UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

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

For the fiscal year ended December 31, 2008

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

For the transition period from                      to                     

Commission file number: 1-10671

THE MERIDIAN RESOURCE CORPORATION

(Exact name of registrant as specified in its charter)

TEXAS (State of incorporation)		76-0319553 (I.R.S. Employer Identification No.)
1401 Enclave Parkway, Suite 300, Houston, Texas (Address of principal executive offices)		77077 (Zip Code)

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

(Title of each class)		(Name of each exchange on which registered)
Common Stock, $0.01 par value Rights to Purchase Preferred Shares		New York Stock Exchange New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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):

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

Aggregate market value of shares of common stock held by non-affiliates of the Registrant at June 30, 2008 $260,739,160

Number of shares of common stock outstanding at March 4, 2009: 93,070,592

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Form (Items 10, 11, 12, 13 and 14) is incorporated by reference from the registrant’s Proxy Statement to be filed on or before April 30, 2009.

 

 

THE MERIDIAN RESOURCE CORPORATION
INDEX TO FORM 10-K

				Page
		PART I
Item 1.		Business			3
Item 1A.		Risk Factors			14
Item 1B.		Unresolved Staff Comments			22
Item 2.		Properties			22
Item 3.		Legal Proceedings			23
Item 4.		Submission of Matters to a Vote of Security Holders			24
		PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			25
Item 6.		Selected Financial Data			27
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			28
Item 7A.		Quantitative and Qualitative Disclosures about Market Risk			47
Item 8.		Financial Statements and Supplementary Data			52
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			99
Item 9A.		Controls and Procedures			99
Item 9B.		Other Information			100
		PART III
Item 10.		Directors, Executive Officers and Corporate Governance			101
Item 11.		Executive Compensation			101
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			101
Item 13.		Certain Relationships and Related Transactions, and Director Independence			101
Item 14.		Principal Accountant Fees and Services			101
		PART IV
Item 15.		Exhibits			101
		Signatures			106
EX-10.31
EX-10.32
EX-10.33
EX-10.34
EX-10.35
EX-23.1
EX-23.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I

Item 1. Business

General

The Meridian Resource Corporation (“Meridian,” the “Company,” “us,” “our,” or “we”) is an independent oil and natural gas company that explores for, acquires and develops oil and natural gas properties utilizing the latest in completion and 3-D seismic technology. The Company was incorporated in Texas in 1990, with headquarters located at 1401 Enclave Parkway, Suite 300, Houston, Texas 77077. The Company’s common stock is traded on the New York Stock Exchange under the ticker symbol “TMR.” You can locate additional information, including the Company’s filings with the Securities and Exchange Commission (“SEC”), on the internet at www.tmrc.com and www.sec.gov.

Through our wholly-owned subsidiaries, we hold interests primarily in the onshore oil and natural gas regions of south Louisiana and Texas and offshore in the Gulf of Mexico. We treat all operations as one line of business.

As of December 31, 2008, we had proved reserves of 80 Bcfe with a present value of future net cash flows of approximately $179 million. Sixty-three percent (63%) of our proved reserves were natural gas and approximately sixty-four percent (64%) were classified as proved developed. We own interests in 19 fields and 100 producing wells, and operated approximately 96% of our total production in 2008.

Recent developments

We rely on our Amended and Restated Credit Agreement (as amended, the “Credit Facility”) for funds during times of increased capital expenditures or decreased cash flow from operations. Recently, our access to capital was restricted by a reduction in the borrowing base under our Credit Facility, and our ability to fund capital expenditures has significantly decreased. In December 2008, our lenders reduced the borrowing base to equal the amount already outstanding under the Credit Facility ($95 million), leaving no additional credit available. With the precipitous decrease in the price of oil and natural gas in the second half of 2008, we are experiencing decreased cash flow from operations. The reduction in available credit under these conditions creates significant uncertainties for the Company.

Our Credit Facility contains a number of positive and negative covenants with which we must comply. As of December 31, 2008, we are in default of one such covenant, the test of our current ratio. The current ratio is defined under the Credit Facility as current assets divided by current liabilities, but excluding current assets or liabilities from commodity price hedging agreements, excluding amounts payable under the Credit Facility itself, and excluding current asset retirement obligations. Unused available funds under the Credit Facility are added to current assets in computing the ratio. The required ratio is one to one or higher; our actual ratio, as defined, at December 31, 2008 is 0.76, absent certain adjustments to current liabilities for potential acceleration of payment due to default of covenants.

We are also in default of a covenant in the Credit Facility that requires us to deliver to our lenders audited financial statements for each fiscal year that do not have a “going concern” or like modification. As a result of our current lack of financial liquidity, our independent registered public accounting firm has included such a modification in its report on our consolidated financial statements. See Note 1 of the Notes to Consolidated Financial Statements included herein.

Presently, our lenders have been informed of our default under these covenants, and have not responded with a notice of any exercise of remedies.

Our lenders have available to them various remedies if they choose to declare an event of default, including

acceleration of payment of all principal and interest. Although they have not demanded any accelerated payments, they may. If they were to make such demands, the Company would likely be forced to sell assets to make any such payments. To mitigate such circumstance to the extent feasible, we are currently pursuing a number of actions to reduce expenses and conserve cash; see “Current Plans,” below.

In addition to the circumstance of default, the borrowing base is scheduled for redetermination as of April 30, 2009. The borrowing base is determined at the discretion of the lenders, based primarily on the value of our proved reserves. We believe it is likely that the lenders will set the base at a level below outstanding borrowings. In that case, the Company would be required to repay the deficit within 90 days. We may not have enough cash available to repay any of our outstanding borrowings nor can we predict the actions of the lenders. As noted above, to mitigate the effects of these circumstances, we are currently pursuing a number of actions to reduce expenses and conserve cash; see “Current Plans,” below.

Our financial position includes one other debt obligation, a five year note for the purchase of a drilling rig (the “rig note”). The “rig note” is payable in monthly installments, with a total outstanding balance of $8.8 million as of December 31, 2008. Any non-compliance or default under the terms of the Credit Facility triggers a default under the terms of the rig note, as well. The remedies available to the lender under the rig note also include acceleration of all principal and interest payments. The lenders under the rig note have been timely advised of the default under the covenants of the Credit Facility. The lenders may accelerate all payments of principal and interest in response to an event of default, or they may elect to take other action. We may not have enough cash available to repay the rig note, nor can we predict the actions of the lenders under the rig note.

As of December 31, 2008, our net working capital reflects a deficit of approximately $109.3 million, which includes $103.8 million of amounts due under these two debt agreements which have been reclassified to current as a result of the defaults noted above.

Management is currently pursuing discussions with the lenders to obtain waivers. In addition, management is exploring a number of options to conserve or increase cash. These actions include a significant reduction of capital spending, renegotiation of drilling rig contracts, cost reductions through headcount reductions as well as reductions of field operating expenses, and sales of assets.

There can be no assurance that cash flow from operations and other sources of liquidity, including asset sales, will be sufficient to meet contractual, operating and capital obligations. The financial statements have been adjusted to reclassify to current liabilities debts which, absent the default and resulting potential for acceleration of payment by the lenders, would have been classified as long-term. The financial statements do not include any other adjustments that might result from the outcome of uncertainty regarding the Company’s ability to raise additional capital, sell assets, or otherwise obtain sufficient funds to meet its obligations. See further information under “Current Plans” and “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Liquidity and Capital Resources — Cash Obligations,” below.

In addition, due to the decrease in oil and natural gas prices at year-end, as well as to the decrease in our reserves, in December 2008 we recorded a significant non-cash impairment, or ceiling test write-down, to our oil and natural gas properties of $216.8 million. We also recorded a $6.7 million non-cash impairment of our drilling rig, due to decreases in utilization and dayrates for similar rigs. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Reserves”, “- Prices,” “- Ceiling Test,” and “- Drilling Rig Obligation.”

Development of our oil and natural gas properties.

Our operations have historically focused on the onshore oil and natural gas regions in south Louisiana and offshore in the Gulf of Mexico. While maintaining and exploiting our older properties, in recent years we have expanded exploration into new areas. Our objective was to replace our reserves, and to strengthen our reserve base with longer lived properties from unconventional gas plays in various regions of Texas, Oklahoma, and Kentucky. We also invested in conventional horizontal gas plays in Texas.

In exploring these new areas, we invested in seismic data, geological research, acreage, and drilling. Our strategy included building a large inventory of lease acreage to provide ourselves a wide range of opportunities and ensure that new discoveries were highly repeatable.

After thorough testing and analysis, some of our new exploration areas showed only limited promise and have been dropped or sold. The most significant success has been in the East Texas Austin Chalk formation, where our acreage is primarily in Polk County. We have drilled 12 wells in East Texas and 11 of them have been completed as producers. We pursued our historical strategy of limiting participations with partners; we operate many of our new discoveries as well as our older properties and are positioned to operate our undrilled leases.

As a result of pursuing our expanded exploration strategy in prior years, we have accumulated the following significant assets:

	•		11 producing natural gas wells in East Texas with significant leaseholds available for development;
	•		Geologic information to assist us in locating and defining the higher yielding areas within our East Texas Austin Chalk holdings;
	•		Experience that has improved efficiencies in drilling and operating in the Austin Chalk, which we have used to reduce costs;
	•		An additional portfolio of approximately 30,000 net acres in Karnes and Lavaca Counties of South Central Texas covering the Austin Chalk, as well as the Eagle Ford Shale where others have had successful drilling; and
	•		A significant library of 3-D and 2-D seismic data, much of which as been reprocessed and utilized for the identification and development of new prospects.

In addition, our historically acquired properties in onshore and offshore Louisiana are valuable assets comprising the majority of our reserve base and current cash flow. Although these fields are mature, we continue to review them for any opportunities for increased or prolonged production.

We believe we have a competitive advantage in the areas where we operate because of our large inventory of lease acreage, seismic data coverage and experienced geotechnical, land and operational staff. We also believe that our operational control over most of our properties adds to our competitive advantage, through greater flexibility and control of costs. Our ability to exploit these advantages, however, will be limited by our current lack of liquidity to fund the necessary capital expenditures.

Current Plans.

Results of our exploratory drilling efforts have been intermittent and while more recent wells have improved both as to drilling costs and productive results, reaching this point has absorbed significant cash flow as well as significant utilization of the borrowing base under our Credit Facility. In the second half of 2008, as our returns on drilling expenditures in the Austin Chalk began to improve, energy prices dropped precipitously. This impacted the borrowing base under our Credit Facility, which is based on the value of our proved reserves and is subject to redetermination at least semi-annually. We have lower expectations of cash flow for the near future, and availability of additional funds under our Credit Facility has been reduced to zero.

Our most basic mission is unchanged. We intend to preserve and exploit the Company’s best assets and continue to produce oil and natural gas. We will continue to make environmental and operational safety in the field our first priority.

However, economic circumstances have necessitated that we revise our short term objectives. We are currently focused primarily on our cash position and our standing with our lenders. Thus cash preservation and strict management of cash flow are currently our highest priorities.

We have identified multiple action areas to achieve our short-term cash-focused objectives, including:

	•		Reducing capital expenditures by shifting away from exploratory efforts on new wells to recompletions and workovers of existing wells based on strict economic analysis focused on increased production and cash flow;
	•		Renegotiation of drilling-related contractual commitments;

	•		Cost reductions in the office, based on headcount reductions and close examination of all other general and administrative expenses;
	•		Cost reductions in the field through close review of lease operating expenses and implementation of more strict efficiency measures;
	•		Sale of non-strategic assets, including both developed and undeveloped properties; and
	•		Partial sale of our key exploratory and development assets in the East Texas Austin Chalk, in order to raise cash and reduce risk through a reduced working interest.

Strategy for preservation and exploitation of our assets.

Our operational objectives for the near term are focused on maintaining current production levels, in spite of the natural declines we will continue to experience from our mature properties. To achieve this objective, we are reviewing our properties for recompletion and other reconditioning opportunities. Each of these is being subjected to rigorous cost analysis, to ensure that the project has economic value at current prices. Pursuit of these opportunities, however, is dependent on the availability of funds, which we cannot presently predict; we expect such availability to be very limited.

Our exploration strategy is necessarily curtailed by the limited resources available to us for capital expenditures. We believe that our best approach for the near term is to minimize drilling expense, maximize cash flow, and maintain or increase the future value of the assets we hold. To achieve that objective we are taking the following steps:

	•		We will cease drilling activities after completion of the two wells in which we are currently participating (one operated and one non-operated);
	•		We are seeking partners to assist us in developing our holdings in East Texas, with the goal of reducing our working interests into the range of 25-35% for new wells;
	•		We have directed our staff to continue to analyze geological and seismic data, which we believe enhances the value of our assets, as well as identifying the best opportunities for capital expenditures under a limited resource scenario;
	•		We have taken steps to reduce or offset our cash obligations under drilling contracts;
	•		We are monitoring the exploration results of others, particularly in the Eagle Ford trend in South Texas; although we cannot allocate funds to these areas currently, we intend to test them when the opportunity arises; and
	•		Although staff reductions have been necessary, we have retained a well-qualified team of exploratory and operational personnel.

Oil and Natural Gas Properties

The following table sets forth production and reserve information by region with respect to our proved oil and natural gas reserves as of December 31, 2008. The reserve volumes were reviewed by T. J. Smith & Company, Inc., independent reservoir engineers.

										Gulf of
		Louisiana				Texas				Mexico				Total
Production for the year ended December 31, 2008
Oil (MBbls)			567				154				44				765
Natural Gas (MMcf)			8,173				842				354				9,369
Reserves as of December 31, 2008
Oil (MBbls) (1)			3,580				795				528				4,903
Natural Gas (MMcf) (1)			42,367				3,406				5,122				50,895

Estimated future net cash flows ($000)(2)														$	239,576
Present value of future net cash flows before income taxes ($000)(3)														$	179,437
Standardized measure of discounted future net cash flows ($000)(4)														$	179,437

Productive Wells

At December 31, 2008, 2007 and 2006, we held interests in the following productive wells. As of December 31, 2008, we own interests in 20 gross (4 net) wells in the Gulf of Mexico which are outside operated and net to 2 oil wells and 2 natural gas wells and 1 gross (1 net) operated offshore oil well. In addition, of the total well count for 2008, 1 well (1 net) are multiple completions.

		2008								2007								2006
		Gross				Net				Gross				Net				Gross				Net
Oil Wells			34				20				33				19				44				28
Natural Gas Wells			66				37				88				43				77				43
Total			100				57				121				62				121				71

Oil and Natural Gas Reserves

Presented below are our estimated quantities of proved reserves of crude oil and natural gas, Future Net Cash Flows, Present Value of Future Net Revenues and the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2008. Information set forth in the following table is based on reserve reports prepared in accordance with the rules and regulations of the SEC. The reserves and associated cash flows were reviewed by T. J. Smith & Company, Inc., independent reservoir engineers.

