Edgar Filing: MERIDIAN RESOURCE CORP

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended: September 30, 2007


o		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 incorporation or organization)		(I.R.S. Employer Identification No.)


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 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one)

Large Accelerated Filer o Accelerated Filer þ Non-Accelerated Filer o

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

Number of shares of common stock outstanding at October 31, 2007: 89,362,734

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, 2007 and 2006		3

Consolidated Balance Sheets as of September 30, 2007 (unaudited) and December 31, 2006		4

Consolidated Statements of Cash Flows (unaudited) for the Nine Months Ended September 30, 2007 and 2006		6

Consolidated Statements of Stockholders’ Equity (unaudited) for the Nine Months Ended September 30, 2007 and 2006		7

Consolidated Statements of Comprehensive Income (Loss) (unaudited) for the Three Months and Nine Months Ended September 30, 2007 and 2006		8

Notes to Consolidated Financial Statements (unaudited)		9

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3. Quantitative and Qualitative Disclosures about Market Risk		30

Item 4. Controls and Procedures		31

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		32

Item 1A. Risk Factors		33

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		34

Item 5. Other Information		34

Item 6. Exhibits		34

SIGNATURES		35
Certification of CEO Pursuant Rule 13a-14(a)
Certification of President Pursuant to Rule 13a-14(a)
Certification of CAO Pursuant Rule 13a-14(a)
Certification of CEO Pursuant to Section 1350
Certification of President Pursuant to Section 1350
Certification of CAO Pursuant to Section 1350

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(thousands of dollars, except per share information)

(unaudited)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007		2006
REVENUES:
Oil and natural gas	$	33,709		$	45,795		$	113,568	$	148,723
Price risk management activities		(13	)		(238	)		3		125
Interest and other		487			502			1,232		1,257

		34,183			46,059			114,803		150,105

OPERATING COSTS AND EXPENSES:
Oil and natural gas operating		6,964			6,486			21,719		16,050
Severance and ad valorem taxes		2,127			3,202			7,590		8,547
Depletion and depreciation		17,574			28,226			58,184		85,396
General and administrative		4,074			4,360			11,859		13,876
Accretion expense		574			430			1,701		1,050
Impairment of long-lived assets		—			134,865			—		134,865
Hurricane damage repairs		—			581			—		2,984

		31,313			178,150			101,053		262,768


EARNINGS (LOSS) BEFORE INTEREST AND INCOME TAXES		2,870			(132,091	)		13,750		(112,663	)


OTHER EXPENSE:
Interest expense		1,530			1,471			4,607		4,338


EARNINGS (LOSS) BEFORE INCOME TAXES		1,340			(133,562	)		9,143		(117,001	)


INCOME TAXES:
Current		68			135			180		503
Deferred		522			(46,818	)		3,840		(40,799	)

		590			(46,683	)		4,020		(40,296	)


NET EARNINGS (LOSS)	$	750		$	(86,879	)	$	5,123	$	(76,705	)


NET EARNINGS (LOSS) PER SHARE:
Basic	$	0.01		$	(0.99	)	$	0.06	$	(0.88	)
Diluted	$	0.01		$	(0.99	)	$	0.05	$	(0.88	)

WEIGHTED AVERAGE NUMBER OF COMMON
Basic		89,312			87,726			89,298		87,179
Diluted		95,022			87,726			94,869		87,179

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(thousands of dollars)


	September 30,		December 31,
	2007		2006
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	24,146	$	31,424
Restricted cash		29		1,282
Accounts receivable, less allowance for doubtful accounts of $210 [2007] and $232 [2006]		19,953		24,285
Due from affiliates		2,876		670
Prepaid expenses and other		6,526		3,457
Assets from price risk management activities		2,232		7,968

Total current assets		55,762		69,086


PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including $55,670 [2007] and $54,356 [2006] not subject to depletion)		1,739,117		1,663,865
Land		48		48
Equipment		13,551		7,492

		1,752,716		1,671,405
Less accumulated depletion and depreciation		1,331,690		1,273,522

Total property and equipment, net		421,026		397,883


OTHER ASSETS:
Assets from price risk management activities		510		490
Other		104		436

Total other assets		614		926


TOTAL ASSETS	$	477,402	$	467,895

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (continued)
(thousands of dollars)


	September 30,			December 31,
	2007			2006
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	11,228		$	6,700
Advances from non-operators		2,511			3,051
Revenues and royalties payable		7,351			7,933
Notes payable		5,067			2,754
Accrued liabilities		22,439			21,938
Liabilities from price risk management activities		801			1,024
Asset retirement obligations		2,977			4,803
Deferred income taxes payable		352			2,336
Current income taxes payable		20			—


Total current liabilities		52,746			50,539


LONG-TERM DEBT		75,000			75,000

OTHER:
Deferred income taxes		7,201			3,364
Liabilities from price risk management activities		372			190
Asset retirement obligations		17,825			18,005

		25,398			21,559


STOCKHOLDERS’ EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized, 89,450,466 [2007] and 89,139,600 [2006] shares issued)		935			928
Additional paid-in capital		536,812			534,441
Accumulated deficit		(214,156	)		(219,279)
Accumulated other comprehensive income		1,016			4,707

		324,607			320,797
Less treasury stock, at cost 141,378 [2007] shares		(349	)		—

Total stockholders’ equity		324,258			320,797

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	477,402		$	467,895

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(thousands of dollars)

(unaudited)


	Nine Months Ended September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings (loss)	$	5,123		$	(76,705)
Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
Depletion and depreciation		58,184			85,396
Amortization of other assets		332			332
Non-cash compensation		2,028			1,784
Non-cash price risk management activities		(3	)		(125	)
Accretion expense		1,701			1,050
Impairment of long-lived assets		—			134,865
Deferred income taxes		3,840			(40,799	)
Changes in assets and liabilities:
Restricted cash		1,253			(31	)
Accounts receivable		4,332			18,133
Prepaid expenses and other		(3,069	)		(5,133	)
Due from affiliates		(2,206	)		(3,390	)
Accounts payable		4,528			(3,446	)
Advances from non-operators		(540	)		3,330
Revenues and royalties payable		(582	)		(1,226	)
Asset retirement obligations		(2,028	)		(3,028	)
Other assets and liabilities		1,431			134

Net cash provided by operating activities		74,324			111,141

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment		(85,559	)		(91,385	)
Acquisition of properties		—			(13,220	)
Proceeds from sale of property		2,552			11,032

Net cash used in investing activities		(83,007	)		(93,573	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions in long-term debt		—			(10,000	)
Proceeds from long-term debt		—			10,000
Reductions in notes payable		(7,227	)		(5,164	)
Proceeds from notes payable		9,540			9,248
Repurchase of common stock		(908	)		—

Net cash provided by financing activities		1,405			4,084

NET CHANGE IN CASH AND CASH EQUIVALENTS		(7,278	)		21,652
Cash and cash equivalents at beginning of period		31,424			23,265

