Forman Petroleum 10K 2000 Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

[x] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2000
Or
[ ] 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 333-31375*

FORMAN PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)

Louisiana (State or other jurisdiction of incorporation or organization)	72-0954774 (I.R.S. Employer Identification No.)

650 Poydras Street - Suite 2200 New Orleans, Louisiana 70130-6101 (Address of principal executive offices)(Zip Code)	(504) 586-8888 (Registrant's telephone number including area code)

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes X No .

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_X_ No____

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. [X]

As of March 30, 2001, there were 984,042 shares of the Registrant's Voting Common Stock, no par value outstanding.

* The Commission file number refers to a Form S-4 Registration Statement filed by the Registrant under the Securities Act of 1933, which became effective September 26, 1997.

FORMAN PETROLEUM CORPORATION

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2000

TABLE OF CONTENTS

PART I		1
ITEM 1.	BUSINESS	1
ITEM 2.	PROPERTIES	14
ITEM 3.	LEGAL PROCEEDINGS	15
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	15
PART II		16
ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS	16
ITEM 6.	SELECTED FINANCIAL AND OPERATING DATA	17
ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 24	24
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	24
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	24
PART III		25
ITEM 10.	DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT	25
ITEM 11.	EXECUTIVE COMPENSATION	27
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	28
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS	29
PART IV.		30
ITEM 14.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K	30

PART I

ITEM 1. BUSINESS

Overview

Forman Petroleum Corporation (the "Company," "we" or "us") is an independent energy company engaged in the acquisition, exploitation, exploration, development and production of natural gas and crude oil. We have been active in the Gulf Coast Basin since 1982.

We emerged from Chapter 11 protection of the United States Bankruptcy Code on December 29, 1999, after operating as a debtor-in-possession since August 6, 1999. On November 2, 2000, the Company filed a motion for final decree with the Bankruptcy Court to close the Company's bankruptcy case. At the hearing on November 29, 2000, the final decree was granted by the Bankruptcy Court. As a result of the implementation of fresh start accounting, our 1999 financial statements are not comparable to our financial statements of prior periods. The effect of the plan of reorganization and the implementation of fresh start accounting on our balance sheet as of December 31, 1999 are discussed in detail in the notes to our consolidated financial statements appearing elsewhere in this report.

Recent Developments

In January 2001, our majority stockholders organized a new corporation, Ascent Energy Inc., to acquire Pontotoc Production, Inc. Pursuant to that certain Agreement and Plan of Merger dated as of January 19, 2001, by and among Ascent Energy, Pontotoc Acquisition Corp. and Pontotoc Production, Inc. ("Pontotoc"), Ascent Energy has agreed to exchange $9.00 in cash and one share of its 8% Series B convertible preferred stock having a liquidation preference of $2.50 per share for each outstanding share of Pontotoc common stock (the "Offer"). Promptly following completion of the Offer, Ascent Energy intends to merge Pontotoc Acquisition Corp., its wholly owned subsidiary, with Pontotoc. Ascent Energy is obligated under the merger agreement to pay Pontotoc $2 million within five days of termination of the merger agreement if the termination is due to the failure of Ascent Energy to obtain financing and all other conditions to the Offer have been met. We have guaranteed this obligation.

On March 20, 2001, we acquired all the outstanding shares of Ascent Energy common stock from our majority stockholders in exchange for $1,000 cash. In addition, we have agreed to cause Ascent Energy to repay approximately $76,000, in the aggregate, to our majority stockholders for certain out-of-pocket costs. Concurrently with the consummation of the Offer, it is expected that we will be restructured as a holding company by contributing all of our assets and liabilities to Ascent Energy in exchange for additional shares of Ascent Energy common stock.

Significant Properties

We have summarized our most significant properties in the tables below.

			As of 12/31/00 Net Proved Reserves (1)
Producing Properties	Our Working Interest	Our Net Revenue Interest	MMcfe	% Developed	December 2000 Average Daily Net Production (Mcfe)
Lake Enfermer Field	92.85%	64.75%	20,083	48.55%	4,296
Manilla Village Field	68.64%	51.89%	7,302	68.79%	170
Boutte Field	100.00%	81.50%	11,188	100.00%	4,768
Bayou Fer Blanc Field	100.00%	70.00%	3,690	0.00%	0

__________________

(1) Estimates of net proved reserves are based on our third party independent reserve report as of December 31, 2000.

Lake Enfermer Field. The Lake Enfermer Field is located in a marsh area on a deep, complexly faulted field, salt structure in Lafourche Parish, Louisiana. Since 1992, we have acquired leases on 3,650 acres in this field and operate the field. The field was first discovered in 1955 and through December 2000 has produced more than 33.5 MMBoe (one million barrels of oil equivalent, determined using the ratio of six Mcf (thousand cubic feet) of natural gas to one barrel of oil).

Manila Village Field. The Manila Village Field is located in a marsh area in Jefferson Parish, Louisiana. We acquired leases on 825 acres in this field in 1991 and operate the field. The field was first discovered in 1949 and through December 2000 had produced 34.1 MMBoe.

Boutte Field. The Boutte Field is located in a marsh area in St. Charles Parish, Louisiana. We acquired leases on 3,250 acres in 1992 and operate the field. The field was discovered in 1953 and through December 2000 had produced a total of 39.6 MMBoe.

Bayou Fer Blanc Field. The Bayou Fer Blanc Field is located in Lafourche Parish, Louisiana next to the Lake Enfermer Field. We purchased our interest in the field in 1997 and operate the field. Although classified as two distinct fields, the Lake Enfermer Field and the Bayou Fer Blanc Field have produced from a single geologic structure. The Bayou Fer Blanc Field was discovered in 1959 and through December 2000 had produced 19.2 MMBoe.

Productive Wells

The following table sets forth the number of producing wells in which we maintain an ownership interest at December 31, 2000:

		Productive Wells

		Gross	Net

Gas		16.00	13.81
Oil		16.00	13.93

	Total	32.00	27.74

Productive wells consist of producing wells and wells capable of production. A gross well is a well in which we maintain a working interest while a net well is deemed to exist when the sum of the fractional working interests owned by us equals one. Wells with multiple completions are counted as one well. Of the gross wells reported in the table, one had multiple completions.

Drilling Activity

The following table sets forth our drilling activity for the last three years:

		Year Ended December 31,

		2000		1999		1998

		Gross	Net	Gross	Net	Gross	Net
Development wells:
	Productive	0.0	0.0	1.0	1.0	0.0	0.0
	Non-productive	0.0	0.0	0.0	0.0	0.0	0.0
	Total	0.0	0.0	1.0	1.0	0.0	0.0
Exploratory wells:
	Productive	0.0	0.0	0.0	0.0	0.0	0.0
	Non-productive	0.0	0.0	1.0	0.5	0.0	0.0
	Total	0.0	0.0	1.0	0.5	0.0	0.0
Total:
	Productive	0.0	0.0	1.0	1.0	0.0	0.0
	Non-productive	0.0	0.0	1.0	0.5	0.0	0.0
	Total	0.0	0.0	2.0	1.5	0.0	0.0

Net Production, Unit Prices and Costs

The following table presents certain information regarding our production volumes, average sale prices and average production costs for the last three years:

					Year Ended December 31,
						2000		1999		1998
Production:
Natural gas (MMcf)					1,797		3,091		4,944
Oil and condensate (MBbls)					270		343		393
	Total (MMcfe)				3,414		5,154		7,302
Average sales price per unit:
Natural gas--
	Revenues from production (per Mcf)				$ 4.05		$ 2.28		$ 2.27
		Effects of hedging activities (per Mcf)			0		0		0

		Average price (per Mcf)			$ 4.05		$ 2.28		$ 2.27


Oil and condensate--
	Revenues from production (per Bbl)				$ 27.49		$ 17.34		$ 12.09
	Effects of hedging activities (per Bbl)				0		0		0

		Average price (per Bbl)			27.49		17.34		12.09


Total revenues from production
		(per Mcfe)			$ 4.30		$ 2.52		$ 2.19

Effects of hedging activities
		(per Mcfe)			0		0		0
			Total average price
				(per Mcfe)	$ 4.30		$ 2.52		$ 2.19

Expenses (per Mcfe):
General and administrative					$ 0.78		$ 0.59		$ 0.38
Lease operating expenses (excluding Production taxes)					$ 0.98		$ 0.61		$ 0.46
Depreciation, depletion and amortization- oil and natural gas properties					$ 1.31		$ 1.09		$ 1.43

Capital Expenditures

The following table presents information regarding our net costs incurred in oil and natural gas property acquisitions, exploration and development activities for the past three years:

		Year Ended December 31,

		2000	1999	1998

Property acquisition
	Proved	$ 574,008	$ 81,840	$ 0
	Unproved	0	0	0
Exploration		1,502,880	3,345,943	2,413,719
Development		46,853	1,745,862	2,118,810
Capitalized general and administrative costs		842,391	0	0

		$ 2,966,132	$ 5,173,645	$ 4,532,529

Oil and Gas Marketing

We sell our natural gas and oil production under price sensitive or market price contracts. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas and oil. The price received by us for natural gas and oil production historically has fluctuated widely. Decreases in the price of natural gas and oil could adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flow. From time to time we may enter into transactions hedging the price of oil and natural gas production. See "Management's Discussion and Analysis of Financial Conditions Results of Operations - Quantitative and Qualitative Disclosures About Market Risk."

Competition and Markets

We operate in a highly competitive environment. We compete with major and independent oil and natural gas companies for the acquisition of desirable oil and natural gas properties, as well as for the equipment and labor required to develop and operate these properties. We also compete with major and independent oil and natural gas companies in the marketing and sale of oil and natural gas to marketers and end-users. Many of our competitors have financial and other resources substantially greater than ours.

Competitors may be able to pay more for natural gas and oil properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire and develop additional properties in the future will depend on our ability to conduct operations, evaluate and select suitable properties and close transactions in this highly competitive market environment.

The marketability of our production depends upon the availability and capacity of gas gathering systems, pipelines and processing facilities, and the unavailability or lack of capacity thereof could result in the shut-in of producing wells or the delay or termination of development plans for properties. In addition, regulatory changes affecting oil and natural gas production and transportation, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas on a profitable basis. In addition, larger competitors may be able to absorb the burden of any regulatory changes more easily than we can, which would adversely affect our competitive position.

Regulation

Our business can be affected by a number of regulatory policies, including the regulation of production, federal and state regulations governing environmental quality and pollution control, state limits of allowable rates of production by a well or proration unit and incentives to promote alternative or competitive fuels. State and federal regulations generally are intended to prevent waste of oil and natural gas, protect rights to produce oil and natural gas between 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 also subject to the jurisdiction of various federal, state and local agencies.

Federal Regulation of Natural Gas. Federal legislation and regulatory controls in the United States have historically affected the price of natural gas and the manner in which natural gas production is marketed. In the past, the federal government has regulated the price at which natural gas could be sold and could reenact price controls in the future.

Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation are subject to extensive federal regulation. Beginning in 1992, the Federal Energy Regulatory Commission issued a series of orders, which required interstate pipelines to provide open-access transportation on a not unduly discriminatory basis for all natural gas shippers. The Federal Energy Regulatory Commission has stated that it intends for these orders and its future restructuring activities to foster increased competition within all phases of the natural gas industry. Although these orders do not directly regulate our production and marketing activities, they do affect how buyers and sellers gain access to the necessary transportation facilities and how we and our competitors sell natural gas.

The courts have largely affirmed the significant features of the Federal Energy Regulatory Commission's deregulation orders and the numerous related orders pertaining to individual pipelines. However, some appeals remain pending and the Federal Energy Regulatory Commission continues to review and modify its regulations regarding the transportation of natural gas. For example, the Federal Energy Regulatory Commission issued Order No. 637 which:

lifts the cost-based cap on pipeline transportation rates in the capacity release market until September 30, 2002, for short-term releases of pipeline capacity of less than one year;
permits pipelines to file for authority to charge different maximum cost-based rates for peak and off-peak periods;
encourages, but does not mandate, auctions for pipeline capacity;requires pipelines to implement imbalance management services;
restricts the ability of pipelines to impose penalties for imbalances, overruns and non-compliance with operational flow orders; and
implements a number of new pipeline reporting requirements.

Order No. 637 also requires the Federal Energy Regulatory Commission's staff to analyze whether the Federal Energy Regulatory Commission should implement additional fundamental policy changes. These include whether to pursue performance-based or other non-cost based ratemaking techniques and whether the Federal Energy Regulatory Commission should mandate greater standardization in terms and conditions of service across the interstate pipeline grid.

We cannot predict what other actions the Federal Energy Regulatory Commission will take on these matters, nor can we accurately predict whether the Federal Energy Regulatory Commission's actions will achieve the goal of increasing competition in markets in which our natural gas is sold. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers.

Oil Sales and Transportation Rates. Sales prices of crude oil and natural gas liquids by us are not regulated. The price we receive from the sale of these products may be affected by the cost of transporting the products to market. In a number of instances, however, the ability to transport and sell these products depends on pipelines whose rates, terms and conditions of service are subject to Federal Energy Regulatory Commission jurisdiction. In other instances, the ability to transport and sell our products depends on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies. Certain regulations implemented by the Federal Energy Regulatory Commission in recent years could result in an increase in the cost of transportation service on these pipelines. However, we do not believe that these regulations affect us any differently than any other producer or marketer.

Environmental Matters. Extensive federal, state and local laws regulating the discharge of materials into the environment or otherwise relating to the protection of the environment affect our oil and natural gas operations. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose ''strict liability'' for environmental contamination, rendering a person liable for environmental damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration and production activities in sensitive areas. In addition, state laws often require various forms of remedial action to prevent pollution, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. We believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on our operations. However, environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could require us to make significant capital expenditures, increase our operating costs or otherwise adversely affect our competitive position.

The Comprehensive Environmental Response, Compensation and Liability Act, also known as ''CERCLA,'' imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a ''hazardous substance'' into the environment. These persons include the current or former owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of investigating and cleaning up hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, companies that incur CERCLA liability frequently also confront third party claims because it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment from a CERCLA site.

The Federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976, also known as "RCRA," regulates the generation, transportation, storage, treatment and disposal of hazardous wastes and can require cleanup of hazardous waste disposal sites. RCRA currently excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil and natural gas from regulation as ''hazardous waste.'' However, other wastes handled at exploration and production sites may not fall within this exclusion. Disposal of non-hazardous oil and natural gas exploration, development and production wastes usually is regulated by state law.

