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: June 30, 2007

OR

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		(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 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 July 31, 2007: 89,350,558

 

 

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 Six Months Ended June 30, 2007 and 2006		3
Consolidated Balance Sheets as of June 30, 2007 (unaudited) and December 31, 2006		4
Consolidated Statements of Cash Flows (unaudited) for the Six Months Ended June 30, 2007 and 2006		6
Consolidated Statements of Stockholders’ Equity (unaudited) for the Six Months Ended June 30, 2007 and 2006		7
Consolidated Statements of Comprehensive Income (Loss) (unaudited) for the Six Months Ended June 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		15
Item 3. Quantitative and Qualitative Disclosures about Market Risk		28
Item 4. Controls and Procedures		29
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		30
Item 1A. Risk Factors		30
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		31
Item 4. Submission of Matters to a Vote of Security Holders		31
Item 5. Other Information		31
Item 6. Exhibits		32
SIGNATURES		33
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of President Pursuant to Rule 13a-14(a)
Certification of CAO Pursuant to 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

(thousands of dollars, except per share information)
(unaudited)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
REVENUES:
Oil and natural gas		$	39,716			$	45,101			$	79,859			$	102,928
Price risk management activities			4				1,003				16				363
Interest and other			321				436				745				755
			40,041				46,540				80,620				104,046
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating			6,988				5,011				14,755				9,564
Severance and ad valorem taxes			2,619				2,610				5,463				5,345
Depletion and depreciation			19,607				27,671				40,610				57,170
General and administrative			3,890				4,405				7,785				9,516
Accretion expense			574				319				1,127				620
Hurricane damage repairs			—				404				—				2,403
			33,678				40,420				69,740				84,618
EARNINGS BEFORE INTEREST AND INCOME TAXES			6,363				6,120				10,880				19,428
OTHER EXPENSE:
Interest expense			1,538				1,489				3,077				2,867
EARNINGS BEFORE INCOME TAXES			4,825				4,631				7,803				16,561
INCOME TAXES:
Current			(26	)			197				112				368
Deferred			2,146				1,591				3,318				6,019
			2,120				1,788				3,430				6,387
NET EARNINGS		$	2,705			$	2,843			$	4,373			$	10,174
NET EARNINGS PER SHARE:
Basic		$	0.03			$	0.03			$	0.05			$	0.12
Diluted		$	0.03			$	0.03			$	0.05			$	0.11
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic			89,329				86,950				89,291				86,900
Diluted			94,906				92,140				94,792				92,346

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

(thousands of dollars)

		June 30,				December 31,
		2007				2006
		(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	33,599			$	31,424
Restricted cash			28				1,282
Accounts receivable, less allowance for doubtful accounts of $232 [2007 and 2006]			21,340				24,285
Due from affiliates			4,906				670
Prepaid expenses and other			7,965				3,457
Assets from price risk management activities			2,820				7,968
Total current assets			70,658				69,086
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including $59,384 [2007] and $54,356 [2006] not subject to depletion)			1,709,815				1,663,865
Land			48				48
Equipment			10,813				7,492
			1,720,676				1,671,405
Less accumulated depletion and depreciation			1,314,116				1,273,522
Total property and equipment, net			406,560				397,883
OTHER ASSETS:
Assets from price risk management activities			949				490
Other			215				436
Total other assets			1,164				926
TOTAL ASSETS		$	478,382			$	467,895

See notes to consolidated financial statements.

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

		June 30,				December 31,
		2007				2006
		(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	5,504			$	6,700
Advances from non operators			6,865				3,051
Revenues and royalties payable			8,990				7,933
Notes payable			6,818				2,754
Accrued liabilities			20,452				21,938
Liabilities from price risk management activities			1,274				1,024
Asset retirement obligations			3,863				4,803
Deferred income taxes payable			411				2,336
Current income taxes payable			30				—
Total current liabilities			54,207				50,539
LONG TERM DEBT			75,000				75,000
OTHER:
Deferred income taxes			6,708				3,364
Liabilities from price risk management activities			662				190
Asset retirement obligations			18,818				18,005
			26,188				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) 07] and 89,139,600 [2006] issued)			934				928
Additional paid in capital			536,309				534,441
Accumulated deficit			(214,906	)			(219,279	)
Accumulated other comprehensive income			1,179				4,707
			323,516				320,797
Less treasury stock, at cost 194,779 [2007] shares			(529	)			—
Total stockholders’ equity			322,987				320,797
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	478,382			$	467,895