		Proved Reserves at December 31, 2008
		Developed
		Producing				Developed
		(1)				Non-Producing				Undeveloped				Total
						(dollars in thousands)
Net Proved Reserves:
Oil (MBbls)			1,431				1,301				2,171				4,903
Natural Gas (MMcf)			19,239				15,815				15,842				50,896
Natural Gas Equivalent (MMcfe)			27,825				23,619				28,869				80,313
Estimated Future Net Cash Flows(2)														$	239,576
Present Value of Future Net Cash Flows (before income taxes)(3)														$	179,437
Standardized Measure of Discounted Future Net Cash Flows(4)														$	179,437

You can read additional reserve information in our Consolidated Financial Statements and the Supplemental Oil and Natural Gas Disclosures (unaudited) included elsewhere herein. We have not included estimates of total proved reserves, comparable to those disclosed herein, in any reports filed with federal authorities other than the SEC.

In general, our engineers based their estimates of economically recoverable oil and natural gas reserves and of the future net revenues therefrom on a number of variable factors and assumptions, such as historical production from the subject properties, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices and future operating costs, all of which may vary considerably from actual results. Therefore, the actual production, revenues, severance and excise taxes, and development and operating expenditures with respect to reserves likely will vary from such estimates, and such variances could be material.

Estimates with respect to proved reserves that we may develop and produce in the future are often based on volumetric calculations and by analogy to similar types of reserves rather than actual production history.

Estimates based on these methods are generally less reliable than those based on actual production history, and subsequent evaluation of the same reserves, based on production history, will result in variations, which may be substantial, in the estimated reserves.

In accordance with applicable requirements of the SEC, the estimated discounted future net revenues from estimated proved reserves are based on prices and costs as of the date of the estimate unless such prices or costs are contractually determined at that date. Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.

Oil and Natural Gas Drilling Activities

The following table sets forth the gross and net number of productive and dry exploratory and development wells that we drilled and completed in 2008, 2007 and 2006.

		Gross Wells												Net Wells
		Productive				Dry				Total				Productive				Dry				Total
Exploratory Wells
Year ended December 31, 2008			6				4				10				2.7				3.1				5.8
Year ended December 31, 2007			13				12				25				4.2				6.6				10.8
Year ended December 31, 2006			7				7				14				4.1				5.4				9.5
Development Wells
Year ended December 31, 2008			7				4				11				5.0				3.2				8.2
Year ended December 31, 2007			—				—				—				—				—			—
Year ended December 31, 2006			1				—				1				0.7				—				0.7

Meridian had two gross (0.8 net) wells in progress at December 31, 2008. In addition, Meridian participated in four successful recompletion operations in 2008.

Production

The following table summarizes the net volumes of oil and natural gas produced and sold, and the average prices received with respect to such sales (net of commodity hedge gains/losses), from all properties in which Meridian held an interest during 2008, 2007 and 2006.

		Year Ended December 31,
		2008				2007				2006
Production:
Oil (MBbls)			765				838				859
Natural gas (MMcf)			9,369				13,239				18,170
Natural gas equivalent (MMcfe)			13,958				18,269				23,323
Average Prices:
Oil ($/Bbl)		$	83.13			$	64.70			$	55.73
Natural gas ($/Mcf)		$	9.07			$	7.29			$	7.77
Natural gas equivalent ($/Mcfe)		$	10.65			$	8.25			$	8.11
Production Expenses:
Lease operating expenses ($/Mcfe)		$	1.74			$	1.55			$	0.97
Severance and ad valorem taxes ($/Mcfe)		$	0.70			$	0.52			$	0.48

Acreage

The following table sets forth the developed and undeveloped oil and natural gas leasehold acreage in which Meridian held an interest as of December 31, 2008. Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether or not such acreage contains proved reserves.

		December 31, 2008
		Developed								Undeveloped
Region		Gross				Net				Gross				Net
Louisiana			30,082				21,002				16,142				14,299
Oklahoma			1,809				699				—				—
Kentucky			—				—				28,750				24,236
Texas			10,842				6,551				139,991				91,442
Gulf of Mexico			28,759				5,613				11,440				3,976
Total			71,492				33,865				196,323				133,953

In addition to the above acreage, we currently have options or farm-ins to acquire leases on approximately 2,183 gross (2,183 net) acres of undeveloped land located in Louisiana. Our undeveloped net acreage, including optioned acreage, expires during the next three years at the rate of 33,600 acres in 2009, 15,200 acres in 2010, and 65,300 acres in 2011.

Geologic/Land and Operations Geophysical Expertise

Meridian employs approximately 67 full-time non-union employees and 11 contract employees. Our office staff includes geologists, geophysicists, land and engineering staff with many years of experience in generating and developing onshore and offshore prospects in the regions in which we operate. Our geologists and geophysicists generate and review all prospects using 2-D and 3-D seismic technology and analogues to producing wells in the areas of interest.

Marketing of Production

We market our production to third parties in a manner consistent with industry practices. Typically, the oil production is sold at the wellhead at posted prices, less applicable transportation deductions, and the natural gas is sold at posted indices, less applicable transportation, gathering and dehydration charges, adjusted for the quality of natural gas and prevailing supply and demand conditions. The natural gas production is sold under long- and short-term contracts (all of which are based on a published index) or in the spot market.

The following table sets forth purchasers of our oil and natural gas that accounted for more than 10% of total revenues for 2008, 2007 and 2006.

		Year Ended December 31,
Customer		2008				2007				2006
Shell Trading (U.S.)			21	%			14	%			—
Superior Natural Gas			17	%			23	%			35	%
Crosstex Gulfcoast Marketing			14	%			16	%			21	%

Other purchasers for our oil and natural gas are available; therefore, we believe that the loss of any of these purchasers would not have a material adverse effect on our results of operations.

Market Conditions

Our revenues, profitability and future rate of growth substantially depend on prevailing prices for oil and natural gas. Oil and natural gas prices have been extremely volatile in recent years and are affected by many factors outside our control. Since 1993, prices for West Texas Intermediate crude have ranged from $8.00 to approximately $145.00 per Bbl and the Gulf Coast spot market natural gas price at Henry Hub, Louisiana, has ranged from $1.08 to $15.40 per MMBtu. The average price we received during the year ended December 31, 2008, was $10.65 per Mcfe compared to $8.25 per Mcfe (each net of commodity hedge gains/losses) during the year ended December 31, 2007. The volatile nature of energy markets makes it difficult to estimate future prices of oil and natural gas; however, any prolonged period of depressed prices would have a material adverse effect on our results of operations and financial condition.

The marketability of our production depends in part on the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and natural gas production and transportation, general economic conditions, changes in supply and changes in demand could adversely affect our ability to produce and market our oil and natural gas. If market factors were to change dramatically, the financial impact on us could be substantial. We do not control the availability of markets and the volatility of product prices is beyond our control and therefore represents significant risk.

Competition

The oil and natural gas industry is highly competitive for prospects, acreage and capital. Our competitors include numerous major and independent oil and natural gas companies, individual proprietors, drilling and income programs and partnerships. Many of these competitors possess and employ financial and personnel resources substantially greater than ours and may, therefore, be able to define, evaluate, bid for and purchase more oil and natural gas properties. There is intense competition in marketing oil and natural gas production, and there is competition with other industries to supply the energy and fuel needs of consumers.

Regulation

The availability of a ready market for any oil and natural gas production depends on numerous factors that we do not control. These factors include regulation of oil and natural gas production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and natural gas available for sale, the availability of

adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas or lack of available natural gas pipeline capacity in the areas in which we may conduct operations. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between multiple owners in a common reservoir, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies.

Oil and natural gas production operations are subject to various types of regulation by state and federal agencies. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion. In addition, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that govern the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability.

All of our federal offshore oil and gas leases are granted by the federal government and are administered by the U. S. Minerals Management Service (the “MMS”). These leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations and the calculation of royalty payments to the federal government. Ownership interests in these leases generally are restricted to United States citizens and domestic corporations. The MMS must approve any assignments of these leases or interests therein.

The federal authorities, as well as many state authorities, require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Individual states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from oil and natural gas wells and the regulation of spacing, plugging and abandonment of such wells. The statutes and regulations of the federal authorities, as well as many state authorities, limit the rates at which we can produce oil and gas on our properties.

Federal Regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas pipeline transportation rates and service conditions, both of which affect the marketing of natural gas produced by us, as well as the revenues we receive for sales of such natural gas. It is not possible to predict what, if any, effect the FERC’s future policies will have on us. Proposals and/or proceedings that might affect the natural gas industry may be considered by FERC, Congress or state regulatory bodies. It is not possible to predict when or if any of these proposals may become effective or what effect, if any, they may have on our operations. We do not believe, however, that our operations will be affected any differently than other natural gas producers or marketers with which we compete.

Price Controls. Our sales of natural gas, crude oil, condensate and natural gas liquids are not regulated and transactions occur at market prices.

State Regulation of Oil and Natural Gas Production. States where we conduct our oil and natural gas activities regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas and other resources. In addition, most states regulate the rate of production and may establish the maximum daily production allowable for wells on a market demand or conservation basis.

Environmental Regulation. Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require us to acquire a permit before we commence drilling; restrict the types, quantities and concentration of various substances that we can release into the environment in connection with drilling and production activities; limit or prohibit our drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and impose substantial liabilities for pollution resulting from our operations.

Moreover, the general trend toward stricter standards in environmental legislation and regulation is likely to continue. For instance, as discussed below, legislation has been proposed in Congress from time to time that would cause certain oil and natural gas exploration and production wastes to be classified as “hazardous wastes”, which would make the wastes subject to much more stringent handling and disposal requirements. If such legislation were enacted, it could have a significant impact on our operating costs, as well as on the operating costs of the oil and natural gas industry in general. Initiatives to further regulate the disposal of oil and natural gas wastes have also been considered in the past by certain states, and these various initiatives could have a similar impact on us. We believe that our current operations are in material compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us.

OPA. The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area where an offshore facility is located. The OPA makes each responsible party liable for oil-removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the party caused the spill by gross negligence or willful misconduct or if the spill resulted from a violation of a federal safety, construction or operating regulation. The liability limits likewise do not apply if the party fails to report a spill or to cooperate fully in the cleanup. Few defenses exist to the liability imposed by the OPA.

The OPA also imposes ongoing requirements on a responsible party, including the requirement to maintain proof of financial responsibility to be able to cover at least some costs if a spill occurs. In this regard, the OPA requires the lessee or permittee of an offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35 million ($10 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to a crude oil spill for which such person is statutorily responsible. The amount of required financial responsibility may be increased above the minimum amounts to an amount not exceeding $150 million depending on the risk represented by the quantity or quality of crude oil that is handled by the facility. The MMS has promulgated regulations that implement the financial responsibility requirements of the OPA. Under the MMS regulations, the amount of financial responsibility required for an offshore facility is increased above the minimum amount if the “worst case” oil spill volume calculated for the facility exceeds certain limits established in the regulations.

The OPA also imposes other requirements, such as the preparation of an oil-spill contingency plan. We have such a plan in place. Failure to comply with ongoing requirements or inadequate cooperation during a spill may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under the OPA and we believe that compliance with the OPA’s financial responsibility and other operating requirements will not have a material adverse impact on us.

CERCLA. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state statutes impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA, persons or companies that are statutorily liable for a release could be subject to joint-and-several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Except as described in Item 3.. Legal Proceedings, we are not aware of any hazardous substance contamination for which we may be liable.

Clean Water Act. The Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), imposes restrictions and controls on the discharge of produced waters and other oil and natural gas wastes into

navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore water. The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges of oil and other hazardous substances and imposes liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. Comparable state statutes impose liability and authorize penalties in the case of an unauthorized discharge of petroleum or its derivatives, or other hazardous substances, into state waters. Except as described in Item 3., Legal Proceedings, we believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act (“RCRA”) is the principal federal statute governing the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility. At present, RCRA includes a statutory exemption that allows most crude oil and natural gas exploration and production waste to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s requirements because our operations generate minimal quantities of hazardous wastes. At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes crude oil and natural gas exploration and production wastes from regulation as hazardous waste. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and could cause us to incur increased operating expenses.

Title to Properties

As is customary in the oil and natural gas industry, we make only a cursory review of title to undeveloped oil and natural gas leases at the time we acquire them. However, before drilling commences, we search the title, and remedy any material defects before we actually begin drilling the well. To the extent title opinions or other investigations reflect title defects, we (rather than the seller or lessor of the undeveloped property) typically are obligated to cure any such title defects at our expense. If we are unable to remedy or cure any title defects so that it would not be prudent for us to commence drilling operations on the property, we could suffer a loss of our entire investment in the property. We believe that we have good title to our oil and natural gas properties, some of which are subject to immaterial encumbrances, easements and restrictions. Under the terms of our credit facility, we may not grant liens on various properties and must grant to our lenders a mortgage on our oil and natural gas properties of at least 75% of our present value of proved properties. Our own oil and natural gas properties also typically are subject to royalty and other similar non-cost-bearing interests customary in the industry.

We acquired substantial portions of our 3-D seismic data through licenses and other similar arrangements. Such licenses contain transfer and other restrictions customary in the industry.

Item 1A. Risk Factors

Each of the following risk factors could adversely affect our business, operating results and financial condition. It is not possible to foresee or identify all such factors. Investors should not consider this list an exhaustive statement of all risks and uncertainties. This report also contains forward-looking statements that involve risks and uncertainties. Our actual results may differ from those anticipated in these forward-looking statements as a result of both the risks described below and factors described elsewhere in this report. You should read the section below entitled “Forward-Looking Statements” for further discussion of these matters.

As a result of our current lack of financial liquidity, we have received a “going concern” modification to our independent accountant’s opinion on our consolidated financial statements.

Our independent registered public accounting firm has included an explanatory paragraph in their report on our December 31, 2008 consolidated financial statements regarding their substantial doubt as to our ability to continue as a going concern. Our lack of sufficient liquidity could make it more difficult for us to secure additional financing or enter into strategic relationships on terms acceptable to us, if at all, and may materially and adversely affect the terms of any financing that we may obtain and our public stock price generally.

Our Credit Facility has substantial restrictions and financial covenants. We are currently in default under, and may have difficulty returning to compliance with, certain of the covenants in our Credit Facility, including our covenant to maintain a ratio of current assets to current liabilities of not less than 1.0 to 1.0, and our covenant to deliver to our lenders audited financial statements for each fiscal year that do not have a “going concern” or like qualification or exception.