Stricter standards for waste handling and disposal may be imposed on the oil and natural gas industry in the future. From time to time legislation has been proposed in Congress that would revoke or alter the current exclusion of exploration, development and production wastes from the RCRA definition of ''hazardous wastes,'' thereby potentially subjecting such wastes to more stringent handling, disposal and cleanup requirements. If such legislation were enacted, it could have a significant impact on our operating costs, as well as the oil and natural gas industry in general. Furthermore, although petroleum, including crude oil and natural gas, is exempt from CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as ''hazardous substances'' under CERCLA. The impact of future revisions to environmental laws and regulations cannot be predicted.

The Oil Pollution Act of 1990, also known as OPA 90, provides that persons responsible for facilities and vessels (including the owners and operators of onshore facilities) are subject to strict joint and several liability for cleanup costs and certain other public and private damages arising from a spill of oil into waters of the United States. OPA 90 established a liability limit for onshore facilities of $35 million. However, facilities located in coastal waters may be considered ''offshore'' facilities subject to greater liability limits under OPA 90 (all removal costs plus $75 million). In addition, a party cannot take advantage of this liability limit if the spill was caused by gross negligence or willful misconduct or resulted from a violation of a federal safety, construction or operating regulation. If a party fails to report a spill or cooperate in the cleanup, liability limits likewise do not apply. OPA 90 also imposes other requirements on facility owners and operators, such as the preparation of an oil spill response plan. Failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject the responsible party to civil or criminal enforcement actions.

OPA 90 also imposes financial responsibility requirements on the person or persons statutorily responsible for certain facilities. Under the related regulations, oil production and storage facilities that are located in wetlands adjacent to coastal waters could be required to demonstrate various levels of financial ability to reimburse governmental entities and private parties for costs that they could incur in responding to an oil spill, if the Minerals Management Services determines that spills from those particular facilities could reach coastal waters.

Operating Risks and Insurance

The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations and hazards such as oil spills, natural gas leaks, ruptures and discharges of toxic gases. The occurrence of any of these operating risks could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property and equipment, pollution or other environmental damage, including damage to natural resources, clean-up responsibilities, penalties and suspension of operations. Such hazards may hinder or delay drilling, development and on-line operations. In accordance with customary industry practice, we maintain insurance against some, but not all, of the risks described above, including insuring the cost of clean-up operations, public liability and physical damage. There can be no assurance that any insurance we obtain will be adequate to cover any losses or liabilities or that such insurance will continue to be available in the future or that such insurance will be available at premium levels that justify its purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and operations.

Employees

On December 31, 2000, we employed 29 people, including 13 that work in our field offices. None of our employees is covered by a collective bargaining agreement, and we believe that our relationships with our employees are satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services.

Cautionary Statements

Certain statements made in this Report that are not historical facts are "forward-looking statements" as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements may include statements that relate to:

our objectives, business plans or strategies, and projected or anticipated benefits or other consequences of such plans or strategies;
projected or anticipated benefits from future or past acquisitions; and

projections involving anticipated capital expenditures or revenues, earnings or other aspects of capital projects or operating results.

Also, you can generally identify forward-looking statements by such terminology as "may," "will," "expect," "believe," "anticipate," "project," "estimate" or similar expressions. We caution you that such statements are only predictions and not guarantees of future performance or events. In evaluating these statements, you should consider various risk factors, including but not limited to the risks listed below. These risk factors may affect the accuracy of the forward-looking statements and the projections on which the statements are based.

All phases of our operations are subject to a number of uncertainties, risks and other influences, many of which are beyond our control. Any one of such influences, or a combination, could materially affect the results of our operations and the accuracy of forward-looking statements made by us. Some important factors that could cause actual results to differ materially from the anticipated results or other expectations expressed in our forward-looking statements include the following:

dependence on exploratory drilling activities, uncertainties about the estimates of reserves and the need to replace reserves;

the volatility of prices of oil and gas;

drilling and operating hazards, including the significant possibility of accidents resulting in personal injury, property damage or environmental damage;

the effect on our performance of regulatory programs and environmental matters;

the continued active participation of our executive officers and key operating personnel.

Many of these factors are beyond our ability to control or predict. We caution investors not to place undue reliance on forward-looking statements. We disclaim any intent or obligation to update the forward-looking statements contained in this Report, whether as a result of receiving new information, the occurrence of future events or otherwise. All subsequent written and oral forward-looking statements attributable us or persons acting on our behalf are expressly qualified in their entirety by the foregoing.

A more detailed discussion of certain of the foregoing factors follows:

Oil and natural gas prices are volatile, and low prices will cause our revenues, profitability and the carrying value of our properties to decrease.

Our revenues, profitability and the carrying value of our properties depend substantially on prevailing prices for oil and natural gas. Historically, prices for oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, oil and natural gas prices, while at historically high levels at the present time, declined significantly in 1997 and 1998 and, for an extended period of time, remained substantially below prices obtained in previous years. Among the factors that can cause this volatility are:

the level of consumer demand;
domestic and foreign supply of oil and natural gas;
weather conditions;
domestic and foreign government regulations and taxes;
the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
political instability or armed conflict in oil or natural gas producing regions;
the price and level of foreign imports;
the price and availability of alternative fuels; and
the overall local and world economic environment.

Prices for oil and natural gas affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. Any substantial and extended decline in the price of oil or natural gas would decrease our cash flows, as well as the carrying value of our proved reserves, our borrowing capacity and our ability to obtain additional capital.

Our capitalization or volatility in our results may prevent us from raising the capital necessary to drill wells.

We may not be able to successfully pursue our business strategy if our balance sheet, volatility in our results or general industry or market conditions prevents us from raising the capital required for our exploration and development activities and other operations. We expect to make substantial expenditures for the exploitation, exploration, development and production of oil and natural gas reserves. If our revenues or cash flow from operations decrease as a result of lower oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, or we are unable to raise additional debt or equity proceeds to fund such expenditures, then we may curtail our drilling, development and other activities. In addition, we may be forced or choose to sell some of our assets on an untimely or unfavorable basis. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources."

The oil and gas reserves data and future net revenues estimates we report are uncertain.

The process of estimating oil and natural gas reserves is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic and other factors beyond our control. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this prospectus.

Actual future production, oil and gas prices, revenues, taxes, development costs, operating expenses and quantities of recoverable oil and gas reserves will vary from those currently estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth in this document and the information incorporated by reference. Our properties may also be susceptible to hydrocarbon drainage from wells on adjacent properties operated by other owners. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, availability of rigs and other equipment, prevailing oil and gas prices and other factors, many of which are beyond our control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to our reserves will vary from the estimates used. Such variances may be material.

You should not assume that the present value of future net cash flows from our proved reserves referred to in this prospectus is the current market value of these reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Current commodity prices are at historically high levels. At current prices, we believe the present value of future net revenue amounts included in this prospectus or incorporated herein cannot be construed as the current market value of the estimated oil and gas reserves attributable to our properties. Actual future prices and costs are likely to differ materially from those used in the present value estimate because of changes in commodity prices or hedging transactions. The timing of both the production and the expenses from the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with us or the oil and gas industry in general will affect the accuracy of the 10% discount factor.

Lower oil and gas prices may cause us to record ceiling test write-downs.

We use the full cost method of accounting to account for our oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and gas properties. Under full cost accounting rules, the net capitalized costs of oil and gas properties may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves at a point in time, discounted at 10%, plus the lower of cost or fair value of unproved properties. If net capitalized costs of oil and gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling test write-down." This charge does not impact cash flow from operating activities, but does reduce our stockholders' equity. The risk that we will be required to write down the carrying value of oil and gas properties increases when oil and gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves. Due to low oil and gas prices in 1997 and 1998, we wrote down our oil and gas properties by $10 million on December 31, 1997, by an additional $12 million on June 30, 1998, and by an additional $7.6 million on December 31, 1998.

Our use of hedging transactions for a portion of our oil and gas production may limit future revenues from price increases and result in significant fluctuations in our stockholders' equity.

We use hedging transactions with respect to a portion of our oil and gas production to achieve more predictable cash flow and to reduce our exposure to price fluctuations. While the use of hedging transactions limits the downside risk of price declines, their use may also limit future revenues from price increases. While intended to reduce the effects of volatility of the price of oil and natural gas, such transactions may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, these hedging arrangements may expose us to the risk of financial loss if:

production is less than expected;
there is a change in the expected differential between the underlying price in the hedging arrangement and actual prices received;
the other party to the hedging contract defaults on its contract obligations; or
a sudden, unexpected event materially affects oil or natural gas prices.

We adopted Statement of Financial Accounting Standards (SFAS) No. 133 as of January 1, 2001. As a result of adopting SFAS No. 133, our stockholders' equity may fluctuate significantly from period to period. SFAS No. 133 generally requires us to record each derivative instrument as an asset or liability measured at its fair value. We must record an initial adjustment in the other comprehensive income component of stockholders' equity on adoption of SFAS No. 133, which amount will likely be significant. Thereafter, we must similarly record changes in the value of our hedging, which could result in significant fluctuations in stockholders' equity from period to period.

For further discussion of our hedging arrangements, please see "Quantitative and Qualitative Disclosures About Market Risk."

Exploration is a high-risk activity. The 3-D seismic data and other advanced technologies we use cannot eliminate exploration risk and require experienced technical personnel whom we may be unable to attract or retain.

Our future success will depend on the success of our future property acquisitions and our drilling operations. Exploitation, exploration and development activities involve numerous risks, including the risk that no commercially productive oil and natural gas reservoirs will be discovered. In addition, we often are uncertain as to the future cost or timing of drilling, completing and producing wells. Furthermore, our drilling operations may be curtailed, delayed or canceled as a result of the additional exploration, time and expenses associated with a variety of factors, including:

economic conditions;
unexpected drilling conditions;
title problems;
pressure or irregularities in formations;
equipment failures or accidents;
adverse weather conditions; and
shortages or delays in availability of drilling rigs or labor and the delivery of equipment.

We cannot assure you that wells in which we have an interest will be productive or that we will recover all or any portion of our drilling or other exploratory costs. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry holes or in wells that are productive but do not produce sufficient net revenues after drilling, operating and other costs to produce an acceptable return on investment.

Even when used and properly interpreted, 3-D seismic data and visualization techniques do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. We could incur losses as a result of these expenditures. Poor results from our exploitation, exploration and development activities could have a material adverse effect on our business, financial condition, cash flows or results of operations.

Competition for explorationists and engineers with experience is intense. Our drilling success will depend, in part, on our ability to attract and retain experienced explorationists and other professional personnel.

The oil and natural gas business involves many operating risks that can cause substantial losses.

Our operations are subject to risks inherent in the oil and natural gas business, including:

fires and explosions;
blow-outs and surface cratering;
uncontrollable flows of oil, underground natural gas and formation water;
natural disasters;
pipe, cement or pipeline failures or collapses;
embedded or unremovable oil field drilling and service tools;
abnormally pressured formations; and
environmental hazards such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic natural gases.

If any of these events occur, we could incur substantial losses as a result of:

injury or loss of life;
severe damage to and destruction of property, natural resources and equipment;
fines and clean-up responsibilities for pollution and other environmental damage; and
suspension of our operations.

Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur.

The occurrence of a significant accident or other event not fully covered by our insurance could have a material adverse effect on our business, financial condition, results of operations or cash flows. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. Because third party drilling contractors are used to drill our wells, we may not realize the full benefit of workers' compensation laws in dealing with their employees. In addition, pollution and environmental risks generally are not fully insurable.

We may be unable to identify liabilities associated with the properties that we acquire or obtain protection from sellers against them.

The acquisition of properties requires us to assess a number of factors, including:

value of the oil or gas properties and likelihood of future production;
future prices of oil and gas;
recoverable reserves;
development and operating costs;
potential environmental and other liabilities;
drilling and production difficulties; and
other factors beyond our control.

Such assessments are inexact and inherently uncertain. We intend to perform such reviews in a manner that we believe at the time to be generally consistent with industry practice. These reviews, however, may not reveal all existing or potential problems, nor would they permit a buyer to become sufficiently familiar with such properties to assess fully their deficiencies or benefits. For instance, inspections may not be performed on every well, and structural or environmental problems, such as pipeline corrosion, may not be observable even when an inspection is undertaken. In addition, we may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. We can make no assurance that any future acquisitions will be beneficial. Any unsuccessful acquisition could have a material adverse affect on us.

The marketability of our production depends primarily upon the availability of gathering systems, pipelines and processing facilities.

Our ability to sell our oil and gas production depends in part upon the availability, proximity and capacity of oil and natural gas gathering systems, pipelines and processing facilities. U.S. federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand all could adversely affect our ability to produce and market oil and natural gas. If market factors change dramatically, the financial impact on us could be substantial. The availability of markets is beyond our control.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute on a timely basis our development plans within our budget.

Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our operations. Recently, drilling activity in South Louisiana has increased, and we have experienced increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity also decreases the availability of drilling rigs. These costs may increase further and necessary equipment and services may not be available to us at economical prices.

Competition in our industry is intense.

We compete with major and independent natural gas and oil companies for property acquisitions. We also compete for the equipment and labor required to operate and develop these properties. Many of our competitors have substantially greater financial operations, staffs, facilities and other resources than us. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for natural gas and oil properties and may be able to define, evaluate, bid for and acquire a greater number of properties than we can. Our ability to acquire additional properties and develop new and existing properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, some of our competitors have been operating in South Louisiana for a much longer time than we have and have demonstrated the ability to operate through industry cycles.

We are subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.

Development, production and sale of natural gas and oil in the U.S. are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

discharge permits for drilling operations;
bonds for ownership, development and production of oil and gas properties;
unitization and pooling of properties;
production rates;
worker safety regulations;
reports concerning operations; and
taxation.

Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. From time to time regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas below actual production capacity in order to conserve supplies of oil and natural gas. Moreover, these laws and regulations could change in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

There is a lack of an established trading market for our securities.

Our outstanding common stock and warrants are subject to transfer restrictions set forth in the Stockholders' Agreement dated as of January 14, 2000 between the Company and the other parties listed on the signature pages thereto and the Warrant Agreement dated as of January 14, 2000 between the Company and the other parties listed on the signature pages thereto. Moreover, there is no existing trading market for the common stock or the warrants and it is not expected that any active market will develop.

TCW controls a major portion of our outstanding common stock.

The TCW Funds and its affiliates own approximately 44.5% of our outstanding common stock. By virtue of such ownership, the TCW Funds will have the power to determine the outcome of various corporate actions requiring shareholder approval.

We have no intention to pay dividends.

We currently intend to retain any earnings for the future operation and development of its business and do not currently intend to declare or pay any dividends on our common stock in the foreseeable future.