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	24,146		$	44,917


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Non-cash activities:
Issuance of shares for contract services	$	(909	)	$	(794	)
Issuance of shares for acquisition of properties	$	—		$	(7,000	)
ARO liability – new wells drilled	$	386		$	4,437
ARO liability – changes in estimates	$	(2,065	)	$	2,921

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Nine Months Ended September 30, 2007 and 2006

(in thousands of dollars and shares)

(unaudited)


												Accumulated
						Additional			Accumulated			Other			Unamortized
	Common Stock					Paid-In			Earnings			Comprehensive			Deferred			Treasury Stock
	Shares			Par Value		Capital			(Deficit)			Income (Loss)			Compensation			Shares			Cost			Total
Balance, December 31, 2005		86,818		$	900	$	524,692		$	(145,395	)	$	(2,314	)	$	(318	)		—		$	—		$	377,565
Effect of adoption of FAS123R		—			—		(318	)		—			—			318			—			—			—
Issuance of rights to common stock		—			4		(4	)		—			—			—			—			—			—
Company’s 401(k) plan contribution		57			1		227			—			—			—			—			—			228
Stock-based compensation – FAS123R		—			—		286			—			—			—			—			—			286
Compensation expense		—			—		1,270			—			—			—			—			—			1,270
Accum. other comprehensive income		—			—		—			—			6,068			—			—			—			6,068
Issuance of shares for contract services		224			2		792			—			—			—			—			—			794
Issuance of shares – Vintage acquisition		2,006			20		6,980																		7,000
Net earnings (loss)		—			—		—			(76,705	)		—			—			—			—			(76,705	)


Balance, September 30, 2006		89,105		$	927	$	533,925		$	(222,100	)	$	3,754		$	—			—		$	—		$	316,506


Balance, December 31, 2006		89,140		$	928	$	534,441		$	(219,279	)	$	4,707		$	—			—		$	—		$	320,797
Issuance of rights to common stock		—			5		(5	)		—			—			—			—			—			—
Company’s 401(k) plan contribution		149			—		169			—			—			—			(106	)		250			419
Shares repurchased		(359	)		—		—			—			—			—			359			(908	)		(908	)
Stock-based compensation – FAS123R		—			—		238			—			—			—			—			—			238
Compensation expense		—			—		1,266			—			—			—			—			—			1,266
Accum. other comprehensive loss		—			—		—			—			(3,691	)		—			—			—			(3,691	)
Issuance of shares for contract services		340			2		623			—			—			—			(104	)		284			909
Issuance of shares as compensation		39			—		80			—			—			—			(8	)		25			105
Net earnings		—			—		—			5,123			—			—			—			—			5,123


Balance, September 30, 2007		89,309		$	935	$	536,812		$	(214,156	)	$	1,016		$	—			141		$	(349	)	$	324,258

See notes to consolidated financial statements.

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,
	2007			2006			2007			2006
Net earnings (loss)	$	750		$	(86,879	)	$	5,123		$	(76,705	)

Other comprehensive income (loss), net of tax, for unrealized gains (losses) from hedging activities:
Unrealized holding gains (losses) arising during period (1)		547			4,389			(1,536	)		6,994
Reclassification adjustments on settlement of contracts (2)		(710	)		(1,672	)		(2,155	)		(926	)

		(163	)		2,717			(3,691	)		6,068


Total comprehensive income (loss)	$	587		$	(84,162	)	$	1,432		$	(70,637	)


(1) net income tax (expense) benefit	$	(294	)	$	(2,363	)	$	827		$	(3,766	)
(2) net income tax (expense) benefit	$	382		$	900		$	1,161		$	499

See notes to consolidated financial statements.

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, 2006, as filed with the Securities and Exchange Commission.

The financial statements included herein as of September 30, 2007, and for the three and nine month periods ended September 30, 2007 and 2006, 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 reclassifications of prior period financial 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. RECENT ACCOUNTING PRONOUNCEMENTS

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements.” SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company is evaluating the impact, if any, that SFAS No. 157 will have on our financial statements.

On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115 (“SFAS No. 159”)”. SFAS No. 159 permits entities to choose to measure eligible financial instruments and certain other items at fair market value, with the objective of improving financial reporting by giving entities the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The adoption of SFAS No. 159 is not expected to have a material impact, if any, on the Company’s financial statements.

3. ACCRUED LIABILITIES

Below is the detail of accrued liabilities on the Company’s balance sheets as of September 30, 2007 and December 31, 2006 (thousands of dollars):


	September 30,		December 31,
	2007		2006
Capital expenditures	$	13,326	$	13,851
Operating expenses/taxes		5,401		4,024
Compensation		1,256		1,197
Other		2,456		2,866

Total	$	22,439	$	21,938

4. 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, collectively the “Lenders”. The current borrowing base under the Credit Facility was redetermined to be $115 million by the syndication group effective October 31, 2007. As of September 30, 2007, outstanding borrowings under the Credit Facility totaled $75 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. The determination of the borrowing base is subject to a number of factors, including quantities of proved oil and natural gas reserves, the bank’s price assumptions and other various factors unique to each member bank. The Company’s Lenders can redetermine the borrowing base to a lower level than the current borrowing base if they determine that the oil and natural gas reserves, at the time of redetermination, are inadequate to support the borrowing base then in effect.

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 present value of proved oil and natural 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 natural 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, limitations on the repurchase of the Company’s common 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, 2007, the three-month LIBOR interest rate was 5.23%. 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.

5. INCOME TAXES

In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes – an Interpretation of SFAS No. 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on recognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The Company adopted the provisions of FIN 48 on January 1, 2007, and the adoption had no material impact on the Company’s results of operations and financial position.

6. 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, willful misconduct and breach of fiduciary duty 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. Mr. James Bond had been added as a defendant by Hawkins claiming Mr. Bond, when he was General Manager of Hawkins, did not have the right to consent, could not consent or breached his fiduciary duty to Hawkins if he did consent to all actions taken by Meridian. Mr. James T. Bond was employed by H.L. Hawkins Jr. and his companies as General Manager until 2002. He served on the Board of Directors of the Company from March 1997 to August 2004. After Mr. Bond’s employment with Mr. Hawkins, Jr. and his companies ended, Mr. Bond was engaged by The Meridian Resource & Exploration LLC as a consultant. This relationship continued until his death. Mr. Bond was also the father-in-law of Michael J. Mayell, the President of the Company. Management continues to vigorously defend this action on the basis that Mr. Hawkins individually and through his agent, Mr. Bond, agreed to the course of action adopted by Meridian and further that Meridian’s actions were not grossly negligent, but were within the business judgment rule. Since Mr. Bond’s death, a pleading has recently been filed substituting the proper party for Mr. Bond. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the Company has not provided any amount for this matter in its financial statements at September 30, 2007.

Title/lease disputes. Title and lease disputes arise due to various events that have occurred in the various states in which the Company operates. These disputes are typically immaterial to the Company but could lead to the Company over- or under-stating reserves prior to when a final resolution to the title dispute is made.