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

(thousands of dollars)
(unaudited)

		Six Months Ended June 30,
		2007				2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings		$	4,373			$	10,174
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depletion and depreciation			40,610				57,170
Amortization of other assets			221				221
Non-cash compensation			1,360				1,197
Non-cash price risk management activities			(16	)			(363	)
Accretion expense			1,127				620
Deferred income taxes			3,318				6,019
Changes in assets and liabilities:
Restricted cash			1,254				(19	)
Accounts receivable			2,945				14,261
Prepaid expenses and other			(4,508	)			(5,911	)
Due from affiliates			(4,236	)			(1,825	)
Accounts payable			(1,196	)			(2,460	)
Advances from non-operators			3,814				651
Revenues and royalties payable			1,057				(1,799	)
Asset retirement obligations			(1,791	)			(590	)
Other assets and liabilities			(814	)			(2,400	)
Net cash provided by operating activities			47,518				74,946
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment			(51,280	)			(64,472	)
Proceeds from sale of property			2,530				10,741
Net cash used in investing activities			(48,750	)			(53,731	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions in long-term debt			—				(10,000	)
Reductions in notes payable			(4,895	)			(3,065	)
Proceeds from notes payable			8,959				7,919
Repurchase of common stock			(657	)			—
Net cash provided by (used in) financing activities			3,407				(5,146	)
NET CHANGE IN CASH AND CASH EQUIVALENTS			2,175				16,069
Cash and cash equivalents at beginning of period			31,424				23,265
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	33,599			$	39,334
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Non-cash activities:
Issuance of shares for contract services		$	(642	)		$	(588	)
ARO liability – new wells drilled		$	321			$	109
ARO liability – changes in estimates		$	216			$	694

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

Six Months Ended June 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			—				2				(2	)			—				—				—				—				—				—
Company’s 401(k) plan contribution			45				1				184				—				—				—				—				- -				185
Stock-based compensation – FAS123R			—				—				167				—				—				—				—				—				167
Compensation expense			—				—				845				—				—				—				—				—				845
Accum. other comprehensive income			—				—				—				—				3,351				—				—				—				3,351
Issuance of shares for contract services			162				2				586				—				—				—				—				—				588
Net earnings			—				—				—				10,174				—				—				—				—				10,174
Balance, June 30, 2006			87,025			$	905			$	526,154			$	(135,221	)		$	1,037			$	—				—			$	—			$	392,875
Balance, December 31, 2006			89,140			$	928			$	534,441			$	(219,279	)		$	4,707			$	—				—			$	—			$	320,797
Issuance of rights to common stock			—				4				(4	)			—				—				—				—				—				—
Company’s 401(k) plan contribution			97				—				137				—				—				—				(55	)			128				265
Shares repurchased			(250	)			—				—				—				—				—				250				(657	)			(657	)
Stock-based compensation – FAS123R			—				—				164				—				—				—				—				—				164
Compensation expense			—				—				846				—				—				—				—				—				846
Accum. other comprehensive loss			—				—				—				—				(3,528	)			—				—				—				(3,528	)
Issuance of shares for contract services			237				2				640				—				—				—				—				—				642
Issuance of shares as compensation stock			31				—				85				—				—				—				—				—				85
Net earnings			—				—				—				4,373				—				—				—				—				4,373
Balance, June 30, 2007			89,255			$	934			$	536,309			$	(214,906	)		$	1,179			$	—				195			$	(529	)		$	322,987

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

(thousands of dollars)

(unaudited)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2007				2006				2007				2006
Net earnings		$	2,705			$	2,843			$	4,373			$	10,174
Other comprehensive income (loss), net of tax, for unrealized gains (losses) from hedging activities:
Unrealized holding gains (losses) arising during period (1)			849				1,761				(2,082	)			2,605
Reclassification adjustments on settlement of contracts (2)			(243	)			(14	)			(1,446	)			746
			606				1,747				(3,528	)			3,351
Total comprehensive income		$	3,311			$	4,590			$	845			$	13,525
(1) net income tax (expense) benefit		$	(457	)		$	(948	)		$	1,121			$	(1,403	)
(2) net income tax (expense) benefit		$	131			$	7			$	778			$	(401	)

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

(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 June 30, 2007, and for the three and six month periods ended June 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 minor 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

On February 15, 2007, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB Statement No. 115 (“SFAS No. 159”)”. The statement 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. The Statement 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 June 30, 2007 and December 31, 2006 (thousands of dollars):