ITEM 2. PROPERTIES

Natural Gas and Oil Reserves

Our proved oil and gas reserves at December 31, 2000 were attributable to four properties located in south Louisiana. The following table presents estimated proved reserves as of December 31, 2000, and the related present value of estimated future net revenues before income taxes at such date, as estimated by our independent petroleum engineers, Netherland, Sewell & Associates, Inc. The present values, discounted at 10% per annum, of estimated future net cash flows before income taxes shown on the table are not intended to represent the current market value of our estimated natural gas and oil reserves.

The present value of future net cash flows before income taxes as of December 31, 2000, was determined using the December 31, 2000, prices of $10.04 per Mcf of natural gas and $25.48 per Bbl of oil.

			Producing	Non- Producing	Undeveloped	Total

Natural gas (MMcf)			5,394	7,410	13,456	26,260
Oil and NGLs (MBbls)			717	1,116	834	2,667
		Total proved reserves (Mmcfe)	9,695	14,106	18,462	42,263
Present value of estimated future net revenues
	before income taxes, discounted at 10% (in thousands)		$ 45,775	$ 44,297	$ 92,242	$ 182,313
Standardized measure of discounted future net
	Cash flows (in thousands)					$ 113,445

These estimates of our proved reserves have not been filed with or included in reports to any federal agency.

The process of estimating natural gas and oil reserves is a complex and subjective process. It requires various assumptions, including assumptions relating to product prices, operating expenses, capital expenditures, taxes and the availability of funds. We must project production rates and timing of development expenditures. We analyze available geological, geophysical, production and other data, and the extent, quality and reliability of this data will vary. As a result, estimates of different engineers may vary. In addition, estimates of reserves are subject to revision based upon future product prices, actual production, results of future development and exploration activities, operating costs and other factors, and the revisions may be material. Accordingly, reserve estimates will generally be different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates highly depends on the accuracy of the assumptions upon which they are based. Accordingly, the reserve data set forth herein represents only estimates.

In accordance with applicable SEC requirements, the estimates of our proved reserves and future net revenues are made using oil and natural gas sales prices that are in effect as of the date of such reserve estimates and are held constant throughout the life of the properties. You should not assume that the present value of future net revenues from our proved reserves is the current market value of these reserves. Estimated quantities of proved reserves and future net revenues therefrom are affected significantly by oil and natural gas prices, which have fluctuated widely in recent years. Current commodity prices are at historically high levels. At current prices, we believe of future net revenue amounts included in this prospectus or incorporated herein cannot be construed as the current market value of the oil and gas reserves attributable to our properties. The average prices of oil and gas we have actually received for years 2000, 1999 and 1998 were $27.49, $17.34 and $12.09 respectively, per barrel and $4.05, $2.28 and $2.27, respectively, per Mcf. Oil prices have remained relatively stable and natural gas prices have continued to decline almost 50% subsequent to December 31, 2000. Accordingly, the discounted future net cash flows would be decreased if the standardized measure were calculated at a later date. Actual future prices and costs are likely to differ materially from those used in the present value estimate because of changes in commodity prices or hedging transactions.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with standards generally accepted in the oil and natural gas industry, subject to such exceptions as, in our view, do not materially detract from the use or value of the properties. As is customary in the oil and gas industry, we perform only a preliminary title investigation before leasing undeveloped properties. A title opinion is typically obtained before the commencement of drilling operations and any material defects are remedied prior to the time the actual drilling of a well is commenced. If the operator or we were unable to remedy or cure any title defect, we could suffer a loss of our entire investment in the property. Our properties are subject to customary royalty interests, liens for current taxes, liens of vendors and other customary burdens, which we do not believe materially interfere with the use of or affect the value of our producing properties. See "Management's Discussion and Analysis of Financial Condition and Results of Operations - General -- Proposed Restructuring and Acquisition."

Acreage

The table below summarizes our developed and undeveloped leasehold acreage as of December 31, 2000:

	Developed Acreage		Undeveloped Acreage

Field	Gross	Net	Gross	Net

Lake Enfermer	1,939	1,785	420	414
Manila Village	742	530	0	0
Boutte	3,090	3,090	0	0
Bayou Fer Blanc	0	0	320	320

	5,771	5,405	740	734

Gross acreage is acreage in which a working interest is owned while a net acre is deemed to exist when the sum of the fractional working interests in gross acres equals one. Undeveloped acreage is considered to be those leased 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. As is customary in the industry, we can retain our interests in undeveloped acreage by drilling activity that establishes commercial production or by payment of delay rentals during the remaining primary term. The oil and natural gas leases in which we have an interest are for varying primary terms; however, most of our developed leased acreage is beyond the primary term and is held by producing wells.

ITEM 3. LEGAL PROCEEDINGS

From time to time, we may be a party to various legal proceedings. We currently are a party to a lawsuit arising in the ordinary course of business. Management does not expect this matter to have a material adverse effect on our financial position or results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

There is no established public trading market for our common stock or our warrants and it is unlikely that any will develop. Pursuant to our bankruptcy reorganization plan, which was confirmed by the Bankruptcy Court on December 29, 1999, we issued 984,042 shares of common stock, no par value, and warrants to purchase up to 490,516 shares of common stock to our former security holders pursuant to Section 1145 of the United States Bankruptcy Code. As of March 30, 2001, there were 21 holders of record of our common stock.

We have never declared or paid any cash dividends on our common stock and do not anticipate paying cash dividends in the foreseeable future.

Pursuant to a registration rights agreement dated as of January 14, 2000, certain of our stockholders are entitled to exercise up to four demand registration rights and to participate in certain other registration statements filed by us on our own behalf or on behalf of other security holders. Each holder of registrable securities (as defined in the agreement) is entitled to participate in any such demand or incidental registration. The agreement also entitles McLain Forman to exercise up to two demand registration rights.

ITEM 6. SELECTED FINANCIAL AND OPERATING DATA

The following table sets forth a summary of our selected historical financial information for the periods set forth below. This information is derived from our financial statements and the notes thereto. See "Item 7. Management Discussion and Analysis of Financial Condition and Results of Operations" and "Item 8. Financial Statements and Supplementary Data."

Selected Historical Financial Information
(In thousands, except per share amounts)


				2000	1999	1998	1997	1996

Statement of Operations Data:
	Oil and natural gas revenue			$ 14,696	$ 12,993	$ 15,950	$ 14,235	$ 10,892
	Operating expenses			11,163	12,494	36,691	24,814	8,909

	Operating income (loss)			3,533	499	(20,741)	(10,579)	1,983
		Interest expense		-	6,244	10,122	7,724	3,983
		Other income		264	123	325	474	225

			Net gain (loss) from operations before reorganization items, income taxes and extraordinary items	3,797	(5,622)	(30,538)	(17,829)	(1,775)
	Reorganization items:
		Reorganization costs		(899)	(1,184)	-	-	-
		Adjust accounts to fair value		-	6,628	-	-	-

	Net gain (loss) before income taxes and extraordinary item			2,898	(537)	(30,538)	(17,829)	(1,775)
		Provision (benefit) for income taxes		(1,182)	(188)	-	-	-

	Net income (loss) before extraordinary items			1,716	(349)	(30,538)	(17,829)	(1,775)
		Extraordinary gain on extinguishment of debt, net of taxes of $10,089		-	46,724	-	-	-

	Net gain (loss)			1,716	46,375	(30,538)	(17,829)	(1,775)
		Preferred stock dividends		-	(1,153)	(1,729)	(923)	-

	Net income (loss) attributed to common shares			$ 1,716	$ 45,222	$ (32,267)	$ (18,752)	$ (1,775)

	Basic and diluted
	Net income (loss) per share attributable to Common shares before extraordinary item			$ 1.74	$( 16.69)	$ (358.52)	$ (208.36)	$ (19.72)
	Extraordinary item per share			-	519.15	-	-	-

	Net income (loss) per share			$ 1.74	$ 502.46	$ (358.52)	$ (208.36)	$ (19.72)

	Weighted average shares outstanding			984,042	90,000	90,000	90,000	90,000

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

General

The following discussion is intended to assist in understanding our financial position and results of operations for each year of the three-year period ended December 31, 2000. Our financial statements and notes thereto contain detailed information that should be referred to in conjunction with the following discussion.

Proposed Restructuring and Acquisition. In January 2001, our majority stockholders organized a new corporation, Ascent Energy Inc., to acquire Pontotoc Production, Inc. Pursuant to that certain Agreement and Plan of Merger dated as of January 19, 2001, by and among Ascent Energy, Pontotoc Acquisition Corp. and Pontotoc Production, Inc. ("Pontotoc"), Ascent Energy has agreed to exchange $9.00 in cash and one share of its 8% Series B convertible preferred stock having a liquidation preference of $2.50 per share for each outstanding share of Pontotoc common stock (the "Offer"). Promptly following completion of the Offer, Ascent Energy intends to merge Pontotoc Acquisition Corp., its wholly owned subsidiary, with Pontotoc. Ascent Energy is obligated under the merger agreement to pay Pontotoc $2 million within five days of termination of the merger agreement if the termination is due to the failure of Ascent Energy to obtain financing and all other conditions to the Offer have been met. We have guaranteed this obligation.

To help fund the Pontotoc acquisition, Ascent Energy plans to offer approximately $21.1 million of its 8% Series A Redeemable Preferred Stock and warrants to purchase shares of its common stock to our existing stockholders on a pro rata basis. Ascent Energy expects to obtain the remainder of the funds necessary to finance the Pontotoc acquisition from borrowings under a new credit facility that it is currently negotiating with its primary lender and from its internal resources.

Upon the closing of the Pontotoc acquisition, Ascent expects to have outstanding 21,100 shares of Series A preferred stock with a liquidation preference of $21.1 million, 5.3 million shares of Series B preferred stock with a liquidation preference of $13.3 million and term debt of approximately $30 million. The credit agreement will be secured by substantially all of our assets, which will be contributed to Ascent Energy concurrently with the consummation of the Offer.

Plan of Reorganization.Our Bankruptcy Plan was confirmed by the Bankruptcy Court on December 29, 1999 and consummated effective January 14, 2000. As of the confirmation date, we had total assets of $33.9 million and liabilities of $96.0 million. Except as described herein, all of our liabilities as of the confirmation date were extinguished pursuant to the Bankruptcy Plan. Pursuant to the Bankruptcy Plan, we issued an aggregate of approximately $3.6 million of promissory notes to general unsecured creditors and paid approximately $300,000 to holders of convenience claims. All disputed claims related to the bankruptcy have been resolved and, by order entered on December 9, 2000, a final decree was entered that closed the bankruptcy case.

Fresh Start Reporting.We have accounted for the reorganization by using the principles of fresh start accounting required by AICPA Statement of Position 90-7, "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code." For accounting purposes, we assumed that the Bankruptcy Plan was consummated on December 31, 1999. Under the principles of fresh start accounting, our total assets were recorded at their assumed reorganization value, with the reorganization value allocated to identifiable tangible assets at their estimated fair value. Accordingly, our oil and gas full cost pool was reduced by approximately $60 million, our unevaluated oil and gas properties were increased by approximately $3 million, our other property and equipment was reduced by approximately $1.6 million, and our accumulated DD&A of $64.1 million was written off. In addition, our senior notes payable of $70 million, the interest payable of $11.1 million on the senior notes, our preferred stock of $13.5 million and the related deferred financing costs of $4.4 million were all written off.

The total reorganization value assigned to our proved oil and gas properties was estimated by adjusting the net pre-tax future cash flows discounted at a 10% annual rate (PV-10) of our proved reserves ($36.4 million) as set forth in the Estimate of Reserves and Future Revenue report on our proved oil and gas properties as of December 31, 1999, prepared by Netherland, Sewell & Associates. This report was prepared in accordance with SEC guidelines, utilizing constant prices existing as of December 31, 1999. We adjusted these prices to reflect the product prices used in valuing producing properties, and then we applied risking factors to the various categories of proved properties, discounting the properties as indicated:

Proved Category	Risk Factor
Proved Producing	95%
Proved Non-producing	75%
Proved Undeveloped	25%

Applying these risk factors and adjusting the product pricing resulted in an estimated net realizable value of the PV-10 of the proved properties of $25.5 million. Our other assets, including other property and equipment, were valued at $4.9 million. As a result of the implementation of fresh start accounting, our financial statements after consummation of the Bankruptcy Plan are not comparable to our financial statements of prior periods.

The effect of the Bankruptcy Plan and the implementation of fresh start accounting on our balance sheet as of December 31, 1999 are discussed in detail in "Item 8. Financial Statements and Supplementary Data."

Operating Environment

Our revenues, profitability and future growth and the carrying value of our oil and natural gas properties are substantially dependent on prevailing prices of oil and natural gas. Our ability to increase our borrowing capacity and to obtain additional capital on attractive terms is also influenced by oil and natural gas prices. Prices for oil and natural gas are subject to large fluctuation in response to relatively minor changes in the supply of or demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control. Any substantial and extended decline in the price of oil or natural gas would have an adverse effect on the carrying value of our proved reserves, borrowing capacity, revenues, profitability and cash flows from operations. Price volatility also makes it difficult to budget for and project the return on either acquisitions or development and exploitation projects.

We use the full cost method of accounting for our investment in oil and natural gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and natural gas reserves are capitalized into a ''full cost pool'' as incurred, and properties in the pool are depleted and charged to operations using the future gross revenue method based on the ratio of current gross revenue to total proved future gross revenues, computed based on current prices. To the extent that such capitalized costs (net of accumulated depreciation, depletion and amortization) less deferred taxes exceed the present value (using a 10% discount rate) of estimated future net cash flow from proved oil and natural gas reserves, and the lower of cost and fair value of unproved properties after income tax effects, excess costs are charged to operations. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date even if oil or natural gas prices increase. We were required to write down our asset base at the end of 1997 due to a downward revision of quantity estimates attributable to a single fault block in the Lake Enfermer Field, combined with significant declines in oil and natural gas prices from the end of 1996. During the second quarter of 1998, we were required to write down our asset base, again due primarily to the continuing decline in oil and natural gas prices. We had an additional full cost ceiling writedown of our asset base at the end of 1998. This writedown was the result of a significant revision to the reserves assigned to a single well in the Lake Enfermer Field, combined with further declines in both oil and natural gas prices during the final quarter of 1998. Lastly, we reduced our full cost pool in 1999 in connection with our bankruptcy.

Results of Operations

The following table sets forth certain operating information with respect to our oil and natural gas operations and summary information with respect to our estimated proved oil and natural gas reserves. See "Item 2. Properties - Natural Gas and Oil Reserves."