Our current Credit Facility contains restrictive covenants that impose significant operating and financial restraints that could impair our ability to obtain future financing, to make capital expenditures, to pay dividends, to engage in mergers or acquisitions, to withstand downturns in our business or in the general economy or to otherwise conduct necessary corporate activities. We are also required to comply with certain financial covenants and ratios. We are currently in default under certain of those covenants. Our ability to return to compliance and maintain compliance in the future is uncertain. Our ability to comply with these covenants and restrictions will be affected by the levels of cash flow from our operations and events or circumstances beyond our control, including events and circumstances that may stem from the condition of financial markets and commodity price levels.

Furthermore, we have pledged substantially all of our oil and natural gas properties and the stock of all of our principal operating subsidiaries as collateral for the indebtedness under our Credit Facility. We are in material default of our obligations under the Credit Facility, and the lenders are entitled to liens on additional oil and natural gas properties. This pledge of collateral to our Credit Facility lenders could impair our ability to obtain additional financing on favorable terms, or at all.

Our failure to comply with any of the restrictions and covenants under our Credit Facility results in an event of default under the facility, which results in an event of default on our rig note as well. The total balance outstanding under the rig note at December 31, 2008 is $8.8 million. The remedies available to the lender under the rig note include acceleration of all principal and interest payments. We may not be able to remit such an accelerated payment or to access sufficient funds from alternative sources to remit any such payment. Even if we could obtain additional financing, the terms of that financing may not be favorable or acceptable to us.

Presently, our lenders have been informed of our default under these covenants, and have not responded with a notice of any exercise of remedies. We cannot predict what action they may take.

Our Credit Facility has periodic borrowing base redeterminations and we may have difficulty maintaining our total borrowing base at the current level of $95 million at future redeterminations, or maintaining or obtaining additional credit at similar terms, which could adversely affect our operations.

As of December 31, 2008, we had outstanding indebtedness of $95.0 million under our Credit Facility, which equaled the current limit to our borrowings under that facility. The Credit Facility limits the amounts we can borrow to the borrowing base amount, determined by the lenders in their sole discretion. The borrowing base will be redetermined semi-annually, and may be redetermined at our request more frequently and by the lenders in their sole discretion based on reserve reports prepared by reserve engineers, together with, among other things, the oil and natural gas prices existing at the time. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the Credit Facility. Any increase in the

borrowing base requires the consent of all the lenders. Outstanding borrowings in excess of the borrowing base must be repaid within 90 days, and we may not have the financial resources in the future to make any mandatory principal repayments required under the Credit Facility.

The borrowing base is scheduled for redetermination as of April 30, 2009. We believe it is likely that the lenders will set the base at a level below outstanding borrowings. We may not have enough cash available to repay any of our outstanding borrowings.

Because of the recent deterioration of the credit and capital markets, we may be unable to obtain financing from sources other than our Credit Facility on acceptable terms or at all.

Global market and economic conditions have been, and continue to be, disruptive and volatile. The debt and equity capital markets have been adversely affected by significant write-offs in the financial services sector relating to subprime mortgages, and the re-pricing of credit risk in the broadly syndicated market, among other things. These events have led to worsening general economic conditions.

In particular, the cost of capital in the debt and equity capital markets has increased substantially, while the availability of funds from those markets has diminished significantly. Also, concerns about the stability of financial markets generally and the solvency of counterparties specifically have led to increases in the cost of obtaining money from the credit markets as many lenders and institutional investors have increased interest rates, enacted tighter lending standards and reduced funding and, in some cases, ceased to provide funding to borrowers.

We have substantial anticipated capital requirements. Our ongoing capital requirements consist primarily of the need to fund our capital budget and the exploitation, development, production and abandonment of oil and natural gas reserves. Historically, we have relied heavily on our credit facilities for our capital needs. As of December 31, 2008, we had outstanding indebtedness of $95.0 million under our Credit Facility, which equaled the current limit to our borrowings under that facility. If we need to raise capital from a source other than our Credit Facility, it is unlikely that additional capital will be available to the extent required and on acceptable terms. If capital on acceptable terms is not available, we may be unable to fully execute our growth strategy, otherwise take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our results of operations and financial condition. We may be forced to sell a significant portion of our assets in order to meet near-term contractual requirements. We may not be able to sell assets on terms that we consider advantageous to the Company and our stockholders.

We have significant near-term contractual obligations, which we may not be able to meet; our working capital is currently a net deficit.

We have significant near-term contractual obligations, including, but not limited to, two drilling contracts, certain obligations to employees for compensation, and certain oil and natural gas property investment commitments. Our net working capital position at December 31, 2008, is a deficit of $109.3 million, which includes $103.8 million of amounts due under the Credit Facility and the rig note which have been reclassified as current as a result of the defaults noted elsewhere herein. Our cash flow and working capital have been significantly impacted by the precipitous decrease in the prices we received for oil and natural gas in the second half of 2008, and continuing into 2009. If we are not able to increase cash flow, our ability to meet these obligations may be impacted, which could have a material adverse effect on our results of operations and financial condition.

Our common stock could be delisted from the New York Stock Exchange.

As of December 4, 2008, we received notification from the New York Stock Exchange that the Company had fallen below certain continued listing criteria, that require a minimum average closing price of $1.00 per share over 30 consecutive trading days. In addition, we are currently monitoring the Company’s compliance with another listing criteria. This criteria requires that average market capital over 30 consecutive trading days

must be at least $15 million. Based on shares currently outstanding, the Company’s average market capital decreases below this level when the stock price drops below approximately $0.16 per share. Some closing prices in the first quarter of 2009 have been below this price. If the Company becomes non-compliant with this criteria, our common stock will be immediately subject to the NYSE’s delisting procedures.

There can be no assurance that the stock of the Company will continue to be listed on the NYSE; there can be no assurance that we will obtain listing on an alternate stock exchange or automated quotation service. A delisting of our common stock could materially and adversely affect, among other things, the liquidity and market price of our common stock; the number of investors willing to hold or acquire our common stock; and our access to capital markets to raise capital in the future.

If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, we may be required to take further write-downs.

In 2008, we recorded a significant non-cash impairment, or ceiling test write-down, to our oil and natural gas properties of $216.8 million. There is a risk that we will be required to take additional write-downs in the future, which would reduce our earnings and shareholders’ equity. A write-down could occur when oil and natural gas prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploration and development results. Downward adjustments to proved reserves may result from decreasing prices of oil and natural gas, as expected development reserves become uneconomic under revised conditions.

The Company follows the full cost method of accounting for its investments in oil and natural gas properties. All costs incurred with the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. Under the rules of the Securities and Exchange Commission (“SEC”) for the full cost method of accounting, the net carrying value of oil and natural gas properties, less related deferred taxes, is limited to the sum of the present value (10% discount rate) of the estimated future after-tax net cash flows from proved reserves, based on the current prices and costs as adjusted for the Company’s cash flow hedge positions, plus the lower of cost or estimated fair value of unproved properties adjusted for related income tax effects.

We review our oil and natural gas properties for impairment quarterly or whenever events and circumstances indicate that the carrying value may not be recoverable. Once incurred, a writedown of oil and natural gas properties is not reversible at a later date even if natural gas or oil prices increase. Given the complexities associated with oil and natural gas reserve estimates and the history of price volatility in the oil and natural gas markets, events may arise that would require us to record additional impairments of the recorded carrying values associated with our oil and natural gas properties.

In addition, our undeveloped leases are subject to expiration and forfeiture if not drilled. Our drilling plans for these areas are subject to the availability of funds for exploration, which is in turn affected by the risk factors described above. The leases may also be sold or assigned, but the oil and natural gas industry is currently undergoing significant market disruptions, which may make it difficult for us to extract value from these assets before expiration. Such circumstances increase the risk of the transfer of unevaluated oil and natural gas properties to the full cost pool where they would be subject to amortization or impairment.

In addition to the impairment of our oil and natural gas properties, we recorded a $6.7 million non-cash impairment of our drilling rig. The rig was purchased in 2007, with the intention of securing access to an appropriate rig and crew for our exploration efforts. Although we utilized the rig for our own drilling during 2008, it has been utilized by others since then based on short-term arrangements. Due to the continued volatility in the prices of oil and natural gas, and its negative effect on the drilling industry, we will continue to review this asset for additional impairment. We cannot predict whether additional impairment will be necessary.

Our indebtedness may adversely affect operations and limit our growth.

As of December 31, 2008, we had total indebtedness under credit agreements and a short term note of $105.6 million compared to approximately $122.5 million of stockholders’ equity. If we are unable to generate sufficient cash flows from operations in the future to service our debt, we may need to refinance all or a portion of our existing debt or to obtain additional financing. Such refinancing or additional financing may not be possible. Our ability to meet our debt service obligations and to reduce our total indebtedness will depend on our future performance and our ability to maintain or increase cash flows from our operations. These outcomes are subject to general economic conditions and to financial, business and other factors affecting our operations, many of which we do not control, including the prevailing market prices for oil and natural gas. Our business may not continue to generate cash flows at or above current levels.

The oil and natural gas markets are volatile and expose us to financial risks.

Our profitability, cash flow and the carrying value of our oil and natural gas properties are highly dependent on the market prices of oil and natural gas. Historically, the oil and natural gas markets have proven cyclical and volatile as a result of factors that are beyond our control. These factors include changes in tax laws, the level of consumer product demand, weather conditions, the price and availability of alternative fuels, the price and level of imports and exports of oil and natural gas, worldwide economic, political and regulatory conditions, and action taken by the Organization of Petroleum Exporting Countries.

Any significant decline in oil and natural gas prices or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved reserves. Consequently, we may not be able to generate sufficient cash flows from operations to meet our obligations and to make planned capital expenditures. Price declines may also affect the measure of discounted future net cash flows of our reserves, a result that could adversely impact the borrowing base under our Credit Facility and may increase the likelihood that we will incur additional impairment charges on our oil and natural gas properties for financial accounting purposes.

Our hedging transactions may not adequately prevent losses.

We cannot predict future oil and natural gas prices with certainty. To manage our exposure to the risks inherent in such a volatile market, from time to time, we have entered into commodities futures, swap or option contracts to hedge a portion of our oil and natural gas production against market price changes. Hedging transactions are intended to limit the negative effect of future price declines, but may also prevent us from realizing the benefits of price increases above the levels reflected in the hedges. Our Credit Facility requires that only lenders under that agreement may act as counterparties under our hedging agreements; our hedging contracts are not collateralized. Recent uncertainty in financial markets could impact the ability of our counterparties under hedging agreements to pay, which could reduce the value of our proved reserves, our hedge-related assets and liabilities, and our expected cash flow.

Our reserve estimates may prove to be inaccurate and future net cash flows are uncertain.

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 assumptions and estimates.

We depend on key personnel to execute our business plans.

The loss of any key executives or any other key personnel could have a material adverse effect on our operations. We depend on the efforts and skills of our key executives. Moreover, our future profitability will depend on our ability to attract and retain qualified personnel. During 2008, our former Chief Executive Officer, Mr. Joseph A. Reeves, and our former Chief Operating Officer and President, Mr. Michael J. Mayell, both of whom had been with the Company since inception, ceased their full-time employment with the Company. Our interim Chief Executive Officer, Paul D. Ching, is contractually committed to serve through June 30, 2009. There can be no assurance that we will be able to attract a qualified individual to succeed him.

We compete against significant players in the oil and natural gas industry, and our failure in the long-term to complete future acquisitions successfully and generate commercial exploration and development drilling opportunities could reduce our earnings and cause revenues to decline.

The oil and natural gas industry is highly competitive. Our ability to acquire additional properties and to discover additional reserves depends on our ability to consummate transactions in this highly competitive environment. We compete with major oil companies, other independent oil and natural gas companies, and individual producers and operators. Many of these competitors have access to greater financial and personnel resources than those to which we have access. Moreover, the oil and natural gas industry competes with other industries in supplying the energy and fuel needs of industrial, commercial and other consumers. Increased competition causing oversupply or depressed prices could materially adversely affect our revenues.

The oil and natural gas markets are heavily regulated.

We are subject to various federal, state and local laws and regulations. These laws and regulations govern safety, exploration, development, taxation and environmental matters that are related to the oil and natural gas industry. To conserve oil and natural gas supplies, regulatory agencies may impose price controls and may limit our production. Certain laws and regulations require drilling permits, govern the spacing of wells and the prevention of waste, and limit the total number of wells drilled or the total allowable production from successful wells. Other laws and regulations govern the handling, storage, transportation and disposal of oil and natural gas and any byproducts produced in oil and natural gas operations. These laws and regulations could materially adversely impact our operations and our revenues.

Laws and regulations that affect us may change from time to time in response to economic or political conditions. Thus, we must also consider the impact of future laws and regulations that may be passed in the jurisdictions where we operate. We anticipate that future laws and regulations related to the oil and natural gas industry will become increasingly stringent and cause us to incur substantial compliance costs.

The nature of our operations exposes us to environmental liabilities.

Our operations create the risk of environmental liabilities. We may incur liability to governments or to third parties for any unlawful discharge of oil, natural gas or other pollutants into the air, soil or water. We could potentially discharge oil or natural gas into the environment in any of the following ways:

	•		from a well or drilling equipment at a drill site,
	•		from a leak in storage tanks, pipelines or other gathering and transportation facilities,
	•		from damage to oil or natural gas wells resulting from accidents during normal operations or natural disasters, or
	•		from blowouts, cratering or explosions.

Environmental discharges may move through the soil to water supplies or adjoining properties, giving rise to additional liabilities. Some laws and regulations could impose liability for failure to obtain the proper permits for, to control the use of, or to notify the proper authorities of a hazardous discharge. Such liability could have a material adverse effect on our financial condition and our results of operations and could possibly cause our operations to be suspended or terminated on such property.

We may also be liable for any environmental hazards created either by the previous owners of properties that we purchase or lease or by acquired companies prior to the date we acquire them. Such liability would affect the costs of our acquisition of those properties. In connection with any of these environmental violations, we may also be charged with remedial costs. Pollution and similar environmental risks generally are not fully insurable.

Although we do not believe that our environmental risks are materially different from those of comparable companies in the oil and natural gas industry, we cannot assure you that environmental laws will not result in decreased production, substantially increased costs of operations or other adverse effects to our combined operations and financial condition.

Our operations entail inherent casualty risks for which we may not have adequate insurance.

We must continually acquire, explore and develop new oil and natural gas reserves to replace those produced and sold. Our hydrocarbon reserves and our revenues will decline if we are not successful in our drilling, acquisition or exploration activities. Casualty risks and other operating risks could cause reserves and revenues to decline.

Our onshore and offshore operations are subject to inherent casualty risks such as hurricanes, fires, blowouts, cratering and explosions. Other risks include pollution, the uncontrollable flows of oil, natural gas, brine or well fluids, and the hazards of marine and helicopter operations such as capsizing, collision and adverse weather and sea conditions. These risks may result in injury or loss of life, suspension of operations, environmental damage or property and equipment damage, all of which would cause us to experience substantial financial losses.

Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipe, collapsed casing and separated cables. Our offshore properties involve higher exploration and drilling risks such as the cost of constructing exploration and production platforms and pipeline interconnections as well as weather delays and other risks. Although we carry insurance that we believe is in accordance with customary industry practices, we are not fully insured against all casualty risks incident to our business. We do not carry business interruption insurance. Should an event occur against which we are not insured, that event could have a material adverse effect on our financial position and our results from operations.

In addition, disruptions in financial markets have affected the credit standing of various insurance companies. Our ability to collect on our current or future claims and to obtain insurance at a price acceptable to us may be adversely affected by such general financial conditions, which are beyond our control.

Our operations also entail significant operating risks.

Our drilling activities involve risks, such as drilling non-productive wells or dry holes, which are beyond our control. The cost of drilling and operating wells and of installing production facilities and pipelines is uncertain. Cost overruns are common risks that often make a project uneconomical. The decision to purchase and to exploit a property depends on the evaluations made by our reserve engineers, the results of which are often inconclusive or subject to multiple interpretations. We may also decide to reduce or cease our drilling operations due to title problems, weather conditions, noncompliance with governmental requirements or shortages and delays in the delivery or availability of equipment or fabrication yards.

We may not be able to effectively market our oil and natural gas production.

We may encounter difficulties in the marketing of our oil and natural gas production. Effective marketing depends on factors such as the existing market supply and demand for oil and natural gas and the limitations imposed by governmental regulations. The proximity of our reserves to pipelines and the available capacity of such pipelines and other transportation, processing and refining facilities also affect our marketing efforts. Even if we discover hydrocarbons in commercial quantities, a substantial period of time may elapse before we begin commercial production. If pipeline facilities in an area are insufficient, we may have to wait for the construction or expansion of pipeline capacity before we can market production from that area. Another risk lies in our ability to negotiate commercially satisfactory arrangements with the owners and operators of production platforms in close proximity to our wells. Also, natural gas wells may be shut in for lack of market demand or because of the inadequate capacity or unavailability of natural gas pipelines or gathering systems.

We are dependent on other operators who influence our productivity.

We have limited influence over the nature and timing of exploration and development on oil and natural gas properties we do not operate, including limited control over the maintenance of both safety and environmental standards. In 2008, 4% of our production and 17% of our reserves were outside operated. The operators of those properties may:

	•		refuse to initiate exploration or development projects (in which case we may propose desired exploration or development activities);
	•		initiate exploration or development projects on a slower schedule than we prefer; or
	•		drill more wells or build more facilities on a project than we can adequately finance, which may limit our participation in those projects or limit our percentage of the revenues from those projects.

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.

Our working interest owners may face cash flow and liquidity concerns.

If oil and natural gas prices remain at present levels or decline further, many of our working interest owners may experience liquidity and cash flow problems. These problems may lead to their attempting to delay the pace of drilling or project development in order to conserve cash. Any such delay may be detrimental to our projects. Some working interest owners may be unwilling or unable to pay their share of the project costs as they become due. A working interest owner may declare bankruptcy and refuse or be unable to pay its share of the project costs and we would be obligated to pay that working interest owner’s share of the project costs.

Our drilling projects are based in part on seismic data, which is costly and cannot ensure the commercial success of the project.

Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies require greater predrilling expenditures than traditional drilling strategies, resulting in higher finding costs. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from exploration activities could have a material adverse effect on our future cash flows, ability to replace reserves and results of operations.

Our inability to acquire or integrate acquired companies or to develop new exploration prospects may inhibit our growth.

From time to time and under certain circumstances, our business strategy may include acquisitions of businesses that complement or expand our current business and acquisition and development of new exploration prospects that complement or expand our prospect inventory. We may not be able to identify attractive acquisition or prospect opportunities. Even if we do identify attractive opportunities, we may not be able to complete the acquisition of the business or prospect or to do so on commercially acceptable terms. If we do complete an acquisition, we must anticipate difficulties in integrating its operations, systems, technology, management and other personnel with our own. These difficulties may disrupt our ongoing operations, distract our management and employees and increase our expenses. Even if we are able to overcome such difficulties, we may not realize the anticipated benefits of any acquisition. Furthermore, we may incur additional debt or issue additional equity securities to finance any future acquisitions. Any issuance of additional securities may dilute the value of shares currently outstanding.

Terrorist attacks and threats or actual war may negatively affect our business, financial condition and results of operations.

Our business is affected by general economic conditions and fluctuations in consumer confidence and spending, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Terrorist attacks against U.S. targets, as well as events occurring in response to or in connection with them, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions impacting our suppliers or our customers, may adversely impact our operations. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. These occurrences could have an adverse impact on energy prices, including prices for our natural gas and crude oil production. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any or a combination of these occurrences could have a material adverse effect on our business, financial condition and results of operations.

Forward-Looking Information

From time to time, we may make certain statements that contain “forward-looking” information as defined in the Private Securities Litigation Reform Act of 1995 and that involve risk and uncertainty. These forward-looking statements may include, but are not limited to exploration and seismic acquisition plans, anticipated results from current and future exploration prospects, future capital expenditure plans, anticipated results from third party disputes and litigation, expectations regarding compliance with our credit facility, the anticipated results of wells based on logging data and production tests, future sales of production, earnings, margins, production levels and costs, market trends in the oil and natural gas industry and the exploration and development sector thereof, environmental and other expenditures and various business trends. Forward-looking statements may be made by management orally or in writing including, but not limited to, this Risk Factors section, the Management’s Discussion and Analysis of Financial Condition and Results of Operations section and other sections of this report and our other filings with the Securities and Exchange Commission under the Securities Act of 1933, as amended, and the Securities Exchange Act of 1934, as amended.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties

Producing Properties

For information regarding Meridian’s properties, see “Item 1. Business” above.

Item 3. Legal Proceedings

H. L. Hawkins litigation. In December 2004, the estate of H.L. Hawkins filed a claim against Meridian for damages “estimated to exceed several million dollars” for Meridian’s alleged gross negligence, willful misconduct and breach of fiduciary duty under certain agreements concerning certain wells and property in the S.W. Holmwood and E. Lake Charles Prospects in Calcasieu Parish in Louisiana, as a result of Meridian’s satisfying a prior adverse judgment in favor of Amoco Production Company. Mr. James Bond had been added as a defendant by Hawkins claiming Mr. Bond, when he was General Manager of Hawkins, did not have the right to consent, could not consent or breached his fiduciary duty to Hawkins if he did consent to all actions taken by Meridian. Mr. James T. Bond was employed by H.L. Hawkins Jr. and his companies as General Manager until 2002. He served on the Board of Directors of the Company from March 1997 to August 2004. After Mr. Bond’s employment with Mr. Hawkins, Jr., and his companies ended, Mr. Bond was engaged by The Meridian Resource & Exploration LLC as a consultant. This relationship continued until his death. Mr. Bond was also the father-in-law of Michael J. Mayell, the Chief Operating Officer of the Company at the time. 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 the Louisiana First Court of Appeal declined to hear Meridian’s writ requesting the court overturn Judge Bates’ ruling. Meridian has filed a motion with Judge Bates asking that she make her ruling a final judgement which would give Meridian the right to appeal now. The Hawkins interests have opposed this motion. 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 December 31, 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 December 31, 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 (together, “Shell”) have demanded contractual indemnity and defense from Meridian based upon the terms of the acquisition agreements 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. On December 9, 2008 Shell sent Meridian a letter reiterating its demand for indemnity. Shell has not to date produced supporting documentation for its claim. Meridian denies that it owes any indemnity under the acquisition agreements; however, the amounts claimed are substantial in nature and if adversely determined, would have a material adverse effect on the Company. 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 December 31, 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.

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

No matters were submitted to a vote of Meridian’s security holders during the fourth quarter of 2008.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

Price Range of Common Stock and Dividend Policy

Our common stock is traded on the New York Stock Exchange under the symbol “TMR.” The following table sets forth, for the periods indicated, the high and low sale prices per share for the common stock as reported on the New York Stock Exchange:

		High				Low
2008:
First quarter		$	1.86			$	1.36
Second quarter			3.09				1.49
Third quarter			3.21				1.82
Fourth quarter			1.81				.56
2007:
First quarter		$	3.01			$	2.28
Second quarter			3.38				2.31
Third quarter			3.08				2.24
Fourth quarter			2.58				1.63

The closing sale price of the common stock on March 3, 2009, as reported on the New York Stock Exchange Composite Tape, was $0.15. As of March 4, 2009, we had approximately 712 shareholders of record.

On December 4, 2008, the Company received notification from the New York Stock Exchange that the Company had fallen below the continued listing criteria which requires a minimum average closing price of $1.00 per share over 30 consecutive trading days. The NYSE has suspended the minimum price requirement on a temporary basis, initially through June 30, 2009. The Company’s business operations, credit agreements, other debt obligations and Securities and Exchange Commission reporting requirements, are unaffected by this notification. The Company’s common stock remains listed on the NYSE under the symbol “TMR,” but the NYSE has assigned a “.BC” indicator to the symbol to denote that the company is below compliance for continued listing requirements.

In addition to the Company’s non-compliance with the listing criteria related to minimum average closing price, the Company is currently monitoring its compliance with another listing criteria. This criteria requires that average market capital over 30 consecutive trading days must be at least $15 million. Based on shares currently outstanding, the Company’s average market capital decreases below this level when the stock price drops below approximately $0.16 per share. Some closing prices in the first quarter of 2009 have been below this price.

Meridian has not paid cash dividends on its common stock and does not intend to pay cash dividends on its common stock in the foreseeable future. We currently intend to retain our cash for the continued development of our business, including exploratory and development drilling activities. We also are currently restricted under our senior secured credit facility from paying any cash dividends on common stock, and for amounts we may spend for purchase of shares of common stock over $5 million per year, without the prior consent of the lenders. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results Operations — Liquidity and Capital Resources.”

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth information as of December 31, 2008, with respect to our compensation plans (including individual compensation arrangements) under which equity securities are authorized for issuance:

Number of securities

remaining available for

Number of securities to

Weighted-average

future issuance under

be issued upon exercise

exercise price of

equity compensation plans

of outstanding options,

outstanding options,

(excluding securities

Plan Category

warrants and rights

warrants and rights

reflected in column (a))

(a)

(b)

(c)

Equity compensation plans approved by security holders

4,024,044

$

2.66

3,970,000

Equity compensation plans not approved by security holders

—

—

—

Total

4,024,044

$

2.66

3,970,000

Item 6. Selected Financial Data

All financial data should be read in conjunction with our Consolidated Financial Statements and related notes thereto included in Item 8 and elsewhere in this report.

		Year Ended December 31,
		2008				2007				2006				2005				2004
		(In thousands, except prices and per share information)
A. Summary of Operating Data
Production:
Oil (MBbls)			765				838				859				882				1,270
Natural gas (MMcf)			9,369				13,239				18,170				20,490				27,839
Natural gas equivalent (MMcfe)			13,958				18,269				23,323				25,781				35,457
Average prices:
Oil ($/Bbl)		$	83.18			$	64.70			$	55.73			$	39.29			$	28.40
Natural gas ($/Mcf)			9.07				7.29				7.77				7.84				5.98
Natural gas equivalent ($/Mcfe)			10.65				8.25				8.11				7.57				5.71
B. Summary of Operations
Total revenues		$	149,165			$	152,178			$	190,957			$	195,696			$	203,118
Depletion and depreciation			72,072				77,076				106,067				97,354				102,915
Net earnings (loss)(1)			(209,886	)			7,137				(73,884	)			27,849				29,248
Net earnings (loss) per share:(1)
Basic		$	(2.30	)		$	0.08			$	(0.84	)		$	0.33			$	0.41
Diluted			(2.30	)			0.08				(0.84	)			0.31				0.37
Dividends per:
Common share		$	—			$	—			$	—			$	—			$	—
Redeemable preferred share			—				—				—				2.60				8.50
Preferred share			—				—				—				—				—
Weighted average common shares outstanding — basic			91,382				89,307				87,670				84,527				72,084
C. Summary Balance Sheet Data
Total assets		$	304,575			$	483,775			$	467,895			$	555,802			$	513,274
Long-term obligations, inclusive of current maturities			103,849				75,000				75,000				75,000				75,129
Redeemable preferred stock			—				—				—				—				31,589
Stockholders’ equity			122,511				325,430				320,797				377,565				316,041

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General

Meridian is an independent oil and natural gas company that explores for, acquires and develops oil and natural gas properties utilizing 3-D seismic technology. Our operations have historically been focused on the onshore oil and natural gas regions in south Louisiana, the Texas Gulf Coast and offshore in the Gulf of Mexico. In recent years, the Company’s goal has been to replace our reserves, and to strengthen our reserve base with longer lived properties from our new areas for exploration. Increases in the prices of oil and natural gas over the past several years have favorably impacted our earnings from operations and enabled us to increase exploration efforts, and our capital spending has increased.

However, recent economic developments, most importantly the precipitous decrease in the prices of oil and natural gas in the second half of 2008, have necessitated that we reduce capital investment and revise our short term focus. While our long-term objective has not changed, our short term goals currently focus on maintaining and improving production, increasing working capital through property sales, and conserving cash through cost saving measures.

The following discussion points are organized around the issues upon which our management is most highly focused, as well as the industry conditions that most influence our performance; the discussion contains information relating to the past year’s performance as well as to our present circumstances and expectations for the coming fiscal year. Following that discussion, we provide the customary year to year analysis of our results of operations, and an expanded review of our liquidity.

Industry and economic conditions. The oil and gas industry has experienced significant volatility in the past year. After several years of rising demand, costs of exploration and development had risen in tandem with the prices for energy products. These economic trends encouraged exploration in more marginal areas at higher costs. However, in the second half of 2008, energy prices dropped precipitously. West Texas Intermediate traded on the spot market at approximately $145 per Bbl in July; by December 31, 2008, the price was approximately $40 per Bbl. Natural gas similarly reached a spot market high in July 2008 of over $13 per mmbtu, but by year-end was trading at approximately $6 per mmbtu.

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 global economic recession, continue to limit credit availability. Typically, as is the case with Meridian, exploration and production companies borrow against the value of their proved reserves. When the market value of those reserves decreases due to energy price fluctuations, their ability to borrow declines; coupled with the recently tightened credit environment, exploration and production companies are experiencing a significant loss of credit availability, and Meridian is no exception.

The decrease in oil and natural gas prices has also caused operating cash flows to decline across the industry and at Meridian; coupled with the loss of credit access, companies’ cash resources may be extremely stressed.

