Edgar Filing: MERIDIAN RESOURCE CORP

e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended: June 30, 2008


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 (State or other jurisdiction of incorporation or organization)		76-0319553 (I.R.S. Employer Identification No.)

1401 Enclave Parkway, Suite 300, Houston, Texas 77077
(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: 281-597-7000

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ Noo

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

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o Noþ

Number of shares of common stock outstanding at July 31, 2008: 91,275,505

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, 2008 and 2007		3

Consolidated Balance Sheets as of June 30, 2008 (unaudited) and December 31, 2007		4

Consolidated Statements of Cash Flows (unaudited) for the Six Months Ended June 30, 2008 and 2007		6

Consolidated Statements of Stockholders’ Equity (unaudited) for the Six Months Ended June 30, 2008 and 2007		8

Consolidated Statements of Comprehensive Income (Loss) (unaudited) for the Six Months Ended June 30, 2008 and 2007		9

Notes to Consolidated Financial Statements (unaudited)		10

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		21

Item 3. Quantitative and Qualitative Disclosures about Market Risk		30

Item 4. Controls and Procedures		31

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		32

Item 1A. Risk Factors		33

Item 6. Exhibits		33

SIGNATURES		34
Retention Incentive Compensation Plan
Certification of CEO Pursuant to Rule 13a-14(a) or Rule 15d-14(a)
Certification of COO Pursuant to Rule 13a-14(a) or Rule 15d-14(a)
Certification of CAO Pursuant to Rule 13a-14(a) or Rule 15d-14(a)
Certification of CEO Pursuant to Section 1350
Certification of COO Pursuant to Section 1350
Certification of CAO Pursuant to Section 1350

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands of dollars, except per share information)
(unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
REVENUES:
Oil and natural gas	$	46,534		$	39,716		$	84,982		$	79,859
Price risk management activities		4			4			(30	)		16
Interest and other		105			321			232			745

		46,643			40,041			85,184			80,620

OPERATING COSTS AND EXPENSES:
Oil and natural gas operating		7,154			6,988			13,224			14,755
Severance and ad valorem taxes		2,996			2,619			5,574			5,463
Depletion and depreciation		17,886			19,607			35,628			40,610
General and administrative		5,215			3,890			9,290			7,785
Contract settlement		9,894			—			9,894			—
Accretion expense		531			574			1,098			1,127

		43,676			33,678			74,708			69,740

EARNINGS BEFORE INTEREST AND INCOME TAXES		2,967			6,363			10,476			10,880


OTHER EXPENSE:
Interest expense		1,372			1,538			2,523			3,077


EARNINGS BEFORE INCOME TAXES		1,595			4,825			7,953			7,803


INCOME TAXES:
Current		(96	)		(26	)		11			112
Deferred		852			2,146			3,540			3,318

		756			2,120			3,551			3,430


NET EARNINGS	$	839		$	2,705		$	4,402		$	4,373


NET EARNINGS PER SHARE:
Basic	$	0.01		$	0.03		$	0.05		$	0.05
Diluted	$	0.01		$	0.03		$	0.05		$	0.05

WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic		91,387			89,329			90,372			89,291
Diluted		94,501			94,906			94,901			94,792

See notes to consolidated financial statements.

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


	June 30,		December 31,
	2008		2007
	(unaudited)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	16,451	$	13,526
Restricted cash		9,925		30
Accounts receivable, less allowance for doubtful accounts of $210 [2008 and 2007]		26,207		19,874
Due from affiliates		—		2,580
Prepaid expenses and other		5,725		4,538
Assets from price risk management activities		200		2,453
Deferred tax asset		16,048		164

Total current assets		74,556		43,165


PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including $58,810 [2008] and $53,645 [2007] not subject to depletion)		1,823,531		1,771,768
Land		48		48
Equipment and other		21,436		18,503

		1,845,015		1,790,319
Less accumulated depletion and depreciation		1,386,535		1,350,577

Total property and equipment, net		458,480		439,742


OTHER ASSETS:
Assets from price risk management activities		355		865
Other		788		3

Total other assets		1,143		868


TOTAL ASSETS	$	534,179	$	483,775

See notes to consolidated financial statements.

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


	June 30,			December 31,
	2008			2007
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY

CURRENT LIABILITIES:
Accounts payable	$	8,058		$	9,583
Advances from non-operators		6,479			6,996
Revenues and royalties payable		7,551			6,592
Due to affiliates		9,770			—
Notes payable		4,273			2,662
Accrued liabilities		18,253			22,011
Liabilities from price risk management activities		17,200			2,772
Asset retirement obligations		5,592			3,365
Current income taxes payable		10			147
Current maturities of long-term debt		1,764			—

Total current liabilities		78,950			54,128

LONG-TERM DEBT		97,953			75,000


OTHER:
Deferred income taxes		20,274			8,238
Liabilities from price risk management activities		4,805			861
Asset retirement obligations		14,759			20,118

		39,838			29,217


COMMITMENTS AND CONTINGENCIES (Note 7)

STOCKHOLDERS’ EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized, 89,450,466 [2008 and 2007] issued)		939			936
Additional paid-in capital		538,225			537,145
Accumulated deficit		(207,740	)		(212,142	)
Accumulated other comprehensive loss		(13,939	)		(221	)

		317,485			325,718

Less treasury stock, at cost 26,566 [2008] and 158,683 [2007]shares		47			288

Total stockholders’ equity		317,438			325,430

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	534,179		$	483,775

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(thousands of dollars)
(unaudited)


	Six Months Ended June 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings	$	4,402		$	4,373
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depletion and depreciation		35,628			40,610
Amortization of other assets		85			221
Non-cash compensation		1,324			1,360
Non-cash price risk management activities		30			(16	)
Accretion expense		1,098			1,127
Deferred income taxes		3,540			3,318
Changes in assets and liabilities:
Restricted cash		(9,895	)		1,254
Accounts receivable		(6,334	)		2,945
Prepaid expenses and other		(1,188	)		(4,508	)
Due to / from affiliates		12,350			(4,236	)
Accounts payable		2,167			556
Advances from non-operators		(517	)		3,814
Revenues and royalties payable		958			1,057
Asset retirement obligations		(627	)		(1,791	)
Other assets and liabilities		2,662			(814	)

Net cash provided by operating activities		45,683			49,270

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment		(72,720	)		(53,032	)
Proceeds from sale of property		4,502			2,530

Net cash used in investing activities		(68,218	)		(50,502	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions in long-term debt		(10,283	)		—
Proceeds from long-term debt		35,000			—
Reductions in notes payable		(3,524	)		(4,895	)
Proceeds from notes payable		5,136			8,959
Repurchase of common stock		—			(657	)
Additions to deferred loan costs		(869	)		—

Net cash provided by financing activities		25,460			3,407

NET CHANGE IN CASH AND CASH EQUIVALENTS		2,925			2,175
Cash and cash equivalents at beginning of period		13,526			31,424

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	16,451		$	33,599


	Six Months Ended June 30,
	2008			2007
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Increase (decrease) of Non-cash Activities:
Issuance of shares for contract services	$	—		$	642
Accrual of capital expenditures	$	(10,248	)	$	(1,752	)
ARO liability — new wells drilled	$	50		$	321
ARO liability — changes in estimates	$	(3,653	)	$	216