		June 30,				December 31,
		2007				2006
Capital expenditures		$	12,400			$	13,851
Operating expenses/taxes			5,127				4,024
Hurricane damage repairs			—				71
Compensation			819				1,197
Interest			485				506
Other			1,621				2,289
Total		$	20,452			$	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 determined to be $115 million by the syndication group effective April 30, 2007. As of June 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 and under certain circumstances preferred stock, limitations on the redemption of preferred 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 June 30, 2007, the three-month LIBOR interest rate was 5.36%. 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 has 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. Bond has recently died. The Company has not provided any amount for this matter in its financial statements at June 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 usually small 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. The Company, in certain instances, has indemnified third parties from the claims made in these lawsuits. In three of the lawsuits, Shell Oil Company and SWEPI LP have demanded indemnity and defense from Meridian; Meridian has denied such demands. The Company has not provided any amount for this matter in its financial statements at June 30, 2007.

During the third 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 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 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.

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 fourth quarter of 2007 when the rig will be mobilized to the Company’s East Texas Austin Chalk play. As of June 30, 2007, approximately $3.5 million has been capitalized as Equipment in the accompanying consolidated balance sheets.

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 June 30, 2007, the Company had repurchased 250,000 common shares at a cost of $657,000. 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 June 30,
		2007				2006
Numerator:
Net earnings		$	2,705			$	2,843
Denominator:
Denominator for basic earnings per share — weighted-average shares outstanding			89,329				86,950
Effect of potentially dilutive common shares:
Warrants			5,576				5,079
Employee and director stock options			1				111
Denominator for diluted earnings per share - weighted-average shares outstanding and assumed conversions			94,906				92,140
Basic earnings per share		$	0.03			$	0.03
Diluted earnings per share		$	0.03			$	0.03

		Six Months Ended June 30,
		2007				2006
Numerator:
Net earnings		$	4,373			$	10,174
Denominator:
Denominator for basic earnings per share — weighted-average shares outstanding			89,291				86,900
Effect of potentially dilutive common shares:
Warrants			5,501				5,027
Employee and director stock options			—				419
Denominator for diluted earnings per share — weighted-average shares outstanding and assumed conversions			94,792				92,346
Basic earnings per share		$	0.05			$	0.12
Diluted earnings per share		$	0.05			$	0.11

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, we 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 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 related to hedge ineffectiveness of approximately $4 thousand and $1.0 million during the three months ended June 30, 2007 and 2006, respectively, and of approximately $16 thousand and $363 thousand during the six months ended June 30, 2007 and 2006, respectively.

The estimated June 30, 2007 fair value of the Company’s oil and natural gas derivatives resulted in an unrealized gain of $1.8 million ($1.2 million net of tax) which is recognized in accumulated other comprehensive income. Based upon June 30, 2007 oil and natural gas commodity prices, approximately $1.5 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 (decreased) oil and natural gas revenues by $374,000 and $21,000 for the three months ended June 30, 2007 and 2006, respectively, and by $2,224,000 and ($1,147,000) for the six months ended June 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 June 30, 2007, the positions effectively hedge approximately 33% of the estimated proved developed natural gas production and 26% 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 June 30, 2007, is provided below:

																		Estimated
																		Fair Value
														Ceiling				Asset (Liability)
						Notional				Floor Price				Price				June 30, 2007
		Type				Amount				($ per unit)				($ per unit)				(in thousands)
Natural Gas (mmbtu)
July 2007 – Dec 2007		Collar					2,460,000			$	7.00			$	11.50			$	920
Jan 2008 – Dec 2008		Collar					2,230,000			$	7.00			$	12.15				523
Jan 2008 – Dec 2008		Collar					1,010,000			$	7.50			$	11.50				358
										Total Natural Gas									1,801
Crude Oil (bbls)
July 2007		Collar					12,000			$	50.00			$	74.00				(12	)
Jan 2008 – Dec 2008		Collar					40,000			$	55.00			$	83.00				(102	)
Aug 2007 –April 2008		Collar					54,000			$	60.00			$	82.00				(46	)
May 2008 – July 2008		Collar					15,000			$	60.00			$	82.00				(25	)
July 2007		Collar					3,000			$	60.00			$	96.10				—
May 2008 – July 2008		Collar					52,000			$	65.00			$	93.15				91
Aug 2007 – July 2008		Collar					40,000			$	70.00			$	87.40				126
										Total Crude Oil									32
																		$	1,833

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 $77,000 and $164,000 was recorded in the three months and six months ended June 30, 2007, respectively, and approximately $85,000 and $167,000 was recognized in the three months and six months ended June 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 six months ended June 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			321
Settlements during 2007			(1,791	)
Revisions to estimates and other changes during 2007			216
Accretion expense for 2007			1,127
Asset retirement obligation at June 30, 2007		$	22,681

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 our obligations to plug the natural gas and oil wells and costs to do so.