Credit agreements. Commodity prices are a significant factor in the determination of the borrowing base available to the Company under our Credit Facility. Recently, the Company’s access to capital was restricted by a reduction in the borrowing base, and our ability to fund capital expenditures has significantly decreased. In December 2008, the borrowing base was reduced to equal the amount already outstanding, leaving no additional credit available. This impacts the Company’s capital spending plans and our ability to replace reserves.

As explained under Item I, General — Recent Developments, we are in default under certain covenants under the terms of our Credit Facility, and although our lenders have not responded with a notice of exercise of remedies, they may. Similarly, we are also in default under the terms of our rig note, which may also be declared in default by the lenders. Under each of these debt agreements, the lenders may accelerate all interest and

principal payments in the event of default. Accordingly, we have classified the $95 million of debt outstanding under the credit facility at December 31, 2008, as well as the $8.8 million rig note, as current in the accompanying consolidated balance sheet as of December 31, 2008.

In addition, the borrowing base under our Credit Facility is scheduled for the next redetermination as of April 30, 2009. The lenders may set the base at a level below outstanding borrowings. In that case, the Company would be required to repay the deficit within 90 days.

As of December 31, 2008, our net working capital reflects a deficit of approximately $109.3 million, which includes $103.8 million of amounts due under these two debt agreements which have been reclassified as current as a result of the defaults noted above.

Cash preservation and strict management of cash flow are currently our highest priorities. We are currently pursuing a number of options to raise cash by selling non-strategic properties on reasonable terms, as well as reducing our ownership in some of our core properties. Our intent is to maintain ownership in our core production areas of south Louisiana and East Texas. See “Item 1, General — Current Plans” for more detailed information on our current plans.

Reserves. Our management has always focused on our reserve base, both the volume of proved reserves and the value of our future net revenues, which we calculate following SEC rules using the prices prevailing at the end of the period. During 2008, our total proved reserves decreased 10.2 Bcfe, due to production and because downward revisions exceeded total reserves added through discoveries, extensions, and positive revisions. We concentrated drilling efforts in 2008 on the East Texas Austin Chalk gas play. Although results there were generally encouraging, with seven new producing wells in 2008, performance of wells drilled in the Chalk in 2007 failed to reach expectations and some of our plans for development are considered uneconomic at current prices. These factors affected reserves by contributing negative revisions and decreasing the contribution of economic reserves from new discoveries.

Prices for oil and natural gas. Our revenues, operating profits, property impairment expense, and access to credit are all significantly impacted by the price of oil and natural gas. Prices also strongly influence our drilling programs, impacting the economic projections for proposed exploration and development activity.

While we received historically high average prices for oil and natural gas in 2008, by year-end our expected oil price, as utilized in our reserve estimates, had decreased approximately 47% from the average received in 2008. Similarly, our expected natural gas price decreased approximately 36% from the average received in 2008. The prices used in our reserve report are based on the prices prevailing at December 31, 2008; since that date, energy prices have continued to be extremely volatile, showing generally further declines.

Our estimated present value of future net revenues (before tax) from oil and natural gas at December 31, 2008 is $179.4 million, a decrease of $235.5 million, or 57%, from the value one year earlier. The decrease is due to both the 10.2 Bcfe decrease in reserves explained above, and the decrease in prices used to compute the value of our reserves. At December 31, 2007, the price per Mcfe used in computing future net revenues was $9.32; at December 31, 2008 it was $6.11 per Mcfe, or 34% lower.

Ceiling test. The carrying value of our oil and natural gas properties are limited according to SEC full cost accounting rules to the present value of our future net revenues from oil and natural gas (the “ceiling test”). Due to the decrease in prices at year-end, as well as to the decrease in our reserves, we recorded a significant non-cash impairment, or ceiling test write-down, to our oil and natural gas properties of $216.8 million. The impairment was also necessitated by the changed economics of our drilling program; a majority of our exploration efforts in the East Texas Austin Chalk were predicated on an expectation of higher natural gas prices than those we now expect to receive, and many of our newer wells were drilled when drilling costs had increased in tandem with increases in energy prices. We have curtailed our exploration and development plans for these economic reasons, as well as due to cash constraints, and the future value of our reserves accordingly reflects the reduction in the volume of undeveloped reserves. However, the most significant

factors necessitating the ceiling test write-down were the decreases in prices and reserves, which directly decrease the ceiling.

Based on the continued volatility of energy prices since December 31, 2008, and the trend toward price decreases, Meridian may have an additional non-cash impairment in the first quarter of 2009.

Production. Management closely monitors production. Results for 2008 reflect a decline in production of 24% overall, primarily in the production of gas. This is the result of natural production declines in our mature south Louisiana properties.

Management team and non-routine contract settlement expenses.. During 2008, we settled the compensation contracts for our former Chief Executive Officer, Mr. Joseph A. Reeves, and our former Chief Operating Officer and President, Mr. Michael J. Mayell. The settlement resulted in a significant cash charge of $9.9 million to general and administrative expense, terminating all obligations under these contracts. In addition, we terminated the deferred compensation plan under which Messrs. Reeves and Mayell had received stock rights in lieu of cash compensation for many years. The termination resulted in issuance of approximately 3.5 million new shares of common stock, and a cash payment of approximately $3.0 million in lieu of stock for personal withholding taxes related to the stock issuance. Messrs. Reeves and Mayell remain on our Board of Directors, and will provide professional services to the Company under short-term consulting contracts that terminate on April 30, 2009.

Expenses. In addition to the non-routine contract settlement expense in 2008, we recorded approximately $1.7 million in compensation expense, net of capitalization, for employee retention bonuses. See Note 12 of Notes to Consolidated Financial Statements included herein for further information about this incentive plan for non-executive employees. This non-routine item has increased our expenses in 2008, but will have a lesser expense impact in 2009 (approximately $0.5 million expected in the first quarter of 2009); however, the cash impact will be greater in 2009 due to the second payment of approximately $2.9 million due March 31, 2009.

We have taken steps in early 2009 to reduce our annual expenses, both in the field and in the office. We reduced our staff by approximately 25 people, or 27%. The severance expense for the employees will be recorded in the first quarter of 2009, and will eliminate the retention incentive bonus they would otherwise have received (and is included in the $0.5 million expected expense mentioned above). The majority of the reduction was in our Houston office. We also have made changes to certain field operations that are also expected to yield cost savings. We will continue to review all expenses for additional opportunities for savings.

Drilling rig obligations. Although baseline field expenses are expected to decline during 2009, potential cash expenditures related to drilling obligations are expected to continue to be significant. During 2007, in order to ensure access to a drilling rig with the technical specifications appropriate to our drilling program, we committed to purchase a drilling rig. At the time, such rigs were in high demand, and as a result of this demand, our drilling program was faced with delays and increased costs. The purchased rig was largely constructed in 2007, and was placed in service near the end of the first quarter of 2008, at a total cost of $13.7 million.

We do not operate the rig; we lease the rig to Orion Drilling Company, LP (“Orion”). Orion pays us a monthly rental fee based on 50% of the monthly net profits of rig operation. The lease of the rig to Orion runs concurrently with a dayrate contract we have entered, under which Orion operates the rig. Each agreement is for twenty-four months terminating in March, 2010. Pursuant to our dayrate contract with Orion, we are obligated to pay the dayrate regardless of any inability to use the rig which may arise. When the rig is not in use on our wells, Orion may contract it to third parties, or the rig may be idled. Orion has been cooperative in actively seeking other parties to use the rig, and in agreeing to credit our obligation to some extent, based on revenues from other parties who utilize the rig when the Company is unable to. The rig was used continuously during 2008 in our East Texas drilling efforts; during the first quarter of 2009, the rig has

been effectively subleased to others, but for short duration, at rates which are less than the dayrate under our contract. We are obligated for the difference in dayrates. We cannot predict whether such use by third parties will be consistent, nor to what extent it may offset our obligations under the dayrate contract.

We have an additional drilling rig commitment with Orion for a second rig, which we do not own; this is also a dayrate contract, which will terminate in February, 2011. We have used this rig continuously in our east Texas drilling program, and it is currently drilling one well which was in progress at December 31, 2008. We have no firm plans to utilize the rig once this well is complete, and have requested that Orion assist us in reducing our obligation under the same understanding as the owned rig described above. That is, we have requested that Orion utilize the rig on other projects and credit our contractual obligation based on this third party usage.

These obligations impact our drilling plans as well as critical cash flow projections for the coming months. If the rigs are idled, or if Orion is unable to fully credit the commitment under our dayrate drilling contracts when the rigs are utilized by third parties, we will incur losses which cannot be capitalized as part of the cost of oil and natural gas properties.

The market for drilling rigs deteriorated in the second half of 2008 in tandem with prices for oil and natural gas. Our rig, which includes a top-drive, is a well-equipped, long-lived asset and nearly new. While we believe it retains value, utilization in the short-term is uncertain, and dayrates have decreased. Based on the economic information available to us, and using conservative estimates of utilization and dayrates, we estimated the present value of the rig at $5.5 million as of December 31, 2008. Accordingly, in the fourth quarter of 2008, we recorded a non-cash impairment expense of $6.7 million to write down the net book value of the rig to $5.5 million. Due to the continued volatility in the prices of oil and natural gas, and its negative effect on the drilling industry, we will continue to review this asset for additional impairment. We cannot predict whether additional impairment will be necessary.

Exploration commitment. The Company has an exploration commitment under a contract regarding exploration in an area which management no longer believes has potential. The commitment totals $2.7 million and is due in the third quarter of 2009. It was recorded as a current liability and included in our full cost pool before impairment.

Tax Rate. Our effective income tax rate has varied significantly in the past several years. During periods of profitability, the effective rate was approximately 38-44%, which is greater than the corporate income tax rate of 35% primarily due to state taxes and other permanent differences. In 2008, we recorded a significant loss due to the non-cash impairment expense described above; the tax benefit to the Consolidated Statement of Operations resulting from the loss was limited to $8.4 million, which is the amount of our deferred tax liabilities at December 31, 2007. We limited the tax benefit by recording a valuation allowance against the deferred tax assets resulting from the 2008 net loss because management believes, given our overall current financial position, that there are significant uncertainties regarding our ability to generate net profits in the near term.

Thus the 4% effective income tax rate for 2008 is anomalous. Future effective tax rates will be reduced by the exhaustion of the valuation allowance over time. The total valuation allowance is $64.6 million.

Tax audit. In the fourth quarter of 2008, we were notified by the Internal Revenue Service that Meridian would be audited for fiscal years 2006 and 2007. We have engaged tax consultants to assist us in cooperating with the audit, which has progressed satisfactorily, although we cannot predict the outcome of the audit.

Operations Overview

During 2008, we achieved several goals in the areas of drilling success, production rates, favorable hedges, drilling cost reductions and prospect development.

Meridian participated in, drilled or recompleted 18 successful wells, eight in East Texas Austin Chalk, nine in South Louisiana, and one in Texas offshore. We managed to maintain roughly flat production levels by offsetting our fields’ 20-30% decline rates, and to enhance our 2008 and 2009 cash flow with favorable hedges. Drilling cost for wells in East Texas were reduced by approximately 20% compared to wells drilled in 2007. We moved out of some uneconomic areas (New Albany Shale, Palo Duro Basin, Oklahoma and Delaware Basin) and have generated several promising prospects in the Atchafalaya Bay and Barataria Bay areas by optimizing our well developed in-house seismic databases and technical team. Like many of our peers, Meridian was also forced to deal with several challenges. Those challenges included production interruptions from two hurricanes and severe commodity price swings that required us to report a non-cash ceiling test impairment as well as negative revisions to proved reserves.

The two areas in which Meridian was most active in 2008 were East Texas and South Louisiana.

East Texas Austin Chalk

During 2008 Meridian participated in nine wells in the East Texas Austin Chalk area, including seven successful completions, and two wells still drilling or under evaluation as of December 31, 2008. The successful wells include:

Blackstone Minerals A-917 No. 1H — tested at gross daily flow rates of up to 7.0 Mmcfe/d

Black Stone Minerals No. 5 — tested at gross daily flow rates of up to 18.1 Mmcfe/d

Freeman No. 1 — tested at gross daily flow rates of up to 16.7 Mmcfe/d

Blackstone Minerals A-507 No. 1 — tested at gross daily flow rates of up to 57 Mmcfe/d

Davis A-388 No. 1 — tested at gross daily flow rates of up to 38 Mmcfe/d

Blackstone Minerals A-507 No. 2 — tested at gross daily flow rates of up to 27.3 Mmcfe/d

Sutton A-574 No. 1 — tested at gross daily flow rates of up to 35.4 Mmcfe/d.

The key to being successful in this area is our focus on strict management of drilling and completion costs and leveraging our large acreage position through development drilling.

South Louisiana

During 2008 Meridian recompleted or drilled nine wells in the Company’s legacy asset areas of South Louisiana. The successful wells include:

Goodrich Cocke No. 7 — gross daily flow rate of 650 Bopd

Avoca 8 No.1 — gross daily flow rate of 2.6 Mmcfe/d

Myles Salt No. 27 — gross daily flow rate of 2.1 Mmcfe/d

CL&F B1 — gross daily flow rate of 700 Mcfe/d

CL&F C1 — gross daily flow rate of 900 Mcfe/d

Goodrich-Cocke No. 6 ST — gross daily flow rate of 2500 Bopd

Myles Salt No. 31 — gross daily flow rates of 300 Bopd

Myles Salt No. 46 — gross daily flow rate of 330 Bopd

Weeks Bay No. 15 — tested at a gross daily flow rate of 685 Bopd

South Louisiana remains a core area for near term and long term upside for Meridian. Weeks Island field is the Company’s largest oil field and continues to provide us additional opportunities from new well locations, sidetracks and development drilling. We are evaluating our reprocessed 3-D seismic data over Weeks Island

and other regions of South Louisiana. The re-processed and newly acquired 3-D data has enhanced our generation of lower to moderate risk new projects in this core area where we are already active and have operations and production facilities in place. We anticipate drilling and recompletion activity in this area during 2009, primarily in the Weeks Island and Biloxi Marshland areas.

South Texas

Levering off the knowledge and experience gained in the East Texas Austin Chalk, we expanded beyond its currently established boundaries to potentially explore and test acreage located in the south-central Texas counties of Karnes and Lavaca. Last year, Meridian built a 30,000 acre leasehold position where we anticipate that potential production will have a higher oil content than our current production in the initial wells in East Texas. Our leases are still in their primary term; due to constraints on our capital budget, management plans to observe the exploration results of other operators during 2009, in order to gain additional geological and operational information about this play.

Capital Expenditure Plans for 2009. The Company anticipates the 2009 capital spending budget will be primarily used for recompletions and similar work on existing properties, and for lease maintenance costs. We anticipate that the budget will be significantly lower than in past years, reflecting our expectations of reduced cash flows due to commodity price declines and the loss of availability of funds under the Credit Facility. These factors will significantly impact funds available for capital spending. We currently anticipate funding the 2009 plan utilizing cash flow from operations and cash on hand, augmented by proceeds from sales of assets as possible.