	Year Ended December 31,
	2000	1999	1998
Production:
Oil (MBbls)	270	343	393
Gas (MMcf)	1,797	3,091	4,944
Oil and gas (MBOE)	569	859	1,217
Sales data (in thousands):
Total oil sales	$ 7,421	$ 5,954	$ 4,752
Total gas sales	$ 7,276	$ 7,038	$ 11,198

Average sales prices:
Oil (per Bbl)	$ 27.49	$ 17.34	$ 12.09
Gas (per Mcf)	$ 4.05	$ 2.28	$ 2.27
Per BOE	$ 25.81	$ 15.13	$ 13.11

Average costs (per BOE):
Lease operating expenses	$ 5.89	$ 3.66	$ 2.76
General and administrative	$ 4.67	$ 3.51	$ 2.28
Depreciation, depletion and amortization	$ 7.87	$ 6.52	$ 8.58

Reserves at December 31:
Oil (MBbls)	2,667	1,612	1,531
Gas (MMcf)	26,260	18,996	14,558
Oil and gas (MBOE)	7,044	4,778	3,957
Present value of estimated pre-tax future Net cash flows (in thousands)	$182,313	$36,440	$19,169

Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

Our oil and gas revenues increased approximately $1.7 million, or 13% during 2000 to $14.7 million compared to $13.0 million in 1999. Production levels for 2000 decreased 33.7% to 569 thousand barrels of oil equivalent (''MBOE'') from 859 MBOE for 1999. Gas production volumes decreased 41.9%, while oil production volumes decreased 21.4%. Our average sale prices (including hedging activities) for oil and natural gas for 2000 were $27.49 per Bbl and $4.05 per Mcf versus $17.34 per Bbl and $2.28 per Mcf in 1999. Revenues increased $5.9 million due to higher oil and gas prices during 2000, offset by a $4.2 million decrease in revenues due to the aforementioned production decreases.

On a BOE basis, lease operating expenses increased 60.7%, to $5.89 per BOE for 2000 from $3.66 per BOE in 1999. For 2000, actual lease operating expenses were up 6.6%, from $3.1 million in 1999 to $3.4 million in 2000. This increase was due primarily to an increase in workover activity in 2000.

Our effective severance tax rate as a percentage of oil and gas revenues decreased to 4.4% for 2000 from 5.6% for 1999. This relatively low effective rate is attributable to the increased production from wells that have a state severance tax exemption under Louisiana's severance tax abatement program. The decreases in the effective tax rates between 1999 and 2000 are partially offset by the increase in the gas severance tax rate in 2000.

For 2000, depreciation, depletion and amortization (''DD&A'') expense decreased 19.9% from 1999. The decrease for the year is attributable to our decreased production and related future capital costs in 2000 and the upward revision of reserves. On a BOE basis, which reflects the decreases in production, the DD&A rate for 2000 was $7.87 per BOE compared to $6.52 per BOE for 1999, an increase of 21%. The increase in DD&A per BOE was due primarily to an increase in the full cost pool and variations in pricing during the year. Reserve additions as of December 31, 2000, affected only the fourth quarter DD&A calculation.

For 2000, on a BOE basis, general and administrative (''G&A'') expenses increased 32.9%, from $3.51 per BOE in 1999 to $4.67 in 2000. The increase in G&A per BOE in 2000 was due to the decrease in production during 2000 as compared to 1999. Actual G&A expenses decreased 11.8%, from $3.0 million in 1999 to $2.7 million in 2000. The decrease in actual G&A expenses for 2000 was primarily the result of the capitalization of G&A expenses, in the amount of $842,391, into the full cost pool in 2000. No G&A was capitalized into the full cost pool for 1999 due to the bankruptcy and lack of funds to conduct acquisition and exploration activities. Without this capitalization of G&A in 2000, G&A on a BOE basis increased 75%, to $6.14 in 2000. Actual G&A in 2000, without the capitalization in 2000, increased $485,000 primarily due to income and franchise taxes, the addition of directors' fees and increases in contract services related to the appointment of our new president in June 2000. The recapitalization costs incurred in conjunction with our reorganization of $899,000 were not included in recurring G&A for comparison purposes.

The discounted present value of our reserves increased 500%, from $36.4 million at the end of 1999 to $182 million at the end of 2000, primarily as a result of the significant increases in both oil and gas prices between December 1999 and December 2000, combined with the new reserves attributable to workovers and recompletions of wells in our Boutte and Lake Enfermer Fields. Our realized oil prices increased 58.6% between December 31, 1999 and December 31, 2000, from an average price per barrel of $17.34 for 1999 to an average price of $27.49 for 2000. Our realized gas prices in 2000 increased 77.8% over the realized 1999 price, from an average price per Mcf of $2.28 for 1999 to an average price per Mcf of $4.05 for 2000.

Interest expense for 2000 decreased from $6.2 million in 1999 to $0 for 2000. Actual interest expense of $274,000 was incurred in 2000 but was capitalized into the unevaluated property within the full cost pool for reporting purposes. This decrease of $5.9 million in interest expense is due to the cessation of interest payable on our senior notes, which were canceled as a result of the reorganization effective January 14, 2000.

Due to the factors described above, our net income from operations before extraordinary items for 2000 was $1.7 million, an increase of $2.1 million from the net loss of $349,405 for 1999.

We were required to establish a net deferred tax liability calculated at the applicable Federal and state tax rates resulting primarily from financial reporting and income tax reporting basis differences in oil and gas properties. Accordingly, as a result of fresh start accounting a net deferred tax liability of $9.9 million was recorded at December 31, 1999.

Year Ended December 31, 1999 Compared to Year Ended December 31, 1998

Our oil and gas revenues decreased approximately $2.9 million, or 18% during 1999 to $13.0 million compared to $16.0 million in 1998. Production levels for 1999 decreased 29% to 859 MBOE from 1,217 MBOE for 1998. Gas production volumes decreased 37.5%, while oil volumes decreased 12.7%. Our average sale prices (including hedging activities) for oil and natural gas for 1999 were $17.34 per Bbl and $2.28 per Mcf versus $12.09 per Bbl and $2.27 per Mcf in 1998. Revenues decreased $5.2 million due to the aforementioned production decreases, offset by a $2.3 million increase in revenues due to higher oil and gas prices during 1999.

On a BOE basis, lease operating expenses increased 32%, to $3.66 per BOE for 1999 from $2.76 per BOE in 1998. For 1999, actual lease operating expenses were down 8.8%, from $3.4 million in 1998 to $3.1 million in 1999. This decrease was due to a decrease in 1999 in the volumes of oil and gas produced.

For 1999, DD&A expense decreased 47% from 1998. The decrease for the year is attributable to our decreased production and related future capital costs in 1999 and the upward revision of reserves. On a BOE basis, which reflects the decreases in production, the DD&A rate for 1999 was $6.52 per BOE compared to $8.58 per BOE for 1998, a decrease of 24%.

For 1999, on a BOE basis, G&A expenses increased 53%, from $2.28 per BOE in 1998 to $3.51 in 1999. Actual G&A expenses increased 8.6%, from $2.8 million in 1998 to $3.0 million in 1999. This increase was due primarily to the administrative costs of the reorganization activity during 1999. The recapitalization costs incurred in conjunction with reorganization of $1,184,000 were not included in recurring G&A for comparison purposes.

The discounted present value of our reserves increased 90%, from $19.2 million at the end of 1998 to $36.4 million at the end of 1999, primarily as a result of the new reserves attributable specifically to the Simoneaux 26 well in our Boutte Field, combined with the significant increases in both oil and gas prices between December 1998 and December 1999. Our realized oil prices increased 43% between December 31, 1998 and December 31, 1999, from an average price per barrel of $12.09 on December 31, 1998 to an average price of $17.34 on December 31, 1999. Our realized gas prices on December 31, 1999 increased 0.4% over the December 31, 1998 price, from an average price per Mcf of $2.27 in 1998 to an average price per Mcf of $2.28 in 1999. We experienced a $19.6 million writedown of our full cost pool during 1998 due to ceiling test limitations. We did not experience any such ceiling test writedown of our full cost pool in 1999.

Interest expense for 1999 decreased from $10.1 million in 1998 to $6.2 million for 1999. This decrease of $3.9 million in interest expense is due to the cessation of interest payable on our senior notes from August 6, 1999, the date we filed for protection under the United States Bankruptcy Code.

Due to the factors described above, the net loss from operations before reorganization costs and extraordinary items decreased from $30.5 million for 1998 to a loss of $0.3 million for 1999.

Liquidity and Capital Resources

Working Capital and Cash Flow.At December 31, 2000, we had $4.7 million of working capital compared to $1.7 million at December 31, 1999. This was primarily due to the significant increase in oil and, more significantly, natural gas prices during 2000. During 2000, we completed five recompletion/workover projects, of which all five were successful. We did not drill any wells in 2000.

We believe that our cash on hand plus expected normal cash flow from operations will be sufficient to fund our capital expenditure plans for development and exploitation activities for 2001 and our obligations on the long term notes payable issued pursuant to the Bankruptcy Plan. In addition, we will continue to pursue farm-in or joint venture partners for drilling prospects on our existing properties. The amount of capital expenditures for these drilling prospects will depend on the participation by other working interest owners, the availability of capital and other industry conditions.

The foregoing discussion includes many forward looking statements which are subject to the risks and uncertainties noted above in "Item 1 - Cautionary Statements" which could cause the actual results to differ materially from our expectations.

Hedging Activities.With the objective of achieving more predictable revenues and cash flows and reducing our exposure to fluctuations in oil and natural gas prices, we have entered into hedging transactions of various kinds with respect to both oil and natural gas. While the use of these hedging arrangements limits the downside risk of reverse price movements, it may also limit future revenues from favorable price movements. During 1998 and 1999, we entered into forward sales arrangements with respect to a portion (between 30-50%) of our estimated natural gas sales. As of March 2001, we had no open forward sales arrangements for natural gas for 2001. We did hedge 200 barrels per day of our oil production in October 1999 for the twelve months ending November 30, 2000, at a price of $22.05 per barrel.

We plan to continuously reevaluate our hedging program in light of market conditions, commodity price forecasts, capital spending and debt service requirements. We may hedge additional volumes into 2001 or we may determine from time to time to terminate our then existing hedging positions.

New Accounting Standards

The Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" in June 1997. This statement establishes accounting and reporting standards for derivative instruments and hedging activities. According to Statement No. 133, we must recognize the fair value of all derivative instruments as either assets or liabilities in our consolidated balance sheet. A derivative instrument meeting certain conditions may be designated as a hedge of a specific exposure. Accounting for changes in a derivative's fair value will depend on the intended use of the derivative and the resulting designation. Any transition adjustments resulting from adopting this statement will be reported in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle. As described under the heading "Quantitative and Qualitative Disclosures About Market Risk" below, we may make use of derivative instruments to hedge specific market risks. We adopted Statement No. 133 on January 1, 2001. Because of the nature of our hedging activities, the adoption of Statement No. 133 did not have a material impact on our financial position or results of operations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Hedging Activity - Our revenues are derived from the sale of oil and natural gas production. From time to time, we enter into hedging transactions that fix, for specific periods and specific volumes of production, the prices we will receive for our production. These agreements reduce our exposure to decreases in the commodity prices on the hedged volumes, while also limiting the benefit we might otherwise have received from increases in commodity prices of the hedged production. The impact of hedges is recognized in oil and gas sales in the period the related production revenues are accrued. See "Item 1. Cautionary Statements - Our use of hedging transactions for a portion of our oil and gas production may limit future revenues from price increases and result in significant fluctuations in our stockholders' equity".

Despite the measures we may take to attempt to control price risk, we will remain subject to price fluctuations for oil and natural gas sold in the spot market. Prices received for natural gas sold in the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Oil and natural gas prices can change dramatically primarily as a result of the balance between supply and demand. The trend since 1998 has been upward, with our average natural gas price received for 2000 of $4.05 per Mcf, up from $2.28 per Mcf in 1999 and $2.27 per Mcf in 1998. Our average oil price received for 2000 was $27.49 per Bbl, up from our average price received of $17.34 in 1999 and $12.09 in 1998. There can be no assurance that prices will not decline from current levels. Declines in domestic oil and natural gas prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis.

Based on projected annual production volumes for 2001, a 10% decline in the prices we receive for our oil and natural gas production would have an approximate $21.6 million negative impact on our discounted future net revenues.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information concerning this Item begins on Page F-1

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following table provides information concerning our directors and executive officers. All directors hold office until the next annual meeting of stockholders of the Company and until their successors have been duly elected and qualified. All officers serve at the discretion of the Board of Directors.

Name	Age	Position	Since
Nicholas Tell, Jr.	39	Chairman of the Board	2000
Jerry W. Box	62	Director	2000
Jeffrey Clarke	55	Director and President	2000
McLain J. Forman, Ph.D.	72	Director and Chief Executive Officer	1982
Harold C. Block	69	Vice President of Land and Acquisition	1997
Marvin J. Gay	58	Vice President of Finance and Administration	1997
Michael A. Habetz	52	Vice President, Manager of Operations	1997
Michael H. Price	52	Chief Financial Officer	1998

The Stockholders' Agreement provides that, subject to certain restrictions, Trust Company of the West ("TCW"), Jefferies & Company, Inc. ("Jefferies") and McLain Forman shall each be entitled to designate one member of the Board of Directors. The fourth member shall be elected by the stockholders of the Company in accordance with the Company's bylaws. The agreement further provides that neither the TCW designee nor the Jefferies designee, nor the fourth director to be elected by the stockholders may be a current director, officer, or employee of Jefferies or any affiliate of Jefferies.

A brief biography of each director and executive officer follows:

Nicholas Tell, Jr., is the Managing Director, Capital Markets and Special Situations, of TCW. Mr. Tell joined TCW when TCW acquired Crescent in 1995. Previously, Mr. Tell was Vice President and Counsel of Crescent where he structured and negotiated many of the firm's private investments. Prior to joining Crescent, Mr. Tell was a Senior Associate at Latham & Watkins. From 1987 through 1992, Mr. Tell was involved in a wide variety of corporate transactions, including mergers and acquisitions and corporate financings for below-investment-grade companies. Mr. Tell received his Juris Doctor from the University of Chicago and his B.A. from Carleton College.

Jerry W. Box served as the President and Chief Operating Officer of Oryx Energy Company from 1998 until shortly after the merger of Oryx Energy Company with Kerr-McGee Corporation in early 1999. From 1988 through 1998, Mr. Box served in various other capacities with Oryx Energy Company. Mr. Box holds a BS and an MS, in Geology, from Louisiana Tech University. He is also a graduate of the Program for Management Development at Harvard Business School.