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Six Months Ended June 30, 2008 and 2007
(in thousands)
(unaudited)


												Accumulated
						Additional			Accumulated			Other
	Common Stock					Paid-In			Earnings			Comprehensive			Treasury Stock
	Shares			Par Value		Capital			(Deficit)			Income (Loss)			Shares			Cost			Total

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 contributions		97			—		137			—			—			(55	)		128			265
Shares repurchased		(250	)		—		—			—			—			250			(657	)		(657	)
Stock-based compensation — FAS123R		—			—		164			—			—			—			—			164
Compensation expense		—			—		846			—			—			—			—			846
Accum. other comprehensive income activity		—			—		—			—			(3,528	)		—			—			(3,528	)
Issuance of shares for contract services		237			2		640			—			—			—			—			642
Issuance of shares as compensation		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


Balance, December 31, 2007		89,450		$	936	$	537,145		$	(212,142	)	$	(221	)		159		$	(288	)	$	325,430
Issuance of rights to common stock		—			3		(3	)		—			—			—			—			—
Company’s 401(k) plan contributions		—			—		(3	)		—			—			(72	)		133			130
Stock-based compensation — FAS123R		—			—		92			—			—			—			—			92
Compensation expense		—			—		968			—			—			—			—			968
Accum. other comprehensive income activity		—			—		—			—			(13,718	)		—			—			(13,718	)
Issuance of shares for contract services		—			—		26			—			—			(60	)		108			134
Net earnings		—			—		—			4,402			—			—			—			4,402

Balance, June 30, 2008		89,450		$	939	$	538,225		$	(207,740	)	$	(13,939	)		27		$	(47	)	$	317,438

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(thousands of dollars)
(unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007

Net earnings	$	839		$	2,705		$	4,402		$	4,373

Other comprehensive income (loss), net of tax, for unrealized gains (losses) from hedging activities:
Unrealized holding gains (losses) arising during period (1)		(11,781	)		849			(15,875	)		(2,082	)
Reclassification adjustments on settlement of contracts (2)		1,765			(243	)		2,157			(1,446	)

		(10,016	)		606			(13,718	)		(3,528	)


Total comprehensive income (loss)	$	(9,177	)	$	3,311		$	(9,316	)	$	845


(1) net income tax (expense) benefit	$	6,344		$	(457	)	$	8,548		$	1,121
(2) net income tax (expense) benefit	$	(951	)	$	131		$	(1,161	)	$	778

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

1. BASIS OF PRESENTATION

The consolidated financial statements reflect the accounts of The Meridian Resource Corporation and its subsidiaries (the “Company” or “Meridian”) after elimination of all significant intercompany transactions and balances. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007, as filed with the Securities and Exchange Commission (“SEC”).

The financial statements included herein as of June 30, 2008, and for the three and six month periods ended June 30, 2008 and 2007, 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. SIGNIFICANT ACCOUNTING POLICIES

Drilling Rig

TMR Drilling Corporation (“TMRD”), a wholly owned subsidiary of the Company, owns a rig which is used primarily to drill wells operated by the Company. In April 2008, an unaffiliated service company, Orion Drilling, Ltd, began leasing the rig from TMRD, and operating it under a dayrate contract with the Company. The Company records drilling expenditures under the dayrate contract as capitalized exploration costs. All TMRD profits or losses related to lease of the rig, including any incidental profits related to the share of drilling costs borne by our joint interest partners, are offset against the full cost pool. SEC guidelines for full cost accounting require this method in cases where services are performed by a company on properties that it owns and/or manages. A total of $148,000 in profit was transferred to the full cost pool in the three months and six months ending June 30, 2008, representing all profits on the lease, including those related to services performed on behalf of our joint interest partners.

In the future the rig may be used by the service company for work on third party wells in which the Company has no economic or management interest. In that case, a proportional amount of TMRD’s profit or loss related to the lease of the rig will be reflected in the statement of operations.

Restricted Cash

The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. The restricted cash balance at June 30, 2008 was $9,925,000 and on December 31, 2007, was $30,000. Restricted cash was increased by $9,895,000 in May 2008, when contractual obligations to certain executives were funded by cash placed in a Rabbi Trust account. The obligations and trust are more fully described in Note 13. Additional restricted cash is related to a contractual obligation with respect to royalties payable.

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 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 Company adopted SFAS 159 on January 1, 2008 and did not elect to apply the fair value method to any eligible assets or liabilities at that time. See Note 3 elsewhere in this report.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS 157”). SFAS 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosure about fair value measurements. The standard applies prospectively to new fair value measurements performed after the required effective dates, which are as follows: on January 1, 2008, for the Company, the standard became applicable to measurements of the fair values of financial instruments and recurring fair value measurements of non-financial assets and liabilities; on January 1, 2009, for the Company, the standard will apply to all remaining fair value measurements, including non-recurring measurements of non-financial assets and liabilities, such as asset retirement obligations and impairments of long-lived assets. The Company adopted the effective portion of SFAS 157 on January 1, 2008; the adoption had no material impact on our financial position or results of operations. We are evaluating the effect of the adoption of the standards which will become effective January 1, 2009, and do not expect their adoption to materially impact our financial position or results of operations.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS 141(R)”). SFAS 141(R) replaces SFAS No. 141, “Business Combinations.” SFAS 141(R) retains the purchase method of accounting for acquisitions, but requires a number of changes, including changes in the way assets and liabilities are recognized in purchase accounting. It also changes the recognition of assets acquired and liabilities assumed arising from contingencies and requires the expensing of acquisition-related costs as incurred. Generally, SFAS 141(R) will be effective for the Company on a prospective basis for all business combinations for which the acquisition date is on or after January 1, 2009. We do not expect the adoption of SFAS 141(R) to have a material impact on our financial position or results of operations, provided we do not undertake a significant acquisition or business combination.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” (“SFAS 161”) which amends FASB Statement No. 133. SFAS 161 provides guidance for additional disclosures regarding derivative contracts, including expanded discussions of risk and hedging strategy, as well as new tabular presentations of accounting data related to derivative instruments. SFAS 161 will be effective for fiscal years and interim periods beginning after November 15, 2008 with early application encouraged. We do not expect the adoption of SFAS 161 to have a material impact on our reported statements of financial position or results of operations.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”), which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America (the GAAP hierarchy). This Statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” We do not expect the adoption of SFAS 162 to have a material effect on our financial statements or related disclosures.

3. FAIR VALUE MEASUREMENT

The Company adopted the provisions of SFAS 157, effective January 1, 2008. SFAS 157 does not expand the use of fair value measurements, but rather, provides a framework for consistent measurement of fair value for those assets and liabilities already measured at fair value under other accounting pronouncements. Certain specific fair value measurements, such as those related to share-based compensation, are not included in the scope of SFAS 157. Primarily, SFAS 157 is applicable to assets and liabilities related to financial instruments, to some long-term investments and liabilities, to initial valuations of assets and liabilities acquired in a business combination, and to long-lived assets carried at fair value subsequent to an impairment write-down. It does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules. SFAS 157 applies to assets and liabilities carried at fair value on the consolidated balance sheet, as well as to supplemental fair value information about financial instruments not carried at fair value, which the Company provides annually under the provisions of SFAS 107, “Disclosures about Fair Value of Financial Instruments.”

