UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: September 30, 2008

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

For the transition period from                      to                     

THE MERIDIAN RESOURCE CORPORATION

(Exact name of registrant as specified in its charter)

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

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

      Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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		Smaller reporting company o
				(Do not check if a smaller reporting company)

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

Number of shares of common stock outstanding at October 31, 2008:			93,045,592

 

 

THE MERIDIAN RESOURCE CORPORATION
Quarterly Report on Form 10-Q

INDEX

		Page
		Number
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Operations (unaudited) for the Three Months and Nine Months Ended September 30, 2008 and 2007			3
Consolidated Balance Sheets as of September 30, 2008 (unaudited) and December 31, 2007			4
Consolidated Statements of Cash Flows (unaudited) for the Nine Months Ended September 30, 2008 and 2007			6
Consolidated Statements of Stockholders’ Equity (unaudited) for the Nine Months Ended September 30, 2008 and 2007			8
Consolidated Statements of Comprehensive Income (Loss) (unaudited) for the Nine Months Ended September 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			31
Item 4. Controls and Procedures			33
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			34
Item 1A. Risk Factors			35
Item 4. Submission of Matters to a Vote of Security Holders			35
Item 6. Exhibits			35
SIGNATURES			36
EX-31.1
EX-31.2
EX-31.3
EX-32.1
EX-32.2
EX-32.3

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

(thousands of dollars, except per share information)

(unaudited)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
REVENUES:
Oil and natural gas		$	36,806			$	33,709			$	121,788			$	113,568
Price risk management activities			3				(13	)			(27	)			3
Interest and other			174				487				406				1,232
			36,983				34,183				122,167				114,803
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating			5,927				6,964				19,151				21,719
Severance and ad valorem taxes			2,551				2,127				8,125				7,590
Depletion and depreciation			15,870				17,574				51,498				58,184
General and administrative			5,944				4,074				15,234				11,859
Contract settlement			—				—				9,894				—
Accretion expense			482				574				1,580				1,701
Hurricane damage repairs			1,462				—				1,462				—
			32,236				31,313				106,944				101,053
EARNINGS BEFORE INTEREST AND INCOME TAXES			4,747				2,870				15,223				13,750
OTHER EXPENSE:
Interest expense			1,399				1,530				3,922				4,607
EARNINGS BEFORE INCOME TAXES			3,348				1,340				11,301				9,143
INCOME TAXES:
Current			23				68				34				180
Deferred			2,626				522				6,166				3,840
			2,649				590				6,200				4,020
NET EARNINGS		$	699			$	750			$	5,101			$	5,123
NET EARNINGS PER SHARE:
Basic		$	0.01			$	0.01			$	0.06			$	0.06
Diluted		$	0.01			$	0.01			$	0.05			$	0.05
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic			92,349				89,312				91,035				89,298
Diluted			94,143				95,022				94,653				94,869

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

(thousands of dollars)

		September 30,				December 31,
		2008				2007
		(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	10,883			$	13,526
Restricted cash			9,961				30
Accounts receivable, less allowance for doubtful accounts of $210 [2008 and 2007]			23,811				19,874
Due from affiliates			—				2,580
Prepaid expenses and other			4,600				4,538
Assets from price risk management activities			2,451				2,453
Deferred tax asset			5,470				164
Total current assets			57,176				43,165
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including $56,482 [2008] and $53,645 [2007] not subject to depletion)			1,852,170				1,771,768
Land			48				48
Equipment and other			21,458				18,503
			1,873,676				1,790,319
Less accumulated depletion and depreciation			1,402,893				1,350,577
Total property and equipment, net			470,783				439,742
OTHER ASSETS:
Assets from price risk management activities			599				865
Other			753				3
Total other assets			1,352				868
TOTAL ASSETS		$	529,311			$	483,775

See notes to consolidated financial statements.

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

		September 30,				December 31,
		2008				2007
		(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	7,522			$	9,583
Advances from non-operators			3,158				6,996
Revenues and royalties payable			7,599				6,592
Due to affiliates			10,048				—
Notes payable			3,329				2,662
Accrued liabilities			29,387				22,011
Liabilities from price risk management activities			2,233				2,772
Asset retirement obligations			4,799				3,365
Current income taxes payable			57				147
Current maturities of long-term debt			1,793				—
Total current liabilities			69,925				54,128
LONG-TERM DEBT			94,493				75,000
OTHER:
Deferred income taxes			19,895				8,238
Liabilities from price risk management activities			628				861
Asset retirement obligations			15,099				20,118
			35,622				29,217
COMMITMENTS AND CONTINGENCIES (Note 7)
STOCKHOLDERS’ EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized, 91,241,389 [2008] and 89,450,466 [2007] issued)			930				936
Additional paid-in capital			535,257				537,145
Accumulated deficit			(207,041	)			(212,142	)
Accumulated other comprehensive income (loss)			125				(221	)
			329,271				325,718
Less treasury stock, at cost, 158,683 [2007]shares			0				288
Total stockholders’ equity			329,271				325,430
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	529,311			$	483,775

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

(thousands of dollars)

(unaudited)

