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Article by DailyStocks_admin    (03-27-08 06:50 AM)

Filed with the SEC from Mar 13 to Mar 19:

Energy Partners (EPL)
Carlson Capital said it has had discussions with Energy Partners about possible changes to the company's board. The investor reiterated that it may seek board representation or work with Energy Partners on strategies to increase shareholder value. Carlson may communicate with one or more shareholders, officers or board members for this purpose. Carlson owns 2,994,968 shares (9.4%).

BUSINESS OVERVIEW

We were incorporated in January 1998 and operate in a single segment as an independent oil and natural gas exploration and production company. Our current operations are concentrated in the Gulf of Mexico Shelf, the deepwater Gulf of Mexico as well as the Gulf Coast onshore region (the “Gulf of Mexico Region”). We concentrate on this area because it provides us with favorable geologic and economic conditions, including multiple reservoir formations, regional economies of scale, extensive infrastructure and comprehensive geologic databases. We believe that this region offers a balanced and expansive array of existing and prospective exploration, exploitation and development opportunities in both established productive horizons and deeper geologic formations. In addition, we may evaluate reserve and exploratory acquisition opportunities outside of this area including in onshore North American basins. As of December 31, 2007, we had estimated proved reserves of approximately 103.1 Bcf of natural gas and 28.1 Mmbbls of oil, or an aggregate of approximately 45.3 Mmboe, with a standardized measure of discounted future net cash flows of $1.1 billion.

We have a team of geoscientists and management professionals with considerable region-specific geological, geophysical, technical and operational experience. We have grown through a combination of exploration, exploitation and development drilling and multi-year, multi-well drill-to-earn programs, as well as strategic acquisitions of oil and natural gas fields, in the Gulf of Mexico Shelf, deepwater and the Gulf Coast onshore areas. As we have grown from our inception, we have strengthened our management team, expanded our property base, reduced our geographic concentration, and moved to a more balanced oil and natural gas reserve profile. We have also expanded our technical knowledge base through the addition of high quality personnel and geophysical and geological data.

Our common stock is traded on the New York Stock Exchange under the symbol “EPL.” We maintain a website at www.eplweb.com which contains information about us, including links to our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all related amendments. In addition, our website contains our Corporate Governance Guidelines and the charters for our Audit, Compensation and Nominating and Governance Committees. Copies of such information are also available by writing to the Secretary of the Company at 201 St. Charles Avenue, Suite 3400, New Orleans, Louisiana 70170. Our website and the information contained in it and connected to it shall not be deemed incorporated by reference into this Report on Form 10-K.

Exploration and Development Expenditures

Our exploration and development expenditures for 2007 totaled $317.3 million. For 2008, we have currently budgeted exploration and development expenditures of up to $200 million. The drilling portfolio, primarily offshore, includes a mixture of lower risk development and exploitation wells, moderate risk exploration opportunities and higher risk, higher potential exploration projects. Our 2008 budget does not include any acquisitions of proved reserves that may occur during the year.

Our Properties

At December 31, 2007, we had interests in 24 producing fields, 6 fields under development and 1 property on which drilling operations were then being conducted, all of which are located in the Gulf of Mexico Region. These fields fall into five areas which we identify as our Eastern, Central, Western and Deepwater offshore and Gulf Coast onshore areas. The Eastern offshore area is comprised of two producing fields, including the East Bay field. The Central offshore area is comprised of four producing fields, all of which are contiguous and cover most of the Bay Marchand salt dome. The fields in these two areas and the acreage surrounding them comprise the core of our property base and the focus of our near term efforts. The Western offshore area, which extends from areas offshore central and western Louisiana to areas offshore Texas, is comprised of 18 producing fields. The Deepwater offshore area is comprised of 24 offshore blocks. Our Gulf Coast onshore area is located in South Louisiana. Over the last several years, we have continued to add to our leasehold acreage position in these areas through federal and state lease sales, acquisitions and trades with industry partners.

Eastern Offshore Area

East Bay, the key asset in our Eastern offshore area, comprising approximately 13% of our production during 2007 and 36% of our proved reserves at the end of 2007, is located 89 miles southeast of New Orleans near the mouth of the Mississippi River. It contains producing wells located onshore along the coastline and in water depths ranging up to approximately 170 feet and is comprised primarily of the South Pass 24, 26 and 27 fields. Through a number of state and federal lease sales, we have acquired acreage that is contiguous to East Bay in several additional South Pass blocks as well as across the river in West Delta blocks. We own an average 96% interest in our acreage position in this area with our working interest ranging from 18% to 100% and our net revenue interest varying up to a maximum of 86%. Inclusive of all lease acquisitions, our leasehold area covered 32,434 gross acres (31,141 net acres) at the end of 2007.