Certain provisions of SFAS 157 have been deferred by the FASB. Accordingly, the Company has not applied the provisions of SFAS 157 to those non-financial assets and liabilities which are measured at fair value on a non-recurring basis. This includes asset retirement obligations, and any assets other than oil and natural gas properties, for which an impairment write-down is recorded during the period. There have been no such asset impairments in the current period.

The Company has applied the provisions of SFAS 157 to assets and liabilities measured at fair value on a recurring basis. This includes oil and natural gas derivatives contracts.

SFAS 157 provides a definition of fair value and a framework for measuring fair value, as well as expanding disclosures regarding fair value measurements. The framework requires fair value measurement techniques to include all significant assumptions that would be made by willing participants in a market transaction. These assumptions include certain factors not consistently provided for previously by those companies utilizing fair value measurement; examples of such factors would include the company’s own credit standing (when valuing liabilities) and the buyer’s risk premium. In adopting SFAS 157, the Company determined that the impact of these additional assumptions on fair value measurements did not have a material effect on financial position or results of operations. The Company is still assessing the potential impact of implementation in 2009 of those portions of the guidance for which the effective date has been deferred by the FASB.

SFAS 157 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to the “levels” described below. The hierarchy is based on the reliability of the inputs used in estimating fair value. The framework for fair value measurement assumes that transparent “observable” (Level 1) inputs generally provide the most reliable evidence of fair value and should be used to measure fair value whenever available. The classification of a fair value measurement is determined based on the lowest level (with Level 3 as lowest) of significant input to the fair value estimation process.

	•		Level 1 fair values are based on observable inputs. Observable inputs are quoted active market prices for assets and liabilities identical to those being valued.

	•		Level 2 fair values are based on observable inputs for similar assets and liabilities to those being valued. Level 2 fair values often rely on valuation models for which the significant inputs are observable Level 1 inputs or inputs which can be derived from Level 1 inputs through correlation.

	•		Level 3 fair values are based on at least one significant unobservable input, and may also utilize observable inputs. Unobservable inputs must be utilized when the asset or liability being valued is not actively traded. Level 3 fair values rely on valuation models that may utilize company-specific information or other unobservable inputs, developed based on the best information available in the circumstances.

The Company utilizes the modified Black-Scholes option pricing model to estimate the fair value of oil and natural gas derivative contracts. Inputs to this model include observable inputs from the New York Mercantile Exchange (NYMEX) for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and gas prices. The Company has classified the fair values of all its derivative contracts as Level 2.

Assets and liabilities measured at fair value on a recurring basis

Fair Value Measurements at June 30, 2008 Using

Quoted Prices in

Active Markets for

Significant Other

Identical Assets

Observable Inputs

Unobservable Inputs

Description

June 30, 2008

(Level 1)

(Level 2)

(Level 3)

Assets from price risk management activities ⁽¹⁾

555

Liabilities from price risk management activities ⁽¹⁾

22,005


(1)		Assets and liabilities from price risk management activities are oil and natural gas derivative contracts, in the form of costless collars to sell oil and natural gas within specific future time periods. These contracts are more fully described in Note 10.

4. ACCRUED LIABILITIES

Below is the detail of accrued liabilities on the Company’s balance sheets as of June 30, 2008 and December 31, 2007 (thousands of dollars):


	June 30,		December 31,
	2008		2007

Capital expenditures	$	8,900	$	14,821
Operating expenses/taxes		5,053		3,881
Compensation		1,340		853
Interest		333		460
Other		2,627		1,996


Total	$	18,253	$	22,011

5. 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. On February 21, 2008, the Company amended this Credit Facility (“Amended Credit Facility”). The lending institutions under the Amended Credit Facility include Fortis Capital Corp. as administrative agent, co-lead arranger and bookrunner; The Bank of Nova Scotia, as co-lead arranger and syndication agent; Comerica Bank, US Bank NA and Allied Irish Bank plc each in their

respective capacities as lenders, collectively the “Lenders.” The current borrowing base under the Amended Credit Facility was determined to be $110 million by the Lenders effective April 30, 2008. The maturity date was extended to February 21, 2012. As of June 30, 2008, outstanding borrowings under the Amended Credit Facility totaled $90 million.

The Amended 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 Amended 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 Amended 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 with at June 30, 2008.

Under the Amended 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 0.75% to 1.75% 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 2.5%, depending on the ratio of the aggregate outstanding loans and letters of credit to the borrowing base. At June 30, 2008, the three-month LIBOR interest rate was 2.78%. The Amended Credit Facility provides for commitment fees of 0.375% calculated on the difference between the borrowing base and the aggregate outstanding loans under the Amended Credit Facility.

On May 2, 2008, the Company, through its wholly owned subsidiary TMRD, entered into a financing agreement with The CIT Group Equipment Financing, Inc. (“CIT”). Under the terms of the agreement, TMRD borrowed $10.0 million, at a fixed interest rate of 6.625%, in order to refinance the purchase of a land-based drilling rig to be used in Company operations. The rig had been recently purchased using cash on hand and funds available to the Company under the Amended Credit Facility. Funds from the new agreement were used to reduce borrowing under the Amended Credit Facility. The new loan is collateralized by the drilling rig, as well as general corporate credit. The term of the loan is five years; monthly payments of $196,248 for interest and principal are to be made until the loan is completely repaid at termination of the agreement on May 2, 2013. At June 30, 2008, the balance is $9.7 million, with $7.9 million reported as long-term debt and $1.8 million as current portion of long-term debt in the Consolidated Balance Sheet.

6. INCOME TAXES

The Company’s effective tax rate of approximately 45% differs from the overall United States corporate tax rate of 35% primarily due to state income taxes, to non-deductible expenses related to the basis of certain oil and gas properties acquired in years past, and to other non-deductible expenses.

7. 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 T. Bond had been added as a defendant by Hawkins claiming Mr. Bond, when he was General Manager of Hawkins, did not have the right to consent, could not consent or breached his fiduciary duty to Hawkins if he did consent to all actions taken by Meridian. Mr. Bond was employed by H.L. Hawkins Jr. and his companies as General Manager until 2002. He served on the Board of Directors of the Company from March 1997 to August 2004. After Mr. Bond’s employment with Mr. Hawkins, Jr., and his companies ended, Mr. Bond was engaged by The Meridian Resource & Exploration LLC as a consultant. This relationship continued until his death. Mr. Bond was also the father-in-law of Michael J. Mayell, the Chief Operating Officer of the Company. A hearing was held before Judge Kay Bates on April 14, 2008. Judge Bates recently granted Hawkins’ Motion finding that Meridian was estopped from arguing that it did not breach its contract with Hawkins as a result of the United States Fifth Circuit’s decision in the Amoco litigation. Meridian disagrees with Judge Bates’ ruling and has recently filed a Writ with the Louisiana First Court of Appeal asking that the court overturn Judge Bates’ ruling. We are awaiting a ruling from the Court of Appeal. Management continues to vigorously defend this action on the basis that Mr. Hawkins individually and through his agent, Mr. Bond, agreed to the course of action adopted by Meridian and further that Meridian’s actions were not grossly negligent, but were within the business judgment rule. Since Mr. Bond’s death, a pleading has recently been filed substituting the proper party for Mr. Bond. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the Company has not provided any amount for this matter in its financial statements at June 30, 2008.