		Nine Months Ended September 30,
		2008				2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net earnings		$	5,101			$	5,123
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depletion and depreciation			51,498				58,184
Amortization of other assets			154				332
Non-cash compensation			1,505				2,028
Non-cash price risk management activities			27				(3	)
Accretion expense			1,580				1,701
Deferred income taxes			6,166				3,840
Changes in assets and liabilities:
Restricted cash			(9,931	)			1,253
Accounts receivable			(3,937	)			4,332
Prepaid expenses and other			(63	)			(3,069	)
Due to / from affiliates			12,628				(2,206	)
Accounts payable			680				4,855
Advances from non-operators			(3,839	)			(540	)
Revenues and royalties payable			1,006				(582	)
Asset retirement obligations			(587	)			(2,028	)
Other assets and liabilities			10,888				1,956
Net cash provided by operating activities			72,876				75,176
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to property and equipment			(100,620	)			(86,411	)
Proceeds from sale of property			7,161				2,552
Net cash used in investing activities			(93,459	)			(83,859	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Reductions in long-term debt			(18,713	)			—
Proceeds from long-term debt			40,000				—
Reductions in notes payable			(5,017	)			(7,227	)
Proceeds from notes payable			5,684				9,540
Repurchase of common stock			(75	)			(908	)
Payment of taxes due on vested stock			(3,035	)			—
Additions to deferred loan costs			(904	)			—
Net cash provided by financing activities			17,940				1,405
NET CHANGE IN CASH AND CASH EQUIVALENTS			(2,643	)			(7,278	)
Cash and cash equivalents at beginning of period			13,526				31,424
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	10,883			$	24,146

		Nine Months Ended September 30,
		2008				2007
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Increase (decrease) of Non-cash Activities:
Issuance of shares for contract services		$	0			$	(909	)
Accrual of capital expenditures		$	(6,342	)		$	(852	)
ARO liability — new wells drilled		$	176			$	386
ARO liability — changes in estimates		$	(4,754	)		$	(2,065	)

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

(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			—				5				(5	)			—				—				—				—				—
Company’s 401(k) plan contributions			149				—				169				—				—				(106	)			250				419
Shares repurchased			(359	)			—				—				—				—				359				(908	)			(908	)
Stock-based compensation — FAS123R			—				—				238				—				—				—				—				238
Compensation expense			—				—				1,266				—				—				—				—				1,266
Accum. other comprehensive income activity			—				—				—				—				(3,691	)			—				—				(3,691	)
Issuance of shares for contract services			340				2				623				—				—				(104	)			284				909
Issuance of shares as compensation			39				—				80				—				—				(8	)			25				105
Net earnings			—				—				—				5,123				—				—				—				5,123
Balance, September 30, 2007			89,309			$	935			$	536,812			$	(214,156	)		$	1,016				141			$	(349	)		$	324,258
Balance, December 31, 2007			89,450			$	936			$	537,145			$	(212,142	)		$	(221	)			159			$	(288	)		$	325,430
Issuance of rights to common stock			—				4				(4	)			—				—				—				—				—
Issuance of shares for rights to common stock			1,803				—				—				—				—				—				—				—
Shares withheld for payment of taxes due on vested stock			—				(10	)			(3,025	)			—				—				—				—				(3,035	)
Company’s 401(k) plan contributions			22				—				92				—				—				(99	)			181				273
Stock-based compensation — FAS123R			—				—				130				—				—				—				—				130
Compensation expense			—				—				968				—				—				—				—				968
Accum. other comprehensive income activity			—				—				—				—				346				—				—				346
Issuance of shares for contract services			—				—				26				—				—				(60	)			107				133
Shares repurchased and retired			(34	)			—				(75	)			—				—				—				—				(75	)
Net earnings			—				—				—				5,101				—				—				—				5,101
Balance, September 30, 2008			91,241			$	930			$	535,257			$	(207,041	)		$	125				—				—			$	329,271

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

(thousands of dollars)

(unaudited)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2008				2007				2008				2007
Net earnings		$	699			$	750			$	5,101			$	5,123
Other comprehensive income (loss), net of tax, for unrealized gains (losses) from hedging activities:
Unrealized holding gains (losses) arising during period (1)			12,479				547				(3,396	)			(1,536	)
Reclassification adjustments on settlement of contracts (2)			1,585				(710	)			3,742				(2,155	)
			14,064				(163	)			346				(3,691	)
Total comprehensive income (loss)		$	14,763			$	587			$	5,447			$	1,432

(1) net income tax (expense) benefit		$	(6,720	)		$	(294	)		$	1,829			$	827
(2) net income tax (expense) benefit		$	(853	)		$	382			$	(2,015	)		$	1,161

See notes to consolidated financial statements.

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES

(unaudited)

1. BASIS OF PRESENTATION

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

The financial statements included herein as of September 30, 2008, and for the three and nine month periods ended September 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 or losses 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 $397,000 and $545,000 in profit was transferred to the full cost pool in the three months and nine months ending September 30, 2008, respectively, 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 September 30, 2008 was $9,961,000 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.

In June, 2008, the FASB Emerging Task Force issued EITF Abstract Issue No. 07-05, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock” (“EITF 07-05”). The issue clarifies the determination of equity instruments which may qualify for an exemption from SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Generally, equity instruments which qualify under the guidelines of EITF 07-05 may be accounted for in equity accounts; those which do not qualify are subject to derivative accounting. The guidance will be effective for fiscal years and interim periods beginning after December 15, 2008. We are evaluating the effect of EITF 07-05 on our financial statements.

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 September 30, 2008

Using

Quoted

Prices in

Active

Significant

Significant

Markets for

Other

Other

Identical

Observable

Unobservable

September

Assets

Inputs

Inputs

Description

30, 2008

(Level 1)

(Level 2)

(Level 3)

Assets from price risk management activities (1)

$

3,050

$

3,050

Liabilities from price risk management activities (1)

$

2,861

$

2,861

4. ACCRUED LIABILITIES

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

		September 30,				December 31,
		2008				2007
Capital expenditures		$	12,744			$	14,821
Operating expenses/taxes			5,856				3,881
Compensation			2,562				853
Interest			388				460
Hurricane-related expenditures			6,154				—
Other			1,683				1,996
Total		$	29,387			$	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. The maturity date of our outstanding loans may be accelerated by the Lenders upon the occurrence of an event of default under the agreement. As of September 30, 2008, outstanding borrowings under the Amended Credit Facility totaled $87 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. In the event our then-redetermined borrowing base is less than our outstanding borrowings under the Amended Credit Facility, we will be required to repay the deficit within a 90-day period. The most recently scheduled redetermination as of October 31, 2008 has not been completed.