Central Offshore Area

The core assets of our Central offshore area, the fields located in Greater Bay Marchand, are located approximately 60 miles south of New Orleans in water depths of 181 feet or less. Our key assets in this area include the South Timbalier 26, 41 and 46 and Bay Marchand fields. These fields, located in the Greater Bay Marchand area, comprised approximately 54% of our production during 2007 and 45% of our proved reserves at the end of 2007.

In 2003, we drilled our initial discovery well in the South Timbalier 41 field, in which we hold a 60% working interest, on acreage acquired earlier that year in a federal lease sale. Several exploratory and development wells have been drilled in the field and all have been successful and have been brought on production. This field, in which additional reserve potential remains to be tested, represents the most significant discovery in our history. We acquired acreage in additional leases in the vicinity of this field in 2005 and subsequent years.

In addition, at the beginning of 2005 we owned a 50% interest in the South Timbalier 26 field. In March 2005, we closed the acquisition of the remaining 50% interest in South Timbalier 26 above approximately 13,000 feet subsea. As a result of the acquisition, we now own a 100% interest in the producing horizons in this field. The acquisition expanded our interest in our core Greater Bay Marchand area and gave us additional flexibility in undertaking the future development of the South Timbalier 26 field. We have interests in 12 producing wells in this field.

Western Offshore Area

The properties in the Western offshore area are located in water depths ranging from 7 to 371 feet with working interests ranging from 17% to 100%. We owned interests in 18 producing fields in this area at December 31, 2007, with another 2 under development.

Deepwater Offshore Area

At December 31, 2007, we owned interests in 24 blocks in the Deepwater offshore area, one of which was under development and two of which were under evaluation at year end. Our working interest in this each of our properties in this area ranges from 25% to 33%. We have several additional prospects identified on our current deepwater acreage and plan to generate prospects and bid on deepwater leases at future Gulf of Mexico lease sales in order to expand our portfolio of drilling opportunities in the area.

Gulf Coast Onshore Area

In 2005, we closed an acquisition of properties and reserves onshore in south Louisiana for $149.6 million in cash, after adjustments. In June 2007, we sold substantially all of our onshore South Louisiana producing assets for approximately $68.6 million after closing adjustments. The remaining properties in the Gulf Coast onshore area are located in south Louisiana with working interests ranging from 16% to 40% and are comprised of undeveloped acreage with one well under development at year end.

Oil and Natural Gas Reserves

The following table presents our estimated net proved oil and natural gas reserves and the present value of our reserves at December 31, 2007, 2006 and 2005. These estimates of proved reserves are based on reserve reports prepared by Netherland, Sewell & Associates, Inc. and Ryder Scott Company, L.P., independent petroleum engineers. Neither the present values, discounted at 10% per annum, of estimated future net cash flows before income taxes, or the standardized measure of discounted future net cash flows shown in the table are intended to represent the current market value of the estimated oil and natural gas reserves we own.

Title to Properties

Our properties are subject to customary royalty interests, liens under indebtedness, liens incident to operating agreements, mechanics’ and materialman liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with the use of our properties in the operation of our business.

We believe that we have satisfactory title to, or rights in, all of our producing properties. As is customary in the oil and natural gas industry, minimal investigation of title is made at the time of acquisition of undeveloped properties. We investigate title prior to the consummation of an acquisition of producing properties and before the commencement of drilling operations on undeveloped properties. We have obtained or conducted a thorough title review on substantially all of our producing properties and believe that we have satisfactory title to such properties in accordance with standards generally accepted in the oil and natural gas industry.

Regulatory Matters

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, as amended (“NGA”), the Natural Gas Policy Act of 1978, as amended (“NGPA”), and regulations promulgated thereunder by the Federal Energy Regulatory Commission (“FERC”) and its predecessors. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of wellhead natural gas sales began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, as amended (the “Decontrol Act”). The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. While sales by producers of natural gas can currently be made at unregulated market prices, Congress could reenact price controls in the future.

Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued Order No. 636 and a series of related orders (collectively, “Order No. 636”) to implement its open access policies. As a result of the Order No. 636 program, the marketing and pricing of natural gas have been significantly altered. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders (collectively, “Order No. 637”), which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. Most major aspects of Order No. 637 have been upheld on judicial review, and most pipelines’ tariff filings to implement the requirements of Order No. 637 have been accepted by the FERC and placed into effect.