Title/lease disputes. Title and lease disputes may arise in the normal course of the Company’s operations. These disputes are usually small but could result in an increase or decrease in reserves once a final resolution to the title dispute is made.

Environmental litigation. Various landowners have sued Meridian (along with numerous other oil companies) in lawsuits

concerning several fields in which the Company has had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from the Company’s oil and natural gas operations. In some of the lawsuits, Shell Oil Company and SWEPI LP have demanded contractual indemnity and defense from Meridian based upon the terms of the purchase and sale agreement related to the fields, and in another lawsuit, Exxon Mobil Corporation has demanded contractual indemnity and defense from Meridian on the basis of a purchase and sale agreement related to the field(s) referenced in the lawsuit; Meridian has challenged such demands. In some cases, Meridian has also demanded defense and indemnity from their subsequent purchasers of the fields. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of these matters or to estimate the amount or range of potential loss should any outcome be unfavorable. Therefore, the Company has not provided any amount for these matters in its financial statements at June 30, 2008.

Litigation involving insurable issues. There are no material legal proceedings involving insurable issues which exceed insurance limits to which Meridian or any of its subsidiaries is a party or to which any of its property is subject, other than ordinary and routine litigation incidental to the business of producing and exploring for crude oil and natural gas.

8. COMMON STOCK

In March 2007, the Company’s Board of Directors authorized a 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 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. During February 2007, the lenders in the Credit Facility unanimously approved an amendment increasing the available limit for the Company’s repurchase of its common stock from $1.0 million to $5.0 million annually. The amendment contained restrictive covenants on the Company’s ability to repurchase its common stock, including (i) the Company cannot utilize funds under the Credit Facility to fund any stock repurchases and (ii) immediately prior to any repurchase, availability under the Credit Facility must be equal to at least 20% of the then effective borrowing base. From March 2007, the inception of the share repurchase program, through June 30, 2008, the Company had repurchased 501,300 common shares at a cost of $1,158,000, of which 474,734 shares have been reissued for 401(k) contributions, for contract services and for compensation. The program does not require the Company to repurchase any specific number of shares and may be modified, suspended, or terminated at any time without prior notice. The Company expects repurchases to be funded by available cash.

The Company issued 1.8 million shares of new stock subsequent to the second quarter of 2008, in connection with certain contract settlements. See Note 13 for further information.

9. 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,
	2008		2007
Numerator:
Net earnings	$	839	$	2,705

Denominator:
Denominator for basic earnings per share — weighted-average shares outstanding ₍₁₎		91,387		89,329
Effect of potentially dilutive common shares:
Warrants		3,099		5,576
Employee and director stock options		15		1

Denominator for diluted earnings per share — weighted-average shares outstanding and assumed conversions		94,501		94,906

Basic earnings per share	$	.01	$	0.03

Diluted earnings per share	$	.01	$	0.03


	Six Months Ended June 30,
	2008		2007
Numerator:
Net earnings	$	4,402	$	4,373
Denominator:
Denominator for basic earnings per share — weighted-average shares outstanding ₍₁₎		90,372		89,291
Effect of potentially dilutive common shares:
Warrants		4,521		5,501
Employee and director stock options		8		—

Denominator for diluted earnings per share — weighted-average shares outstanding and assumed conversions		94,901		94,792

Basic earnings per share	$	.05	$	0.05

Diluted earnings per share	$	.05	$	0.05


(1)		Includes approximately 2.9 million shares issuable due to discontinuation on April 29, 2008 of the Company’s deferred compensation plan. Of these committed shares, approximately 1.8 million shares have been issued in the third quarter of 2008, and 1.1 million shares (which is net of shares expected to be withheld for personal withholding tax) are expected to be issued upon dissolution of the trust in which they are to be held. See Note 13 for further information.

10. 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’s Amended Credit Facility (Note 5) requires that counterparties in derivative transactions be limited to the Lenders, including affiliates of the Lenders. The Company does not obtain collateral to support the agreements, but the master derivative contracts with each counterparty allow offset against the participatory interest of the counterparty in any outstanding balance under the Amended Credit Facility. In practice, no such offset has been made, and all settlements have been made in cash. Balances owed by the Company under derivative contracts are collateralized by the security interests supporting the Amended Credit Facility. The agreements contain no other terms related to net settlement nor offset, and no other terms related to collateral or acceleration of payment terms.

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, “Accounting for Derivative Instruments and Certain Hedging Activities,” 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. All other changes in fair value are reported in the statement of comprehensive income as unrealized gains or losses from hedging activities. The Company recognized a gain of $4 thousand related to hedge ineffectiveness during each of the three month periods ended June 30, 2008 and 2007, and for the six-month periods ended June 30, 2008 and 2007, a loss of $30 thousand and a gain of $16 thousand, respectively, related to hedge ineffectiveness.

As of June 30, 2008, the estimated fair value of the Company’s oil and natural gas contracts was an unrealized loss of approximately $21.4 million ($13.9 million net of tax), which is recognized in accumulated other comprehensive loss. Based upon oil and natural gas commodity prices at June 30, 2008, approximately $17 million of the loss deferred in accumulated other comprehensive loss could potentially decrease gross revenues over the next twelve months. These derivative agreements expire at various dates through December 31, 2009.

All of the Company’s current hedging contracts are in the form of costless collars. The costless collars provide the Company with a lower limit “floor” price and an upper limit “ceiling” price on the hedged volumes. The floor price represents the lowest price the Company will receive for the hedged volumes while the ceiling price represents the highest price the Company will receive for hedged volumes. The costless collars are settled monthly based on the NYMEX futures contract.

Net settlements under these contracts increased (decreased) oil and natural gas revenues by ($2,715,000) and $374,000 for the three months ended June 30, 2008 and 2007, respectively, and by ($3,319,000) and $2,224,000 for the six months ended June 30, 2008 and 2007, 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, 2008, the positions effectively hedge approximately 38% of the estimated proved developed natural gas production and 30% of the estimated proved developed oil production during the respective terms of the hedging agreements. The 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 values of the hedging agreements are recorded on the consolidated balance sheet as assets or liabilities. The estimated fair values of the hedging agreements as of June 30, 2008, are provided below:


								Estimated
								Fair Value
								Asset (Liability)
		Notional		Floor Price		Ceiling Price		June 30, 2008
	Type	Amount		($ per unit)		($ per unit)		(in thousands)
Natural Gas (mmbtu)
Jul 2008 — Dec 2008	Collar		930,000	$	7.00	$	12.15	$	(1,642	)
Jul 2008 — Dec 2008	Collar		420,000	$	7.50	$	11.50		(951	)
Jul 2008 — Dec 2008	Collar		860,000	$	7.50	$	10.10		(3,018	)
Jan 2009 — Dec 2009	Collar		1,230,000	$	7.50	$	10.45		(3,357	)
Jul 2008 — Dec 2008	Collar		90,000	$	8.00	$	10.50		(274	)
Jan 2009 — Dec 2009	Collar		760,000	$	8.00	$	10.30		(2,103	)
Jan 2009 — Dec 2009	Collar		540,000	$	8.00	$	13.35		(736	)