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, restrictions on incurrence of additional debt, and an unqualified audit report on the Company’s consolidated financial statements, all of which the Company is in compliance with at September 30, 2008.

Under the Amended Credit Facility, the Company may secure either (i) an alternative base rate loan that bears interest at a rate per annum equal to the greater of (a) 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 September 30, 2008, the three-month LIBOR interest rate was 4.05%. The Amended Credit Facility provides for commitment fees of 0.375% calculated on the difference between the borrowing base and the aggregate outstanding loans and letters of credit under the Amended Credit Facility. As of November 10, 2008, outstanding borrowing under the Amended Credit Facility totaled $90 million.

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 September 30, 2008, the balance was $9.3 million, with $7.5 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 55% differs from the overall United States corporate tax rate of 35% primarily due to a $1.2 million write-down of a deferred tax asset in the third quarter of 2008, related to shares issued from the deferred compensation plan (see Note 13 below). The effective tax rate is also increased due to state income taxes, to non-deductible expenses related to the basis of certain oil and natural 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 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 but recently the Louisiana First Court of Appeal declined to hear Meridian’s writ requesting the court overturn Judge Bates’ ruling. 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 been filed substituting the proper party for Mr. Bond. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the Company has not provided any amount for this matter in its financial statements at September 30, 2008.

Parsons Exploration litigation. On May 3, 2007, Parsons Exploration Company, LLC (“Parsons”) filed a claim against Meridian for damages and specific performance requiring Meridian to assign Parsons an overriding royalty interest in certain wells the Company has drilled in east Texas. The complaint alleges that the Company breached its contractual and fiduciary obligations to Parsons under an Exploration and Prospect Origination Agreement between the parties dated April 22, 2003. The complaint also alleges that the Company engaged in a civil conspiracy to breach its contractual and fiduciary obligations to Parsons and tortiously interfered with existing and prospective business relationships/contracts of Parsons. The Company has been served notice of the lawsuit and discovery has commenced. The Company intends to vigorously defend this matter. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the Company has not provided any amount for this matter in its financial statements at September 30, 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 September 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.

Hurricane damages. Certain oil and natural gas properties sustained physical damage during two hurricanes in the third quarter of 2008, Hurricane Gustav and Hurricane Ike. The Company has recorded $1.5 million in expense for repairs, and a $4.6 million insurance receivable in the third quarter, based on the most current information available. Damage estimates for non-operated properties are preliminary and subject to revision. Also, additional information regarding non-operated properties may be obtained which bears on the applicability of insurance deductibles, and may also require revision to loss estimates.

Extension of drilling contract. The Company has extended a day-rate agreement with a drilling contractor for an additional two years, to February 1, 2011. The increase in commitment for the extended period is approximately $10.6 million per contract year. Formerly, the contract was to have expired on February 1, 2009.

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 September 30, 2008, the Company had repurchased 535,416 common shares at a cost of $1,234,000, of which 501,300 shares have been reissued for 401(k) contributions, for contract services and for compensation, and 34,116 have been retired. In addition, the Company issued shares to certain executives during the third quarter upon the discontinuation of its deferred compensation plan (see Note 13). Shares sufficient to cover the value of these employees’ withholding taxes were withheld from issuance, and the Company made a cash payment for the withholding tax. This transaction may be considered an indirect repurchase and has been presented on the Consolidated Statements of Cash Flows as a financing item. The total number of shares withheld was 1,001,511, at a value of approximately $3,035,000. The share buyback 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 during the third quarter of 2008, when the deferred compensation plan was discontinued. On October 2, 2008, the Company issued an additional 1.7 million new shares to a Rabbi Trust. 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 September 30,
		2008				2007
Numerator:
Net earnings		$	699			$	750
Denominator:
Denominator for basic earnings per share — weighted-average shares outstanding (1)			92,349				89,312
Effect of potentially dilutive common shares:
Warrants			1,775				5,710
Employee and director stock options			19				—
Denominator for diluted earnings per share — weighted-average shares outstanding and assumed conversions			94,143				95,022
Basic earnings per share		$	0.01			$	0.01
Diluted earnings per share		$	0.01			$	0.01

		Nine Months Ended September 30,
		2008				2007
Numerator:
Net earnings		$	5,101			$	5,123
Denominator:
Denominator for basic earnings per share — weighted-average shares outstanding (1)			91,035				89,298
Effect of potentially dilutive common shares:
Warrants			3,606				5,571
Employee and director stock options			12				—
Denominator for diluted earnings per share — weighted-average shares outstanding and assumed conversions			94,653				94,869
Basic earnings per share		$	0.06			$	0.06
Diluted earnings per share		$	0.05			$	0.05

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. 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 from the Company’s counterparties to support counterparty obligations under the agreements. The master derivative contracts with each counterparty allow the Company, so long as it is not a defaulting party, after a default or the occurrence of a termination event, to set-off against the interest of the counterparty in any outstanding balance under the Amended Credit Facility. In practice, no such set-off 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 also contain provisions permitting netting of multiple unrelated transactions that settle on the same day and in the same currency.