The Outer Continental Shelf Lands Act (“OCSLA”) requires that all pipelines operating on or across the outer continental shelf (“OCS”) provide open access, non-discriminatory transportation service. Previously the FERC enforced this provision pursuant to its authority under both the NGA and the OCSLA. One of FERC’s principal goals in carrying out OCSLA’s mandate is to increase transparency in the market to provide producers and shippers on the OCS with greater assurance of open access service on pipelines located on the OCS and non-discriminatory rates and conditions of service on such pipelines. In 2003, the courts determined that the FERC had only limited authority to enforce its open access rules on the OCS and decided, instead, that such authority primarily rested with others, including the Department of the Interior. The U.S. Minerals Management Service (“MMS”), within the Department of the Interior, has jurisdiction under OCSLA to ensure that all shippers seeking service on OCS pipelines transporting oil or gas pursuant to MMS-granted easements or rights-of-way receive open and non-discriminatory access to such transportation. In furtherance of this mandate, MMS has proposed regulations intended to better ensure such access for OCS shippers by providing complaint procedures and informal alternative processes to address allegations that a shipper has been denied open and non-discriminatory access to an OCS pipeline.

Additional proposals and proceedings that might affect the natural gas industry are pending before FERC and the courts. For example, the Federal Energy Policy Act, signed into law in August 2005, contains various provisions designed to increase the level of competition and transparency in FERC-regulated natural gas markets (e.g. one such provision, recently implemented by FERC in its regulations, makes market-based rate authority generally available to new interstate natural gas storage facilities), those provisions are now in various stages of implementation by FERC. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC will continue. 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.

Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is materially different from the effect of such regulation on our competitors.

Regulation of Transportation of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. The transportation of oil in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on inflation) for transportation rates for oil that allowed for an increase or decrease in the cost of transporting oil to the purchaser. A review of these regulations by the FERC in 2000 was successfully challenged on appeal by an association of oil pipelines. On remand, the FERC in February 2003 increased the index slightly, effective July 2001. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is materially different from the effect of such regulation on our competitors.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Our subsidiary, EPL Pipeline, L.L.C., owns an approximately 12-mile oil pipeline, which transports oil produced from South Timbalier 26 and a portion of South Timbalier 41 on the Gulf of Mexico OCS to Bayou Fourchon, Louisiana. Production transported on this pipeline includes oil produced by us from South Timbalier 26 and by us and our working interest partner in South Timbalier 41. EPL Pipeline, L.L.C. has on file with the Louisiana Public Service Commission and FERC tariffs for this transportation service and offers non-discriminatory transportation for any willing shipper.

Regulation of Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling and plugging and abandonment surety bonds and reports concerning operations. The states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and the plugging and abandonment of wells. Many states also have regulations restricting production to the market demand for oil and natural gas. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Some of our offshore operations are conducted on federal leases that are administered by MMS and are required to comply with the regulations and orders promulgated by MMS under OCSLA. Among other things, we are required to obtain prior MMS approval for any exploration plans we pursue and our development and production plans for these leases. MMS regulations also establish construction requirements for production facilities located on our federal offshore leases and govern the plugging and abandonment of wells and the removal of production facilities from these leases. Under limited circumstances, MMS could require us to suspend or terminate our operations on a federal lease.

MMS also establishes the basis for royalty payments due under federal oil and natural gas leases through regulations issued under applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and natural gas leases. The basis for royalty payments established by MMS and the state regulatory authorities is generally applicable to all federal and state oil and natural gas lessees. Accordingly, we believe that the impact of royalty regulation on our operations should generally be the same as the impact on our competitors.

The failure to comply with these rules and regulations can result in substantial penalties, including lease termination in the case of federal leases. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Environmental Regulations

General. Various federal, state and local laws and regulations governing the protection of the environment, such as the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), the Resource Conservation and Recovery Act, as amended (“RCRA”), the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”), and the Federal Clean Air Act, as amended (the “Clean Air Act”), affect our operations and costs. In particular, our exploration, development and production operations, our activities in connection with storage and transportation of oil and other hydrocarbons and our use of facilities for treating, processing or otherwise handling hydrocarbons and related wastes may be subject to regulation under these and similar state legislation. These laws and regulations:


• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

•

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and


•

impose substantial liabilities for pollution resulting from our operations, including the performance of remedial measures to address pollution as a result of operations.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties or the imposition of injunctive relief. Changes in environmental laws and regulations occur regularly, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those in the oil and natural gas industry in general. While we believe that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements would not have a material adverse impact on us, there is no assurance that this trend will continue in the future.