Total Natural Gas									(12,081	)

Crude Oil (bbls)
Jul 2008 — Dec 2008	Collar		28,000	$	55.00	$	83.00		(1,618	)
Jul 2008 — Dec 2008	Collar		11,000	$	65.00	$	80.60		(661	)
Jul 2008 — Dec 2008	Collar		23,000	$	65.00	$	85.00		(1,284	)
Jul 2008	Collar		5,000	$	60.00	$	82.00		(290	)
Jul 2008	Collar		4,000	$	65.00	$	93.15		(188	)
Jul 2008	Collar		3,000	$	70.00	$	87.40		(158	)
Jul 2008 — Dec 2008	Collar		11,000	$	75.00	$	102.50		(432	)
Jan 2009 — Dec 2009	Collar		23,000	$	70.00	$	93.55		(1,106	)
Jul 2008 — Dec 2008	Collar		31,000	$	85.00	$	111.40		(957	)
Jan 2009 — Dec 2009	Collar		43,000	$	80.00	$	111.00		(1,495	)
Jan 2009 — Dec 2009	Collar		49,000	$	85.00	$	128.50		(1,180	)

Total Crude Oil									(9,369	)

								$	(21,450	)

11. SHARE-BASED COMPENSATION

Stock Options

The Company records share-based compensation expense under the provisions of SFAS No. 123R, “Share-Based Payment.” Compensation expense is based on the fair value of the share-based award determined at grant date and recognized over the service period, which is generally the vesting period of the award. Share-based compensation expense of approximately $711,000 and $1,324,000 was recorded in the three months and six months ended June 30, 2008, respectively, and $631,000 and $1,360,000 was recognized in the three months and six months ended June 30, 2007, respectively. Compensation paid in share-based awards include stock options to our employees and directors, stock rights awarded under our deferred compensation plan for certain executives (see Note 13), and restricted stock issued in lieu of cash to fulfill certain other compensation-related obligations.

12. 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 Company records the fair value of asset retirement obligation liabilities for wells, platforms, and facilities as the expected present value of the future costs to abandon the assets. Estimates of future costs include estimated costs, inflation factors, and timing of abandonment, which are updated as circumstances and information changes. Liabilities are initially offset by additions to the full cost pool, and increase over time due to accretion of the present value; accretion is recorded as an expense. Additions to the full cost pool are amortized through depletion expense. The Company records gains or losses from settlements as an adjustment to the full cost pool.

The following table describes the change in the Company’s asset retirement obligations for the six months ended June 30, 2008 (thousands of dollars):


Asset retirement obligation at December 31, 2007	$	23,483

Additional retirement obligations recorded in 2008		50
Settlements during 2008		(627	)
Revisions to estimates and other changes during 2008		(3,653	)
Accretion expense for 2008		1,098

Asset retirement obligation at June 30, 2008		20,351
Less: current portion		5,592

Asset retirement obligation, long-term, at June 30, 2008	$	14,759

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.

13. CONTRACT SETTLEMENTS, RABBI TRUST, AND SUBSEQUENT EVENTS

In April 2008 the Company made significant changes in the structure of the compensation of our top two executives, Messrs. Reeves and Mayell, our Chief Executive Officer and Chief Operating Officer. Effective April 29, 2008, the employment contracts for Messrs. Reeves and Mayell were replaced with new agreements. In addition, certain other agreements that governed other elements of their compensation packages were also settled. Messrs. Reeves and Mayell agreed to these changes under the terms of the settlement agreements executed by each of them effective April 29, 2008. The agreements provide for payments totaling approximately $4.9 million to each of Messrs. Reeves and Mayell, for a total of $9.9 million to the Company.

In addition, the Company discontinued the deferred compensation plan provided to these officers which resulted in the issuance of a total of 1,803,291 shares of new common stock for Messrs. Reeves and Mayell (combined) on July 2, 2008. The shares issued were net of a reduction of 1,001,511 shares withheld in lieu of the executives’ personal withholding tax. An additional 1,712,114 shares (856,057 shares to each of the two officers) will be distributed upon dissolution of the trust. Substantially all of the compensation expense related to these shares was recognized historically, when the rights to such future shares were granted; the rights have also been consistently included in Company computations of diluted earnings per share. The discontinuation of the plan requires conversion of the rights into shares of common stock.

A total of $9.9 million was recorded as contract settlement expense in the second quarter of 2008 for the cash portion of the settlement. The Company expects to record a $1.2 million non-cash expense due to write-down of the deferred tax asset related to the stock rights; the write-down is the result of the difference between the market value of the stock when the rights were issued and expensed, and the market value at conversion of the rights into shares. The Company will determine the

necessity, if any, for additional deferred tax asset write-down at the date of distribution of the additional 1.7 million shares, based on the share price at that time.

The cash payments to Messrs. Reeves and Mayell were placed in a Rabbi Trust, which is included on the Consolidated Balance Sheets under “Restricted Cash” as of June 30, 2008. The Company also plans to set aside in the trust, the additional 1.7 million shares to be distributed. Such shares are expected to be from new issuances, and will be accounted for as treasury shares so long as they remain in the trust. Both the shares and the cash from the trusts will be distributed to the officers upon dissolution of the trust. Until distribution, the assets of the trust belong to the Company, but are effectively restricted due to the obligation to the officers.

On July 29, 2008, the Company reached an agreement with a former employee to terminate a compensation agreement. Under the terms of the termination agreement, the Company will pay the former employee $825,000 and will repurchase from him, 34,116 shares of Company stock, which had been issued to him in lieu of cash compensation. The total cost of repurchasing the shares will be approximately $76,000. The Company has no further obligation to this former employee. The termination payment will be recorded as general and administrative expense in the third quarter of 2008.

14. OTHER SUBSEQUENT EVENTS

On July 3, 2008, the Company initiated the Meridian Resource & Exploration LLC Retention Incentive Compensation Plan, and under the terms of the plan, distributed a total of $1.4 million in bonuses to its non-executive employees. The purpose of the plan is to encourage the retention of valued employees for the immediate term. The current employment market for experienced personnel in the oil and gas industry is very strong. The Company believes the incentive program will help to equalize our employees’ compensation with current market conditions and motivate them to continue their careers with Meridian. The terms of the plan include a second and final bonus to those employees who continue their employment with the Company through March 31, 2009. The second payment, due March 31, 2009, is expected to total approximately $2.9 million; the expense will be accrued ratably over the time period July 2008 through March 2009. The Company will record the initial payment of $1.4 million as general administrative expense in the third quarter of 2008. A portion of the bonus expense is expected be capitalized to the full cost pool in accordance with Company practice for internal expenses related to exploration and development of oil and gas properties.

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. Management modified its business strategy while retaining its position in the Gulf Coast region of south Louisiana and Texas and has directed cash flow from operations generated from increased energy prices to acquisition of large exploratory acreage positions, with the objective of finding properties with multiple repeatable wells and longer-lived reserves.

Operations Update

South Louisiana Exploitation

The Company continues its exploitation of the Weeks Island field. Three projects are currently underway with continued operations scheduled throughout the remainder of 2008.