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 gains (losses) of $3,000 and ($13,000) related to hedge ineffectiveness during the three months ended September 30, 2008 and 2007, respectively, and for the nine month periods ended September 30, 2008 and 2007, gains (losses) of ($27,000) and $3,000, respectively, related to hedge ineffectiveness.

As of September 30, 2008, the estimated fair value of the Company’s oil and natural gas contracts was a net unrealized gain of approximately $191,000 ($125,000 net of tax), which is recognized in accumulated other comprehensive income. Based upon oil and natural gas commodity prices at September 30, 2008, approximately $218,000 of the net gain deferred in accumulated other comprehensive income could potentially increase gross revenues over the next twelve months. These derivative agreements expire at various dates through December 31, 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 ($2,439,000) and $1,100,000 for the three months ended September 30, 2008 and 2007, respectively, and by ($5,757,000) and $3,300,000 for the nine months ended September 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 September 30, 2008, the positions effectively hedge approximately 35% of the estimated proved developed natural gas production and 25% 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 September 30, 2008, are provided below:

																		Estimated
																		Fair Value
																		Asset (Liability)
														Ceiling				September 30,
						Notional				Floor Price				Price				2008
		Type				Amount				($ per unit)				($ per unit)				(in thousands)
Natural Gas (mmbtu)
Oct 2008 – Dec 2008		Collar					420,000			$	7.00			$	12.15			$	75
Oct 2008 – Dec 2008		Collar					190,000			$	7.50			$	11.50				61
Oct 2008 – Dec 2008		Collar					430,000			$	7.50			$	10.10				135
Oct 2008 – Dec 2008		Collar					30,000			$	8.00			$	10.50				20
Jan 2009 – Dec 2009		Collar					1,230,000			$	7.50			$	10.45				413
Jan 2009 – Dec 2009		Collar					760,000			$	8.00			$	10.30				422
Jan 2009 – Dec 2009		Collar					540,000			$	8.00			$	13.35				450
Total Natural Gas																			1,576
Crude Oil (bbls)
Oct 2008 – Dec 2008		Collar					15,000			$	55.00			$	83.00				(290	)
Oct 2008 – Dec 2008		Collar					6,000			$	65.00			$	80.60				(126	)
Oct 2008 – Dec 2008		Collar					13,000			$	65.00			$	85.00				(227	)
Oct 2008 – Dec 2008		Collar					6,000			$	75.00			$	102.50				(39	)
Oct 2008 – Dec 2008		Collar					12,000			$	85.00			$	111.40				(22	)
Jan 2009 – Dec 2009		Collar					23,000			$	70.00			$	93.55				(384	)
Jan 2009 – Dec 2009		Collar					43,000			$	80.00			$	111.00				(284	)
Jan 2009 – Dec 2009		Collar					49,000			$	85.00			$	128.50				(15	)
Total Crude Oil																			(1,387	)
																		$	189

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 $180,000 and $1,505,000 was recorded in the three months and nine months ended September 30, 2008, respectively, and $934,000 and $2,937,000 was recognized in the three months and nine months ended September 30, 2007, respectively. Compensation paid in share-based awards included 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 nine months ended September 30, 2008 (thousands of dollars):

Asset retirement obligation at December 31, 2007		$	23,483
Additional retirement obligations recorded in 2008			176
Settlements during 2008			(587	)
Revisions to estimates and other changes during 2008			(4,754	)
Accretion expense for 2008			1,580
Asset retirement obligation at September 30, 2008			19,898
Less: current portion			4,799
Asset retirement obligation, long-term, at September 30, 2008		$	15,099

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 EMPLOYEE RETENTION

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. In the third quarter, the Company recorded 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 September 30, 2008. On October 2, 2008, the Company also set aside in the trust, the additional 1.7 million shares to be distributed. The shares were 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 trust 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 paid the former employee $825,000 and repurchased 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 was approximately $76,000. The Company has no further obligation to this former employee. The termination payment was recorded as general and administrative expense in the third quarter of 2008.

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 $1.6 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, 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 $3.2 million; the expense is being accrued ratably over the time period July 2008 through March 2009. A portion of the bonus expense is capitalized to the full cost pool in accordance with Company practice for internal expenses related to exploration and development of oil and natural gas properties. The Company recognized $1.2 million in expense, net of capitalization, in the third quarter and expects to recognize approximately $0.5 million in retention bonus expense in each of the next two quarters (fourth quarter of 2008 and first quarter of 2009).

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

The Company’s 2008 capital expenditures have been focused on exploitation in two primary areas, south Louisiana legacy fields (Weeks Island and Turtle Bayou) and its East Texas Austin Chalk play. The revitalization of the legacy assets across south Louisiana and the development of our large acreage position in the heart of our East Texas Austin Chalk program, plays a key role in the Company’s current and future operations. As an expansion of that idea, the Company has acquired approximately 30,000 acres in Karnes and Lavaca counties, Texas, in the midst of, and on strike with, a recently discovered, very large potential, Eagleford shale play.

In the face of the new commodity pricing, these two exploitation plays provide the Company with a solid future drilling inventory of lower risk wells to replace reserves and production. This development program can be executed, as well as the development of the Company’s exploration inventory and Archtop project, within projected 2009 cash flows of approximately

$70 million (depending on pricing).

South Louisiana Exploitation

Meridian holds a deep inventory in its Weeks Island field in Louisiana where it has focused a large part of its 2008 activities and capital budget, both of which have resulted in reduced finding cost and replacement of reserves (after production and revisions). The Company continues to exploit this area with continued permitting and drilling operations scheduled throughout the remainder of 2008 and 2009. Four different wells were recently finished and one project is about to begin. Current inventory for the field suggests numerous additional projects are possible, targeting significant remaining oil and gas reserves in the field.