Environmental litigation. Various landowners have sued Meridian (along with numerous other oil companies) in 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 Company’s oil and natural gas operations. In some of the lawsuits, Shell Oil Company and SWEPI LP have demanded contractual indemnity and defense from Meridian based upon the terms of the purchase and sale agreement, related to the fields and in another lawsuit, Exxon Mobil Corporation has demanded contractual indemnity and defense from Meridian on the basis of a purchase and sale agreement related to the field(s) referenced in the lawsuit; Meridian has challenged such demands. In some cases, Meridian has also demanded defense and indemnity from their subsequent purchasers of the fields. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of these matters or to estimate the amount or range of potential loss should any outcome be unfavorable. Therefore, the Company has not provided any amount for these matters in its financial statements at September 30, 2007.

Consent Decree. During the fourth quarter of 2007 the Company entered into a Consent Decree with the United States Environmental Protection Agency (“EPA”) in settlement of alleged violations of the Clean Water Act, as amended by the Oil Pollution Act of 1990. Under the Consent Decree, the Company will pay $504,000 in civil penalties for alleged discharges of crude oil into navigable waters or adjoining shorelines from the Company’s operations at the Weeks Island field in Iberia Parish, Louisiana. The Company will also be subject to certain injunctive relief, requiring the Company to enhance certain pipeline survey, monitoring and reporting activities. Under the Consent Decree, the Company does not admit any liability arising out of the occurrences described in the Consent Decree or the related Complaint. During the second quarter of 2007, the Company recorded an expense for the above amount in oil and natural gas operating expenses.

Litigation involving insurable issues. There are no material legal proceedings involving insurable issues which exceed 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.

Commitments. The Company has an agreement for the construction and purchase of one newly built land based drilling rig with an engineering design and fabrication/rig contractor, for approximately $12 million. This contractor will ultimately operate, crew and maintain the rig. Delivery of the rig is currently expected in the first quarter of 2008 when the rig will be mobilized to the Company’s East Texas Austin Chalk play. As of September 30, 2007, approximately $6.0 million has been capitalized as Equipment in the accompanying consolidated balance sheet.

7. COMMON STOCK

In March 2007, the Company’s Board of Directors authorized a new share repurchase program. Under the program, the Company may repurchase in the open market or through privately negotiated transactions up to $5 million worth of common shares per year over the next three years. The timing, volume, and nature of share repurchases will be at the discretion of management, depending on market conditions, applicable securities laws, and other factors. Prior to implementing this program, the Company was required to seek approval of the repurchase program from the Lenders under the Credit Facility. The repurchase program was approved by the Lenders, subject to certain restrictive covenants. As of September 30, 2007, the Company had repurchased 359,300 common shares at a cost of $908,000, of which 217,922 shares have been issued for 401(k) contributions, for contract services and for compensation. It is the intent of the Company to continue this program through this and future years.

8. EARNINGS PER SHARE

The following table sets forth the computation of basic and diluted net earnings per share (in thousands, except per share):


	Three Months Ended September 30,
	2007		2006
Numerator:
Net earnings (loss)	$	750	$	(86,879	)

Denominator:
Denominator for basic earnings per share — weighted-average shares outstanding		89,312		87,726
Effect of potentially dilutive common shares:
Warrants		5,710		N/A
Employee and director stock options		—		N/A

Denominator for diluted earnings per share - weighted-average shares outstanding and assumed conversions		95,022		87,726

Basic earnings (loss) per share	$	0.01	$	(0.99	)

Diluted earnings (loss) per share	$	0.01	$	(0.99	)


	Nine Months Ended September 30,
	2007		2006
Numerator:
Net earnings (loss)	$	5,123	$	(76,705	)
Denominator:
Denominator for basic earnings per share — weighted-average shares outstanding		89,298		87,179
Effect of potentially dilutive common shares:
Warrants		5,571		N/A
Employee and director stock options		—		N/A

Denominator for diluted earnings per share — weighted-average shares outstanding and assumed conversions		94,869		87,179

Basic earnings (loss) per share	$	0.06	$	(0.88	)

Diluted earnings (loss) per share	$	0.05	$	(0.88	)

9. OIL AND NATURAL GAS HEDGING ACTIVITIES

The Company may address market risk by selecting instruments with value fluctuations that correlate strongly with the underlying commodity being hedged. From time to time, the Company enters 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 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, 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 SFAS No. 133 and any changes in fair value are recorded in accumulated 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 gains (losses) related to hedge ineffectiveness of approximately ($13,000) and ($238,000) during the three months ended September 30, 2007 and 2006, respectively, and of approximately $3,000 and $125,000 during the nine months ended September 30, 2007 and 2006, respectively.

The estimated September 30, 2007 fair value of the Company’s oil and natural gas derivatives resulted in an unrealized gain of approximately $1.6 million ($1.0 million net of tax) which is recognized in accumulated other comprehensive income. Based upon September 30, 2007 oil and natural gas commodity prices, approximately $1.4 million of the gain deferred in accumulated other comprehensive income could potentially increase gross revenues over the next twelve months. These derivative agreements expire at various dates through December 31, 2008.

Net settlements under these contracts increased oil and natural gas revenues by $1.1 million and $2.6 million for the three months ended September 30, 2007 and 2006, respectively, and by $3.3 million and $1.4 million for the nine months ended September 30, 2007 and 2006, respectively, as a result of hedging transactions.

The Company has 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. As of September 30, 2007, the positions effectively hedge approximately 31% of the estimated proved developed natural gas production and 37% of the estimated proved developed oil production during the respective terms of the hedging 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.

The fair value of the hedging agreements is recorded on the consolidated balance sheet as assets or liabilities from price risk management activities. The estimated fair value of the hedging agreements as of September 30, 2007, is provided below:


								Estimated
								Fair Value
								Asset (Liability)
								September 30,
		Notional		Floor Price		Ceiling Price		2007
	Type	Amount		($ per unit)		($ per unit)		(in thousand)
Natural Gas (mmbtu)
Oct 2007 – Dec 2007	Collar		1,110,000	$	7.00	$	11.50	$	555
Jan 2008 – Dec 2008	Collar		2,230,000	$	7.00	$	12.15		871
Jan 2008 – Dec 2008	Collar		1,010,000	$	7.50	$	11.50		567

						Total Natural Gas			1,993

Crude Oil (bbls)
Jan 2008 – Dec 2008	Collar		40,000	$	55.00	$	83.00		(124	)
Oct 2007 – Dec 2008	Collar		30,000	$	65.00	$	80.60		(82	)
Oct 2007 – Dec 2008	Collar		40,000	$	65.00	$	85.00		(45	)
Oct 2007 –April 2008	Collar		42,000	$	60.00	$	82.00		(123	)
May 2008 – July 2008	Collar		15,000	$	60.00	$	82.00		(45	)
Oct 2007 – July 2008	Collar		42,000	$	65.00	$	93.15		(4	)
Oct 2007 – July 2008	Collar		32,000	$	70.00	$	87.40		(1	)

						Total Crude Oil			(424	)

								$	1,569

See Note 12. Subsequent Events, for additional information.