Results of Operations

Year Ended December 31, 2008, Compared to Year Ended December 31, 2007

Revenue.

Oil and natural gas revenues, which include oil and natural gas hedging activities (see Note 13 of Notes to Consolidated Financial Statements included elsewhere herein), during the twelve months ended December 31, 2008, decreased $2.1 million (1%) to $149.2 million, as compared to 2007 revenues of $152.2 million, due to a 24% decrease in production volumes primarily from natural production declines, partially offset by a 29% increase in average commodity prices on a natural gas equivalent basis and new discoveries brought on between the comparable periods. Our average daily production decreased to 38.1 MMcfe for 2008 from 50.1 MMcfe during 2007. Oil and natural gas production volume totaled 13,958 MMcfe for 2008, compared to 18,269 MMcfe for 2007. During 2008, the Company’s drilling activity was primarily focused in the East Texas project area and the Terrebonne Parish area of South Louisiana. During 2008, the Company drilled or participated in the drilling of 22 wells of which 14 wells were completed, representing a 64% success rate. The following table summarizes Meridian’s operating revenues, production volumes and average sales prices for the years ended December 31, 2008 and 2007.

		Year Ended
		December 31,								Increase
		2008				2007				(Decrease)
Production:
Oil (MBbls)			765				838				(9	%)
Natural gas (MMcf)			9,369				13,239				(29	%)
Natural gas equivalent (MMcfe)			13,958				18,269				(24	%)
Average Sales Price:
Oil (per Bbl)		$	83.18			$	64.70				29	%
Natural gas (per Mcf)			9.07				7.29				24	%

		Year Ended
		December 31,								Increase
		2008				2007				(Decrease)
Natural gas equivalent (per Mcfe)			10.65				8.25				29	%
Operating Revenues (000’s):
Oil		$	63,636			$	54,218				17	%
Natural gas			84,998				96,491				(12	%)
Total		$	148,634			$	150,709				(1	%)

Operating Expenses.

Oil and natural gas operating expenses on an aggregate basis decreased $4.1 million (14%) to $24.3 million in 2008, compared to $28.3 million in 2007. On a unit basis, lease operating expenses increased $0.19 per Mcfe to $1.74 per Mcfe for the year 2008 from $1.55 per Mcfe for the year 2007. Oil and natural gas operating expenses decreased between the periods primarily due to lower insurance and workover costs; in addition, some fields were shut-in during the third and fourth quarters of 2008 due to hurricane damage. The increase in the per Mcfe rate was attributable to the lower production between the two corresponding periods.

Severance and Ad Valorem Taxes.

Severance and ad valorem taxes increased $0.3 million (3%) to $9.7 million in 2008, compared to $9.4 million in 2007, primarily because of an increase in the average price of oil. 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 (effective July 1, 2008) for natural gas. Generally in 2008, although total revenue was flat, a larger proportion was generated from oil, for which severance taxes are computed on a percentage basis. Natural gas taxes are based on a per mcf rate which on average did not significantly change. On an equivalent unit of production basis, severance and ad valorem taxes increased to $0.70 per Mcfe for 2008 from $0.52 per Mcfe for 2007. The effective severance tax rate for oil is significantly higher than that for natural gas, particularly when natural gas prices are trending higher, as they were throughout a good portion of 2008; thus the change in the mix of revenues and volumes toward more oil increased the effective tax rate, which is reflected in the per unit costs.

Depletion and Depreciation.

Depletion and depreciation expense decreased $5.0 million (6%) during 2008 to $72.1 million compared to $77.1 million for 2007. This was primarily the result of a 24% decrease in production volumes in 2008 compared to 2007, partially offset by an increase in the depletion rate compared to 2007. On a unit basis, depletion and depreciation expenses increased to $5.16 per Mcfe for 2008, compared to $4.22 per Mcfe for 2007. Depletion and depreciation expense on a per Mcfe basis increased primarily due to capital costs.

Impairment of Long-Lived Assets.

A decline in oil and natural gas prices as of December 31, 2008, resulted in the Company recognizing a non-cash impairment totaling $216.8 million of its oil and natural gas properties under the full cost method of accounting. In addition, we recorded impairment expense of $6.7 million on our drilling rig. See Note 4 of Notes to Consolidated Financial Statements included elsewhere herein, for additional information.

General and Administrative Expense.

General and administrative expenses, which are net of costs capitalized in our oil and natural gas properties (see Note 20 of Notes to Consolidated Financial Statements included elsewhere herein), increased $2.8 million (17%) to $19.1 million in 2008 compared to $16.2 million for the year 2007, primarily due to the cost of a retention bonus program for non-executive employees, and to a contract settlement with a former employee. (See Note 12 of Notes to Consolidated Financial Statements). On an equivalent unit of production basis, general and administrative expenses increased $0.47 per Mcfe to $1.36 per Mcfe for 2008 compared to $0.89 per Mcfe for 2007.

Contract Settlement Expense.

Contract settlement expense of $9.9 million was recorded in the second quarter of 2008 when the employment contracts of certain executive officers were replaced and certain other agreements governing other elements of their compensation packages were settled. There was no contract settlement expense recorded in 2007. See further information in Note 12 of Notes to Consolidated Financial Statements.

Accretion Expense.

In accordance with the Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 143”) the Company records long-term liabilities representing the discounted present value of the estimated asset retirement obligations with offsetting increases in capitalized oil and natural gas properties. This liability will continue to be accreted to its future value in subsequent reporting periods. The Company recorded accretion expense of $2.1 million and $2.2 million in 2008 and 2007, respectively. The slight decrease in 2008 levels in comparison to 2007 is primarily the result of revisions to estimated abandonment costs and actual abandonments, offset by additional wells drilled and placed on production during the year.

Hurricane Damage Repairs.

Hurricane damage repairs of $1.5 million were recorded in 2008 for hurricanes Ike and Gustav, primarily related to the Company’s insurance deductibles for each storm. There were no hurricane damage repairs recorded in 2007.

Interest Expense.

Interest expense decreased $0.7 million (11%) to $5.4 million in 2008 compared to $6.1 million for 2007. The decrease was primarily a result of decreased interest rates during 2008, partially offset by higher debt balances.

Taxes on Income.

Income tax expense for 2008 was a benefit of $8.5 million as compared to a provision of $5.7 million for 2007. Income taxes are generally provided on book income after taking into account permanent differences between book income and taxable income. The benefit for 2008 was primarily the result of the impairment of long-lived assets recognized during the fourth quarter of 2008. The effective tax rate of 44% in 2007 is typical of the rate experienced by the Company in a year without unusual items. The 2007 rate differs from the statutory corporate tax rate of 35% due to state income taxes, non-deductible expenses related to the basis of certain oil and natural gas properties acquired in years past, and non-deductible expenses. The effective tax rate of 4% in 2008 is the result of recording the impairment loss and the deferred tax asset valuation allowance. When there is uncertainty as to the ability to recover a deferred tax asset through future taxable income, no benefit can be recognized, and this was the case in 2008.

Year Ended December 31, 2007, Compared to Year Ended December 31, 2006

Oil and natural gas revenues, which include oil and natural gas hedging activities (see Note 13 of Notes to Consolidated Financial Statements included elsewhere herein), during the twelve months ended December 31, 2007, decreased $38.3 million (20%) as compared to 2006 revenues due to a 22% decrease in production volumes primarily from natural production declines, partially offset by a 2% increase in average commodity prices on a natural gas equivalent basis and new discoveries brought on between the comparable periods. Our average daily production decreased from 63.9 MMcfe during 2006 to 50.1 MMcfe for 2007. Oil and natural gas production volume totaled 18,269 MMcfe for 2007, compared to 23,323 MMcfe for 2006. During 2007, the Company’s drilling activity was primarily focused in the East Texas project area, the Oklahoma project area and the Terrebonne Parish area of South Louisiana. During 2007, the Company drilled or participated in the drilling of 25 wells of which 13 wells were completed, representing a 52% success rate. The following table summarizes Meridian’s operating revenues, production volumes and average sales prices for the years ended December 31, 2007 and 2006.

		Year Ended
		December 31,								Increase
		2007				2006				(Decrease)
Production:
Oil (MBbls)			838				859				(2	%)
Natural gas (MMcf)			13,239				18,170				(27	%)
Natural gas equivalent (MMcfe)			18,269				23,323				(22	%)
Average Sales Price:
Oil (per Bbl)		$	64.70			$	55.73				16	%
Natural gas (per Mcf)			7.29				7.77				(6	%)
Natural gas equivalent (per Mcfe)			8.25				8.11				2	%
Operating Revenues (000’s):
Oil		$	54,218			$	47,859				13	%
Natural gas			96,491				141,182				(32	%)
Total		$	150,709			$	189,041				(20	%)

Operating Expenses.

Oil and natural gas operating expenses on an aggregate basis increased $5.7 million (25%) to $28.3 million in 2007, compared to $22.6 million in 2006. On a unit basis, lease operating expenses increased $0.58 per Mcfe to $1.55 per Mcfe for the year 2007 from $0.97 per Mcfe for the year 2006. Oil and natural gas operating expenses increased between the periods primarily due to significantly higher insurance costs, industry wide increases in service costs and increased maintenance-related activities. For the policy year beginning in May 2006 through April 2007, insurance premiums increased over 450% from the prior policy year. During 2007, insurance premiums increased by $2.2 million and represented 39% of the difference in lease operating expenses between the periods. During the second quarter of 2007 approximately $0.5 million was expensed due to a civil penalty arising from environmental litigation (see Note 7 to Consolidated Financial Statements). The remaining $3.0 million increase in operating expenses was associated with the addition and acquisition of producing wells and additional costs related to Biloxi Marshlands area production and facilities including compression, storage, and repairs. Although the Company’s insurance costs rose for the period from May 2006 through April 2007, the premium for the policy for May 2007 through April 2008 has decreased by approximately 30%. We continue to insure our assets with improved coverage as a safeguard against losses for the Company in the event of another hurricane. The increase in the per Mcfe rate was additionally attributable to the lower production between the two corresponding periods.

Severance and Ad Valorem Taxes.

Severance and ad valorem taxes decreased $1.9 million (16%) to $9.4 million in 2007, compared to $11.3 million in 2006, primarily because of a decrease in oil and natural gas production partially offset by a higher average natural gas tax rate. Meridian’s oil and natural gas production is primarily from Louisiana and is therefore subject to Louisiana severance tax. The severance tax rates for Louisiana are 12.5% of gross oil revenues and $0.269 per Mcf (effective July 1, 2007) for natural gas. For the first six months of 2007, and the last six months of 2006, the rate was $0.373 per Mcf for natural gas, an increase from $0.252 per Mcf for the first half of 2006. On an equivalent unit of production basis, severance and ad valorem taxes increased to $0.52 per Mcfe for 2007 from $0.48 per Mcfe for 2006.

Depletion and Depreciation.

Depletion and depreciation expense decreased $29.0 million (27%) during 2007 to $77.1 million compared to $106.1 million for 2006. This was primarily the result of a decrease in the depletion rate as compared to the 2006 period and the 22% decrease in production volumes in 2007 from 2006 levels. On a unit basis, depletion and depreciation expenses decreased to $4.22 per Mcfe for 2007, compared to $4.55 per Mcfe for 2006. Depletion and depreciation expense on a per Mcfe basis decreased primarily due to the impact of the impairment of long-lived assets during 2006 as referenced below.

Impairment of Long-Lived Assets.

A decline in oil and natural gas prices as of September 30, 2006, resulted in the Company recognizing a non-cash impairment totaling $134.9 million ($87.7 million after tax) of its oil and natural gas properties under the full cost method of accounting. Additionally, the effect of this write-down resulted in a decrease in the Company’s depletion rate for 2007, but the rate increased in 2008 due to capital costs. See Note 4 of Notes to Consolidated Financial Statements included elsewhere herein, for additional information.

General and Administrative Expense.

General and administrative expenses, which are net of costs capitalized in our oil and natural gas properties (see Note 20 of Notes to Consolidated Financial Statements included elsewhere herein), decreased $0.5 million (3%) to $16.2 million in 2007 compared to $16.7 million for the year 2006, primarily due to a decrease in professional services. On an equivalent unit of production basis, general and administrative expenses increased $0.18 per Mcfe to $0.89 per Mcfe for 2007 compared to $0.71 per Mcfe for 2006.

Accretion Expense.

In accordance with the Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 143”) the Company records long-term liabilities representing the discounted present value of the estimated asset retirement obligations with offsetting increases in capitalized oil and natural gas properties. This liability will continue to be accreted to its future value in subsequent reporting periods. The Company has charged approximately $2.2 million and $1.6 million to earnings as accretion expense during 2007 and 2006, respectively. The increase in 2007 levels in comparison to 2006 is primarily the result of additional wells drilled and placed on production during the year and revisions to estimated abandonment costs in the industry.

Hurricane Damage Repairs.

There were no hurricane damage repairs recorded in 2007, as compared to $4.3 million in 2006 related to damages incurred from the 2005 hurricanes Katrina and Rita, primarily related to the Company’s insurance deductible and repair costs in excess of insured values. Due to the extensive damage throughout the area and the limited resources available for repairs, significant cost increases were experienced by the industry. The actual repair costs were higher than originally estimated and exceeded our claim limits and therefore resulted in increased expense.

Interest Expense.

Interest expense increased $0.1 million (2%) to $6.1 million in 2007 compared to $6.0 million for 2006. The increase was primarily a result of increased interest rates during 2007.

Taxes on Income.

The provision (benefit) for income tax expense for 2007 was $5.7 million as compared to ($38.5 million) for 2006. Income taxes are generally provided on book income after taking into account permanent differences between book income and taxable income. The benefit for 2006 was primarily the result of the impairment of long-lived assets recognized during the third quarter of 2006. The effective tax rate of 44% in 2007 is typical of the rate experienced by the Company in a year without unusual items. The 2007 rate differs from the statutory corporate tax rate of 35% due to state income taxes, non-deductible expenses related to the basis of certain oil and natural gas properties acquired in years past, and non-deductible expenses. The effective tax rate of 35% for the net loss in 2006 is the result of the impairment loss recorded that year at a 35% benefit.

Liquidity and Capital Resources

Cash Flows. Net cash flow provided by operating activities was $92.8 million for the year ended December 31, 2008, as compared to $97.0 million for the year ended December 31, 2007, a decrease of $4.2 million or 4%, primarily due to funding $9.9 million of contract settlement expenses in 2008 for certain officers (see Note 12 of Notes to Consolidated Financial Statements included elsewhere herein) and lower oil and natural gas revenues primarily due to lower production, partially offset by changes in working capital accounts.