The Myles Salt No. 31 well was successfully sidetracked in the updip “O” sands. The well was logged and tested, resulting in gross daily production rates of approximately 250 barrels of oil per day and 300 Mcf of gas (1.3 Mmcfe/d, net). The Myles Salt No. 46 well was also recently recompleted and tested, with objectives in the “P” sands. This well tested at a rate of approximately 270 barrels of oil per day and 380 Mcf of gas (1.2 Mmcfe/d, net). Meridian owns approximately 92% working interest and 72% working interest in these two wells, respectively.

The Weeks Bay No. 15 well was drilled to a depth of approximately 8,900 feet to test a lower Miocene sand. The well was logged indicating approximately 43 feet of apparent pay and is scheduled to be tested in November, 2008. Meridian owns approximately 92% working interest in this well.

The Myles Salt No. 4 well was sidetracked to approximately 9,400 feet to test sands in the Miocene formation. Upon reaching the first set of objectives, the well was logged. It was determined that the targeted sands were considered to be tight and uneconomic. The well was temporarily suspended for consideration of later re-entry and deepening for the original target sands.

The Company has moved on a rig, and is preparing to re-enter and sidetrack the Goodrich-Cocke No. 3 well (Boone Prospect). The well will be targeting sands in the Miocene formation at a depth of approximately 7,500 feet. Meridian owns approximately 63% working interest in this well.

In offshore Louisiana, the Company is participating in the drilling of the Main Pass 301 A-6 well. This outside operated well targeted sands in the Miocene formation at a depth of approximately 12,500 feet and was drilled in 225 feet of water. Recently the well reached total depth and was logged, resulting in approximately 27 feet of apparent pay sands. The well is scheduled to be tested in November, 2008. Meridian has a 15% working interest in the well.

Additionally, in offshore Texas, Meridian recently participated in the recompletion of the Galveston Block 343 A-4 well. This outside operated well targeted sands in the Pliocene formation at a depth of approximately 7,600 feet and was drilled in 75 feet of water. The well logged pay in its targeted sands and was tested, resulting in approximately 3.0 Mmcfe per day. Meridian has a 12% working interest in the well.

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 has two rigs operating and is participating in one outside operated well. Currently, the Company’s plan is to fully develop this very prolific producing area and step out westward over the entire 90,000 acres. Historical data of wells in the region suggest that the statistical average reserves per well range between 3 and 14 Bcfe including large components of oil in many of the wells adding to the economics of each. Recent wells indicate that the majority of the Company’s acreage position contains the thicker chalk sections and higher liquids as a component of production similar to those recently tested and two wells currently being drilled.

The two wells are in concurrent stages of drilling their respective horizontal laterals. The Sutton A-574 No. 1 well has completed drilling on its first horizontal lateral and is in the early stages of drilling the second lateral. The first lateral extended approximately 4,400 feet of length. The Company has approximately 63% working interest in this dual horizontal lateral well.

The second well in this area, the BSM 507 No. 2 well has completed drilling on its first horizontal lateral at a measured depth of approximately 17,300 feet, or approximately 4,300 feet in length. A perforated liner was installed in the first lateral and work has begun on drilling the curve for the second lateral. Meridian owns approximately 55% working interest in this well.

Production Impact from Hurricanes

The Company’s operations were interrupted by the two back-to-back hurricanes, Gustav and Ike, neither of which caused material damage to Meridian’s producing or drilling facilities, but which impeded and delayed the timing of production from several of its south Louisiana fields. Through October 2008, Meridian estimates the amount of delayed production due to the storms to be between 775 and 825 Mmcfe.

Current average production levels ranges between 38 and 40 Mmcfe per day. As previously announced, production is yet to be restored in the Bayou Gentilly field (approx 1.5 Mmcfe/d pre-storm net) and several outside operated offshore fields (approx 1.0 Mmcfe/d pre-storm net). The minor damage to the wells that remain shut-in has been repaired; however, the Company is still waiting on repairs to be completed by third party pipelines and processing facilities. Repairs are anticipated to be finished, and production restored, during the fourth quarter of 2008.

Capital Expenditure Plans for 2008

The 2008 capital expenditures plan is currently forecast at approximately $115.0 million. The actual expenditures for the remainder of the year 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, and the availability of funds under the Amended Credit Facility. We currently anticipate funding the remainder of the 2008 plan utilizing cash flow from operations and cash on hand, in addition to utilizing available credit.

Extension of drilling contract

The Company has extended a day-rate agreement with a drilling contractor for an additional two years, to February 1, 2011. The increase in commitment for the extended period is approximately $10.6 million per contract year. Formerly, the contract was to have expired on February 1, 2009.

Other Conditions

Industry Conditions. Revenues, profitability and future growth rates of Meridian are substantially dependent upon prevailing prices for oil and natural gas “commodity prices”. Commodity prices have been extremely volatile in recent years and are affected by many factors outside of our control. Our average oil price (after adjustments for hedging activities) for the three months ended September 30, 2008, was $99.42 per barrel compared to $69.92 per barrel for the three months ended September 30, 2007, and $98.96 per barrel for the three months ended June 30, 2008. Our average natural gas price (after adjustments for hedging activities) for the three months ended September 30, 2008, was $9.67 per Mcf compared to $6.77 per Mcf for the three months ended September 30, 2007, and $11.09 per Mcf for the three months ended June 30, 2008.

Fluctuations in commodity prices 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.