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 and Offshore, Mid-Continent, South Louisiana and Offshore, 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, and maintain its exposure to its historical high returns of and on capital deployed while at the same time developing longer lived reserves.

East Texas Area

This play holds the potential for becoming a significant resource play for the Company with a strong lease acreage position that will support a repeatable, multiple well-drilling and development program for the foreseeable future. Results from initial drilling activities in this key area have already made this a significant contributor to the Company’s plans for return to growth through increases in both production and reserves.

The Company and its joint venture partners currently hold approximately 38,000 gross acres in the play. Meridian continues to increase its position in this very competitive area and anticipates being able to add an additional 15,000 to 20,000 acres in the coming months. With the increased acreage position, the number of possible drilling locations increases in general terms to between 50 and 55 wells. Assuming continued success in the expansion of the play, the Company anticipates that it will maintain two rigs in this region until the play is fully developed. Meridian is the operator of the field, and, depending on participations and acreage contributions, will hold up to 75% working interest in each unit.

The Blackstone Minerals (“BSM”) No. 4 well has reached its total depth (“TD”). The single lateral well was drilled vertically to approximately 13,000 feet with the horizontal portion extending out approximately 5,500 feet for a total measured depth of approximately 18,500 feet. The well will be completed during August 2007 after which the well will be tested.

The BSM No. 2 well is currently drilling at approximately 15,700 feet MD. The single lateral well was drilled vertically to approximately 13,100 feet with the horizontal portion currently extending out approximately 2,600 feet. The targeted length for the lateral is 6,000 feet. Mechanical issues associated with the rig being used for this well and, separately, third party downhole directional tools, have caused delays in the length of time previously estimated to drill and complete this well. However, the Company has worked diligently with the owners of the rig to make the necessary repairs and expects improved progress in the rate of drilling going forward. The horizontal lateral is expected to reach TD during the third quarter of 2007.

The Company is participating in the Bear Creek No. 1-H well, which is currently drilling at approximately 14,000 feet MD on the first of two scheduled laterals approximately five miles northeast of Meridian’s operating area. Meridian holds approximately 7% working interest in this outside operated well.

The next wells scheduled for drilling in this area are the Freeman No. 1 well and the BSM No. 5 well. Each well is scheduled to drill and complete dual horizontal laterals extending roughly north and south between 5,000 and 6,000 feet each. The BSM No. 5 well is located approximately 1.5 miles northwest of the BSM No. 4 well. The Freeman No. 1 well is located approximately 4 miles northwest of the BSM No. 4 well.

The previously announced purchase and construction of one newly built land based drilling rig is on track for delivery. The rig is being designed and fabricated by Orion Drilling Company LP in Corpus Christi, Texas. The rig will be operated, crewed and maintained by Orion. Delivery of the rig is currently expected in the fourth quarter of 2007 when it will be mobilized to the Company’s East Texas Austin Chalk play. Depending on the success of the operations in the play, the Company has plans for a two-rig, multi-well drilling program to exploit and develop the Company’s acreage under lease for an anticipated three to seven year period.

Texas Gulf Coast and Offshore

In August of 2006, the Company purchased all of the Texas Gulf Coast assets of Vintage Petroleum LLC for approximately $21 million in cash and stock. The assets were comprised of both producing properties as well as exploration and exploitation properties as identified on the proprietary and acquired 3-D seismic data over the properties. Since the purchase, Meridian has participated in six wells in the area including one well that is currently drilling with one more still budgeted for 2007. Six additional prospective well locations have emerged as a result of the successful drilling in this area.

The Company recently participated in the outside operated ST 974 No. 2 well located in Nueces Bay in San Patricio County, Texas (northeast of Corpus Christi). The well targeted a shallow Frio sand in a separate fault block of the East White Point field. The well was drilled to approximately 6,400 feet MD and logged prospective pay in the Frio sand section at 6,300 feet with two additional prospective sands (including the Brigham sand) above it. The well was recently tested in the 6,300’ sand section at a gross daily flow rate of 90 barrels of oil per day and 120 Mcf per day. The well is currently producing oil into sales. The primary objective sand, the Brigham sand, is scheduled to be tested in the next couple of weeks. If successful, the well will co-mingle production from both the 6,300’ sand and the Brigham sand. Depending on the results of testing and production, it is anticipated that this prospect can be offset with an additional development well. The Company owns approximately 23% working interest in the well and its offset.