Jeffrey Clarke has been the President of the Company since June 2000. From September 1993 to March 2000, Mr. Clarke served as Chairman and Chief Executive Officer of Coho Energy, Inc., an independent energy company engaged in the development and production of, and exploration for, crude oil and natural gas principally in Mississippi and Oklahoma. From August 1990 to September 1993, Mr. Clarke served as President and Chief Operating Officer of Coho Energy, Inc. Prior to that time, Mr. Clarke served in various capacities with Coho Resources, Ltd. and Coho Resources, Inc., affiliates of Coho Energy, Inc. Coho Energy, Inc. and certain of its affiliates filed for protection under Chapter 11 of the United States Bankruptcy Code on August 23, 1999. Coho's bankruptcy reorganization plan was approved in March 2000. Mr. Clarke holds a BS, in Physics, from University of Wales, 1967, and conducted postgraduate work in Physics at the University of East Anglia, 1967-1968.

McLain J. Forman, Ph.D. founded the Company in 1982 and has served as President and Chief Executive Officer of the Company since inception. Dr. Forman served as Chairman of the Board from 1982 through 1999. Dr. Forman began his career in 1955 as a consulting geologist as a member of the predecessor firm of Atwater Consultants Ltd. Since 1960, Dr. Forman has directed and supervised exploration and production activities for clients and for his own account in the Gulf Coast Region. From 1972 to 1982, Dr. Forman concentrated his efforts on originating and developing wildcat exploration prospects with various industry and financial partners. With the formation of the Company in 1982, his focus shifted to exploratory and development prospects, and in 1991 the Company began to selectively acquire and exploit producing properties. Dr. Forman earned a B.S. degree in Geology from Tulane University and an M.A. degree and a Ph.D. in geology from Harvard University.

Harold C. Block is the Vice President of Land and Acquisitions. Mr. Block joined Forman Exploration Company, the predecessor of the Company, in 1973 as Manager of the Land Department, and in 1982 he moved to his current position with the Company. Mr. Block began his career with F.A. Callery, Inc. in 1957, where he became Land Manager in 1959. Upon leaving Callery in 1971 until he joined the Company, Mr. Block was a consultant and organized and conducted an oil and gas exploration program. Mr. Block has a B.B.A. degree in Management from the University of Houston.

Michael A. Habetz is Vice President, Manager of Operations. Mr. Habetz has been a Vice President and the Manager of Operations since he joined the Company in 1993. From 1970 to 1987, he held various supervisory and management positions with Texaco and Edwin L. Cox, where he was responsible for all phases of drilling, completion, workover and production operations. From 1987 until 1991, Mr. Habetz provided consulting engineering services through Energy Research and Development Corporation, and in 1991, he began to provide those services on a consulting basis for the Company. Mr. Habetz holds a B.S. degree in Mechanical Engineering from Louisiana State University.

Michael H. Price is the Chief Financial Officer of the Company. Before joining the Company in December, 1997, Mr. Price was Vice President of the Chase Manhattan Bank for twelve years, and was earlier employed by Atwater Consultants and Amoco International Oil Company. Mr. Price holds an MBA from the University of Chicago and earned an M.Sc. from the London School of Economics and Political Science.

Marvin J. Gay is the Vice President of Finance and Administration. Mr. Gay has been a Vice President of the Company since he joined the Company at its inception in 1982. Mr. Gay was the Controller and Treasurer of Forman Exploration Company, the predecessor of the Company, from 1974 to 1982. Before joining the Company, Mr. Gay was a consultant with Arthur Andersen & Co. Mr. Gay holds a B.B.A. in Accounting from the University of Mississippi. He is a Certified Public Accountant and a member of the American Institute of Certified Public Accountants.

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth certain information for each of the fiscal years ended December 31, 2000, 1999, and 1998 with respect to the compensation paid to Mr. Forman, the Chief Executive Officer and Chief Operating Officer, Mr. Clarke, the President, and the four other most highly compensated executive officers of the Company. No other executive officers of the Company received annual compensation (including salary and bonuses earned) that exceeded $100,000 for the fiscal years ended December 31, 2000, 1999 and 1998.

Name and Principal Position	Year	Annual Compensation		Long-Term Compensation Securities Underlying Options Awarded	All Other Compensation
Name and Principal Position	Year	Salary	Bonus		All Other Compensation
McLain J. Forman, PhD., Chief Executive Officer	2000 1999 1998	$225,000 225,000 225,500	$202,500 -0- -0-	$ -0- -0- -0-	$ -0- -0- -0-
Jeffrey Clarke, President	2000 1999 1998	-0- -0- -0-	-0- -0- -0-	-0- -0- -0-	120,000 (1) -0- -0-
Harold C. Block, Vice President of Land and Acquisitions	2000 1999 1998	131,000 131,000 131,000	39,300 -0- -0-	-0- -0- -0-	-0- -0- -0-
Michael A. Habetz, Vice President, Manager of Operations	2000 1999 1998	130,000 130,000 130,000	39,000 -0- -0-	-0- -0- -0-	-0- -0- -0-
Mike H. Price, Chief Financial Officer	2000 1999 1998	140,000 129,333 36,000	42,000 -0- -0-	-0- -0- -0-	-0- -0- 81,000 (2)
Marvin J. Gay Treasurer, Vice President of Finance and Administration	2000 1999 1998	120,000 114,833 104,500	36,000 -0- -0-	-0- -0- -0-	-0- -0- -0-

(1) The "Other Compensation" paid to Mr. Clarke was paid to him over the six month period from July 1, 2000 through December 31, 2000, during which time he was working for the Company on a contractual basis.

(2) The "Other Compensation" paid to Mr. Price was paid to him during the time in which he was working for the Company on a contractual basis prior to his employment by the Company.

401(K) Plan

The Company has adopted a defined contribution retirement plan that complies with Section 401(k) of the Code (the ''401(k) Plan''). Pursuant to the terms of the 401(k) Plan, all employees with at least one year of continuous service are eligible to participate and may contribute up to 15% of their annual compensation (subject to certain limitations imposed under the Code). The 401(k) Plan provides that a discretionary match of employee contributions may be made by the Company in cash. The Company made a $58,398 matching contribution to the 401(k) Plan in 1998 based upon each individual employee's plan contributions during 1998. In December 1999 the Company made another matching contribution, in the amount of $72,012, again based upon each individual employee's plan contributions for 1999. During 2000, the Company made monthly matching contributions, in the amount of $73,806 based upon each individual employee's plan contributions for the respective month. These matching employer contributions to the 401(k) Plan are fully vested to the individuals over a three-year period. Employee contributions under the 401(k) Plan are 100% vested and participants are entitled to payment of vested benefits upon termination of employment. The amounts held under the 401(k) Plan are invested among various investment funds maintained under the 401(k) Plan in accordance with the directions of each participant.

Compensation of Directors

Directors of the Company will receive compensation for their service as directors in the amount of $5,000 per month for up to 18 meetings per year and an additional $3,000 per meeting for each additional meeting above 18 per year. Directors of the Company are also entitled to reimbursement of their reasonable out-of-pocket expenses in connection with their travel to and attendance at meetings of the Board of Directors or committees thereof.

Employment Agreements

Effective January 14, 2000, the Company entered into employment agreements with Messrs. Forman, Price, Block, Habetz and Gay (the "Named Executive Officers"), among others. The agreements provide for employment of the Named Executive Officers in their current positions through April 30, 2002, subject to earlier termination, at a fixed annual salary and an annual bonus based upon the attainment of certain quantitative goals. The agreements provide for a salary of $225,000, $140,000, $131,000, $130,000 and $120,000 per calendar year, respectively for Messrs. Forman, Price, Block, Habetz and Gay. The agreement with Mr. Forman provides for a maximum bonus of 90% of his base salary and the agreements with Messrs. Price, Block, Habetz and Gay provide, for a maximum bonus of 30% of such individual's base salary.

If the Company terminates the Named Executive Officer's employment without Cause (as defined in the agreement) or the Named Executive Officer terminates his employment for Good Reason (as defined in the agreement), the Company must (i) pay the executive his accrued base salary as of the date of termination plus his annual base salary for the remainder of his employment term and (ii) provide the executive with continuing group medical, dental, disability and life insurance benefits until the later of 18 months from the date of termination or the original expiration date of the employment term. Should the executive prevail in any cause of action, suit, arbitration or other legal proceeding initiated to enforce the provisions of the agreement, the Company indemnifies the executive for all costs including reasonable attorneys' fees incurred by the executive in connection with such cause of action, suit, arbitration or other legal proceeding. If the executive terminates his employment for reasons other than Good Reason or the Company terminates the executive for Cause, the Company must pay to the executive his accrued base salary as of the date of termination. If the executive is terminated for Cause following a Change of Control (as defined in the agreement), the executive will also be paid his base salary for the remainder of his employment term and will be provided continuing group medical, dental, disability and life insurance benefits until the later of 18 months from the date of termination or the original expiration date of the employment term.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table and notes thereto set forth information regarding ownership of shares of the Company's Common Stock as of March 30, 2001:

Principal Shareholders	Number of Shares of Common Stock Owned⁽¹⁾	Percent of Outstanding Common Stock⁽²⁾
Trust Company of the West 11100 Santa Monica Boulevard Suite 2000 Los Angeles, California 90025	438,100⁽³⁾	44.5%
Jefferies & Company, Inc. 11100 Santa Monica Boulevard 12th Floor Los Angeles, California 90025	326,261	33.2%
Bank of America Investments, Inc. 233 South Wacker Drive Suite 2800 Chicago, Illinois 60606-6306	88,376	9.0%
Alliance Capital 1345 Avenue of the Americas 37^th Floor New York, New York 10105	79,336	8.1%

____________________

(1) Excludes shares that may be acquired within 60 days upon exercise of Class A, Class B, Class C or Class D Warrants. The exercise prices for the warrants are as follows: $34.74 for Class A Warrants, $92.80 for Class B Warrants, $117.80 for Class C Warrants, and $137.80 for Class D Warrants. The following table sets forth information regarding ownership of shares of the Company's Common Stock, calculated in accordance with Rule 13d-3 under the Securities Exchange Act of 1934.

Principal Shareholders	Common Shares	Class A Warrants	Class B Warrants	Class C Warrants	Class D Warrants	Total	Percent of Outstanding Common Stock^(a)

Trust Company of the West	438,100	8,662	25,971	25,971	25,971	524,675^(b)	35.6%
Jefferies & Company, Inc.	326,261	3,841	11,520	11,520	11,520	364,662	24.7%
Bank of America Investment, Inc.	88,376	1,064	3,192	3,192	3,192	99,016	6.7%
Alliance Capital	79,336	982	2,946	2,946	2,946	89,156	6.1%

Management

McLain J. Forman	10	33,690	101,100	101,100	101,100	337,000	22.9%
All Directors and Executive	10	33,690	101,100	101,100	101,100	337,000	22.9%
Officers as a group (8 persons)

_________________________

	(a)	Based on 1,474,558 shares of outstanding Common Stock.
	(b)	Includes 14,851 shares held on behalf of Brown University, 1,637 shares held on behalf of Allstate Insurance Co., and 3,273 shares held on behalf of Allstate Life Insurance Company.
(2)		Based on 984,042 shares of outstanding Common Stock.
(3)		Includes 13,214 shares held on behalf of Brown University.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

In connection with the Pontotoc acquisition, Ascent Energy, our wholly-owned subsidiary, has agreed to pay its president, Jeffrey Clarke, a success fee in the amount of approximately $350,000.

PART IV.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. Financial Statements

The following financial statements of the Company and the Report of the Company's Independent Public Accountants thereon are included on pages F-1 through F-18 of this Form 10-K.

Report of Independent Public Accountants
Balance Sheet as of the years ended December 31, 2000 and 1999
Statement of Operations for the three years in the period ended December 31, 2000
Statement of Stockholders' Equity (Deficit) for the three years in the period ended December 31, 2000
Statement of Cash Flows for the three years in the period ended December 31, 2000
Notes to the Financial Statements

2. Financial Statement Schedules

All schedules are omitted because the required information is inapplicable or the information is presented in the Financial Statements or the notes thereto.

3. Exhibits

The following instruments and documents are included as Exhibits to this Form 10-K:

__________	______________________________________________________________________________
Exhibit No.	Exhibit

3.1		Amended and Restated Articles of Incorporation dated January 14, 2000.⁽¹⁾
3.1		Amended and Restated Bylaws.⁽²⁾
4.1		Stockholders' Agreement dated as of January 14, 2000 by and among Forman Petroleum Corporation and each of the other Persons listed on the signature pages thereto.⁽¹⁾
10.1		Registration Rights Agreement dated as of January 14, 2000 by and between Forman Petroleum Corporation and each of the other Persons listed on the signature pages thereto.⁽¹⁾
10.2		Warrant Agreement dated as of January 14, 2000 by and between Forman Petroleum Corporation and each of the other Persons listed on the signature pages thereto.⁽¹⁾
10.3		Form of Employment Agreement.⁽¹⁾
21.1		Subsidiaries of the Company.
23.1		Consent of Arthur Andersen, L.L.P.

___________________

(1)	Incorporated by reference to the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1999.
(2)	Incorporated by reference to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2000.

Reports on Form 8-K

None

INDEX TO FINANCIAL STATEMENTS

	Page
Report of Independent Public Accountants	F–2
Balance Sheets as of the Years Ended December 31, 2000 and 1999	F–3
Statements of Operations for each of the Three Years in the Period Ended December 31, 2000	F–4
Statements of Stockholder's Equity (Deficit) for each of the Three Years in the Period Ended December 31, 2000	F–5
Statements of Cash Flows for each of the Three Years In the Period Ended December 31, 2000	F–6
Notes to Financial Statements	F–7

F –1

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders of Forman Petroleum Corporation:

We have audited the accompanying balance sheets of Forman Petroleum Corporation (a Louisiana corporation) as of December 31, 2000 and 1999, and the related statements of operations, stockholders' equity (deficit) and cash flows for the year ended December 31, 2000 (post–confirmation) and the years ended December 31, 1999 and 1998 (pre–confirmation). 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 auditing standards generally accepted in the United States. 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 financial statements referred to above present fairly, in all material respects, the financial position of Forman Petroleum Corporation as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States.

As discussed in Note 1, effective December 29, 1999, the Company was reorganized under a plan confirmed by the United States Bankruptcy Court in the United States District Court for the Eastern District of Louisiana and adopted a new basis of accounting whereby all remaining assets and liabilities were adjusted to their estimated fair values. Accordingly, financial statements for periods subsequent to the reorganization are not comparable to the financial statements presented for prior periods.

