrowing base at any time, provided that no party can request more than one such redetermination between the regularly scheduled borrowing base redeterminations. Obligations under the Credit Facility are secured by pledges of outstanding capital stock of the Company's 25 subsidiaries and by a first priority lien on not less than 75% (95% in the case of an event of default) of its present value of proved oil and gas properties. In addition, the Company is required to deliver to the lenders and maintain satisfactory title opinions covering not less than 70% of the present value of proved oil and gas properties. The Credit Facility also contains other restrictive covenants, including, among other items, maintenance of certain financial ratios, restrictions on cash dividends on Common Stock and under certain circumstances Preferred Stock, limitations on the redemption of Preferred Stock and an unqualified audit report on the Company's consolidated financial statements, all of which the Company is in compliance. Under the Credit Facility, the Company may secure either (i) (a) an alternative base rate loan that bears interest at a rate per annum equal to the greater of the administrative agent's prime rate; or (b) federal funds-based rate plus -1/2 of 1%, plus an additional 0.5% to 1.25% depending on the ratio of the aggregate outstanding loans and letters of credit to the borrowing base or; (ii) a Eurodollar base rate loan that bears interest, generally, at a rate per annum equal to the London interbank offered rate ("LIBOR") plus 1.5% to 2.25%, depending on the ratio of the aggregate outstanding loans and letters of credit to the borrowing base. At September 30, 2005, the three-month LIBOR interest rate was 4.065%. The Credit Facility also provides for commitment fees of 0.375% calculated on the difference between the borrowing base and the aggregate outstanding loans under the Credit Facility. 8.5% REDEEMABLE CONVERTIBLE PREFERRED STOCK. A private placement of $66.85 million of 8.5% redeemable convertible preferred stock was completed during May 2002. The preferred stock was convertible into shares of the Company's Common Stock at a conversion price of $4.45 per share. Dividends were payable semi-annually in cash or additional preferred stock. At the option of the Company, one-third of the preferred shares could be forced to convert to Common Stock if the closing price of the Company's Common Stock exceeded 150% of the conversion price for 30 out of 40 consecutive trading days on the New York Stock Exchange. The preferred stock was subject to redemption at the option of the Company after March 2005, and mandatory redemption on March 31, 2009. During the first six months of 2005, the Company completed the conversion of all of the remaining outstanding shares of preferred stock to Common Stock, with $31.6 million of stated value being converted into approximately 7.1 million shares of the Company's Common Stock. OIL AND NATURAL GAS HEDGING ACTIVITIES. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. The Company enters into derivative contracts to hedge the price risks associated with a portion of anticipated future oil and gas production. These contracts allow the Company to predict with greater certainty the effective oil and natural gas prices to be received for our hedged production. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at or prior to expiration or exchanged for physical delivery contracts. The Company does not obtain collateral to support the agreements, but monitors the financial viability of counter-parties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price risk. The Company has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. These contracts have been designated as cash flow hedges as provided by SFAS No. 133 and any changes in fair value of the cash flow hedge resulting from ineffectiveness of the hedge is reported in the consolidated statement of operations as revenues. CAPITAL EXPENDITURES. Total capital expenditures for this nine month period approximated $103.8 million. Although the Company plans to continue additional drilling during the remainder of 2005, such operations will depend primarily on achieving anticipated cash flows, permitting of wells and the availability of suitable drilling rigs. Meridian recently completed the final field work on its 3-D seismic survey at its Biloxi Marshlands acreage and preliminary indications are that a number of additional drilling locations are present in the area encompassing the new survey which will form the basis for its future drilling activities during 2006. 26 Based on internal projections, using its internal risked analysis of production based on an expected capital expenditures program for 2005 of $139 million, the Company believes that it can further improve its balance sheet while, at the same time, continuing its scheduled capital expenditure program, drilling 15 to 20 low-risk wells during 2005 and acquiring and re-processing additional 3-D seismic data over its Biloxi Marshlands project and other exploration areas targeted for exploration growth. DIVIDENDS. It is our policy to retain existing cash for reinvestment in our business, and therefore, we do not anticipate that dividends will be paid with respect to the Common Stock in the foreseeable future. During May 2002, the Company completed the private placement of approximately $67 million of 8.5% Redeemable Convertible Preferred Stock and dividends were payable semi-annually. A semi-annual cash dividend of $1.3 million was paid in January 2005. A final cash dividend of $0.9 million was paid during the second quarter of 2005. During the first six months of 2005, the Company completed the conversion of all of the remaining outstanding shares of the 8.5% Redeemable Convertible Preferred Stock to Common Stock, with $31.6 million of stated value being converted into approximately 7.1 million shares of the Company's Common Stock. As a result of these conversions in 2005, the Company will realize an annual cash savings of approximately $2.6 million