10. STOCK-BASED COMPENSATION

Stock Options

Effective January 1, 2006, the Company adopted the provisions of SFAS No. 123R, “Shared-Based Payment,” using the modified prospective method. SFAS No. 123R replaces SFAS No. 123, “Accounting for Stock-Based Compensation” and amends SFAS No. 95, “Statement of Cash Flows.” SFAS No. 123R addresses the accounting for share-based payment transactions in which an enterprise received 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. SFAS No. 123R eliminates the ability to account for share-based compensation transactions using Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees”, and generally requires instead that such transactions be accounted for using the fair-value based method. Prior to adoption of SFAS No. 123R, the Company followed the intrinsic value method in accordance with APB No. 25 to account for stock options.

Compensation expense is recorded for stock option awards over the requisite vesting periods based upon the market value on the date of the grant. Stock-based compensation expense of approximately $74,000 and $238,000 was recorded in the three months and nine months ended September 30, 2007, respectively, and approximately $119,000 and $286,000 was recognized in the three months and nine months ended September 30, 2006, respectively.

11. ASSET RETIREMENT OBLIGATIONS

The Company follows SFAS No. 143, “Accounting for Asset Retirement Obligations,” which 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 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. The Company records gains or losses from settlements as an adjustment to the full cost pool. 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, 2007, and for the year ended December 31, 2006 (thousands of dollars):


Asset retirement obligation at December 31, 2005	$	11,964
Additional retirement obligations recorded in 2006		4,559
Settlements during 2006		(6,026	)
Revisions to estimates and other changes during 2006		10,723
Accretion expense for 2006		1,588

Asset retirement obligation at December 31, 2006		22,808
Additional retirement obligations recorded in 2007		386
Settlements during 2007		(2,028	)
Revisions to estimates and other changes during 2007		(2,065	)
Accretion expense for 2007		1,701

Asset retirement obligation at September 30, 2007	$	20,802

The Company’s revisions to estimates represent changes to the expected amount and timing of payments to settle the asset retirement obligations. These changes primarily result from obtaining new information about the timing of obligations to plug the natural gas and oil wells and costs to do so.

12. SUBSEQUENT EVENTS

During November 2007, the Company entered into a series of hedging contracts to hedge a portion of its crude oil and natural gas production for December 2007 through December 2009. The hedge contracts were completed in the form of costless collars. The costless collars provide the Company with a lower limit floor price and an upper limit ceiling price on the hedged volumes. The floor price represents the lowest price the Company will receive for the hedged volumes, while the ceiling price represents the highest price the Company will receive for the hedged volumes. The costless collars will be settled monthly based on the NYMEX futures contract of oil and natural gas during each respective month. These hedge contracts, combined with those discussed in Note 9, effectively hedge approximately 35% of the estimated proved developed natural gas production, and 30% of the estimated proved developed oil production during the respective terms of the hedging agreements. The following table summarizes the contracted volumes and prices for the costless collars.


	Notional		Floor Price		Ceiling Price
	Amount		($ per unit)		($ per unit)
Natural Gas (mmbtu)
Dec 2007 - Dec 2008		2,050,000	$	7.50	$	10.10
Jan 2009 - Dec 2009		1,230,000	$	7.50	$	10.45
Crude Oil (bbls)
Dec 2007 - Dec 2008		22,000	$	75.00	$	102.50
Jan 2009 - Dec 2009		23,000	$	70.00	$	93.55

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General.

The Company’s business plan has been modified to extend and expand its exploration portfolio beyond its conventional assets in the Louisiana and Texas Gulf Coast regions to include the establishment of large acreage positions in known unconventional and resource plays located within producing regions of the lower continental United States containing longer-lived reserves. In recognition of the maturity of the Company’s traditional producing region and the paradigm of crude oil and natural gas pricing, management modified its business strategy while retaining its position in the Gulf Coast region of south Louisiana and Texas and leveraged off the higher cash flows generated from these properties to acquire exploration opportunities with large acreage positions, multiple repeatable wells and longer-lived reserves. These include East Texas, Texas Gulf Coast, Mid-Continent, South Louisiana, and unconventional resources.

Operations Overview. The Company is on track with the execution of its business plan and aggressively pursuing its drilling with other growth activities whereby it has set targeted spending of $127 million during 2007. As an integral part of these efforts, the Company has created a balanced portfolio of projects that it believes will reduce its risk profile, thereby improving success while at the same time developing longer lived reserves.

During the third quarter, the Company continued its growth activity in five of its seven operating areas. In the East Texas area, two wells were completed, two wells are currently drilling and additional acreage was leased. In South Louisiana, three wells were successfully recompleted at Weeks Island, one well was successfully drilled at Thornwell Field and two prospects are being prepared for spud/re-entry. In the Texas Gulf Coast, two wells were successfully tested. In the New Albany Shale Play two wells were successfully drilled and are being evaluated. In Oklahoma one well was successfully drilled, tested and is producing.

East Texas

The Company continues to make strides in production, acreage and reserves in this growing core area. Meridian originally started in this play with approximately 7,600 acres in late 2005 with a joint venture to test the Woodbine and Austin Chalk formations. To date, the original acreage position has grown to approximately 63,000 gross acres in this play with plans for an additional 20,000 acres in the coming months. This acreage position provides enough inventory for 60+ possible locations. Depending on the success of the operations in the play, the Company has plans for at least a two-rig, multi-well drilling program to exploit the Company’s acreage under lease for an anticipated three to five-year period. The Company currently has four producing wells in the region, with two additional wells drilling at this time. The daily production from this area has increased from 0% to approximately 6% of the Company’s overall daily production in the past 12 months.

Early last month, the Company completed and tested its fourth successful well in the area, the Blackstone Minerals (“BSM”) No. 2 well. The single lateral well was drilled vertically to approximately 13,100 feet with

the single horizontal lateral extending out approximately 5,900 feet into the Austin Chalk formation. The well was tested at gross daily flow rates as high as 4.3 million cubic feet of natural gas per day (“Mmcf/d”) and 240 barrels of oil per day (“Bopd”). Flowing tubing pressure was measured at approximately 800 psi through an open choke. The well is currently producing at a stabilized rate of 2.0 Mmcf/d and 75 Bopd. The Company expects that the well will display similar producing characteristics to other Austin Chalk wells in the area, with the typical hyperbolic decline curve. Unlike the Company’s other wells in this area, this well is producing approximately 700 barrels of water per day. The Company’s working interest in the well is approximately 42%.

The next two wells to be drilled by the Company in this area were recently spud. The BSM No. 5 well (68% WI) and the Freeman No. 1 well (57% WI) are each scheduled to drill and complete dual horizontal laterals extending north and south between roughly 5,000 and 6,000 feet each. Currently the BSM No. 5 well is at approximately 12,700 feet in depth in the vertical portion of the well and the Freeman No. 1 is at approximately 11,800 feet.