The Goodrich-Cocke No. 6 ST well was recently sidetracked and drilled to the F-sand in the Miocene formation at a depth of approximately 8,500 feet. The well logged approximately 100 feet of prospective oil pay in the formation. Completion casing is currently being set, with initial testing of the zone expected to take place in the third quarter 2008. The Company owns

approximately 63% working interest (50% net) in the well.

Two additional operations are underway, one on the Myles Salt No. 31 well, and the Myles Salt No. 46 well, with objectives in the “O” and “P” sands, respectively. Meridian owns approximately 92% working interest and 72% working interest in these two wells respectively.

In offshore Louisiana, the Company is participating in the drilling of the Main Pass 301 A-6 well. This outside operated well will be targeting sands in the Miocene formation at a depth of approximately 12,500 feet and be drilled in 225 feet of water. Meridian has a 15% working interest in the well which is scheduled to spud in the third quarter 2008. A subsequent prospect, the Main Pass 301 A-4 well is tentatively scheduled to be drilled in the fourth quarter of this year.

The Company’s Bayou Gentilly field will be shut in by the natural gas transmission company for a scheduled repair of its pipeline in the area which will cause the well to be shut-in beginning August 15^th to be returned on or about October 15^th2008. The amount of production being shut-in during that time is estimated to be 1.5 Mmcfe per day net.

Austin Chalk Program

In the East Texas area, the Company continues to exploit and develop its 90,000+ acres in the Austin Chalk program where it is has two rigs operating. Currently, two wells are in different stages of completion and drilling. The BSM 507 No. 1 well has reached total depth and is scheduled to be tested in the third quarter 2008. On this well, approximately 13,000 feet of vertical section was drilled, followed by two horizontal laterals reaching out approximately 5,400 feet and 6,200 feet in length, for an aggregate of approximately 24,600 feet of wellbore. This well is located approximately five miles southeast of Leggett, Texas. Meridian owns approximately 38% working interest in this well.

A second well in this area, the Davis A-388, is currently drilling the second horizontal lateral section at a depth of approximately 16,800 feet MD. The Company has approximately 45% working interest in this dual horizontal lateral well.

Two additional operated wells and one outside operated well are scheduled to be spud in this area prior to year-end in the thicker sections of Austin Chalk where the Company is realizing notable cost savings for drilling.

In south Texas, the Company has acquired a significant lease position (approximately 30,000 acres) within a major Austin Chalk play in the region that covers over 200,000 acres. The Company has scheduled a well to be drilled in the fourth quarter in this area.

South Texas — Bee County

In Bee County, Meridian has scheduled a well to be drilled to test sands in the Vicksburg formation. The Beck No. 1 well is a shallow oil test at a depth of approximately 3,700 feet. Meridian has a 90% working interest in the well which is scheduled to spud in the third quarter 2008. Should this well be successful, additional wells would be possible to exploit this shallow oil field.

Hurricane Edouard

The Company has conducted onsite inspections of its production facilities in south central and southwestern Louisiana to assess potential damage from the storm. Preliminary assessments indicate that production facilities are intact and undamaged. The fields in the affected area were shut-in for approximately one day, but were back online immediately thereafter.

Capital Expenditure Plans for 2008

The Company anticipates a 2008 capital spending budget of approximately $100.0 million for new prospect opportunities, ranging in depths from shallow to deep. Based on current projections, these expenditures are within the Company’s expected

operating cash flows (including cash on hand) and allow the Company the flexibility to take on additional prospects, acquisitions or joint ventures as the opportunities are presented or developed throughout the year.

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, 2008, was $98.96 per barrel compared to $61.20 per barrel for the three months ended June 30, 2007, and $86.91 per barrel for the three months ended March 31, 2008. Our average natural gas price (after adjustments for hedging activities) for the three months ended June 30, 2008, was $11.09 per Mcf compared to $7.77 per Mcf for the three months ended June 30, 2007, and $8.55 per Mcf for the three months ended March 31, 2008. 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. Refer to Item 3, Quantitative and Qualitative Disclosures about Market Risk, for information regarding commodity price risk management activities utilized to mitigate a portion of the near term effects of this exposure to price volatility.

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, 2007, for further discussion.

Results of Operations

Three Months Ended June 30, 2008 Compared to Three Months Ended June 30, 2007

Operating Revenues. Second quarter 2008 oil and natural gas revenues, which include oil and natural gas hedging activities (see Note 10 of Notes to Consolidated Financial Statements), increased $6.8 million (17%) as compared to second quarter 2007 revenues due to a 52% increase in average commodity prices on a natural gas equivalent basis, partially offset by a 23% decrease in production volumes. Oil and natural gas production volumes totaled 3,645 Mmcfe for the second quarter of 2008 compared to 4,734 Mmcfe for the comparable period of 2007. Our average daily production decreased from 52.0 Mmcfe during the second quarter of 2007 to 40.1 Mmcfe for the second quarter of 2008. Second quarter 2008 production was generally lower due to natural production declines. In addition, pipeline repairs at the Biloxi Marshlands field shut in production for 35 days during the second quarter of 2008, which resulted in a loss of approximately 250 Mmcfe.

The following table summarizes the Company’s operating revenues, production volumes and average sales prices for the three months ended June 30, 2008 and 2007:


	Three Months Ended
	June 30,				Increase
	2008		2007		(Decrease)
Production Volumes:
Oil (Mbbl)		188		201		(6	%)
Natural gas (MMcf)		2,516		3,526		(29	%)
Mmcfe		3,645		4,734		(23	%)

Average Sales Prices:
Oil (per Bbl)	$	98.96	$	61.20		62	%
Natural gas (per Mcf)	$	11.09	$	7.77		43	%
Mmcfe	$	12.77	$	8.39		52	%

Operating Revenues (000’s):
Oil	$	18,622	$	12,314		51	%
Natural gas	$	27,912	$	27,402		2	%

Total Operating Revenues	$	46,534	$	39,716		17	%

Operating Expenses. Oil and natural gas operating expenses on an aggregate basis increased $0.2 million (2%) to $7.2 million during the second quarter of 2008, compared to $7.0 million in the second quarter of 2007. Second quarter 2008 expenses increased due to higher saltwater disposal and compression expenses compared to the second quarter 2007 which included a one-time civil penalty expense arising from environmental litigation. On a unit basis, lease operating expenses increased $0.48 per Mcfe to $1.96 per Mcfe for the second quarter of 2008 from $1.48 per Mcfe for the second quarter of 2007. The increase in the per Mcfe rate was attributable to the lower production between the two corresponding periods.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes increased $0.4 million (14%) to $3.0 million for the second quarter of 2008, compared to $2.6 million during the same period in 2007 primarily because of the increase in crude oil prices, partially offset by the decrease in production and a lower natural gas tax rate. Meridian’s oil and natural gas production is primarily from Louisiana, and is therefore subject to Louisiana severance tax. The severance tax rates for Louisiana are 12.5% of gross oil revenues and $0.269 per Mcf for natural gas, a decrease from $0.373 per Mcf in the second quarter of 2007. On an equivalent unit of production basis, severance and ad valorem taxes increased to $0.82 per Mcfe from $0.55 per Mcfe for the comparable three-month period in 2007.