on the Preferred Stock dividends. FORWARD-LOOKING INFORMATION From time to time, we may make certain statements that contain "forward-looking" information as defined in the Private Securities Litigation Reform Act of 1995 and that involve risk and uncertainty. These forward-looking statements may include, but are not limited to exploration and seismic acquisition plans, anticipated results from current and future exploration prospects, future capital expenditure plans, anticipated results from third party disputes and litigation, expectations regarding compliance with our credit facility, the anticipated results of wells based on logging data and production tests, future sales of production, earnings, margins, production levels and costs, market trends in the oil and natural gas industry and the exploration and development sector thereof, environmental and other expenditures and various business trends. Forward-looking statements may be made by management orally or in writing including, but not limited to, the Management's Discussion and Analysis of Financial Condition and Results of Operations section and other sections of our filings with the Securities and Exchange Commission under the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended. Actual results and trends in the future may differ materially depending on a variety of factors including, but not limited to the following: CHANGES IN THE PRICE OF OIL AND NATURAL GAS. The prices we receive for our oil and natural gas production and the level of such production are subject to wide fluctuations and depend on numerous factors that we do not control, including seasonality, worldwide economic conditions, the condition of the United States economy (particularly the manufacturing sector), foreign imports, political conditions in other oil-producing countries, the actions of the Organization of Petroleum Exporting Countries and domestic government regulation, legislation and policies. Material declines in the prices received for oil and natural gas could make the actual results differ from those reflected in our forward-looking statements. OPERATING RISKS. The occurrence of a significant event against which we are not fully insured could have a material adverse effect on our financial position and results of operations. Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and natural gas, including uncontrollable flows of oil, natural gas, brine or well fluids into the environment (including groundwater and shoreline contamination), blowouts, cratering, mechanical difficulties, fires, explosions, unusual or unexpected formation pressures, pollution and environmental hazards, each of which could result in damage to or destruction of oil and natural gas wells, production facilities or other property, or injury to persons. In 27 addition, we are subject to other operating and production risks such as title problems, weather conditions, compliance with government permitting requirements, shortages of or delays in obtaining equipment, reductions in product prices, limitations in the market for products, litigation and disputes in the ordinary course of business. Although we maintain insurance coverage considered to be customary in the industry, we are not fully insured against certain of these risks either because such insurance is not available or because of high premium costs. We cannot predict if or when any such risks could affect our operations. The occurrence of a significant event for which we are not adequately insured could cause our actual results to differ from those reflected in our forward-looking statements. DRILLING RISKS. Our decision to purchase, explore, develop or otherwise exploit a prospect or property will depend in part on the evaluation of data obtained through geophysical and geological analysis, production data and engineering studies, which may be imprecise. Therefore, we cannot assure you that all of our drilling activities will be successful or that we will not drill uneconomical wells. The occurrence of unexpected drilling results could cause the actual results to differ from those reflected in our forward-looking statements. UNCERTAINTIES IN ESTIMATING RESERVES AND FUTURE NET CASH FLOWS. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas we cannot measure in an exact manner, and the accuracy of any reserve estimate is a function of the quality available of data and of engineering and geological interpretation and judgment. Reserve estimates may be imprecise and may be expected to change as additional information becomes available. There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. The quantities of oil and natural gas that we ultimately recover, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may differ from those assumed in these estimates. Significant downward revisions to our existing reserve estimates could cause the actual results to differ from those reflected in our forward-looking statements. BORROWING BASE FOR THE CREDIT FACILITY. The Credit Agreement with Fortis Capital Corp. is presently scheduled for borrowing base redetermination dates on a semi-annual basis with the next such redetermination scheduled for April 30, 2006. The borrowing base is redetermined on numerous factors including current reserve estimates, reserves that have recently been added, current commodity prices, current production rates and estimated future net cash flows. These factors have associated risks with each of them. Significant reductions or increases in the borrowing base will be determined by these factors, which, to a significant extent, are not under the Company's control. 