Commodity price declines, such as those recently experienced in the second half of 2008, affect the market value of oil and natural gas

properties and the credit standing of companies which own them. Commodity prices are a significant factor in the determination of the borrowing base available to the Company under the Amended Credit Facility. If the Company’s access to capital is restricted by a reduction in the borrowing base, its ability to fund capital expenditures will decrease. This may impact the Company’s ability to replace reserves. In addition, if the borrowing base is redetermined at a level below outstanding borrowings, the Company will be required to repay the deficit within 90 days. Such repayment may place additional strain on sources of liquidity already impacted by declines in commodity prices, such as operating cash flows. The Company may not be able to find alternative sources of capital on terms acceptable to us.

Commodity prices are also important to the carrying value of oil and natural gas properties, which are limited according to SEC full cost accounting rules by the “ceiling test” described below (see “Forward-Looking Statements”). Commodity price declines strongly impact the future net revenues utilized in the ceiling test. Declines in future net revenues could require the Company to record a non-cash write-down of oil and natural gas properties.

Economic Conditions. Global capital markets have experienced significant disruptions in the past year, resulting in the closing or restructuring of numerous large financial institutions. Extreme uncertainty about creditworthiness, liquidity and interest rates, as well as the impact on the global economy, continue to limit credit availability. Continued tight credit conditions and a recessionary economy could impact the Company in several ways, including those discussed below.

The Company depends on operating cash flows and availability of credit under its Amended Credit Facility for the cash to fund current operations and to continue exploration and development activities. Five banks participate in the Amended Credit Facility. Credit conditions could impact their ability to provide funds under the agreement when the Company so requests.

Several of the bank participants act as counterparties in oil and natural gas hedging agreements with the Company. Although the hedging agreements provide the Company with certain protective rights of set-off of hedge receipts against borrowings under the Amended Credit Facility, in some circumstances the Company could potentially suffer a credit loss. In such case, the Company would be exposed to commodity price fluctuations, and the protection intended by the hedge would be lost.

Operating cash flows are supported by collections from oil and natural gas purchasers and joint working interest owners, who may in turn be affected by adverse credit or other economic conditions and unable to pay Meridian timely or at all.

Key suppliers and joint working interest owners of the Company may be affected by economic conditions such that they were unable to perform, which would affect operations and profitability of the Company.

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

Operating Revenues. Third 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 $3.1 million (9%) as compared to third quarter 2007 revenues due to a 49% increase in average commodity prices on a natural gas equivalent basis, partially offset by a 27% decrease in production volumes. Oil and natural gas production volumes totaled 3,060 Mmcfe for the third quarter of 2008 compared to 4,173 Mmcfe for the comparable period of 2007. Our average daily production decreased from 45.4 Mmcfe during the third quarter of 2007 to 33.3 Mmcfe for the third quarter of 2008.

The variance in production volumes between the two periods is due in large part to the impact of hurricanes Gustav and Ike which struck south Louisiana and the upper Texas coast. These storms forced the Company to temporarily shut-in production in these core operating areas. The Company sustained some physical damage from the storms, but more importantly, experienced delays in bringing production back on-line in several of its operating areas due primarily to lack of access to the fields and being shut-in by third party pipelines and processing facilities. The amount of delayed production for the third quarter related to the storms is estimated at approximately 550 to 600 Mmcfe.

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

		Three Months Ended
		September 30,								Increase
		2008				2007				(Decrease)
Production Volumes:
Oil (Mbbl)			174				185				(6	%)
Natural gas (MMcf)			2,017				3,067				(34	%)
Mmcfe			3,060				4,173				(27	%)
Average Sales Prices:
Oil (per Bbl)		$	99.42			$	69.92				42	%
Natural gas (per Mcf)		$	9.67			$	6.77				43	%
Mmcfe		$	12.03			$	8.08				49	%
Operating Revenues (000’s):
Oil		$	17,299			$	12,936				34	%
Natural gas		$	19,507			$	20,773				(6	%)
Total Operating Revenues		$	36,806			$	33,709				9	%

Operating Expenses. Oil and natural gas operating expenses on an aggregate basis decreased $1.1 million (15%) to $5.9 million during the third quarter of 2008, compared to $7.0 million in the third quarter of 2007. Third quarter 2008 expenses decreased primarily due to decreased workovers and repairs and lower insurance costs. On a unit basis, lease operating expenses increased $0.27 per Mcfe to $1.94 per Mcfe for the third quarter of 2008 from $1.67 per Mcfe for the third quarter of 2007. The increase in the rate was primarily attributable to the lower production between the two corresponding periods.

Severance and Ad Valorem Taxes. Severance and ad valorem taxes increased $0.5 million (20%) to $2.6 million for the third quarter of 2008, compared to $2.1 million during the same period in 2007 primarily because of the increase in crude oil prices, partially offset by the decrease in 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 $0.288 per Mcf for natural gas, an increase from $0.269 per Mcf in the third quarter of 2007. On an equivalent unit of production basis, severance and ad valorem taxes increased to $0.83 per Mcfe from $0.51 per Mcfe for the comparable three-month period in 2007.

Depletion and Depreciation. Depletion and depreciation expense decreased $1.7 million (10%) during the third quarter of 2008 to $15.9 million, from $17.6 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 $0.98 per Mcfe, to $5.19 per Mcfe for the three months ended September 30, 2008, compared to $4.21 per Mcfe for the same period in 2007, primarily due to additional capital expenditures.