Depletion and Depreciation. Depletion and depreciation expense decreased $1.7 million (9%) during the second quarter of 2008 to $17.9 million, from $19.6 million for the same period of 2007. This was primarily the result of a decrease in oil and natural gas production. On a unit basis, depletion and depreciation expense increased by $0.77 per Mcfe, to $4.91 per Mcfe for the three months ended June 30, 2008, compared to $4.14 per Mcfe for the same period in 2007, primarily due to additional capital expenditures.

General and Administrative Expense. General and administrative expense was $5.2 million for 2008 compared to $3.9 million for 2007. The $1.3 million increase was primarily due to increased legal fees, consulting services, and other expenses associated with certain contract settlements. On an equivalent unit of production basis, general and administrative expenses increased $0.61 per Mcfe to $1.43 per Mcfe for the second quarter of 2008 compared to $0.82 per Mcfe for the comparable 2007 period primarily due to lower production volumes between the periods, in addition to increased costs.

Contract Settlement Expense. Contract settlement expense of $9.9 million occurred in the second quarter of 2008 when the employment contracts of certain executive officers were renegotiated. See further information in Note 13 of Notes to Consolidated Financial Statements.

Interest Expense. Interest expense decreased $0.1 million (11%), to $1.4 million for the second quarter of 2008 in comparison to $1.5 million for the second quarter of 2007. The decrease is primarily a result of lower interest rates, partially offset by a higher debt balance.

Six Months Ended June 30, 2008 Compared to Six Months Ended June 30, 2007

Operating Revenues. Oil and natural gas revenues during the six months ended June 30, 2008, which include oil and natural gas hedging activities (see Note 10 of Notes to Consolidated Financial Statements) increased $5.1 million (6%) as compared to first half 2007 revenues due to a 44% increase in average sale prices on a natural gas equivalent basis, partially offset by a 26% decrease in production volumes. Our average daily production decreased from 55.2 Mmcfe during the first six months of 2007 to 40.5 Mmcfe for the first six months of 2008. Oil and natural gas production volume totaled 7,376 Mmcfe for the first six months of 2008, compared to 9,991Mmcfe for the comparable period of 2007. The variance in production volumes between the two periods is primarily due to natural production declines. In addition, pipeline repairs at the Biloxi Marshlands field shut in production for 35 days during the second quarter of 2008, which resulted in a loss of approximately 250 Mmcfe.

The following table summarizes the Company’s operating revenues, production volumes and average sales prices for the six months ended June 30, 2008 and 2007:


	Six Months Ended
	June 30,				Increase
	2008		2007		(Decrease)
Production Volumes:
Oil (Mbbl)		372		450		(17	%)
Natural gas (MMcf)		5,142		7,290		(29	%)
Mmcfe		7,376		9,991		(26	%)

Average Sales Prices:
Oil (per Bbl)	$	93.00	$	55.17		69	%
Natural gas (per Mcf)	$	9.79	$	7.55		30	%
Mmcfe	$	11.52	$	7.99		44	%

Operating Revenues (000’s):
Oil	$	34,628	$	24,833		39	%
Natural gas		50,354		55,026		(9	%)

Total Operating Revenues	$	84,982	$	79,859		6	%

Operating Expenses. Oil and natural gas operating expenses on an aggregate basis decreased $1.6 million (10%) to $13.2 million during the first six months of 2008, compared to $14.8 million in 2007. Expenses decreased primarily due to decreased workovers, lower insurance costs, sale of properties and decreased maintenance-related activities and the second quarter of 2007 included a one—time civil penalty expense arising from environmental litigation. On a unit basis, lease operating expenses increased $0.31 per Mcfe to $1.79 per Mcfe for the first six months of 2008 from $1.48 per Mcfe for the first half of 2007. The increase in the per Mcfe rate is due primarily to lower production.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes increased slightly for the first six months of 2008 in comparison to the same period in 2007 primarily because of an increase in oil volumes and prices and a higher natural gas tax rate, 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 $0.269 per Mcf for natural gas for the first six months of 2008, a decrease from $0.373 per Mcf for the first half of 2007. On an equivalent unit of production basis, severance and ad valorem taxes increased to $0.76 per Mcfe from $0.55 per Mcfe for

the comparable six-month period. Beginning July 1, 2008, the revised severance tax rate for natural gas production in Louisiana over the next twelve months will be $0.288 per Mcf.

Depletion and Depreciation. Depletion and depreciation expense decreased $5.0 million (12%) during the first half of 2008 to $35.6 million, from $40.6 million for the same period of 2007. This was primarily the result of the decline in natural gas production, partially offset by an increase in the depletion rate as compared to the 2007 period. On a unit basis, depletion and depreciation expense increased by $0.77 per Mcfe, to $4.83 per Mcfe for the six months ended June 30, 2008, compared to $4.06 per Mcfe for the same period in 2007. The rate increase between the periods was due primarily to increased capital expenditures.

General and Administrative Expense. General and administrative expense was $9.3 million for the first six months of 2008 and for the same period in 2007 was $7.8 million. This increase was primarily due to increases in contract and consulting services, other professional fees, and legal services, and other expenses associated with certain contract settlements. On an equivalent unit of production basis, general and administrative expenses increased $0.48 per Mcfe to $1.26 per Mcfe for the first six months of 2008 compared to $0.78 per Mcfe for the comparable 2007 period.

Interest Expense. Interest expense decreased $0.6 million (18%), to $2.5 million for the first six months of 2008 in comparison to the first half of 2007. The decrease is primarily a result of decreased interest rates.

Liquidity and Capital Resources

Working Capital. During the second quarter of 2008, Meridian’s capital expenditures were internally financed with cash flow from operations, cash on hand and the net drawdowns on the amended credit facility. As of June 30, 2008, the Company had a cash balance of $16.5 million and a working capital deficit of $4.4 million.

Cash Flows. Net cash provided by operating activities was $45.7 million for the six months ended June 30, 2008, as compared to $49.3 million for the same period in 2007. The decrease of $3.6 million was primarily due to changes in working capital, particularly an increase in accounts receivable of $6.3 million, partially offset by movements in other working capital accounts.

Net cash used in investing activities was $68.2 million during the six months ended June 30, 2008, versus $50.5 million in the first six months of 2007, due to increased capital expenditures partially offset by higher property sales.

Cash flows provided by financing activities during the second six months of 2008 were $25.5 million, compared to cash provided by financing activities of $3.4 million during the first six months of 2007, primarily due to the net drawdowns on the amended credit facility of $15 million and the $10 million in proceeds from the new financing agreement related to acquisition of the drilling rig.

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. On February 21, 2008, the Company amended this Credit Facility (“Amended Credit Facility”). The lending institutions under the Amended Credit Facility, include Fortis Capital Corp. as administrative agent, co-lead arranger and bookrunner; The Bank of Nova Scotia, as co-lead arranger and syndication agent; Comerica Bank, US Bank NA and Allied Irish Bank plc each in their respective capacities as lenders, collectively the “Lenders”. The current borrowing base under the Amended Credit Facility was determined to be $110 million by the Lenders effective April 30, 2008. The maturity date was extended to February 21, 2012. As of June 30, 2008, outstanding borrowings under the Amended Credit Facility totaled $90 million.