In addition, in the immediate area, and as a result of acreage positions held by the Company, Meridian is participating in the Bear Creek No. 1-H well. This outside operated well reached total depth (18,100 MD) on the second of two scheduled horizontal laterals and is currently in the process of being completed. The well is approximately five miles northeast of Meridian’s primary operating area. Meridian holds approximately 7% working interest in this well.

The Company’s new rig, which will be dedicated to the East Texas area, is anticipated to be delivered during early first quarter 2008. At that time Meridian will have three rigs operating in the area until sometime in the second quarter 2008. Two of the three rigs will be operated, maintained and crewed by Orion Drilling Company LP (“Orion”). One of the rigs operated by Orion will be owned by Meridian and one will be on a long-term contract in this area. It is anticipated that Orion’s management and operations of the rigs will improve drilling efficiencies and costs for these wells.

South Louisiana

The Northeast Bayou Chene prospect located in St. Mary Parish, Louisiana, is being readied for spud in the next few weeks. The well is scheduled to be drilled to a total depth of approximately 17,000 feet TVD to test the “Rob L” sands in the Lower Miocene formation. The Company has a 34% before casing point (48% after casing point) working interest in this well, and the gross unrisked reserve target is between 35 and 40 Bcfe.

In the Weeks Island area, the J. A. Smith No. 1 well, (the “Y-Not” prospect) located in Iberia Parish, Louisiana, is being prepared for a re-entry to test the “Y” sand in the Lower Miocene formation. Previously the well was completed in the uphole “W” sand which has since been depleted. The well is scheduled to be deepened another 600 to 700 feet to approximately 16,000 feet MD. The Company owns an approximate 97% working interest in the well.

Meridian recently finished a recompletion in the Weeks Island State Unit No. A-25 well that extended the reserve expectations from this mature field, and still has multiple behind pipe sands that can be exploited in the future. This recompletion resulted in added production of 230 Bopd on an 8/64^th inch choke. This recompletion is one of several identified projects in Weeks Island that serve as an integral part of the Company’s portfolio management.

The Company recently finished another recompletion on its Smith State Unit No. C-11 well located in the Weeks Island area. The well had previously declined in production to the point of being non-commercial. The work resulted in a successful completion with the well producing at a rate of 1.7 Mmcf/d and 20 Bopd.

Also in the Weeks Island area, the Company finished a recompletion on the Myles Salt No. 32 well that extended the reserve expectations from this mature field that the Company acquired from Shell Oil during

1998. The recompletion perforated only ten feet of additional section and resulted in added production of 300 Bopd with the possible extension of future productive sands in this well bore of up to an additional 75 feet.

Additionally, Meridian is participating in the outside operated Johnson No. 1 exploration well which is located in Acadia Parish, Louisiana. The well is currently at approximately 14,500 feet, targeting sands in the Upper Frio formation at a depth of approximately 15,000 feet. Meridian owns approximately 30% working interest in the well.

As previously reported, the Thornwell Field, located in Jefferson Davis Parish, continues to render exploitation-styled wells and production. This field was acquired as part of the Shell Oil south Louisiana asset package in 1998. Meridian participated in the first exploration well in this field during 1999. Since that time Meridian and its partners have drilled over 23 successful wells in the field resulting in the discovery of over 100 Bcfe, gross. Recently, the Company participated in the drilling of the Potter 33 No. 3 well in Thornwell Field. The well was drilled to approximately 11,950 feet and logged over 100 feet of overall gas pay in the “Bol Perc” sand section. The well was tested at a gross daily flow rate of up to 5.7 Mmcf/d with approximately 200 barrels of condensate. Flowing tubing pressure was measured at approximately 7,300 psi through a 13/64th-inch choke. Production from the well is flowing directly into sales. Meridian owns approximately 30% non-operated working interest (20% net) in the well. Additionally, the Company has identified five more amplitude prospects in the area.

In the Bayou Gentilly area (southwest of the Biloxi Marshland area), the natural gas transmission company that takes natural gas from the Company’s Delacroix No. 1 well has shut-in production from that well. Repairs to the transmission company’s line, resulting from a downstream explosion in early August are still ongoing. Meridian is being informed by the pipeline operator that repairs should be completed by mid-November. The amount of production being shut-in is estimated to be 3.4 Mmcfe/d net. This shut-in caused a decrease in production of approximately 205 Mmcfe for the third quarter.

Texas Gulf Coast

The Company’s Nueces Bay area continues successful operations and discoveries. The outside operated ST 974 No. 2 well, that was successfully completed and previously tested in the 6,300’ sand section (shallow Frio), was recently tested in the uphole Brigham sand section. This sand section (the primary objective of the well) tested at a rate of approximately 1.1 Mmcf/d. Further monitoring and analysis of this sand will determine if the operator will co-mingle production from both the 6,300’ sand and the Brigham sand. Depending on production from the Brigham sand, it is anticipated that this well can be offset with one or two additional development wells. The Company owns approximately 23% working interest in the well and its possible offsets.

The ST 786 No. 12 well on the Indian Point prospect located in the Nueces Bay project area was recently perforated (as previously announced and planned) in an uphole sand section of the lower Frio formation. The results of the test were uneconomic in this particular zone. Therefore Meridian and its partners are currently evaluating future completion opportunities for the well. This well was drilled to a depth of approximately 15,150 feet MD and had apparent gas pay in six Frio sand intervals. The Company owns approximately 49% working interest in this well and is the operator.

As previously reported, the ST 976 No. 2 well on the East White Point prospect was drilled, completed and tested. The well was drilled to approximately 13,650 feet MD, targeting numerous Frio sands. Approximately 55 feet of the primary objective sand (the Lower Guedin located at about 11,600 feet) was perforated. The well was tested directly into sales at a gross daily flow rate of 7.1 Mmcf/d with approximately 700 barrels of condensate per day. Flowing tubing pressure was measured at approximately 4,750 pounds per square inch (“psi”) through a 16/64th-inch choke. This is the same sand that was successfully discovered and exploited in the previously drilled B.P. America well during the fourth quarter of 2006. The Company owns approximately 23% non-operated working interest (17% net revenue interest) in the well. Currently the well is

producing approximately 1.9 Mmcf/d and 215 barrels of condensate per day.

New Albany Shale Play

In the Illinois Basin, Meridian recently reached total depth on its first well, the Farms of Meadow Hills No. 1 well. This well was drilled to 4,600 feet, targeting the Devonian New Albany Shale formation. A second well, the Keach No. 1, also recently reached TD at approximately 4,600 feet, also targeting the New Albany Shale formation. The next step forward for these two wells is to run a full suite of logs and gather core samples for thorough geochemical analysis. The results of this analysis will further determine the best plan for exploiting this potential resource. The Company currently owns an approximate 39,000-acre lease position. The Company’s working interest in the play is 92% with Meridian as operator.