Net cash flows used in investing activities were $116.9 million for the year ended December 31, 2008, as compared to $113.6 million for the year ended December 31, 2007. This increase was due to higher expenditures for property and equipment in 2008.

Net cash flows provided by financing activities were $23.9 million for the year ended December 31, 2008, as compared to net cash flows used in financing activities of $1.3 million for 2007. Historically, the trend of our cash provision has been toward increasing use of our Credit Facility and other new debt (in thousands):

		2008				2007				2006
Cash provided by—
Operating activities		$	92,767			$	96,991			$	137,272
Net drawdown under credit facility			20,000				—				—
New debt for drilling rig			10,000				—				—
Sales of property			7,171				3,060				11,032
			129,938				100,051				148,304
Cash utilized in—
Additions to property and equipment			124,059				116,696				141,796
Repurchase of common stock			75				1,158				—
Reductions of drilling rig debt			1,150				—				—
			125,284				117,854				141,796
Other source (uses), net—			(4,826	)			(95	)			1,651
Net increase (decrease) in cash—		$	(172	)		$	(17,898	)		$	8,159

As noted above, we are in default under the terms of our Credit Facility, and our borrowing base is limited to the $95.0 million currently borrowed. This has also triggered an event of default under our rig note. The lenders under the rig note have been timely advised of the default under the Credit Facility and may respond with a declaration of default under the rig note. Under both these debt agreements, the creditors may accelerate all payments of principle and interest in response to an event of default, or they may elect to take other action. Thus far, neither lender has responded with a notice of any exercise of remedies. With credit markets extremely tight and the decrease in value of our proved reserves due to decreased energy prices, it is unlikely that supplemental credit sources will be available to us in the near term. In addition, the terms of our Credit Facility restrict our ability to engage in other borrowing transactions. At present, cash flows from operations and sales of property are our primary sources of cash.

We anticipate reduced cash from operations in 2009, due to the significant reduction in prices for oil and natural gas, and due to expected natural production declines, although we expect some offsets due to reduced general and administrative and field operations expenses. However, as described earlier, we have obligations under two long-term drilling contracts which may significantly impact operational cash flows. If we are unable to effectively sublease the two rigs continuously, or if the terms of agreements do not completely cover the commitment under our drilling contracts, we will incur negative cash flow under those contracts. We hope to limit such losses by utilizing the rigs in our own drilling as intended, but significant uncertainty exists regarding our capital expenditures for 2009 and forward. Reduction in capital spending is our first alternative after expense reductions to improve cash flow.

Cash Obligations. The following summarizes the Company’s contractual obligations at December 31, 2008, and the effect such obligations are expected to have on its liquidity and cash flow in future periods (in thousands):

		Less Than				1-3				After
		One Year				Years				3 Years				Total
Short and long term debt		$	105,624			$	—			$	—			$	105,624
Interest (6)			261				—				—				261
Drilling rigs (1) (2)			19,586				13,734				—				33,320
Drilling obligation (3)			2,666				—				—				2,666
Contract settlement obligation (4)			9,894				—				—				9,894
Retention incentive compensation plan (5)			2,946				—				—				2,946
Non-cancelable operating leases			2,170				3,700				—				5,870
Total contractual cash obligations		$	143,147			$	17,434			$	—			$	160,581

Current Credit Facility. On December 23, 2004, the Company amended the 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 PLC, RZB Finance LLC and Standards Bank PLC completed the syndication group. The initial borrowing base under the Credit

Facility was $130 million. The borrowing base under the Credit Facility was redetermined by the syndication group to be $115 million effective October 31, 2007.

The terms of the Credit Facility contain numerous covenants and restrictions. Currently, we are in default of a covenant which requires that we maintain a current ratio (as defined in the Credit Facility) of one to one. Our current ratio, as defined, is 0.76 at December 31, 2008. Presently, our lenders have been informed of our default under these covenants, and have not responded with a notice of any exercise of remedies. Among the remedies available to the lenders upon an event of default is acceleration of all principal and interest payments. Accordingly, we have classified all indebtedness under the Credit Facility, $95.0 million, in current liabilities on the accompanying Consolidated Balance Sheets. We cannot predict what action our lenders may take.

On February 21, 2008, the Company amended the 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 maturity date was extended to February 21, 2012, and the borrowing base was redetermined to be $110 million. Interest rates were slightly increased by increasing the range of the add-on to the prime base rate by 250 basis points on the lower end of the range and by 500 basis points on the higher end of the range; the range of the add-on to the alternative base rate was increased by 250 basis points on the higher end of the range.

On December 19, 2008, the Company entered into the Second Amendment to Credit Agreement to the Credit Facility (“Second Amendment”). The Second Amendment redetermined the borrowing base at $95 million, limiting borrowing to the amount outstanding at December 31, 2008. In addition, interest rates were increased by increasing the range of the add-on to the prime base rate by 500 basis points on the lower end of the range and by 750 basis points on the higher end of the range; the range of the add-on to the alternative base rate was increased by the same amounts.

The Credit Facility is subject to semi-annual borrowing base redeterminations on April 30 and October 31 of each year. In addition to the scheduled semi-annual borrowing base redeterminations, the Lenders or the Company have the right to redetermine the borrowing base at any time, provided that no party can request more than one such redetermination between the regularly scheduled borrowing base redeterminations. The determination of our borrowing base is subject to a number of factors, including quantities of proved oil and natural gas reserves, the banks’ price assumptions and other various factors unique to each member bank. Our Lenders can redetermine the borrowing base to a lower level than the current borrowing base if they determine that our oil and natural gas reserves, at the time of redetermination, are inadequate to support the borrowing base then in effect. In the event our then-redetermined borrowing base is less than our outstanding borrowings under the Credit Facility, we will be required to repay the deficit within a 90-day period.

Obligations under the Credit Facility are secured by pledges of outstanding capital stock of the Company’s subsidiaries and by a first priority lien on not less than 75% (95% in the case of an event of default) of its present value of proved oil and natural gas properties. In addition, the Company is required to deliver to the Lenders and maintain satisfactory title opinions covering not less than 70% of the present value of proved oil and natural gas properties. The Credit Facility also contains other restrictive covenants, including, among other items, maintenance of certain financial ratios, restrictions on cash dividends on common stock and under certain circumstances preferred stock, limitations on the redemption of preferred stock, limitations on repurchases of common stock, restrictions on incurrence of additional debt, and an unqualified audit report on the Company’s consolidated financial statements. The Company is in compliance with each of these covenants, with the exception of the requirement that we maintain a current ratio (as defined in the Credit Facility) of 1.0, and the requirement that we deliver an unqualified audit report on our consolidated financial statements. As of December 31, 2008, our current ratio, as defined, was 0.76. As a result of our current lack of financial liquidity, our independent registered public accounting firm has included a modification in its report on our consolidated financial statements included herein.

Under the Credit Facility, the Company may secure either (i) (a) an alternative base rate loan that bears interest at a rate per annum equal to the greater of the administrative agent’s prime rate; or (b) federal funds-based rate plus ¹/2 of 1%, plus an additional 1.25% to 2.50% 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 2.0% to 3.25%, depending on the ratio of the aggregate outstanding loans and letters of credit to the borrowing base. At December 31, 2008, the three-month LIBOR interest rate was 1.425%. The Credit Facility continues to provide 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 agreements. As of March 13, 2009, outstanding borrowing under the Credit Facility totaled $95.0 million.

Rig Note. On May 2, 2008, the Company, through its wholly owned subsidiary TMR Drilling Corporation (“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 purchased using cash on hand and funds available to the Company under the Credit Facility. Funds from the new agreement were used to reduce borrowing under the Credit Facility. The 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.

Our failure to comply with any of the restrictions and covenants under our Credit Facility results in a default under the facility, which results in an event of default under our rig note. The total balance outstanding under the rig note at December 31, 2008 is $8.8 million. The remedies available to CIT under the rig note include acceleration of all principal and interest payments. Accordingly, we have classified all indebtedness under the rig note, $8.8 million, in current liabilities on the accompanying Consolidated Balance Sheets at December 31, 2008.

Presently, CIT has been informed of our default under the covenants of the Credit Facility, and has not responded with a notice of any exercise of remedies. We cannot predict what action they may take.

Capital Expenditures. Capital expenditures in 2008 consisted of $117.6 million for property and equipment additions related to exploration and development of various prospects, including leases, seismic data acquisitions, production facilities, and related drilling and workover activities and property acquisitions.

The Company anticipates the 2009 capital spending budget will be primarily used for recompletions and similar work on existing properties, and for lease maintenance costs. We anticipate that the budget will be significantly lower than in past years, reflecting our expectations of reduced cash flows due to commodity price declines and the loss of availability of funds under the Credit Facility. These factors will significantly impact funds available for capital spending. We currently anticipate funding the 2009 plan utilizing cash flow from operations and cash on hand, augmented by proceeds from sales of assets as possible.

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.

Off-Balance Sheet Arrangements. None.

Share Repurchase Program. 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. As of December 31, 2008, availability under the Credit Facility was less than the required 20%, and repurchases have been suspended.

As of December 31, 2008, the Company had repurchased 535,416 common shares at a cost of $1,234,000, of which 501,300 shares have been issued for 401(k) contributions, for contract services, and for compensation. The program does not require the Company to repurchase any specific number of shares and may be modified, suspended or terminated at any time without prior notice. The Company does not expect to make share repurchases in the near term.

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 in the United States of America. The following summarizes several of our critical accounting policies. See a complete list of significant accounting policies in Note 2 of the notes to the consolidated financial statements included herein.

Use of Estimates. 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, and disclosure of contingent assets and liabilities, if any, at the date of the financial statements. Reserve estimates significantly impact depletion and potential impairments of oil and natural gas properties. The Company analyzes its estimates, including those related to oil and natural gas revenues, bad debts, oil and natural gas properties, derivative contracts, income taxes and contingencies and litigation. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements.

Property and Equipment. The Company follows the full cost method of accounting for its investments in oil and natural gas properties. All costs incurred with the acquisition, exploration and development of oil and natural gas properties, including unproductive wells, are capitalized. Under the full cost method of accounting, such costs may be incurred both prior to or after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion and equipment. Included in capitalized costs are general and administrative costs that are directly related to acquisition, exploration and development activities, and which are not related to production, general corporate overhead or similar activities. For the years 2008, 2007, and 2006, such capitalized costs totaled $17.4 million, $16.5 million, and $15.4 million, respectively. General and administrative costs related to production and general overhead are expensed as incurred.

Proceeds from the sale of oil and natural gas properties are credited to the full cost pool, except in transactions involving a significant quantity of reserves or where the proceeds received from the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss would be recognized.

Future development, site restoration, and dismantlement and abandonment costs, are estimated property by property based upon current economic conditions and are included in amortization of our oil and natural gas property costs.

The provision for depletion and amortization of oil and natural gas properties is computed by the unit-of-production method. Under this computation, the total unamortized costs of oil and natural gas properties (including future development, site restoration, and dismantlement and abandonment costs), excluding costs of unproved properties, are divided by the total estimated units of proved oil and natural gas reserves at the beginning of the period to determine the depletion rate. This rate is multiplied by the physical units of oil and natural gas produced during the period.

Changes in the quantities of our reserves could significantly impact the Company’s expense of depletion and amortization of oil and natural gas properties. A 10% decrease in reserves would have increased our expense for the year by approximately 3%; however, a 10% increase in our reserves would have decreased our expense for the year by approximately 3%.

The cost of unevaluated oil and natural gas properties not subject to depletion is assessed quarterly to determine whether such properties have been impaired. In determining impairment, an evaluation is performed on current drilling results, lease expiration dates, current oil and natural gas industry conditions, available geological and geophysical information, and actual exploration and development plans. Any impairment assessed is added to the cost of proved properties being amortized.

At December 31, 2008, we had $39.9 million allocated to unevaluated oil and natural gas properties. A 10% decrease in the unevaluated oil and natural gas properties balance would have increased our expense of depletion and amortization of oil and natural gas properties by less than 1% and a 10% increase would have decreased our provision by less than 1% for the year ended December 31, 2008.

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 after-tax 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 depletion expense 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.

At December 31, 2008, the unamortized cost of our oil and natural gas properties, net of related deferred income taxes, exceeded the ceiling under the full cost method of accounting for our oil and natural gas properties. Accordingly, based on December 31, 2008 pricing of $5.79 per Mcf of natural gas and $44.04 per barrel of oil, in the fourth quarter of 2008, the Company recognized a non-cash impairment of $216.8 million ($203.2 million after tax) of the Company’s oil and natural gas properties under the full cost method of accounting. A non-cash impairment of $134.9 million ($87.7 million after tax) was recognized in the third quarter of 2006, based on prices prevailing at that time.

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 December 31, 2008, we had no cushion (i.e., the excess of the ceiling over our capitalized costs). Thus, any decrease in prices affecting the end of subsequent accounting periods, net of the effect of our hedging positions, may require us to record additional impairment charges. Any future impairment would be impacted by changes in the accumulated costs of oil and natural gas properties, which may in turn be affected by sales or acquisitions of properties and additional capital expenditures. Future impairment would also be impacted by changes in estimated future net revenues, which are impacted by additions and revisions to oil and natural gas reserves. A 10% decrease in prices would have increased our 2008 non-cash impairment expense by approximately $31.3 million, or 15%.

Price Risk Management Activities. The Company follows SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”) which requires that changes in the derivatives’ fair value be recognized currently in earnings unless specific cash flow hedge accounting criteria are met. The statement also establishes accounting and reporting standards requiring that every derivative instrument be reported in the balance sheet as either an asset or liability measured at its fair value. Cash flow hedge accounting for qualifying hedges allows the gains and losses on derivatives to offset related results on the hedged item in the earnings statements and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

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 our hedged production. Although derivatives often fail to achieve 100% effectiveness for accounting purposes, our 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 133 and any changes in fair value are recorded in other comprehensive income until earnings are affected by the variability in cash flows of the designated hedged item. Any changes in fair value resulting from the ineffectiveness of the hedge are reported in the consolidated statement of operations as a component of revenues. The Company recognized a loss of $18,000 during the year ended December 31, 2008, a gain of $21,000 during the year ended December 31, 2007, and a gain of $128,000 during the year ended December 31, 2006.

As of December 31, 2008, the estimated fair value of the Company’s oil and natural gas agreements was an unrealized gain of $8.1 million ($8.1 million net of tax) which is recognized in Accumulated Other Comprehensive Income (Loss). Based upon oil and natural gas commodity prices at December 31, 2008, all of the unrealized gain deferred in Accumulated Other Comprehensive Income (Loss) could potentially increase gross revenues in 2009. The derivative agreements expire at various dates through December 31, 2009.

Net settlements under these contract agreements increased oil and natural gas revenues by $4,663,000, $3,252,000 and $3,821,000 for the years ended December 31, 2008, 2007, and 2006, respectively.