The outside operated ST 976 No. 2 well on the East White Point prospect located in the Nueces Bay project area is being drilled to test several deep Frio sands. These are the same sands that were successfully exploited in the previously drilled B.P. America well during the fourth quarter of 2006. This well is currently at approximately 10,700 feet on its way to a total depth of approximately 13,000 feet MD. Meridian owns approximately 23% working interest in this well.

The ST 786 No. 12 well on the Indian Point prospect located in the Nueces Bay project area was fracture stimulated in one of two deep Anderson sand sections of the lower Frio formation. The results of the fracture stimulation were in and of themselves uneconomic. Therefore, operations were begun to move up the hole to test and fracture stimulate the upper portion of the Anderson (Frio) sand. During the preparations for the next test, downhole tools became stuck in the deviated hole which has required several weeks of time to clear and retrieve. The retrieval process is nearly complete and the Company expects to be moving forward shortly with its plans to exploit the remaining uphole sands.

The Company recently drilled the High Island 55 No. 7 well, located in the shallow offshore waters of the Texas Gulf Coast. The well was drilled to approximately 8,000 feet targeting the Siph D “A” sand section. The well was logged with the results showing sands that contained no hydrocarbons. The well was plugged and abandoned.

Mid-Continent

In the Mid-Continent region of north central Oklahoma, the Company is proceeding with plans to develop its approximately 22,000 acre position in the Hunton/Woodford de-watering play pilot project. Since acquiring the leases, the company has drilled four wells including one saltwater disposal well. Of the three gas wells drilled to date, the Constellation 8-2 well was successfully completed in the Mississippian formation.

The other two wells (Constellation No. 8-1 and Enterprise No. 7-1) were determined be depleted in the Hunton formation, rendering them uneconomic in that zone. Subsequent to this determination, and its affects on the acreage surrounding these wells, the Company has adjusted its original 2007 budgeted plans of fourteen total wells for this area to a lesser number depending on further testing and results. During the course of the next five months, the Company has plans to drill up to four additional wells with the possibility of more to follow depending on the success of those tests. The Company still believes this is a good prospective area and recognizes it as a potentially important component of its overall strategic plan for long term growth and asset diversification. Meridian operates the field and owns approximately 80% working interest.

South Louisiana and Offshore

South Louisiana remains a core area for Meridian where it has built a large knowledge and information base that it believes holds significant value for the development of future projects and significant potential for increased reserves and production during 2007. Although the Company is expanding beyond its traditional footprint of South Louisiana, it continues to be a core area for growth and a strategic part of the Company’s portfolio management by generating and participating in the drilling of targets for larger reserves with strong cash flows. Several projects remain to be tested during 2007 to complete the Company’s planned capital spending for this region.

In offshore Gulf of Mexico, the Company is drilling a prospect on its West Cameron Block 332 project area located in the federal offshore waters approximately 50 miles off the southwest coast of Louisiana. Currently the well is at a depth of approximately 8,100 feet MD headed for the targeted formation in the Upper Miocene sand at a depth of approximately 13,800 feet. The gross unrisked reserve potential for this prospect is approximately 15 to 30 Bcfe. Meridian owns 17% working interest before casing point and 37% working interest after casing point and is the operator of the well. If successful, it is contemplated that at least one additional well will be drilled on this lease block.

Deep Archtop

The Company continues to develop its Deep Archtop prospect for drilling. The project is designed to test a Jurassic Cotton Valley four-way closure in the Biloxi Marshlands area of St. Bernard Parish, Louisiana. This 30,000-foot prospect has over 14,400 acres of closure, imaged by 3-D seismic and offers reserve potential of up to 5-7 trillion cubic feet of gas.

The Company has acquired additional acreage over the play from both the State of Louisiana and multiple landowners in the vicinity. In addition, meetings with both State of Louisiana agencies and local governmental authorities have been held with positive results that support the Company’s planned routes, drilling location and timing. The Company will spend the coming year in pre-drill work, followed by 300-plus days to drill the well which is estimated to cost up to $60 million. The shallow marshlands water location provides the potential for significant savings in drilling the test well and post development infrastructure compared to similarly sized offshore projects which typically cost much more and require longer periods of time to construct the necessary pipelines and production facilities. Meridian owns production facilities and pipelines in the immediate area. Meridian intends to retain and pay its share of approximately 20-25% working interest in this well. The Company has set a target date of mid-year 2008 for initiating drilling operations on this significant test well.