Oklahoma Mid-Continent Play

In the Mid-Continent area, the Company recently tested the Benkendorf No. 21-1 well. This well was drilled in the Nash area of the Greater Carrier Hunton-Woodford de-watering play in Grant County, Oklahoma. The well was drilled to approximately 6,400 feet and logged 14 feet of gross pay in the Hunton formation. The well was swab tested, resulting in approximately 500 Mcf gas per day. Other offset similar wells in the area have produced at higher rates, therefore the Company anticipates improvements from the current rate. The de-watering process has begun and a gas gathering line is being constructed. This is expected to be completed in the coming weeks. Meridian operates the field and owns approximately 80% working interest.

Other Conditions

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, 2007, was $69.92 per barrel compared to $64.17 per barrel for the three months ended September 30, 2006, and $61.20 per barrel for the three months ended June 30, 2007. Our average natural gas price (after adjustments for hedging activities) for the three months ended September 30, 2007, was $6.77 per Mcf compared to $7.16 per Mcf for the three months ended September 30, 2006, and $7.77 per Mcf for the three months ended June 30, 2007. 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.

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, 2006, for further discussion.

Results of Operations

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

Operating Revenues. Third quarter 2007 oil and natural gas revenues, which include oil and natural gas hedging activities (see Note 9 of Notes to Consolidated Financial Statements), decreased $12.1 million (26%) as compared to third quarter 2006 revenues due to a 27% decrease in production volumes partially offset by a 1% increase in average commodity prices on a natural gas equivalent basis. Oil and

natural gas production volumes totaled 4,173 Mmcfe for the third quarter of 2007 compared to 5,715 Mmcfe for the comparable period of 2006. Our average daily production decreased from 62.1 Mmcfe during the third quarter of 2006 to 45.4 Mmcfe for the third quarter of 2007. The variance in production volumes between the two periods is primarily due to natural production declines and the shut-in of production at the Company’s Bayou Gentilly facility due to extensive pipeline repairs by the pipeline operator, partially offset by production from new discoveries brought online since the third quarter of 2006. Meridian is being informed by the pipeline operator that repairs should be completed by mid-November. The amount of production being shut-in is estimated to be 3.4 Mmcfe/d net to the Company. This shut-in caused a decrease of approximately 205 Mmcfe for the third quarter of 2007.

The following table summarizes the Company’s operating revenues, production volumes and average sales prices for the three months ended September 30, 2007 and 2006:


	Three Months Ended
	September 30,				Increase
	2007		2006		(Decrease)
Production Volumes:
Oil (Mbbl)		185		230		(20	%)
Natural gas (MMcf)		3,067		4,337		(29	%)
Mmcfe		4,173		5,715		(27	%)

Average Sales Prices:
Oil (per Bbl)	$	69.92	$	64.17		9	%
Natural gas (per Mcf)	$	6.77	$	7.16		(5	%)
Mmcfe	$	8.08	$	8.01		1	%

Operating Revenues (000’s):
Oil	$	12,936	$	14,760		(12	%)
Natural gas		20,773		31,035		(33	%)

Total Operating Revenues	$	33,709	$	45,795		(26	%)

Operating Expenses. Oil and natural gas operating expenses on an aggregate basis increased $0.5 million (7%) to $7.0 million during the third quarter of 2007, compared to $6.5 million in the third quarter of 2006. On a unit basis, lease operating expenses increased $0.54 per Mcfe to $1.67 per Mcfe for the third quarter of 2007 from $1.13 per Mcfe for the third quarter of 2006. Oil and natural gas operating expenses increased between the periods primarily due to industry wide increases in service costs, increased maintenance-related activities, and the addition of new producing wells in East Texas and southern Louisiana and from the Vintage acquisition. The increase in the per Mcfe rate was additionally attributable to the lower production between the two corresponding periods.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes totaled $2.1 million for the third quarter of 2007, a 34% decrease from $3.2 million for the third quarter of 2006. For the third quarter of 2007, there was an increase in oil prices that was more than offset by a lower natural gas tax rate and a decrease in oil and natural gas production. Meridian’s oil and natural gas production is primarily from Louisiana, and is therefore subject to Louisiana severance tax. The current severance tax rates for Louisiana are 12.5% of gross oil revenues and $0.269 per Mcf for natural gas, a decrease from $0.373 per Mcf for natural gas for the third quarter of 2006. On an equivalent unit of production basis, severance and ad valorem taxes decreased to $0.51 per Mcfe from $0.56 per Mcfe for the three-month period.

Depletion and Depreciation. Depletion and depreciation expense decreased $10.6 million (38%) during the third quarter of 2007 to $17.6 million, from $28.2 million for the same period of 2006. This was primarily the result of a decrease in the depletion rate as compared to the 2006 period and the decrease in oil and natural gas production. On a unit basis, depletion and depreciation expense decreased by $0.73 per Mcfe, to $4.21 per Mcfe for the three months ended September 30, 2007, compared to $4.94 per Mcfe for the same period in 2006. The rate decrease between the periods was due to the impact of the impairment of long-lived assets recognized during the third quarter of 2006.

General and Administrative Expense. General and administrative expense decreased $0.3 million (7%) to $4.1 million compared to $4.4 million for 2006. The decrease between the periods was due to lower accounting, legal and other professional fees and to decreased office rental rates. On an equivalent unit of production basis, general and administrative expenses increased $0.22 per Mcfe to $0.98 per Mcfe for the third quarter of 2007 compared to $0.76 per Mcfe for the comparable 2006 period primarily due to lower production rates between the periods. Stock-based compensation expense of approximately $74,000 was recognized in the three months ended September 30, 2007 compared to $119,000 for the three month period ended September 30, 2006.

Hurricane Damage Repairs. This reduction was due to no additional costs during the third quarter of 2007 related to the repairs of damages incurred from the 2005 hurricanes Katrina and Rita.

Interest Expense. Interest expense was $1.5 million for both the third quarter of 2007 and the third quarter of 2006. The 2007 interest expense is net of approximately $99,000 of capitalized interest for the period associated with the construction of the drilling rig.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

Operating Revenues. Oil and natural gas revenues during the nine months ended September 30, 2007, which include oil and natural gas hedging activities (see Note 9 to Consolidated Financial Statements) decreased $35.2 million (24%) as compared to 2006 revenues due to a 21% decrease in production volumes and a 3% decrease in average sale prices on a natural gas equivalent basis. Our average daily production decreased from 65.9 Mmcfe during the first nine months of 2006 to 51.9 Mmcfe for the first nine months of 2007. Oil and natural gas production volume totaled 14,164 Mmcfe for the first nine months of 2007, compared to 17,997 Mmcfe for the comparable period of 2006. The variance in production volumes between the two periods is primarily due to natural production declines and mechanical issues in the Weeks Island field, partially offset by production from new discoveries brought online since the third quarter of 2006.