The Amended 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 various other 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.

On May 2, 2008, the Company, through its wholly owned subsidiary TMRD, entered into a financing agreement with The CIT Group Equipment Financing, Inc. (“CIT”). Under the terms of the agreement, TMRD borrowed $10.0 million, at a fixed interest rate of 6.625% in order to refinance the purchase of a land-based drilling rig to be used in Company operations. The rig was recently purchased using cash on hand and funds available to the Company under the Amended Credit Facility. Funds from the new agreement were used to reduce borrowing under the Amended Credit Facility. The new loan is collateralized by the drilling rig, as well as general corporate credit. The term of the loan is five years; monthly payments of $196,248 for interest and principal are to be made until the loan is completely repaid at termination of the agreement on May 2, 2013.

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.

These hedging contracts have been designated as cash flow hedges as provided by SFAS No. 133, “Accounting for Derivative Instruments and Certain Hedging Activities,” and any changes in fair value of the cash flow hedge resulting from ineffectiveness of the hedge are reported in the consolidated statement of operations as revenues. All other changes in fair value are reported in the statement of comprehensive income as unrealized gains or losses from hedging activities.

Capital Expenditures. Total capital expenditures for the six months ended June 30, 2008 were approximately $62.5 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 2008 capital expenditures plan is currently forecast at approximately $100.0 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 2008 plan utilizing cash flow from operations and cash on hand. When appropriate, excess cash flow from operations beyond that needed for the 2008 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, 2008, we had a cushion (i.e. the excess of the ceiling over our capitalized costs) of approximately $354.9 million (before tax).

Borrowing base for the Credit Facility. The Amended Credit Facility 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, 2008. The borrowing base is redetermined on numerous factors including current reserve estimates, reserves that have recently been added, current commodity prices, current production rates and estimated future net cash flows. These factors have associated risks with each of them. Significant reductions or increases in the borrowing base will be determined by these factors, which, to a significant extent, are not under the Company’s control.

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

On June 12, 2008, the Company issued an aggregate of 60,105 shares of common stock to two former employees for compensation related obligations. The Company relied on the exemption from registration provided under Section 4(2) of the Securities Act of 1933, as amended, as a transaction not involving a public offering.

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 Amended Credit Facility. Since interest charged on borrowings under the Amended Credit Facility floats with prevailing interest rates (except for the applicable interest period for Eurodollar loans), the carrying value of borrowings under the Amended Credit Facility should approximate the fair market value of such debt. Changes in interest rates, however, will change the cost of borrowing. Assuming $90 million remains borrowed under the Amended Credit Facility, we estimate our annual interest expense will change by $0.9 million for each 100 basis point change in the applicable interest rates utilized under the Amended Credit Facility.

Hedging Contracts

From time to time, Meridian addresses 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.

All of the Company’s current hedging contracts are in the form of costless collars. The costless collars provide the Company with a lower limit “floor” price and an upper limit “ceiling” price on the hedged volumes. The floor price represents the lowest price the Company will receive for the hedged volumes while the ceiling price represents the highest price the Company will receive for the hedged volumes. The costless collars are settled monthly based on the NYMEX futures contract.

The notional amount is equal to the total net volumetric hedge position of the Company during the periods presented. As of June 30, 2008, the positions effectively hedge approximately 38% of our proved developed natural gas production and 30% of our 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 NYMEX future prices for the applicable trading months.

The fair values of our hedging agreements are recorded on our consolidated balance sheet as assets or liabilities. The estimated fair value of our hedging agreements as of June 30, 2008, is provided below (see the Company’s website at www.tmrc.com for a quarterly breakdown of the Company’s hedge position for 2008 and beyond):


								Estimated
								Fair Value
								Asset (Liability)
		Notional		Floor Price		Ceiling Price		June 30, 2008
	Type	Amount		($ per unit)		($ per unit)		(in thousands)
Natural Gas (mmbtu)
Jul 2008 — Dec 2008	Collar		930,000	$	7.00	$	12.15	$	(1,642	)
Jul 2008 — Dec 2008	Collar		420,000	$	7.50	$	11.50		(951	)
Jul 2008 — Dec 2008	Collar		860,000	$	7.50	$	10.10		(3,018	)
Jan 2009 — Dec 2009	Collar		1,230,000	$	7.50	$	10.45		(3,357	)
Jul 2008 — Dec 2008	Collar		90,000	$	8.00	$	10.50		(274	)
Jan 2009 — Dec 2009	Collar		760,000	$	8.00	$	10.30		(2,103	)
Jan 2009 — Dec 2009	Collar		540,000	$	8.00	$	13.35		(736	)

Total Natural Gas									(12,081	)

Crude Oil (bbls)
Jul 2008 — Dec 2008	Collar		28,000	$	55.00	$	83.00		(1,618	)
Jul 2008 — Dec 2008	Collar		11,000	$	65.00	$	80.60		(661	)
Jul 2008 — Dec 2008	Collar		23,000	$	65.00	$	85.00		(1,284	)
Jul 2008	Collar		5,000	$	60.00	$	82.00		(290	)
Jul 2008	Collar		4,000	$	65.00	$	93.15		(188	)
Jul 2008	Collar		3,000	$	70.00	$	87.40		(158	)
Jul 2008 — Dec 2008	Collar		11,000	$	75.00	$	102.50		(432	)
Jan 2009 — Dec 2009	Collar		23,000	$	70.00	$	93.55		(1,106	)
Jul 2008 — Dec 2008	Collar		31,000	$	85.00	$	111.40		(957	)
Jan 2009 — Dec 2009	Collar		43,000	$	80.00	$	111.00		(1,495	)
Jan 2009 — Dec 2009	Collar		49,000	$	85.00	$	128.50		(1,180	)

Total Crude Oil									(9,369	)

								$	(21,450	)

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, Chief Operating Officer, and Chief Accounting Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of the end of the second quarter of 2008. Based upon that evaluation, our Chief Executive Officer, Chief Operating Officer, and Chief Accounting Officer concluded that the design and operation of our disclosure controls and procedures are effective. There have been no significant changes in our internal controls or in other factors during the second quarter of 2008 that could significantly affect these controls.

Changes in Internal Controls

During the three month period ended June 30, 2008, 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.

Environmental litigation. Various landowners have sued Meridian (along with numerous other oil companies) in lawsuits

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, 2007. There have been no changes to these risk factors during the quarter ended June 30, 2008.

ITEM 6. Exhibits.

10.1		Meridian Resource & Exploration LLC Retention Incentive Compensation Plan.

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 Chief Operating Officer 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 Chief Operating 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.

32.3		Certification of Chief Accounting Officer pursuant Rule 13a-14(b) or Rule 15d-14(b) under the Securities Exchange Act of 1934, as amended, and 18 U.S.C. Section 1350.

SIGNATURES

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


	THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES (Registrant)
Date: August 11, 2008	By:	/s/ LLOYD V. DELANO
		Lloyd V. DeLano
		Senior Vice President Chief Accounting Officer

Index to Exhibits

10.1		Meridian Resource & Exploration LLC Retention Incentive Compensation Plan.

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 Chief Operating Officer 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 Chief Operating 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.

32.3		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.

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