Unconventional Resource Plays

The Company’s push for diversity and growth continues to develop in the Delaware Basin, Palo Duro Basin and Illinois Basin.

In the Delaware Basin, the Company and its joint venture partner have completed their evaluation of the previously acquired 2D seismic in the area and have selected the first two locations to be drilled in the fourth quarter. These wells will target the Barnett and Woodford Shale sections which range between 5,500 and 8,500 feet. Targeted reserves range between 2 and 3 Bcf per well. Meridian’s 50% joint venture partner will operate substantially all of the drilling and production for the project. The group owns approximately 85,000 acres in the area and anticipates that it will drill a minimum of two wells during 2007.

In the New Albany Shale Play in the Illinois Basin, the Company continues to acquire leases and currently owns an approximate 30,000-acre lease position. Meridian has plans for two wells in this area between now and the end of the year. The Company’s working interest in the play is 92% with Meridian as operator.

In the Palo Duro Basin Play, the Company owns approximately 35,000 gross acres. Several operators in the basin are in various stages of testing optimal drilling and completion techniques for wells in the area, with reported successful results. The Company owns 92% working interest in the play and is currently developing a plan for drilling operations in this region.

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 June 30, 2007, was $61.20 per barrel compared to $56.01 per barrel for the three months ended June 30, 2006, and $50.30 per barrel for the three months ended March 31, 2007. Our average natural gas price (after adjustments for hedging activities) for the three months ended June 30, 2007, was $7.77 per Mcf compared to $7.29 per Mcf for the three months ended June 30, 2006, and $7.34 per Mcf for the three months ended March 31, 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 June 30, 2007 Compared to Three Months Ended June 30, 2006

Operating Revenues. Second 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 $5.4 million (12%) as compared to second quarter 2006 revenues due to a 19% decrease in production volumes partially offset by a 9% increase in average commodity prices on a natural gas equivalent basis. Oil and natural gas production volumes totaled 4,734 Mmcfe for the second quarter of 2007 compared to 5,850 Mmcfe for the comparable period of 2006. Our average daily production decreased from 64.3 Mmcfe during the second quarter of 2006 to 52.0 Mmcfe for the second quarter of 2007. 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 second quarter of 2006.

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

		Three Months Ended
		June 30,								Increase
		2007				2006				(Decrease)
Production Volumes:
Oil (Mbbl)			201				199				1	%
Natural gas (MMcf)			3,526				4,657				(24	%)
Mmcfe			4,734				5,850				(19	%)
Average Sales Prices:
Oil (per Bbl)		$	61.20			$	56.01				9	%
Natural gas (per Mcf)		$	7.77			$	7.29				7	%
Mmcfe		$	8.39			$	7.71				9	%
Operating Revenues (000’s):
Oil		$	12,314			$	11,145				10	%
Natural gas			27,402				33,956				(19	%)
Total Operating Revenues		$	39,716			$	45,101				(12	%)

Operating Expenses. Oil and natural gas operating expenses on an aggregate basis increased $2.0 million (39%) to $7.0 million during the second quarter of 2007, compared to $5.0 million in the second quarter of 2006. On a unit basis, lease operating expenses increased $0.62 per Mcfe to $1.48 per Mcfe for the second quarter of 2007 from $0.86 per Mcfe for the second quarter 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 second quarter of 2007 insurance premiums increased by $0.6 million and represented 30% of the difference in lease operating expenses between the quarters. During the second quarter of 2007 approximately $0.5 million has been expensed due to a civil penalty arising from environmental litigation (see Note 6 to Consolidated Financial Statements). The remaining $0.9 million increase in operating expense was associated with the addition of new producing wells in East Texas and southern Louisiana and from the Vintage acquisition, as well as 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 totaled $2.6 million for the second quarter of 2007, the same as the second quarter of 2006. For the second quarter of 2007, there was an increase in oil volumes and prices and a higher natural gas tax rate that was offset by a decrease in 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 $0.373 per Mcf for natural gas, an increase from $0.252 per Mcf for the second quarter of 2006. On an equivalent unit of production basis, severance and ad valorem taxes increased to $0.55 per Mcfe from $0.45 per Mcfe for the three-month period. Beginning July 1, 2007, the revised severance tax rate for natural gas production in Louisiana over the next twelve months will be $0.269 per Mcf. This will significantly decrease the amount of severance taxes being paid in future periods.