General and Administrative Expense. General and administrative expense was $5.9 million for the third quarter of 2008 compared to $4.1 million for the third quarter of 2007. The $1.8 million increase was primarily due to a contract termination with a former employee, as well as to the cost of the non-executive employee retention incentive plan described in Note 13 of Notes to Consolidated Financial Statements. On an equivalent unit of production basis, general and administrative expenses increased $0.96 per Mcfe to $1.94 per Mcfe for the third quarter of 2008 compared to $0.98 per Mcfe for the comparable 2007 period primarily due to lower production volumes between the periods, in addition to increased costs.

Hurricane Damage Repairs. The expense of $1.5 million for damage repairs incurred from hurricanes Gustav and Ike primarily relates to the Company’s insurance deductibles.

Interest Expense. Interest expense decreased $0.1 million (9%), to $1.4 million for the third quarter of 2008 in comparison to $1.5 million for the third quarter of 2007. The decrease is primarily a result of lower interest rates, partially offset by higher debt balances.

Income Tax Expense. The Company’s effective tax rate increased from 44% to 79% for the third quarter of 2008, as compared to the third quarter of 2007, due to a $1.2 million write-down of a deferred tax asset in the third quarter of 2008, related to shares issued from the deferred compensation plan (see Note 13 of Notes to Financial Statements).

Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007

Operating Revenues. Oil and natural gas revenues during the nine months ended September 30, 2008, which include oil and natural gas hedging activities (see Note 10 of Notes to Consolidated Financial Statements) increased $8.2 million (7%) as compared to first nine months of 2007 revenues due to a 46% increase in average sale prices on a natural gas equivalent basis, partially offset by a 26% decrease in production volumes. Average daily production decreased from 51.9 Mmcfe during the first nine months of 2007 to 38.1 Mmcfe for the first nine months of 2008. Oil and natural gas production volume totaled 10,436 Mmcfe for the first nine months of 2008, compared to 14,164 Mmcfe for the comparable period of 2007. The variance in production volumes between the two periods is due to the impact of hurricanes Gustav and Ike, as well as 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 nine months ended September 30, 2008 and 2007:

		Nine Months Ended
		September 30,								Increase
		2008				2007				(Decrease)
Production Volumes:
Oil (Mbbl)			546				635				(14	%)
Natural gas (MMcf)			7,159				10,357				(31	%)
Mmcfe			10,436				14,164				(26	%)
Average Sales Prices:
Oil (per Bbl)		$	95.10			$	59.51				60	%
Natural gas (per Mcf)		$	9.76			$	7.32				33	%
Mmcfe		$	11.67			$	8.02				46	%
Operating Revenues (000’s):
Oil		$	51,927			$	37,769				37	%
Natural gas			69,861				75,799				(8	%)
Total Operating Revenues		$	121,788			$	113,568				7	%

Operating Expenses. Oil and natural gas operating expenses on an aggregate basis decreased $2.5 million (12%) to $19.2 million during the first nine months of 2008, compared to $21.7 million in 2007. Expenses decreased primarily due to decreased workovers and repairs and lower insurance costs; in addition, 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 $1.84 per Mcfe for the first nine months of 2008 from $1.53 per Mcfe for the first nine months 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 $0.5 million for the first nine months of 2008 in comparison to the same period in 2007 primarily because of an increase in oil prices, partially offset by decreases in oil and natural gas production and a lower average natural gas tax rate. Meridian’s oil and natural gas production is primarily from Louisiana, and is therefore subject to Louisiana severance tax. The severance tax rates for Louisiana are 12.5% of gross oil revenues and were $0.269 per Mcf for natural gas for the first six months of 2008, a decrease from $0.373 per Mcf for the first half of 2007. The natural gas rate for the third quarter of 2008 is slightly higher ($0.288 per Mcf) than that of the third quarter 2007 ($0.269 per Mcf). On an equivalent unit of production basis, severance and ad valorem taxes increased to $0.78 per Mcfe from $0.54 per Mcfe for the comparable nine-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 $6.7 million (11%) during the first nine months of 2008 to $51.5 million, from $58.2 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 $0.82 per Mcfe, to $4.93 per Mcfe for the nine months ended September 30, 2008, compared to $4.11 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 $15.2 million for the first nine months of 2008 and for the same period in 2007 was $11.9 million. This increase was primarily due to increases in contract and consulting services, other professional fees, and legal services, the cost of a contract termination with a former employee, and the cost of the non-executive employee retention incentive plan. On an equivalent unit of production basis, general and administrative expenses increased $0.62 per Mcfe to $1.46 per Mcfe for the first nine months of 2008 compared to $0.84 per Mcfe for the comparable 2007 period.

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.

Hurricane Damage Repairs. This expense of $1.5 million for damage repairs incurred from hurricanes Gustav and Ike, primarily relates to the Company’s insurance deductibles.

Interest Expense. Interest expense decreased $0.7 million (15%), to $3.9 million for the first nine months of 2008 in comparison to the first nine months of 2007. The decrease is primarily a result of decreased interest rates partially offset by higher debt balances.

Income Tax Expense. The Company’s effective tax rate increased from 44% to 55% during the first nine months of 2008 in comparison to the first nine months of 2007, due to a $1.2 million write-down of a deferred tax asset in the third quarter of 2008, related to shares issued from the deferred compensation plan (see Note 13 of Notes to Financial Statements).

Liquidity and Capital Resources

Working Capital. During the third quarter of 2008, Meridian’s capital expenditures were internally financed with cash flow from operations, cash on hand and the net drawdowns under the Amended Credit Facility. As of September 30, 2008, the Company had a cash balance of $10.9 million and a working capital deficit of $12.7 million.

Cash Flows. Net cash provided by operating activities was $72.9 million for the nine months ended September 30, 2008, as compared to $75.2 million for the same period in 2007. The decrease of $2.3 million was primarily due to changes in working capital accounts, as well as to lower net income before depletion.