See Item 7A, Quantitative and Qualitative Disclosures about Market Risk, for additional discussion of disclosures about market risk.

Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, and bank borrowings. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature

of these short-term instruments. The fair value of bank borrowings under the Credit Facility approximate the carrying amounts as of December 31, 2008 and 2007. The rate is variable and had been recently renegotiated on December 19, 2008; in addition, the value of the underlying collateral is in excess of the outstanding amount. The Company also has a smaller bank debt with a fixed rate (the rig note). The fair value of the rig note, computed for disclosure purposes only, is estimated as $5.5 million; the carrying value of the debt is $8.8 million. The fair value was estimated based on the fair value of the underlying collateral, which is a drilling rig owned by the Company. See Note 4 of Notes to Consolidated Financial Statements included herein for further information on how fair value for the rig was estimated; see Note 5 for further information on the Credit Facility and the rig note.

Deferred Tax Asset Valuation Allowance. Under the liability method, deferred tax assets and liabilities are recognized for the estimated future tax effects attributable to temporary differences and carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient taxable income within the carryback/carryforward period to absorb future deductible temporary differences or a carryforward. In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized, including such evidence as the scheduled reversal of deferred tax liabilities and projected future taxable income. As a result of the current assessment, in 2008 we recorded a valuation allowance against deferred tax assets equal to the full amount of those assets.

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

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115” (“SFAS 159”). SFAS 159 permits entities to choose to measure eligible financial assets and liabilities at fair value. Unrealized gains and loses on items for which the fair value option has been elected are reported in earnings. We 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.

In September 2006, the SEC issued Staff Accounting Bulletin No. 108 (“SAB 108”). Due to diversity in practice among registrants, SAB 108 expresses SEC staff views regarding the process by which misstatements in financial statements are evaluated for purposes of determining whether financial statement restatement is necessary. The Company adopted the provisions of SAB 108 on January 1, 2007, and the adoption did not have a material impact on our financial position or results of operations.

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, 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, 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 other than oil and natural gas properties. The Company adopted the effective portion of SFAS 157 on January 1, 2008; the adoption did not have a material impact on our financial position or results of operations. We do not expect the adoption in 2009 of application of the new standard to non-financial assets and liabilities to have a material impact on our financial position or results of operations.

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. 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) is effective on a prospective basis for all business combinations completed 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 became effective November 15, 2008. The adoption of SFAS 162 had no 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; we expect that certain of our outstanding warrants will be subject to derivative accounting, and we cannot predict the effect on our results of operations, as it is dependent on our stock price.

In December 2008, the Securities and Exchange Commission published a Final Rule, “Modernization of Oil and Gas Reporting”. The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The use of average prices will affect future impairment and depletion calculations.

The new disclosure requirements are effective for annual reports on Forms 10-K for fiscal years ending on or after December 31, 2009. A company may not apply the new rules to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. The Company has not yet determined the impact of this Final Rule, which will vary depending on changes in commodity prices on its disclosures financial position or results of operations.

ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk

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

Interest Rates

We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. Our long-term borrowings primarily consist of borrowings under the Credit Facility. Since interest charged on borrowings under the Credit Facility floats with prevailing interest rates (except for the applicable interest period for Eurodollar loans), the carrying value of borrowings under the Credit Facility should approximate the fair market value of such debt. Changes in interest rates, however, will change the cost of borrowing. Assuming $95 million remains borrowed under the Credit Facility, we estimate our annual interest expense will change by $0.95 million for each 100 basis point change in the applicable interest rates utilized under the 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 agreements 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 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 Credit Facility. In practice, no such set-off has been made, and all settlements have been made in cash. As of December 31, 2008, however, the Company is in default of two covenants contained in the Credit Facility, the breach of which is also a default under the master derivative agreements. The Company’s hedge counterparties are not obligated to make payments to the Company under the hedging agreements while the Company’s default is continuing. The Company’s set-off rights under the master derivative agreements cannot be exercised due to such default. The Company’s hedging counterparties may exercise their remedies under the hedging agreements, and potentially under the Credit Facility, on account of the Company’s default. If a counterparty were to default in payment of an obligation, the Company would be exposed to commodity price fluctuations, and the protection intended by the hedge would be lost. The value of assets from hedging activities would be impacted. In addition, as expected cash flows from hedging contracts are included in computing future net revenues, the “ceiling test” could be impacted, which could result in a non-cash write-down of oil and natural gas properties. Balances owed by the Company under derivative agreements are collateralized by the security interests supporting the Credit Facility. The agreements also contain provisions permitting netting of multiple unrelated transactions that settle on the same day and in the same currency.

All of the Company’s current hedging agreements 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. The positions effectively hedge approximately 34% of our proved developed natural gas production and 19% 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 December 31, 2008, is provided below (see the Company’s website at www.tmrc.com for a quarterly breakdown of the Company’s hedge position for 2008 and beyond):

																		Estimated
																		Fair Value
																		Asset (Liability)
						Notional				Floor Price				Ceiling Price				December 31, 2008
		Type				Amount				($ per unit)				($ per unit)				(in thousands)
Natural Gas (mmbtu)
Jan 2009 - Dec 2009		Collar					1,230,000			$	7.50			$	10.45			$	2,070
Jan 2009 - Dec 2009		Collar					760,000			$	8.00			$	10.30				1,592
Jan 2009 - Dec 2009		Collar					540,000			$	8.00			$	13.35				1,166
Total Natural Gas																		$	4,828
Crude Oil (bbls)
Jan 2009 - Dec 2009		Collar					23,000			$	70.00			$	93.55			$	434
Jan 2009 - Dec 2009		Collar					43,000			$	80.00			$	111.00				1,236
Jan 2009 - Dec 2009		Collar					49,000			$	85.00			$	128.50				1,638
Total Crude Oil																			3,308
																		$	8,136

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

The definitions set forth below apply to the indicated terms as used in this Annual Report on Form 10-K. All volumes of natural gas referred to are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

“Bbl” One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.

“Bbl/d” One barrel per day.

“Bcf” Billion cubic feet.

“Bcfe” Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“Btu” British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“Completion” The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“Developed acreage” The number of acres allocated or assignable to producing wells or wells capable of production.

“Developed well” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole or well” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Equivalents” When we refer to “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one barrel of oil is equal to six thousand cubic feet of natural gas.

“Exploratory well” A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

“Farm-in or farm-out” An agreement where the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

“Field” An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

“Gross acres or gross wells” The total acres or wells, as the case may be, in which a working interest is owned.

“Intangible Drilling and Development Costs” Expenditures made by an operator for wages, fuel, repairs, hauling, supplies, surveying, geological works, etc., incident to and necessary for the preparing for and drilling of wells and the construction of production facilities and pipelines.

“Lease Operating Expense” Recurring expenses incurred to operate wells and equipment on a producing lease. Examples include pumping and gauging, chemicals, compression, fuel and water, insurance and property taxes.

“MBbls” One thousand barrels of crude oil or other liquid hydrocarbons.

“Mcf” One thousand cubic feet.

“Mcfe” One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“Mcfe/d” One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids, per day.

“MD” Measured depth.

“MMBls” One million barrels of crude oil or other liquid hydrocarbons.

“MMbtu” One million Btus.

“MMMbtu” One billion Btus.

“MMcf” One million cubic feet.

“MMcf/d” One million cubic feet per day.

“MMcfe” One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

“Net acres or net wells” The sum of the fractional working interests owned in gross acres or gross wells.

“Net revenue interest” An interest in the production and revenues created from the working interest which is generally calculated “net” or after deducting any royalty interests.

“NYMEX” New York Mercantile Exchange.

“OCS” Outer Continental Shelf in the Gulf of Mexico.

“Oil” Crude oil and condensate

“Present value or PV10” When used with respect to natural gas and oil reserves, the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

“Productive well” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Proved developed nonproducing reserves” Proved developed reserves expected to be recovered from zones behind casing in existing wells.

“Proved developed producing reserves” Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and able to produce to market.

“Proved reserves” The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. In addition, please refer to the definitions of proved oil and natural gas reserves as provided in Rule 4-10(a)(2)(3)(4) of Regulation S-X of the federal securities laws.

“Proved undeveloped location” A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

“Proved undeveloped reserves” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

“Recompletion” The completion for production of an existing well bore to another formation from that in which the well has been previously completed.

“Reservoir” A porous and permeable underground formation containing a natural accumulation of producible oil or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“Royalty interest” An interest in a natural gas and oil property entitling the owner to a share of natural gas or oil production free of costs of production.

“Tangible Drilling and Development Costs” The costs of physical lease and well equipment and structures and the costs of assets that themselves have a salvage value.

“TVD” Total vertical depth.

“Undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil, regardless of whether the acreage contains proved reserves.

“WI” Working interest.

“Working interest” The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

“Workover” Operations on a producing well to restore or increase production.

Item 8. Financial Statements and Supplementary Data

Index to Financial Statements

Below is an index to the financial statements and notes contained in Financial Statements and Supplementary Data.

		Page
Report of Independent Registered Public Accounting Firm			54
Consolidated Statements of Operations			55
Consolidated Balance Sheets			56
Consolidated Statements of Cash Flows			58
Consolidated Statements of Stockholders’ Equity			59
Consolidated Statements of Comprehensive Income (Loss)			60
Notes to Consolidated Financial Statements			61
1. Organization and Basis of Presentation			61
2. Summary of Significant Accounting Policies			62
3. Asset Retirement Obligations			68
4. Impairment of Long-Lived Assets			69
5. Debt			70
6. Contractual Obligations			72
7. Commitments and Contingencies			72
8. Taxes on Income			74
9. Fair Value Measurement			77
10. Stockholders’ Equity			80
11. Profit Sharing and Savings Plan			85
12. Contract Settlement, Rabbi Trust, and Employee Retention			86
13. Oil and Natural Gas Hedging Activities			87
14. Major Customers			89
15. Related Party Transactions			90
16. Earnings Per Share			91
17. Accrued Liabilities			92
18. Quarterly Results of Operations (Unaudited)			93
19. Supplemental Oil and Natural Gas Disclosures (Unaudited)			94

CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

All schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and therefore have been omitted.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors
The Meridian Resource Corporation
Houston, Texas

We have audited the accompanying consolidated balance sheets of The Meridian Resource Corporation as of December 31, 2008 and 2007 and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of The Meridian Resource Corporation at December 31, 2008 and 2007, and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, at December 31, 2008, the Company was in violation of certain debt covenants resulting in the default on its revolving credit and other debt agreements, which raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The Meridian Resource Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 16, 2009 expressed an unqualified opinion thereon.

/s/ BDO Seidman, LLP

Houston, Texas
March 16, 2009

THE MERIDIAN RESOURCE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(thousands, except per share data)

		Year Ended December 31,
		2008				2007				2006
REVENUES:
Oil and natural gas		$	148,634			$	150,709			$	189,041
Price risk management activities			(18	)			21				128
Interest and other			549				1,448				1,788
			149,165				152,178				190,957
OPERATING COSTS AND EXPENSES:
Oil and natural gas operating			24,280				28,338				22,614
Severance and ad valorem taxes			9,727				9,409				11,259
Depletion and depreciation			72,072				77,076				106,067
General and administrative			19,063				16,221				16,674
Contract settlement			9,894				—				—
Accretion expense			2,064				2,230				1,588
Impairment of long-lived assets			223,543				—				134,865
Hurricane damage repairs			1,462				—				4,314
			362,105				133,274				297,381
EARNINGS (LOSS) BEFORE OTHER EXPENSES & INCOME TAXES			(212,940	)			18,904				(106,424	)
OTHER EXPENSES:
Interest expense			5,408				6,090				5,982
EARNINGS (LOSS) BEFORE INCOME TAXES			(218,348	)			12,814				(112,406	)
INCOME TAXES:
Current			(269	)			650				369
Deferred			(8,193	)			5,027				(38,891	)
			(8,462	)			5,677				(38,522	)
NET EARNINGS (LOSS)			(209,886	)			7,137				(73,884	)
NET EARNINGS (LOSS) APPLICABLE TO COMMON STOCKHOLDERS		$	(209,886	)		$	7,137			$	(73,884	)
NET EARNINGS (LOSS) PER SHARE:
Basic		$	(2.30	)		$	0.08			$	(0.84	)
Diluted		$	(2.30	)		$	0.08			$	(0.84	)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES:
Basic			91,382				89,307				87,670
Diluted			91,382				94,944				87,670

See notes to consolidated financial statements.

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

		December 31,
		2008				2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	13,354			$	13,526
Restricted cash			9,971				30
Accounts receivable, less allowance for doubtful accounts of $210 [2008] and $210 [2007]			16,980				19,874
Due from affiliates			—				2,580
Prepaid expenses and other			3,292				4,538
Assets from price risk management activities			8,447				2,453
Deferred tax asset			—				164
Total current assets			52,044				43,165
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, full cost method (including $39,927 [2008] and $53,645 [2007] not subject to depletion)			1,877,925				1,771,768
Land			48				48
Equipment and other			21,371				18,503
			1,899,344				1,790,319
Less accumulated depletion and depreciation			1,647,496				1,350,577
Total property and equipment, net			251,848				439,742
OTHER ASSETS:
Assets from price risk management activities			—				865
Other			683				3
Total other assets			683				868
TOTAL ASSETS		$	304,575			$	483,775

See notes to consolidated financial statements.

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

		December 31,
		2008				2007
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable		$	15,097			$	9,583
Advances from non-operators			5,517				6,996
Revenues and royalties payable			6,267				6,592
Due to affiliates			8,145				—
Notes payable			1,775				2,662
Accrued liabilities			18,831				22,011
Liabilities from price risk management activities			311				2,772
Asset retirement obligations			1,457				3,365
Current income taxes payable			47				147
Current maturities of long-term debt			103,849				—
Total current liabilities			161,296				54,128
LONG-TERM DEBT			—				75,000
OTHER:
Deferred income taxes			—				8,238
Liabilities from price risk management activities			—				861
Asset retirement obligations			20,768				20,118
			20,768				29,217
COMMITMENTS AND CONTINGENCIES (Notes 6, 7, 11, and 12)
STOCKHOLDERS’ EQUITY:
Common stock, $0.01 par value (200,000,000 shares authorized, 93,045,592 [2008] and 89,450,466 [2007] shares issued) 07] and 89,139,600 [2006] issued)			948				936
Additional paid-in capital			538,561				537,145
Accumulated deficit			(422,028	)			(212,142	)
Accumulated other comprehensive income (loss)			8,129				(221	)
			125,610				325,718
Less treasury stock, at cost, 1,712,114 [2008] and 158,683 [2007] shares			3,099				288
Total stockholders’ equity			122,511				325,430
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY		$	304,575			$	483,775

See notes to consolidated financial statements.

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