Depletion and Depreciation. Depletion and depreciation expense decreased $8.1 million (29%) during the second quarter of 2007 to $19.6 million, from $27.7 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 natural gas production. On a unit basis, depletion and depreciation expense decreased by $0.59 per Mcfe, to $4.14 per Mcfe for the three months ended June 30, 2007, compared to $4.73 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 $0.5 million (12%) to $3.9 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 $0.07 per Mcfe to $0.82 per Mcfe for the second quarter of 2007 compared to $0.75 per Mcfe for the comparable 2006 period primarily due to lower production rates between the periods. Stock-based compensation expense of approximately $78,000 was recognized in the three months ended June 30, 2007 compared to $85,000 for the three month period ended June 30, 2006.

Hurricane Damage Repairs. This reduction was due to no additional costs during the second 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 second quarter of 2007 and the second quarter of 2006.

Six Months Ended June 30, 2007 Compared to Six Months Ended June 30, 2006

Operating Revenues. Oil and natural gas revenues during the six months ended June 30, 2007, which include oil and natural gas hedging activities (see Note 9 to Consolidated Financial Statements) decreased $23.1 million (22%) as compared to first half 2006 revenues due to a 19% decrease in production volumes and a 5% decrease in average sale prices on a natural gas equivalent basis. Our average daily production decreased from 67.9 Mmcfe during the first six months of 2006 to 55.2 Mmcfe for the first six months of 2007. Oil and natural gas production volume totaled 9,991 Mmcfe for the first six months of 2007, compared to 12,282 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 second 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 the first half of 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 six months ended June 30, 2007 and 2006:

		Six Months Ended
		June 30,								Increase
		2007				2006				(Decrease)
Production Volumes:
Oil (Mbbl)			450				423				6	%
Natural gas (MMcf)			7,290				9,744				(25	%)
Mmcfe			9,991				12,282				(19	%)
Average Sales Prices:
Oil (per Bbl)		$	55.17			$	52.43				5	%
Natural gas (per Mcf)		$	7.55			$	8.29				(9	%)
Mmcfe		$	7.99			$	8.38				(5	%)
Operating Revenues (000’s):
Oil		$	24,833			$	22,179				12	%
Natural gas			55,026				80,749				(32	%)
Total Operating Revenues		$	79,859			$	102,928				(22	%)

Operating Expenses. Oil and natural gas operating expenses on an aggregate basis increased $5.2 million (54%) to $14.8 million during the first six months of 2007, compared to $9.6 million in 2006. On a unit basis, lease operating expenses increased $0.70 per Mcfe to $1.48 per Mcfe for the first six months of 2007 from $0.78 per Mcfe for the first half 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 six months of 2007 insurance premiums increased by $2.0 million and represented 38% of the difference in lease operating expenses between the halves. During the second quarter of 2007 approximately $0.5 million has been expensed due to a civil penalty arising from environmental litigation (see Note 6 to Consolidated Financial Statements). The remaining $2.7 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 increased slightly for the first six months of 2007 in comparison to the same period in 2006 primarily because of an increase in oil volumes and prices and a higher natural gas tax rate, partially offset by a decrease in natural gas production. 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 $0.373 per Mcf for natural gas for the first six months of 2007, 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 $0.55 per Mcfe from $0.44 per Mcfe for the comparable six-month period. Beginning July 1, 2007, the revised severance tax rate for natural gas production in Louisiana over the next twelve months will be $0.269 per Mcf. This will significantly decrease the amount of severance taxes being paid in future periods.

Depletion and Depreciation. Depletion and deprecation expense decreased $16.6 million (29%) during the first half of 2007 to $40.6 million, from $57.2 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 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 $0.59 per Mcfe, to $4.06 per Mcfe for the six months ended June 30, 2007, compared to $4.65 per Mcfe for the same period in 2006.

General and Administrative Expense. General and administrative expense was $7.8 million for the first six months of 2007 and for the same period in 2006 was $9.5 million. This 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 $0.01 per Mcfe to $0.78 per Mcfe for the first six months of 2007 compared to $0.77 per Mcfe for the comparable 2006 period. Stock-based compensation expense of approximately $164,000 was recognized in the six months ended June 30, 2007 compared to $167,000 for the six month period ended June 30, 2006.

Hurricane Damage Repairs. This 2006 expense of $2.4 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 $0.2 million (7%), to $3.1 million for the first six months of 2007 in comparison to the first half of 2006. The increase is primarily a result of increased interest rates.