Net cash used in investing activities was $93.5 million during the nine months ended September 30, 2008, versus $83.9 million in the first nine months of 2007, due to increased capital expenditures partially offset by higher property sales.

Cash flows provided by financing activities during the first nine months of 2008 were $17.9 million, compared to cash provided by financing activities of $1.4 million during the first nine months of 2007, primarily due to the net drawdowns on the amended credit facility of $12 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. The maturity date of outstanding loans may be accelerated by the Lenders upon the occurrence of an event of default under the agreement. As of September 30, 2008, outstanding borrowings under the Amended Credit Facility totaled $87 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. In the event our then-redetermined borrowing base is less than our outstanding borrowings under the Amended Credit Facility, we will be required to repay the deficit within a 90-day period. The most recently scheduled redetermination as of October 31, 2008 has not been completed.

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, restrictions on incurrence of additional debt, and an unqualified audit report on the Company’s consolidated financial statements, all of which the Company is in compliance with at September 30, 2008.

Under the Amended Credit Facility, the Company may secure either (i) an alternative base rate loan that bears interest at a rate per annum equal to the greater of (a) 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 September 30, 2008, the three-month LIBOR interest rate was 4.05%. The Amended Credit Facility provides for commitment fees of 0.375% calculated on the difference between the borrowing base and the aggregate outstanding loans and letters of credit under the Amended Credit Facility. As of November 10, 2008, outstanding borrowing under the Amended Credit Facility totaled $90 million.

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 September 30, 2008, the balance was $9.3 million, with $7.5 million reported as long-term debt and $1.8 million as current portion of long-term debt in the Consolidated Balance Sheet.

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 nine months ended September 30, 2008 were approximately $94.3 million. Our strategy is to blend exploration drilling activities with high-confidence workover and development projects in order to capitalize on periods of high commodity prices. Capital expenditures were for acreage acquisitions, exploratory drilling, geological and geophysical, workovers, and related capitalized general and administrative expenses.

The 2008 capital expenditures plan is currently forecast at approximately $115.0 million. The actual expenditures for the remainder of the year 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, and the availability of funds under the Amended Credit Facility. We currently anticipate funding the remainder of the 2008 plan utilizing cash flow from operations and cash on hand, in addition to utilizing available credit.

We expect capital expenditures for 2009 to be impacted by our ability to access credit markets, which may be limited if general credit conditions do not improve. If availability of funds under the Amended Credit Facility is restricted and/or operating cash flows are insufficient for planned activity, we may decrease capital expenditures. Property sales may provide funds for investment as well.

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 September 30, 2008, we had a pre-tax cushion (i.e. the excess of the ceiling over our capitalized costs) of approximately $60.0 million. A 10% increase in prices would have increased the cushion by approximately 98%. A 10% decrease in prices would have decreased the cushion by approximately 97%.

Borrowing base for the Amended Credit Facility. The Amended Credit Facility with Fortis Capital Corp. as administrative agent, is scheduled for borrowing base redetermination dates on a semi-annual basis. The most recently scheduled redetermination as of October 31, 2008 has not been completed. The borrowing base is redetermined on numerous factors including current reserve estimates, reserves that have recently been added, current commodity prices, current production rates and estimated future net cash flows. These factors have associated risks with each of them. Significant reductions or increases in the borrowing base will be determined by these factors, which, to a significant extent, are not under the Company’s control.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk.

The Company is currently exposed to market risk from hedging contracts changes and changes in interest rates. A discussion of the market risk exposure in financial instruments follows.

Interest Rates

We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. Our long-term borrowings primarily consist of borrowings under the 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 $87 million remains borrowed under the Amended Credit Facility, we estimate our annual interest expense will change by approximately $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 September 30, 2008, the positions effectively hedge approximately 35% of our proved developed natural gas production and 25% 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 September 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)
														Ceiling				September 30,
						Notional				Floor Price				Price				2008
		Type				Amount				($ per unit)				($ per unit)				(in thousands)
Natural Gas (mmbtu)
Oct 2008 – Dec 2008		Collar					420,000			$	7.00			$	12.15			$	75
Oct 2008 – Dec 2008		Collar					190,000			$	7.50			$	11.50				61
Oct 2008 – Dec 2008		Collar					430,000			$	7.50			$	10.10				135
Oct 2008 – Dec 2008		Collar					30,000			$	8.00			$	10.50				20
Jan 2009 – Dec 2009		Collar					1,230,000			$	7.50			$	10.45				413
Jan 2009 – Dec 2009		Collar					760,000			$	8.00			$	10.30				422
Jan 2009 – Dec 2009		Collar					540,000			$	8.00			$	13.35				450
Total Natural Gas																			1,576
Crude Oil (bbls)
Oct 2008 – Dec 2008		Collar					15,000			$	55.00			$	83.00				(290	)
Oct 2008 – Dec 2008		Collar					6,000			$	65.00			$	80.60				(126	)
Oct 2008 – Dec 2008		Collar					13,000			$	65.00			$	85.00				(227	)
Oct 2008 – Dec 2008		Collar					6,000			$	75.00			$	102.50				(39	)
Oct 2008 – Dec 2008		Collar					12,000			$	85.00			$	111.40				(22	)
Jan 2009 – Dec 2009		Collar					23,000			$	70.00			$	93.55				(384	)
Jan 2009 – Dec 2009		Collar					43,000			$	80.00			$	111.00				(284	)
Jan 2009 – Dec 2009		Collar					49,000			$	85.00			$	128.50				(15	)
Total Crude Oil																			(1,387	)
																		$	189