Since the third quarter of 2006, the Company has taken an aggressive approach to increase its acreage position and drilling activities in East Texas and has contracted for the purchase of one rig and a twelve-month lease of an additional rig that will better ensure an uninterrupted drilling and completion schedule and the replacement of production and reserves. Although natural gas prices for the industry in general have experienced a decline since 2006, the Company’s effective hedging strategy continues to partially insulate it against the total impact of such price declines.

The following table summarizes the Company’s operating revenues, production volumes and average sales prices for the nine months ended September 30, 2007 and 2006:


	Nine Months Ended
	September 30,				Increase
	2007		2006		(Decrease)
Production Volumes:
Oil (Mbbl)		635		653		(3	%)
Natural gas (MMcf)		10,357		14,081		(26	%)
Mmcfe		14,164		17,997		(21	%)

Average Sales Prices:
Oil (per Bbl)	$	59.51	$	56.59		5	%
Natural gas (per Mcf)	$	7.32	$	7.94		(8	%)
Mmcfe	$	8.02	$	8.26		(3	%)

Operating Revenues (000’s):
Oil	$	37,769	$	36,939		2	%
Natural gas		75,799		111,784		(32	%)

Total Operating Revenues	$	113,568	$	148,723		(24	%)

Operating Expenses. Oil and natural gas operating expenses on an aggregate basis increased $5.7 million (35%) to $21.7 million during the first nine months of 2007, compared to $16.0 million in 2006. On a unit basis, lease operating expenses increased $0.64 per Mcfe to $1.53 per Mcfe for the first nine months of 2007 from $0.89 per Mcfe for the first nine months of 2006. Oil and natural gas operating expenses increased between the periods primarily due to significantly higher insurance costs, industry wide increases in service costs and increased maintenance-related activities. For the policy year beginning in May 2006 through April 2007, insurance premiums increased over 450% from the prior policy year. During the first nine months of 2007 insurance premiums increased by $2.1 million and represented 37% of the difference in lease operating expenses between the periods. During the second quarter of 2007 approximately $0.5 million was expensed due to a civil penalty arising from environmental litigation (see Note 6 to Consolidated Financial Statements). The remaining $3.1 million increase in operating expenses was associated with the addition and acquisition of producing wells and additional costs related to Biloxi Marshlands area production and facilities including compression, storage and repairs. Although the company’s insurance costs rose for the period from May 2006 through April 2007, the premium for the policy for May 2007 through April 2008 has decreased by approximately 30%. We continue to insure our assets with improved coverage as a safeguard against losses for the Company in the event of another hurricane. The increase in the per Mcfe rate was additionally attributable to the lower production between the two corresponding periods.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes decreased $1.0 million (11%) for the first nine months of 2007 in comparison to the same period in 2006 primarily because of the decrease in oil and natural gas production volumes, partially offset by a higher average 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 $0.269 per Mcf (effective July 1, 2007) for natural gas. For the first six months of 2007 and the last six months of 2006, the rate was $0.373 per Mcf for natural gas, an increase from $0.252 per Mcf for the first half of 2006. On an equivalent unit of production basis, severance and ad valorem taxes increased to $0.54 per Mcfe from $0.47 per Mcfe for the comparable nine-month period.

Depletion and Depreciation. Depletion and depreciation expense decreased $27.2 million (32%) during the first nine months of 2007 to $58.2 million, from $85.4 million for the same period of 2006. This was primarily the result of a decrease in the depletion rate as compared to the 2006 period, and the decline in

natural gas production. The rate decrease between the periods was due to the impact of the impairment of long-lived assets recognized during the third quarter of 2006. On a unit basis, depletion and depreciation expense decreased by $0.64 per Mcfe, to $4.11 per Mcfe for the nine months ended September 30, 2007, compared to $4.75 per Mcfe for the same period in 2006.

General and Administrative Expense. General and administrative expense was $11.9 million for the first nine months of 2007 and for the same period in 2006 was $13.9 million. This 15% decrease was primarily due to reductions in contract and consulting services, other professional fees, legal services and a decrease in office rent between the periods. On an equivalent unit of production basis, general and administrative expenses increased $0.07 per Mcfe to $0.84 per Mcfe for the first nine months of 2007 compared to $0.77 per Mcfe for the comparable 2006 period. Stock-based compensation expense of approximately $238,000 was recognized in the nine months ended September 30, 2007 compared to $286,000 for the nine month period ended September 30, 2006.

Hurricane Damage Repairs. This 2006 expense of $3.0 million is due to damages incurred from the 2005 hurricanes Katrina and Rita, primarily related to the Company’s insurance deductible and costs in excess of insured values.

Interest Expense. Interest expense increased $0.3 million (6%), to $4.6 million for the first nine months of 2007 in comparison to the first nine months of 2006. The increase is primarily a result of increased interest rates. The 2007 interest rate expense is net of approximately $191,000 of capitalized interest for the period associated with the construction of the drilling rig.

Liquidity and Capital Resources

Working Capital. During the third quarter of 2007, Meridian’s capital expenditures were internally financed with cash flow from operations and cash on hand. As of September 30, 2007, the Company had a cash balance of $24.1 million and working capital of $3.0 million.

Cash Flows. Net cash provided by operating activities was $74.3 million for the nine months ended September 30, 2007, as compared to $111.1 million for the same period in 2006. The decrease of $36.8 million was primarily due to lower natural gas commodity prices and lower production volumes.

Net cash used in investing activities was $83.0 million during the nine months ended September 30, 2007, versus $93.6 million in the first nine months of 2006.

Cash flows provided by financing activities during the first nine months of 2007 were $1.4 million, compared to $4.1 million during the first nine months of 2006. This decrease in cash provided by financing activities was primarily due to the 2007 change in the reductions in notes payable in connection with the Company’s annual insurance renewal and the repurchase of common stock.

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, collectively the “Lenders”. The borrowing base under the Credit Facility was redetermined to be $115 million by the syndication group effective October 31, 2007. As of September 30, 2007, outstanding borrowings under the Credit Facility totaled $75 million.

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. The determination of our borrowing base is subject to a number of factors, including quantities of proved oil and natural gas reserves, the bank’s price assumptions and other various factors unique to each member bank. Our Lenders can redetermine the borrowing base to a lower level than the current borrowing base if they determine that our oil and natural gas reserves, at the time of redetermination, are inadequate to support the borrowing base then in effect.

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 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 natural 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 an unqualified audit report on the Company’s consolidated financial statements, all of which the Company is in compliance.

Oil and Natural Gas Hedging Activities. The Company may address market risk by selecting instruments with fluctuating values that 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. 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 hedging 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 are reported in other comprehensive income except that changes in fair value resulting from ineffectiveness of the hedge are reported in the consolidated statement of operations as a component of revenues.

Capital Expenditures. Total capital expenditures for the nine months ended September 30, 2007, were approximately $85.6 million. Our strategy is to blend exploration drilling activities with high-confidence workover and development projects in order to capitalize on periods of high commodity prices. Capital expenditures were for acreage acquisitions, exploratory drilling, geological and geophysical, workovers, and related capitalized general and administrative expenses.