Liquidity and Capital Resources

Working Capital. During the second quarter of 2007, Meridian’s capital expenditures were internally financed with cash flow from operations and cash on hand. As of June 30, 2007, the Company had a cash balance of $33.6 million and working capital of $16.5 million.

Cash Flows. Net cash provided by operating activities was $47.5 million for the six months ended June 30, 2007, as compared to $74.9 million for the same period in 2006. The decrease of $27.4 million was primarily due to lower natural gas commodity prices and lower natural gas production volumes.

Net cash used in investing activities was $48.8 million during the six months ended June 30, 2007, versus $53.7 million in the first six months of 2006.

Cash flows provided by financing activities during the first six months of 2007 were $3.4 million, compared to cash used in financing activities of $5.1 million during the first six months of 2006. This increase in cash provided by financing activities was primarily due to the second quarter 2007 increase in notes payable issued in connection with the Company’s annual insurance renewal.

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 Bankc 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 April 30, 2007. As of June 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 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 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 June 30, 2007, the three-month LIBOR interest rate was 5.36%. 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.

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 revenues.

Capital Expenditures. Total capital expenditures for this period were approximately $51.3 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 and amortization 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 June 30, 2007, we had a cushion (i.e. the excess of the ceiling over our capitalized costs) of approximately $78 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 October 31, 2007. 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 June 30, 2007, the positions effectively hedge approximately 33% of the estimated proved developed natural gas production and 26% 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)
						Notional				Floor Price				Ceiling Price				June 30, 2007
		Type				Amount				($ per unit)				($ per unit)				(in thousands)
Natural Gas (mmbtu)
July 2007 – Dec 2007		Collar					2,460,000			$	7.00			$	11.50			$	920
Jan 2008 – Dec 2008		Collar					2,230,000			$	7.00			$	12.15				523
Jan 2008 – Dec 2008		Collar					1,010,000			$	7.50			$	11.50				358
										Total Natural Gas									1,801
Crude Oil (bbls)
July 2007		Collar					12,000			$	50.00			$	74.00				(12	)
Jan 2008 – Dec 2008		Collar					40,000			$	55.00			$	83.00				(102	)
Aug 2007 –April 2008		Collar					54,000			$	60.00			$	82.00				(46	)
May 2008 – July 2008		Collar					15,000			$	60.00			$	82.00				(25	)
July 2007		Collar					3,000			$	60.00			$	96.10				—
May 2008 – July 2008		Collar					52,000			$	65.00			$	93.15				91
Aug 2007 – July 2008		Collar					40,000			$	70.00			$	87.40				126
										Total Crude Oil									32
																		$	1,833

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 second 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 second quarter of 2007 that could significantly affect these controls.

Changes in Internal Controls

During the three month period ended June 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.

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 has 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. Bond has recently died. The Company has not provided any amount for this matter in its financial statements at June 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 usually small 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. The Company, in certain instances, has indemnified third parties from the claims made in these lawsuits. In three of the lawsuits, Shell Oil Company and SWEPI LP have demanded indemnity and defense from Meridian; Meridian has denied such demands. The Company has not provided any amount for this matter in its financial statements at June 30, 2007.

During the third 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 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 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 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 June 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 June 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
April 2007			—
May 2007			—
June 2007			100,000			$	3.05				100,000			$	4,343,000
Total			100,000			$	3.05				100,000			$	4,343,000

ITEM 4. Submission of Matters to a Vote of Security Holders.

At the annual meeting of shareholders held on June 21, 2007, the Company’s shareholders elected one Class I Director and three Class II Directors. The following summarizes the votes for and withheld for each nominee.

Nominee		Class		For				Withheld
C. Mark Pearson		I			65,644,701				10,900,617
E. L. Henry		II			63,043,927				13,501,391
Joe E. Kares		II			63,030,977				13,514,341
Gary Messersmith		II			64,541,096				12,094,222

Shareholders also voted to accept a proposal to adopt the 2007 Long Term Incentive Plan and a proposal to approve the performance criteria for performance awards under the 2007 Long Term Incentive Plan. The following summarizes the votes related to these proposals.

Proposal		For				Against				Withheld				Non-Vote
2007 Long Term			34,677,502				10,518,784				384,743				30,964,289
Incentive Plan
Performance Criteria			35,477,035				9,679,178				424,817				30,964,288
for 2007 Long Term Incentive Plan

ITEM 5. Other Information.

During the third 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)

Exhibit Index

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.