New Orleans, Louisiana,
March 12, 2001

F–2

FORMAN PETROLEUM CORPORATION

BALANCE SHEETS

	December 31,
	2000	1999

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$ 3,728,332	$ 3,180,925
Accounts receivable	135,473	236,663
Oil and gas revenue receivable	2,594,724	1,359,393
Deferred taxes	371,778	–
Unbilled well costs	198	257
Prepaid expenses and tax overpayment	372,960	43,845
Total current assets	7,203,465	4,821,083

PROPERTY AND EQUIPMENT:
Oil and gas properties, full cost method	28,481,661	25,515,529
Unevaluated oil and gas properties	5,006,197	4,732,139
Other property and equipment	287,524	200,000
	33,775,382	30,447,668
Less– accumulated depreciation, depletion and amortization	(4,484,364)	–

Net property and equipment	29,291,018	30,447,668

OTHER ASSETS:
Escrowed and restricted funds	487,783	490,044

Total assets	$ 36,982,266	$ 35,758,795

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities	$ 518,760	$ 1,571,710
Undistributed oil and gas revenues	745,024	895,064
Current portion of notes payable	1,219,214	640,608
Total current liabilities	2,482,998	3,107,382
Notes payable	1,309,790	2,066,173
Deferred tax liability	10,788,208	9,900,580
Total liabilities	14,580,996	15,074,135
STOCKHOLDERS' EQUITY:
Common stock, no par value, 10,000,000 shares authorized, 984,042 and 984,032 shares issued and outstanding at December 31, 2000 and 1999, respectively	20,685,007	20,684,660
Retained earnings	1,716,263	–
Total stockholders' equity	22,401,270	20,684,660
Total liabilities and stockholders' equity	$ 36,982,266	$ 35,758,795

The accompanying notes are an integral part of these financial statements.

F – 3

FORMAN PETROLEUM CORPORATION

STATEMENTS OF OPERATIONS

		Years Ended December 31,
			2000		1999		1998
Revenues:
Oil and gas sales		$ 14,696,688		$ 12,992,714		$ 15,950,329
Interest income		186,284		–		239,581
Overhead reimbursements		41,173		64,980		71,325
Other income		36,344		58,292		14,608

	Total revenues	14,960,489		13,115,986		16,275,843

Costs and expenses:
Production taxes		559,334		731,542		540,837
Lease operating expenses		3,353,441		3,146,581		3,359,200
General and administrative expenses		2,656,765		3,013,809		2,774,498
Interest expense		–		6,243,778		10,122,131
Full cost ceiling writedown		–		–		19,575,047
Recapitalization expense		109,130		–		–
Depreciation, depletion and amortization		4,484,364		5,601,733		10,442,032

	Total expenses	11,163,034		18,737,443		46,813,745

Net income (loss) from operations before reorganization items, income taxes and extraordinary item		3,797,455		(5,621,457)		(30,537,902)
Reorganization items:
Reorganization costs		(898,760)		(1,184,111)		–
Adjust accounts to fair value (Note 1)		–		6,268,022		–

Net income (loss) before income taxes and extraordinary item		2,898,695		(537,546)		(30,537,902)
Provision (benefit) for income taxes		1,182,432		(188,141)		–

Net income (loss) before extraordinary item		1,716,263		(349,405)		(30,537,902)
Extraordinary gain on extinguishment of debt, net of taxes of $10,088,721		–		46,724,052		–

Net income (loss)		1,716,263		46,374,647		(30,537,902)
Preferred stock dividends		–		(1,152,991)		(1,729,068)
Net income (loss) attributable to common shares		$ 1,716,263		$45,221,656		$ (32,266,970)

Per common share amounts:
Net income (loss) per share attributable to common shares before extraordinary item		$ 1.74		$( 16.69)		$(358.52)
Extraordinary item per share		–		519.15		–

Net income (loss) per share		$ 1.74		$ 502.46		$(358.52)

Weighted average basic and diluted shares outstanding		984,042		90,000		90,000

The accompanying notes are an integral part of these financial statements.

F –4

FORMAN PETROLEUM CORPORATION

STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)

Common
Stock

Treasury
Stock

Additional
Paid–In
Capital

Accumulated
Deficit

Total

BALANCE, December 31, 1997		$ 1,000		$ (10)		$ –	$(24,174,967)		$(24,173,977)

	Net loss	–		–		–	(30,537,902)		(30,537,902)
ACCRETION OF DISCOUNT ON MANDATORILY REDEEMABLE PREFERRED STOCK				–		–	(41,666)		(41,666)
ACCRUE DIVIDENDS ON MANDATORILY REDEEMABLE PREFERRED STOCK				–		–	(1,729,068)		(1,729,068)

BALANCE, December 31, 1998		$ 1,000		$ (10)		$ –	$(56,483,603)		$(56,482,613)
	Net income	–	–		–			46,374,647		46,374,647
ACCRETION OF DISCOUNT ON MANDATORILY REDEEMABLE PREFERRED STOCK		–	–		–			(27,778)		(27,778)
ACCRUE DIVIDENDS ON MANDATORILY REDEEMABLE PREFERRED STOCK		–	–		–			(1,152,991)		(1,152,991)
OLD COMMON STOCK SURRENDERED		(1,000)	10		–			–		(990)
NEW COMMON STOCK ISSUED IN REORGANIZATION		20,684,660	–		–			–		20,684,660
DISCHARGE OF PREFERRED STOCK IN REORGANIZATION		–	–		–			13,555,971		13,555,971
FRESH START ACCOUNTING ADJUSTMENTS (Note 1)		–	–		–			(2,266,246)		(2,266,246)

BALANCE, December 31, 1999		$20,684,660	$ –		$ –			$ –		$20,684,660

NEW COMMON STOCK ISSUED IN EXCHANGE FOR WARRANTS		347	–		–			–		347
NET INCOME		–	–		–			1,716,263		1,716,263

BALANCE, December 31, 2000		$20,685,007	$ –		$ –			$ 1,716,263		$22,401,270

The accompanying notes are an integral part of these financial statements.

F – 5

FORMAN PETROLEUM CORPORATION

STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2000		1999	1998

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 1,716,263	$ 46,374,647		$ (30,537,902)
Adjustments to reconcile net income (loss) to net cash provided by operating activities–
Extraordinary item	–	(46,724,052)		–
Depreciation and amortization	4,484,364	5,601,733		30,316,309
Deferred income tax provision (benefit)	515,850	(188,141)		–
Adjust accounts to fair value	–	(6,268,022)		–
Interest on obligations discharged in bankruptcy	–	6,144,915		–
Withdrawal from interest escrow account	–	–		3,978,148
Change in assets and liabilities–
Decrease (Increase) in oil and gas revenue receivable	(1,235,331)	(702,960)		1,750,882
Decrease (Increase) in accounts receivable	101,190	(188,833)		550,161
(Increase) Decrease in unbilled well costs	59	11,067		(3,166)
Decrease (Increase) in prepaid expenses and tax overpayment	(329,115)	253,309		(297,154)
(Decrease) Increase in accounts payable and accrued liabilities	(1,052,950)	1,500,435		(4,059,766)
(Decrease) Increase in undistributed oil and gas revenues	(150,040)	(473,127)		(258,274)
Increase in interest payable	–	–		5,512,640
Decrease (Increase) in advance to operator	–	1,200,000		(1,200,000)
Decrease in capitalized recapitalization costs	–	384,313		–

Net cash provided by operating activities	4,050,290	6,925,284		5,751,878

CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties	(3,240,190)	(5,173,645)		(4,523,589)
Reduction of escrow account	2,261	3,437		21,615
Purchase of other property and equipment	(87,524)	(48,639)		(67,964)

Net cash used in investing activities	(3,325,453)	(5,218,847)		(4,569,938)

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of notes payable	(177,777)	–		–
Proceeds from sale of common stock	347	–		–
Deferred financing costs	–	–		(165,321)

Net cash used in financing activities	(177,430)	–		(165,321)

NET INCREASE IN CASH AND CASH EQUIVALENTS	547,407	1,706,437		1,016,619
CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD	3,180,925	1,474,488		457,869

CASH AND CASH EQUIVALENTS – END OF PERIOD	$ 3,728,332	$ 3,180,925		$ 1,474,488

SUPPLEMENTAL DISCLOSURES:
Cash paid for–
Interest	$ 274,058	$ 82,451		$ 4,609,491

Income taxes	$ 920,500	$ –		$ –

The accompanying notes are an integral part of these financial statements.

F – 6

FORMAN PETROLEUM CORPORATION

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2000 AND 1999

1. OPERATIONS AND REORGANIZATION:

Forman Petroleum Corporation ("Forman" or the "Company"), a Louisiana corporation, is an independent energy company engaged in the exploration, development, acquisition and production of crude oil and natural gas, with operations primarily in the onshore Gulf Coast area of Louisiana. Forman was incorporated in Louisiana in 1982 and began operations in that year.

Restructuring and Merger

In January, 2001, the Company's majority stockholders organized Acsent Energy Inc., a Delaware corporation (Ascent), to acquire Pontotoc Production, Inc. (Pontotoc). Ascent's outstanding common stock is represented by 1,000 subscribed, but unpaid, shares of $0.001 par value stock owned in equal halves by TCW Shared Opportunity Fund, L.P. (TCW), an affiliate of TCW Asset Management Corporation, and Jefferies & Company, Inc. (Jefferies), who also together own controlling interest, subject to certain restrictions, in the Company. Ascent is authorized to issue an aggregate 30,000,000 shares of stock consisting of 20,000,000 shares of $0.001 par value common stock and 10,000,000 shares of $0.001 par value, preferred stock. Ascent expects to engage in the exploration, development and production of oil and gas in the Gulf Coast and mid–continent regions of the United States.

In January 2001, Ascent entered into an agreement to acquire all outstanding common stock (5.3 million shares as of March 2001) of Pontotoc. Under the agreement, the consideration for each share of Pontotoc will be $9 in cash and one share of Ascent's 8% Series B Convertible Preferred Stock (the Series B Preferred) with a liquidation value of $2.50 per share. This stock will be redeemable by Ascent at any time, convertible to common shares at any time at the option of the holder, and will mandatorily convert to common stock of Ascent on the two–year anniversary of its issuance, such that the Series B Preferred holders would hold 10% of the fully diluted common stock of Ascent as of the consummation of the acquisition. Upon conversion, the Series B Preferred holders would receive cash for accrued and unpaid dividends. Ascent will also pay cash of $500,000 to Pontotoc option holders for the difference between $10.50 and the strike price of their options. This acquisition will be accounted for as a purchase and the total consideration is estimated to be approximately $61 million. Upon the closing of the acquisition, based on the offer, Ascent expects to have outstanding 21,100 shares of Series A Preferred stock with a liquidation preference of $21.1 million, 5.3 million shares of Series B Preferred stock with a liquidation preference of $13.3 million and term debt of approximately $30 million.

In connection with this transaction, the Company will acquire all outstanding shares of common stock of Ascent, and Ascent will become a wholly owned subsidiary of Forman. Ascent plans to offer approximately $21.1 million of its Series A Preferred (the Series A Preferred) stock and warrants to the existing stockholders of Forman on a pro rata basis to help fund the Pontotoc acquisition. The Series A Preferred will have a liquidation preference of $1,000 per share and bear dividends at 8% per annum. The Series A Preferred will be mandatorily redeemable by Ascent five years from the date of issuance at liquidation value plus accrued and unpaid dividends. Subject to final determination by Ascent's board of directors, the warrants will entitle the holders thereof to purchase approximately 4.4 million shares of Ascent common stock and will have a term of ten years. The warrants will be exercisable at a price to be determined by Ascent's board of directors.

Ascent is negotiating the terms of a credit agreement with its primary lender which will provide the remainder of the funds that will be required to acquire Pontotoc. The credit agreement will be secured by substantially all of the assets of the Company, which will be contributed to Ascent concurrently with the acquisition of Pontotoc.

Ascent is obligated under the Agreement to pay Pontotoc $2 million within five days of termination of the Agreement if the termination is due to failure to obtain financing if all other conditions of the Agreement have been met. This obligation is guaranteed by Forman.

F – 7

Reorganization

On August 6, 1999, the Company filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States District Court for the Eastern District of Louisiana (the Bankruptcy Court) (Case No. 99–14319). On November 22, 1999, the Company and certain of its creditors filed a Second Amended Joint Plan of Reorganization, as amended on December 29, 1999 (the Bankruptcy Plan). The Company's reorganization plan was confirmed by the Bankruptcy Court on December 29, 1999 and consummated January 14, 2000.

Pursuant to the Bankruptcy Plan, all of the Company's issued and outstanding securities were canceled and, as of December 31, 2000, the Company issued 984,042 shares of common stock, no par value, and warrants to purchase up to 490,516 shares of common stock to the Company's former security holders.

As of the confirmation date, the Company had total assets of $33.9 million and liabilities of $96.0 million. With the exception of an aggregate of approximately $2.7 million of promissory notes issued pursuant to the Bankruptcy Plan, approximately $300,000 in convenience claims which were paid in full in 2000, undistributed oil and gas revenues of $895,000, and approximately $3 million in additional pre–petition bankruptcy claims that were disputed by the Company and have now been resolved before the Bankruptcy Court, all of the Company's liabilities and preferred stock as of the confirmation date were extinguished pursuant to the Bankruptcy Plan.

As of September 30, 2000, the Company had resolved all pre–petition bankruptcy claims that had previously been disputed by the Company. The Bankruptcy Court overruled the Company's objection to one creditor's proof of claim. Thereafter, in accordance with the Bankruptcy Plan, the Company issued the holder of that claim a promissory note in the approximate amount of $984,000 in July, 2000. In addition, on July 24, 2000, the Company compromised its objection to a creditor's proof of claim by paying approximately $501,000 in cash and agreeing to perform future work worth approximately $122,000. The Company's objection to the Louisiana Department of Revenue and Taxation's proof of claim, in the amount of $223,000, was resolved in favor of the Company. As a result, the Company is obligated to pay $119,000 to the Louisiana Department of Revenue and Taxation over six years, with interest, in accordance with the Bankruptcy Plan. Finally, in September and October, 2000, the Company resolved all other disputed proofs of claims, in the aggregate amount of $632,000, by paying approximately $416,000 in cash to the holders of those claims.

All disputed proofs of claim have been resolved. Accordingly, on November 2, 2000, the Company filed a motion for final decree with the Bankruptcy Court to close the Company's bankruptcy case. At the hearing on November 29, 2000, the final decree was granted by the Bankruptcy Court.

Costs incurred during 1999 directly related to the Company's reorganization, consisting primarily of legal, accounting and financial consulting fees, were recorded to reorganization costs in the accompanying statement of operations. These costs are net of interest income earned on cash and cash equivalents because the maintenance of cash balances during 1999 was directly related to the Company's bankruptcy filing.

The Company ceased accruing interest on its Senior Debt and dividends on its preferred stock on August 6, 1999, when it filed for relief under Chapter 11.