The 2007 capital expenditures plan is currently forecast at approximately $127 million. The actual expenditures will be determined based on a variety of factors, including prevailing prices for oil and natural gas, our expectations as to future pricing and the level of cash flow from operations. We currently anticipate funding the 2007 plan utilizing cash flow from operations and cash on hand. When appropriate, excess cash flow from operations beyond that needed for the 2007 capital expenditures plan will be used to de-lever the Company by development of exploration discoveries or direct payment of debt.

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.

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 and plans to sell properties, anticipated results from third party disputes and litigation, expectations regarding future financing and 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 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 are inherently 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 of available 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.

Full-Cost Ceiling Test. At the end of each quarter, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future net revenues from proved properties using period-end prices, after giving effect to cash flow hedge positions, discounted at 10%, and the lower of cost or fair value of unproved properties adjusted for related income tax effects.

The calculation of the ceiling test and the provision for depletion are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify a revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Due to the imprecision in estimating oil and natural gas revenues as well as the potential volatility in oil and natural gas prices and their effect on the carrying value of our proved oil and natural gas reserves, there can be no assurance that write-downs in the future will not be required as a result of factors that may negatively affect the present value of proved oil and natural gas reserves and the carrying value of oil and natural gas properties, including volatile oil and natural gas prices, downward revisions in estimated proved oil and natural gas reserve quantities and unsuccessful drilling activities. At September 30, 2007, we had a cushion (i.e. the excess of the ceiling over our capitalized costs) of approximately $73 million (before tax).

Borrowing base for the Credit Facility. The credit agreement with Fortis Capital Corp. as administrative agent, is presently scheduled for borrowing base redetermination dates on a semi-annual basis with the next such redetermination scheduled for April 30, 2008. 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.

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 million remains borrowed under the Credit Facility, 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.

The Company has 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. As of September 30, 2007, the positions effectively hedge approximately 31% of the estimated proved developed natural gas production and 37% of the estimated proved developed oil production during the respective terms of the 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.


								Estimated
								Fair Value
								Asset (Liability)
						Ceiling		September 30,
		Notional		Floor Price		Price		2007
	Type	Amount		($ per unit)		($ per unit)		(in thousands)
Natural Gas (mmbtu)
Oct 2007 – Dec 2007	Collar		1,110,000	$	7.00	$	11.50	$	555
Jan 2008 – Dec 2008	Collar		2,230,000	$	7.00	$	12.15		871
Jan 2008 – Dec 2008	Collar		1,010,000	$	7.50	$	11.50		567

						Total Natural Gas			1,993

Crude Oil (bbls)
Jan 2008 – Dec 2008	Collar		40,000	$	55.00	$	83.00		(124	)
Oct 2007 – Dec 2008	Collar		30,000	$	65.00	$	80.60		(82	)
Oct 2007 – Dec 2008	Collar		40,000	$	65.00	$	85.00		(45	)
Oct 2007 –April 2008	Collar		42,000	$	60.00	$	82.00		(123	)
May 2008 – July 2008	Collar		15,000	$	60.00	$	82.00		(45	)
Oct 2007 – July 2008	Collar		42,000	$	65.00	$	93.15		(4	)
Oct 2007 – July 2008	Collar		32,000	$	70.00	$	87.40		(1	)
						Total Crude Oil			(424	)

								$	1,569

The above excludes hedges entered into after September 30, 2007; see Note 12, Subsequent Events, of the Notes to Consolidated Financial Statements for additional information.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We conducted an evaluation under the supervision of and with the participation of Meridian’s management, including our Chief Executive Officer, President 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 2007. Based upon that evaluation, our Chief Executive Officer, President 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 2007 that could significantly affect these controls.

Changes in Internal Controls

During the three month period ended September 30, 2007, there were no changes in the Company’s internal control over financial reporting that have materially affected or are reasonably likely to materially affect such internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings.

Litigation.

Environmental litigation. Various landowners have sued Meridian (along with numerous other oil companies) in 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 Company’s oil and natural gas operations. In some of the lawsuits, Shell Oil Company and SWEPI LP have demanded contractual indemnity and defense from Meridian based upon the terms of the purchase and sale agreement related to the fields, and in another lawsuit, Exxon Mobil Corporation has demanded contractual indemnity and defense from Meridian on the basis of a purchase and sale agreement related to the field(s) referenced in the lawsuit; Meridian has challenged such demands. In some cases, Meridian has also demanded defense and indemnity from their subsequent purchasers of the fields. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of these matters or to estimate the amount or range of potential loss should any outcome be unfavorable. Therefore, the Company has not provided any amount for these matters in its financial statements at September 30, 2007.

ITEM 1A. Risk Factors.

For a discussion of the Company’s risk factors, see Item 1A, “Risk Factors”, in the Company’s Form 10-K for the year ended December 31, 2006. There have been no changes to these risk factors during the quarter ended September 30, 2007.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

Following is a summary of our repurchase activity for the three-month period ending September 30, 2007:


	Total						Approximate Dollar Value
	Number of				Total Number of Shares		of Shares that May Yet Be
	Shares		Average Price		Purchased as Part of a		Purchased Under the Plan
Period	Purchased		Paid Per Share		Publicly Announced Plan (a)		During 2007

July 2007		—		—		—		—
August 2007		109,300	$	2.29		109,300	$	4,092,000
September 2007		—		—		—		—

Total		109,300	$	2.29		109,300	$	4,092,000

(a) In March 2007, our Board of Directors authorized the repurchase in the open market or through privately negotiated transactions of up to $5 million worth of common shares per year over the next three years. The timing, volume, and nature of share repurchases will be at the discretion of management, depending on market conditions, applicable securities laws, and other factors. As of September 30, 2007, the Company had repurchased 359,300 common shares in the open market at an aggregate cost of $908,000 of which 217,922 shares have been issued for 401(k) contributions, for contract services and for compensation. Such shares are reflected in the accompanying Consolidated Balance Sheet as “treasury stock.” See Note 7 of the Notes to Consolidated Financial Statements. It is our intent to continue this program through this and future years.

ITEM 5. Other Information.

During the fourth quarter of 2007 the Company expects to enter into a Consent Decree with the United States Environmental Protection Agency (“EPA”) regarding alleged violations of the Clean Water Act, as amended by the Oil Pollution Act of 1990. Under the Consent Decree, the Company will pay $504,000 in civil penalties for alleged discharges of crude oil into navigable waters or adjoining shorelines from the Company’s operations at the Weeks Island field in Iberia Parish, Louisiana. The Company will also be subject to certain injunctive relief, requiring the Company to conduct certain pipeline surveys, monitoring and reporting. Under the Consent Decree, the Company does not admit any liability arising out of the occurrences described in the Consent Decree or the related Complaint.

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.

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 9, 2007	By:	/s/ LLOYD V. DELANO

		Lloyd V. DeLano
		Senior Vice President
		Chief Accounting Officer

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