28 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The Company is currently exposed to market risk from hedging contracts changes and changes in interest rates. A discussion of the market risk exposure in financial instruments follows. INTEREST RATES We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. Our long-term borrowings primarily consist of borrowings under the Credit Facility. Since interest charged on borrowings under the Credit Facility floats with prevailing interest rates (except for the applicable interest period for Eurodollar loans), the carrying value of borrowings under the Credit Facility should approximate the fair market value of such debt. Changes in interest rates, however, will change the cost of borrowing. Assuming $75.1 million remains borrowed under the Credit Agreement, we estimate our annual interest expense will change by $0.75 million for each 100 basis point change in the applicable interest rates utilized under the Credit Agreement. HEDGING CONTRACTS Meridian may address market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. From time to time, we may enter into derivative contracts to hedge the price risks associated with a portion of anticipated future oil and natural gas production. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at or prior to expiration or exchanged for physical delivery contracts. Meridian does not obtain collateral to support the agreements, but monitors the financial viability of counter-parties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price risk. Meridian has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. We have entered into certain derivative contracts as summarized in the table below. The Notional Amount is equal to the total net volumetric hedge position of the Company during the periods presented. The positions effectively hedge approximately 26% of our proved developed natural gas production and 28% of our proved developed oil production during the respective terms of these agreements. The fair values of the hedges are based on the difference between the strike price and the New York Mercantile Exchange future prices for the applicable trading months. Swap / Floor Ceiling Fair Value Notional Price Price Sept 30, 2005 Type Amount ($ per unit) ($ per unit) (in thousands) ------ --------- ------------ ------------ -------------- NATURAL GAS (MMBTU) Oct 2005 Swap 350,000 $ 6.34 N/A $ (2,646) Oct 2005 Collar 350,000 $ 6.50 $ 7.90 (2,102) Nov 2005 - Mar 2006 Collar 2,980,000 $ 7.50 $ 11.25 (10,381) Apr 2006 - Oct 2006 Collar 1,130,000 $ 8.00 $ 14.50 (47) --------- Total Natural Gas (15,176) --------- CRUDE OIL (BBLS) Oct 2005 - Jul 2006 Collar 173,000 $ 37.50 $ 47.50 (3,356) Oct 2005 - Jul 2006 Collar 33,000 $ 40.00 $ 50.00 (571) Aug 2006 - Jul 2007 Collar 168,000 $ 50.00 $ 74.00 (521) --------- Total Crude Oil (4,448) --------- $ (19,624) ========= 29 ITEM 4. CONTROLS AND PROCEDURES We conducted an evaluation under the supervision and with the participation of Meridian's management, including our Chief Executive Officer and Chief Accounting Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the third quarter of 2005. Based upon that evaluation, our Chief Executive Officer and Chief Accounting Officer concluded that the design and operation of our disclosure controls and procedures are effective. There have been no significant changes in our internal controls or in other factors during the third quarter of 2005 that could significantly affect these controls. 30 PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS. H. L. HAWKINS LITIGATION. In December 2004, the estate of H.L. Hawkins filed a claim against Meridian for damages "estimated to exceed several million dollars" for Meridian's alleged gross negligence and willful misconduct under certain agreements concerning certain wells and property in the S.W. Holmwood and E. Lake Charles Prospects in Calcasieu Parish in Louisiana, as a result of Meridian's satisfying a prior adverse judgment in favor of Amoco Production Company. Meridian has filed an answer denying Hawkins' claims and asserted a counterclaim for attorney's fees, court costs and other expenses, and for declaratory relief that Meridian is entitled to retain the amounts that it had been paid by Hawkins. The Company has not provided any amount for this matter in its financial statements at September 30, 2005. ENVIRONMENTAL LITIGATION. Various landowners have sued Meridian (along with numerous other oil companies) in various similar lawsuits concerning the Weeks Island, Gibson, Bayou Pigeon, West Lake Verret and White Castle Fields. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs' lands from alleged contamination and otherwise from the defendants' oil and gas operations. The Company has not provided any amount for these matters in its financial statements at September 30, 2005. LITIGATION INVOLVING INSURABLE ISSUES. There are no other material legal proceedings which exceed our insurance limits to which Meridian or any of its subsidiaries is a party or to which any of its property is subject, other than ordinary and routine litigation incidental to the business of producing and exploring for crude oil and natural gas. ITEM 6. EXHIBITS. 31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. 31.2 Certification of President pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. 31.3 Certification of Chief Accounting Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. 32.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350. 32.2 Certification of President pursuant to Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350. 32.3 Certification of Chief Accounting Officer pursuant Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350. 31 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES (Registrant) Date: November 8, 2005 By: /s/ LLOYD V. DELANO ----------------------------- Lloyd V. DeLano Senior Vice President Chief Accounting Officer 32 EXHIBITS INDEX TO EXHIBITS 31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. 31.2 Certification of President pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. 31.3 Certification of Chief Accounting Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as amended. 32.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350. 32.2 Certification of President pursuant to Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350. 32.3 Certification of Chief Accounting Officer pursuant Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350.