Fresh Start Reporting

The Company has accounted for the reorganization using the principles of fresh start accounting required by AICPA Statement of Position 90–7, "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code" (SOP 90–7). For accounting purposes, the accompanying financial statements reflect the confirmed plan as if it was consummated on December 31, 1999. Under the principles of fresh start accounting, the Company's total assets and liabilities were recorded at their estimated fair market values. Accordingly, the Company's net proved oil and gas properties were increased by approximately $3.0 million, its unevaluated oil and gas properties were increased by approximately $3.1 million and other net property and equipment was increased by approximately $0.2 million. Obligations arising from the Bankruptcy Plan were recorded at the amounts expected to be paid in settlements of such obligations. In addition, the Company's Senior Notes with a net book value of $68.6 million, related interest

F – 8

payable of $11.1 million, preferred stock of $13.6 million and deferred financing costs related to the Senior Notes and preferred stock of $4.4 million were all written off. Since the former holders of the Company's Senior Notes (the former noteholders) received 92.5% of the shares of the common stock (Note 5), the gain on discharge of indebtedness was computed using 92.5% of the net assets received by the former noteholders. The remaining 7.5% of the net assets allocable to the former holders of the Company's preferred stock was recorded to equity and is included in fresh start accounting adjustments in the accompanying statement of stockholders' equity. Also included in such amount is the write–off of the remaining deferred costs allocable to the preferred stock.

The effect of the Bankruptcy Plan on the Company's balance sheet as of December 31, 1999, is as follows (in thousands):

		Adjustments to Record Confirmation of Plan
	Preconfirmation	Discharge of Debt andPreferred Stock	Fresh Start	Reorganized Balance Sheet
ASSETS
CURRENT ASSETS	$ 4,821	$ -	$ -	$ 4,821
PROPERTY AND EQUIPMENT:
Oil and gas properties, net	24,158	–	6,090	30,248
Other property and equipment	22	–	178	200
DEFERRED FINANCING COSTS, net	4,398	(4,398)	–
ESCROWED AND RESTRICTED FUNDS	490	–	–	490

	$ 33,889	$ (4,398)	$ 6,268	$ 35,759

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
LIABILITIES NOT SUBJECT TO
COMPROMISE:
Accounts payable and accrued liabilities	$ 2,467	$ –	$ –	$ 2,467
Current portion of promissory notes	26	614	–	640
Other noncurrent liabilities	19	–	–	19
Deferred taxes	(2,382)	10,089	2,194	9,901

	130	10,703	2,194	13,027
LIABILITIES SUBJECT TO COMPROMISE:
Prepetition liabilities	2,521	(2,521)	–	–
Promissory notes	–	2,047	–	2,047
Notes payable – secured (including interest of $11,155)	79,767	(79,767)	–	–
Mandatorily redeemable preferred stock	13,555	(13,555)	–	–
STOCKHOLDERS' DEFICIT:
Common stock – old	1	(1)	–	–
Common stock – new	–	14,417	6,268	20,685
Accumulated deficit	(62,085)	64,279	(2,194)	–

	33,759	(15,101)	4,074	22,732

	$ 33,889	$ (4,398)	$ 6,268	$ 35,759

F – 9

The fair market value assigned to the Company's proved oil and gas properties was estimated by adjusting the net pre–tax future cash flows discounted at a 10% annual rate (PV10) of the Company's proved reserves ($36.4 million at December 31, 1999) as set forth in the Estimate of Reserves and Future Revenue report on the Company's proved oil and gas properties as of December 31, 1999, prepared by Netherland, Sewell & Associates, independent reservoir engineers. This report was prepared in accordance with SEC guidelines, utilizing constant prices existing as of December 31, 1999. The Company adjusted these prices to reflect the product prices used in valuing producing properties, ($21 per barrel of oil and $2.75 per mcf of gas) then applied risk factors to the various categories of proved reserves as follows:

Proved Category	Risk Factor
Proved Producing	95%
Proved Non–producing	75%
Proved Undeveloped	25%

Applying these risk factors and adjusting the product pricing resulted in an estimated fair market value of the proved properties of $25.5 million. The Company's other assets, including other property and equipment, were valued at $4.9 million.

As a result of the implementation of fresh start accounting, the financial statements as of and for the year ended December 31, 1999 reflecting the fresh start accounting principles discussed above are not comparable to the financial statements of prior periods.

2. SIGNIFICANT ACCOUNTING POLICIES:

Oil and Gas Properties

Forman uses the full–cost method of accounting, which involves capitalizing all exploration and development costs incurred for the purpose of finding oil and gas reserves, including the costs of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. The Company also capitalizes certain related employee costs and general and administrative costs which can be directly identified with significant acquisition, exploration and development projects undertaken. Such costs are amortized on the future gross revenue method whereby amortization is computed using the ratio of gross revenues generated during the period to total estimated future gross revenues from proved oil and gas reserves. Additionally, the capitalized costs of oil and gas properties cannot exceed the present value of the estimated net cash flow from its proved reserves, together with the lower of cost or estimated fair value of its undeveloped properties (the full cost ceiling). Transactions involving sales of reserves in place, unless extraordinarily large portions of reserves are involved, are recorded as adjustments to accumulated depreciation, depletion and amortization.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents.

Depreciation of Other Property and Equipment

Depreciation of property and equipment other than oil and gas properties is provided on the straight–line method over the estimated useful lives of the assets.

Deferred Financing Costs

For oil and gas property acquisitions which were burdened by an overriding royalty interest assigned to its lenders, the Company allocated a portion of the purchase price of such acquisitions to deferred financing costs. The amount allocated is proportional to the discounted future net cash flows associated with the interest assigned as compared to

F – 10

the total discounted future net cash flows for the acquisition (before carve–out of the overriding royalty interest) as of the date of the acquisition. These allocated costs, along with other costs of obtaining financing, were deferred and amortized using the effective interest method over the original term of the related debt. All such costs were reduced to zero in the reorganization discussed in Note 1.

Fair Value of Financial Instruments

Cash, cash equivalents, accounts receivable, accounts payable and promissory notes were reflected at their fair market values at December 31, 1999, in accordance with SOP 90–7 as discussed in Note 1. As of December 31, 2000, the fair market value of the financial instruments mentioned above approximated their respective book values.

Income Taxes

The income tax effects of the Company's reorganization had a material impact on the tax basis of the Company's oil and gas interests and its net operating loss carryforwards (Note 4).

Pervasiveness of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Recapitalization Costs – 1998

Costs incurred during 1998, consisting primarily of consulting and financial advisory fees, were capitalized in anticipation of the possible debt restructuring or recapitalization of the Company. These costs were written off in 1999 when the Company filed for bankruptcy.

Derivatives

The Company uses derivative financial instruments such as swap agreements and forward sales contracts for price protection purposes on a limited amount of its future production and does not use them for trading purposes. Such derivatives are accounted for on an accrual basis and amounts paid or received under the agreements are recognized as oil and gas sales in the period in which they accrue. For the years ended December 31, 2000, 1999 and 1998, the Company recorded additions to oil and gas sales of $–0–, $109,800 and $–0–, respectively, under these agreements. The Company entered into a forward sales agreement to sell 200 barrels per day of its oil production in October, 1999 for the twelve months ending November 30, 2000, at a price of $22.05 per barrel. As of December 31, 2000 the Company had open forward gas sales positions for the months of January, February and March, 2001 of 60,000 MBTU per month at prices of $7.09, $7.04 and $7.14, respectively.

Certain Concentrations

During 2000, 100% of the Company's oil and gas production was sold to four customers. Based on the current demand for oil and gas, the Company does not believe the loss of any of these customers would have a significant financially disruptive effect on its business or financial condition.

Per Share Amounts

Net income or loss per share of common stock was calculated by dividing net loss applicable to common stock by the weighted–average number of common shares outstanding during the year. Due to the net loss from continuing operations reported in 1998, all options and warrants outstanding (representing 43,600) were excluded from the

F – 11

computation because they would have been antidilutive. For 2000 and 1999, warrants and options were excluded because the exercise price of outstanding options and warrants (490,516 in 2000 and 43,600 in 1999) exceeded the fair value of the company's common stock.

Recent Accounting Pronouncements

In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Statement establishes accounting and reporting standards that require every derivative instrument (including certain derivative instruments embedded in other contracts) to be recorded in the balance sheet as either an asset or a liability measured at its fair value and that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. The Company adopted SFAS No. 133 on January 1, 2001. Because of the nature of the Company's hedging activities, the adoption of SFAS No. 133 did not have a material impact on the Company's financial position or results of operations.

Reclassifications

Certain prior year amounts have been reclassified to conform to the presentation of such items in the current year.

3. NOTES PAYABLE AND PREFERRED STOCK:

As discussed in Note 1, all of the Company's debt, including accrued interest, and preferred stock were discharged in the reorganization. The Company has issued to certain general unsecured creditors seven promissory notes aggregating to approximately $3.65 million payable beginning April 1, 2000, in equal monthly installments of principal and interest over three years and bearing interest at the rate of 8% per year. Additionally, the Company has notes outstanding of $20,485 related to purchases of automobiles and trucks. Aggregate minimum principal payments at December 31, 2000, required on these notes for the next five years are as follows (in thousands): 2001 – $1,219; 2002 – $1,310; 2003 – $–0–; 2004 – $0; 2005 – $0.

4. INCOME TAXES:

The Company follows the asset and liability method of accounting for deferred income taxes prescribed by the Financial Accounting Standards Board Statement No. 109 (FAS 109) "Accounting for Income Taxes". Under the applicable income tax rules and regulations, the Company is not required to recognize taxable income, or pay taxes on the gain resulting from discharge of indebtedness (DOI) as a result of the Bankruptcy Plan. Rather, the gain (represented for tax purposes as the face value of the debt and accrued interest discharged in excess of the fair market value of the reorganized company) reduces the Company's net operating loss carryforwards (NOLs). Any remaining gain (after offsetting the Company's NOLs) reduces the Company's tax basis in its net assets. The magnitude of the DOI resulted in the elimination of $20.9 million of NOLs from 1998 and $9.6 million of NOLs generated during 1999. Additionally, it substantially eliminated the tax basis in the net assets of the reorganized Company. The significant excess of book basis over tax basis in the net assets of the Company resulted in the recording of a $9.9 million deferred tax liability in the reorganized balance sheet (See Note 1). Realization of the NOLs used to offset the gain on DOI also resulted in the reversal of the valuation allowance, the impact of which is included in the tax effect of the extraordinary item of $10.1 million in the accompanying statement of operations.

The provision for income taxes for the years ended December 31, 1999 and 2000 consisted of the following (in thousands):

	2000	1999
Current

$ 667

$ –

Deferred

515

(188)

Total provision (benefit)

$ 1,182

$ (188)

F–12

At December 31, the Company has the following deferred tax assets and liabilities recorded (in thousands):

	2000	1999
Temporary differences:
Oil and gas properties

$ 10,788

9,901

Other

(372)

–

Net deferred tax liability

$ 10,416

$ 9,901

The provision for income taxes (on net loss before extraordinary item) at the Company's effective tax rate differed from the provision for income taxes at the federal statutory rate as follows (in thousands):

	December 31, 2000	December 31, 1999
Computed provision (benefit) at the expected federal statutory rate	$ 985	$ (188)
State taxes and other	197	–
Income tax provision (benefit)	$ 1,182	$ (188)

5. COMMON STOCK AND WARRANTS:

In connection with the consummation of the Bankruptcy Plan, as of December 31, 2000, the Company has issued approximately 984,042 shares of common stock to the former holders of the Company's senior notes and preferred stock. Pursuant to the Bankruptcy Plan, the Company has issued the new shares of common stock upon the surrender of the certificates representing the senior notes and the preferred stock. The common stock was allocated as follows: (i) 13.2143 shares of common stock were issued for each $1,000 of principal amount of canceled Senior Notes and (ii) 0.3120 shares of common stock were issued for each canceled share of preferred stock. The new common stock is subject to a stockholders agreement which contains restrictions on voting, sale and transfer, among other restrictions, of the common stock. Additionally, controlling stockholders (as defined) are entitled under a registration rights agreement to effect up to four registrations of the common stock to be filed on their behalf by the Company. McLain Forman is also entitled to effect up to two registrations under certain conditions (as defined in the agreement).

The Company has also issued, as of December 31, 2000, warrants to purchase up to approximately 490,516 shares of common stock. These warrants consist of 49,048 Series A Warrants (exercise price $34.74), 147,156 Series B Warrants (exercise price $92.80), 147,156 Series C Warrants (exercise price $117.80), and 147,156 Series D Warrants (exercise price $137.80). Each of these warrants is currently exercisable and will automatically expire on January 14, 2007. Of these warrants, approximately 68% of each series was issued to McLain Forman, the former sole shareholder, with the remaining warrants being issued to the former preferred stock and noteholders as described below. Ten Series A Warrants were exercised in 2000.

In connection with the 1997 offerings of Senior Notes and preferred stock, the Company had issued warrants to purchase 43,600 shares of common stock at an initial exercise price of $1.00 per share, subject to adjustment in certain defined cases. The Company had allocated $666,667 and $333,333 of the proceeds received from the sale of the note units and equity units, respectively, to the warrants issued, which had been recorded as additional paid in capital at December 31, 1997. In addition, the Company had also issued warrants to purchase 4,844 shares of common stock under the same conditions as discussed above. The Company recorded $111,100 of additional paid–in capital for these warrants, which was being amortized as deferred financing costs over the term of the note units.

F – 13

Pursuant to the Bankruptcy Plan, holders of the Company's old common stock warrants that were issued in June 1997 in connection with the Company's offering and sale of the Senior Notes received in the aggregate approximately 10,850 Series A Warrants and approximately 32,550 of each of the Series B, Series C, and Series D Warrants. Each holder of a Senior Note warrant received 0.1637 Series A Warrants and 0.4910 Series B, Series C, and Series D Warrants for each Senior Note warrants canceled pursuant to the Bankruptcy Plan. Holders of the Company's warrants that were issued in June 1997 in connection with the Company's offering and sale of the preferred stock (the Equity Warrants) received in the aggregate approximately 5,450 Series A Warrants and approximately 16,350 of each of the Series B, Series C, and Series D Warrants. Each holder of an Equity Warrant received 0.0273 Series A Warrants and 0.0818 Series B, Series C, and Series D Warrants for each Equity Warrant canceled pursuant to the Bankruptcy Plan. McLain Forman received 33,780 Series A Warrants and 101,100 of each of the Series B, Series C, and Series D Warrants in connection with the consummation of the Bankruptcy Plan and pursuant to his employment agreement.

The issuance of the common stock and the warrants pursuant to the Bankruptcy Plan was exempt from registration under the Securities Act of 1933, as amended, pursuant to Section 1145 of the United States Bankruptcy Code.

The warrants had no measurable value upon issuance based on the calculation of their fair value using the Black –Scholes option pricing model.

6. COMMITMENTS AND CONTINGENCIES:

Employment Agreements

Effective January 14, 2000, the Company entered into employment agreements with certain members of executive management. The agreements provide for employment of certain members of executive management in their current positions through April 30, 2001, subject to earlier termination, at a fixed annual salary and an annual bonus based upon the attainment of certain quantitative goals. The agreements provide for aggregate salaries of $961,000 per calendar year to the executives and a maximum bonus of 30% of base salary to each executive, except for the former sole shareholder for whom the maximum bonus is 90% of base salary. The maximum bonuses of $423,000 attributable to fiscal 2000 were recorded in the accompanying financial statements and are payable by March 31, 2001.

If the Company terminates an executive without cause (as defined in the agreement) or the executive terminates employment for good reason (as defined in the agreement), the Company must (i) pay the executive his accrued base salary as of the date of termination plus his annual base salary for the remainder of his employment term and (ii) provide the executive with continuing group medical, dental, disability and life insurance benefits until the later of 18 months from the date of termination or the original expiration date of the employment term. Should the executive prevail in any cause of action, suit, arbitration or other legal proceeding initiated to enforce the provisions of the agreement, the Company indemnifies the executive for all costs including reasonable attorneys' fees incurred by the executive in connection with such cause of action, suit, arbitration or other legal proceeding. If the executive terminates his employment for reasons other than good reason or the Company terminates the executive for cause, the Company must pay to the executive his accrued base salary as of the date of termination. If the executive is terminated for cause following a change of control (as defined in the agreement), the executive will also be paid his base salary for the remainder of his employment term and will be provided continuing group medical, dental, disability and life insurance benefits until the later of 18 months from the date of termination or the original expiration date of the employment term.

F – 14

Operating Leases

Forman has two noncancellable operating leases for the rental of office space, which expire on September 14, 2004 and January 14, 2005. Future commitments under these leases are as follows:

December 31,	Amount
2001	$ 235,544
2002	$ 251,886

2003

$ 257,333

2004

$ 237,260

2005

$ –0–

Rental expense under operating leases during 2000, 1999 and 1998 was $210,480, $240,980, and $200,841, respectively.

Legal Proceedings

From time to time, the Company may be a party to various legal proceedings. The Company currently is a party to a lawsuit arising in the ordinary course of business. Management does not expect this matter to have a material adverse effect on the Company's financial position or results of operations.

7. ESCROWED AND RESTRICTED FUNDS:

Cash restricted for payment of abandonment costs for the Boutte and Bayou Dularge Fields is classified as a long–term asset. Such amounts are invested in short–term interest–bearing investments. The cash is escrowed under an agreement which required Forman to make additional specified monthly contributions through November 1995. As of December 31, 2000, the escrow accounts are fully funded.

8. EMPLOYEE BENEFITS:

As part of the reorganization discussed in Note 1, the 1997 Stock Option Plan was dissolved and all outstanding options were cancelled. There was no other activity with respect to the Plan during 2000.

401(K) Plan

The Company has adopted a defined contribution retirement plan that complies with Section 401(k) of the Code (the 401(k) Plan). Pursuant to the terms of the 401(k) Plan, all employees with at least one year of continuous service are eligible to participate and may contribute up to 15% of their annual compensation (subject to certain limitations imposed under the Code). The 401(k) Plan provides that a discretionary match of employee contributions may be made by the Company in cash. In December 1998, the Company made a matching contribution, in the amount of $58,398, based upon each individual employee's plan contributions for 1998. In December, 1999 the Company made another matching contribution, in the amount of $70,012, based upon each individual employee's plan contributions for 1999. During 2000, the Company made matching contributions on a monthly basis, in the aggregate amount of $76,244, based upon each individual employee's plan contributions for 2000. These matching employer contributions to the 401(k) Plan are fully vested to the individual employees after three years of service. The amounts held under the 401(k) Plan are invested among various investment funds maintained under the 401(k) Plan in accordance with the directions of each participant. Employee contributions under the 401(k) Plan are 100% vested and participants are entitled to payment of vested benefits upon termination of employment.

9. WRITEDOWN OF OIL AND GAS PROPERTIES:

During 1998, the Company wrote down its oil and gas properties by $19,575,047. The amount of the writedown represents the excess capitalized costs over estimated future net revenues attributable to oil and gas reserves discounted at 10%, less estimated future income taxes. The estimated future net revenues used in the calculation were based on year–end reserve volumes (as determined by an independent petroleum engineer), using 1998 year end oil prices of $10.44 per barrel and 1998 year end gas prices of $1.87 per thousand cubic feet, with no provision for future escalation. The Company also wrote down its oil and gas property investments during 1997 by $10,008,121. The estimated future net revenues used in the ceiling test calculation for 1997 were based on year–end reserve volumes (as determined by an independent petroleum engineer), utilizing March, 1998 oil prices of $14.47

F – 15

per barrel and March, 1998 gas prices of $2.40 per thousand cubic feet, with no provision for future escalation. The utilization of these prices resulted in an increase in the amount charged to operations during 1997 of $8,167,879 over the amount that would have been recorded using year–end prices.

10. OIL AND GAS ACTIVITIES:

The following tables provide information required by SFAS No. 69 "Disclosures About Oil and Gas Producing Activities."

Capitalized Costs

Capitalized costs and accumulated depreciation, depletion and amortization relating to the Company's oil and gas producing activities, all of which are conducted within the continental United States, are summarized below:

Year Ended December 31,

2000

1999

1998

Proved producing oil and gas properties	$ 28,481,661	$ 25,515,529	$ 77,067,569
Unevaluated properties	5,006,197	4,732,139	4,485,359
Accumulated depreciation, depletion and amortization (Note 1)	(4,435,612)	–	(57,938,060)
Net capitalized costs	$ 29,052,246	$ 30,247,668	$ 23,614,868

Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below:

	Year Ended December 31,
	2000	1999	1998

Acquisition costs	$ 574,008	$ 81,840	$ –
Exploration costs	46,853	1,745,862	2,413,719
Development costs	1,502,880	3,345,943	2,118,810
Capitalized G&A costs	842,391	–	–

Costs incurred	$ 2,966,132	$ 5,173,645	$ 4,532,529

Gross cost incurred excludes sales of proved and unproved properties which are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. For 2000, G&A costs in the amount of $842,000 were capitalized into the full cost pool. No such capitalization of G&A was made for either 1998 or 1999.

The following table discloses financial data associated with the capitalized unevaluated costs as of December 31, 2000:

			Costs incurred during theYear Ended December 31,
		Balance at December 31, 2000	2000	1999
Acquisition costs	$ 4,732,139		$ –	$ 4,732,139
Capitalized interest	274,058		274,058	–

Costs incurred	$ 5,006,197		$ 274,058	$ 4,732,139

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Reserves – (Unaudited)

Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.

Proved oil and natural gas reserve quantities and the related discounted future net cash flows before income taxes for the periods presented are based on estimates prepared by Ryder Scott Company for 1998 and by Netherland, Sewell & Associates for 1999 and 2000. Both Ryder Scott and Netherland Sewell are independent petroleum engineers. Such estimates have been prepared in accordance with guidelines established by the Securities and Exchange Commission.

The Company's net ownership interests in estimated quantities of proved oil and natural gas reserves and changes in net proved reserves, all of which are located in the continental United States, are summarized below:

Oil, Condensate and Natural Gas Liquids
(Bbls)
Year Ended December 31,
2000	1999	1998

Proved developed and undeveloped reserves:
Beginning of year	1,612,124	1,530,724	2,259,567
Revisions of previous estimates	169,698	273,709	(335,803)
Purchases of oil and gas properties	405,571	–	–
Extensions and discoveries	749,697	151,085	–
Production	(269,899)	(343,394)	(393,040)
End of year	2,667,191	1,612,124	1,530,724
Proved developed reserves at end of year	1,832,778	1,330,675	1,310,274


Natural Gas (Mcf)
Year Ended December 31,
2000	1999	1998

Proved developed and undeveloped reserves:
Beginning of year	18,995,838	14,558,000	22,105,000
Revisions of previous estimates	934,260	3,405,862	(2,602,860)
Purchases of oil and gas properties	1,256,479	–	–
Extensions and discoveries	6,870,554	4,123,150	–
Production	(1,797,305)	(3,091,174)	(4,944,140)
End of year	26,259,826	18,995,838	14,558,000
Proved developed reserves at end of year	12,804,123	13,599,050	9,865,000

F – 17

Standardized Measure (Unaudited)

The table of the Standardized Measure of Discounted Future Net Cash Flows related to the Company's ownership interests in proved oil and gas reserves as of period end is shown below:

Year Ended December 31,

2000

1999

1998

(In Thousands)

Future cash inflows	$ 331,656	$ 88,182	$ 43,256
Future oil and natural gas operating expenses	(43,647)	(29,045)	(14,598)
Future development costs	(17,666)	(7,371)	(5,821)
Future net cash flows before income taxes	270,343	51,766	22,837
Future income taxes	(100,313)	(17,401)	–
Future net cash flows	170,030	34,365	22,837
10% annual discount for estimating timing of cash flows	(56,585)	(9,962)	(3,668)
Standardized measure of discounted future net cash flows	$ 113,445	$ 24,403	$ 19,169

Future cash flows are computed by applying year–end prices of oil and natural gas to year–end quantities of proved oil and natural gas reserves. Future operating expenses and development costs are computed primarily by the Company's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company's proved oil and natural gas reserves at the end of the year, based on year end costs and assuming the continuation of existing economic conditions. Future income taxes are computed using the Company's tax basis in evaluated oil and gas properties and other related tax carryforwards. In 1998, the present value of future net cash flows before income taxes was exceeded by the Company's tax basis in the oil and gas properties and other tax attributes; therefore, future income taxes have not been reflected in that year. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Company's oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and the risks inherent in reserve estimates. The weighted average prices of oil and gas used with the above tables at December 31, 2000, 1999 and 1998 were $25.48, $24.58 and $10.44 respectively, per barrel and $10.04, $2.56 and $2.15, respectively, per Mcf. Oil prices have remained relatively stable and natural gas prices have continued to decline almost 50% subsequent to December 31, 2000. Accordingly, the discounted future net cash flows could be decreased if the standardized measure were calculated at a later date.

F – 18

Changes in Standardized Measure (Unaudited)

Changes in standardized measure of future net cash flows relating to proved oil and gas reserves are summarized below:

Year Ended December 31,

2000

1999

1998

(In Thousands)

Changes due to current year operations:
Sales of oil and natural gas, net of oil and natural gas operating expenses	$ (11,048)	$ (9,246)	$ (12,050)
Extensions and discoveries	72,785	8,604	–
Purchases of oil and gas properties	9,289	–	–
Changes due to revisions in standardized variables:
Prices and operating expenses	80,438	10,747	(24,336)
Revisions of previous quantity estimates	12,931	6,897	(4,675)
Estimated future development costs	(8,684)	3,055	(2,192)
Accretion of discount	3,608	1,917	5,226
Net change in income taxes	(57,191)	(12,037)	4,715
Production rates, timing and other	(13,086)	(4,703)	4,939
Net Change	89,042	5,234	(28,373)
Beginning of year	24,403	19,169	47,542
End of year	$ 113,445	$ 24,403	$ 19,169

F – 19

11. SUMMARIZED QUARTERLY FINANCIAL INFORMATION – UNAUDITED:

The following table summarizes the quarterly financial information for 1999 and 2000. For 2000, the Company capitalized $842,000 of G&A expenses and $274,000 of interest incurred during 2000 into the full cost pool in the fourth quarter. For presentation purposes, the expenses as reported in the respective quarterly Form 10Qs for the first three quarters of 2000 have been restated below to reflect this capitalization ratably over the four quarterly periods of 2000.

	1999
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Total

Revenues	$2,625,787	$2,945,597	$3,806,493	$3,738,109	$13,115,986
Expenses	6,584,445	6,846,622	4,930,491	375,885	18,737,443

Net income (loss) from operations	(3,958,658)	(3,901,025)	(1,123,998)	3,362,224	(5,621,457)
Reorganization items and income taxes	–	–	–	(5,272,052)	(5,272,052)

Net income (loss) before extraordinary items	(3,958,658)	(3,901,025)	(1,123,998)	8,634,276	(349,405)
Extraordinary items	–	–	–	46,724,052	46,724,052
Net income (loss)	(3,958,658)	(3,901,025)	(1,123,998)	55,358,328	46,374,647
Preferred stock dividend	473,539	479,164	200,288	–	1,152,991
Net income (loss) attributable to common shares	$(4,432,197)	$(4,380,189)	$(1,324,286)	$55,358,328	$45,221,656
Basic and diluted earnings (loss) per share:
Net income (loss) per share attributable to common shares before extraordinary item	$(49.25)	$(48.67)	$(14.71)	$ 95.94	$ (16.69)
Extraordinary item per share	–	–	–	519.15	519.15
Net income (loss) per share	$(49.25)	$(48.67)	$(14.71)	$615.09	$502.46


	2000
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	Total

Revenues	$3,382,051	$3,241,941	$3,762,392	$4,574,105	$14,960,489
Expenses	2,504,620	2,687,521	3,265,193	2,705,700	11,163,034

Net income (loss) from operations	877,431	554,420	497,199	1,868,405	3,797,455
Reorganization items and income taxes	1,196,317	–	76,330	808,545	2,081,192

Net income (loss)	$(318,886)	$554,420	$420,869	$1,059,860	$1,716,263

Basic and diluted earnings (loss) per share:	$(0.32)	$0.56	$0.43	$1.07	$1.74

F – 20

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.

	FORMAN PETROLEUM CORPORATION



	By: /s/ Jeffrey Clarke
		Jeffrey Clarke
		President

Date: March 30, 2001

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Form 10-K has been signed by the following persons in the capacities and on the dates indicated.

Name	Title	Date
/s/ Nicholas Tell, Jr. Nicholas Tell, Jr.	Chairman of the Board	March 30, 2001
/s/ Jeffrey Clarke Jeffrey Clarke	President and Director (Principal Executive Officer)	March 30, 2001
/s/ McLain J. Forman McLain J. Forman	Chief Executive Officer, COO and Director	March 30, 2001
/s/ Michael H. Price Michael H. Price	Chief Financial Officer (Principal Financial Officer)	March 30, 2001
/s/ Marvin J. Gay Marvin J. Gay	Vice President of Finance and Administration (Controller and Principal Accounting Officer)	March 30, 2001
/s/ Jerry W. Box Jerry W. Box	Director	March 30, 2001

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Forman Petroleum Inactive 10-K2000 FY Annual report

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