As with the industry generally, compliance with existing regulations increases our overall cost of business. The areas affected include:


•

unit production expenses primarily related to the control and limitation of air emissions and the disposal of produced water;


•

capital costs to drill exploration and development wells primarily related to the management and disposal of drilling fluids and other oil and natural gas exploration wastes; and


•

capital costs to construct, maintain and upgrade equipment and facilities.

Superfund. CERCLA, also known as “Superfund,” imposes liability for response costs and damages to natural resources, without regard to fault or the legality of the original act, on some classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” or “operator” of a disposal site and entities that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA also authorizes the Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our ordinary operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance.” We may be jointly and severally liable under CERCLA or comparable state statutes for all or part of the costs required to clean up sites at which these wastes have been disposed.

We currently own or lease properties that for many years have been used for the exploration and production of oil and natural gas. Although we and our predecessors have used operating and disposal practices that were standard in the industry at the time, “hazardous substance” may have been disposed or released on, under or from the properties owned or leased by us or on, under or from other locations where these wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose actions with respect to the treatment and disposal or release of “hazardous substance” were not under our control. These properties and wastes disposed on these properties may be subject to CERCLA and analogous state laws. Under these laws, we could be required:


•

to remove or remediate previously disposed wastes, including wastes disposed or released by prior owners or operators;


•

to clean up contaminated property, including contaminated groundwater;


•

to pay for natural resource damages resulting from the releases; or


•

to perform remedial operations to prevent future contamination.

At this time, we do not believe that we are associated with any Superfund site and we have not been notified of any claim, liability or damages under CERCLA.

Oil Pollution Act of 1990. The Oil Pollution Act of 1990, as amended (the “OPA”) and regulations thereunder impose liability on “responsible parties” for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. Liability under OPA is strict, and under certain circumstances joint and several, and potentially unlimited. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permittee of the area in which an offshore facility is located. The OPA also requires the lessee or permittee of the offshore area in which a covered offshore facility is located to establish and maintain evidence of financial responsibility in the amount of $35.0 million ($10.0 million if the offshore facility is located landward of the seaward boundary of a state) to cover liabilities related to an oil spill for which such person is statutorily responsible. The amount of required financial responsibility may be increased above the minimum amounts to an amount not exceeding $150.0 million depending on the risk represented by the quantity or quality of oil that is handled by the facility. We carry insurance coverage to meet these obligations, which we believe is customary for comparable companies in our industry. A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions. We are not aware of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on us.

U.S. Environmental Protection Agency. U.S. Environmental Protection Agency regulations address the management and disposal of oil and natural gas operational wastes under three federal acts more fully discussed in the paragraphs that follow. The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”), provides a framework for the safe disposal of discarded materials and the management of solid and hazardous wastes. The direct disposal of operational wastes into offshore waters is also limited under the authority of the Clean Water Act. When injected underground, oil and natural gas wastes are regulated by the Underground Injection Control program under Safe Drinking Water Act. If wastes are classified as hazardous, they must be properly transported, using a uniform hazardous waste manifest, documented, and disposed at an approved hazardous waste facility. We are covered under the Clean Water Act permitting requirements for discharges associated with exploration and development activities. We take the necessary steps to ensure all offshore discharges associated with a proposed operation, including produced waters, will be conducted in accordance with such requirements.

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

CEO BACKGROUND

John C. Bumgarner, Jr. , age 65, has been a director since January 2000. Mr. Bumgarner is currently serving as managing member of Utica Plaza Management Company, a family-owned real estate company. Mr. Bumgarner was chief operating officer and president of strategic investments for Williams Communications Group, Inc., a high technology company, from May 2001 to November 2002. Williams Communications Group, Inc. filed a Plan of Reorganization with the U.S. Bankruptcy Court for the Southern District of New York in August 2002. Mr. Bumgarner joined The Williams Companies, Inc. in 1977 and served as senior vice president of Williams Corporate Development and Planning and then also served as president of Williams International Company prior to joining Williams Communications Group, Inc. Mr. Bumgarner is also a director of Management Planning Systems, Inc. and Sirenza Microdevices, Inc. Mr. Bumgarner is a former treasurer of Skelly Oil.

Jerry D. Carlisle, age 61, has been a director since March 2003. Mr. Carlisle has been vice president and director of DarC Marketing, Inc., a family-owned marketing company, since 1997. From 1983 to 1997, Mr. Carlisle was vice president, controller and chief accounting officer of LL&E and, from 1979 to 1983, he held various management positions at LL&E. Mr. Carlisle has a masters of business administration from Loyola University, is a certified public accountant, and serves as a trustee of the Mississippi State University Business School.

Harold D. Carter, age 68, has been a director since May 1998. Since 1995, Mr. Carter has been an independent oil and natural gas consultant and investment advisor. Mr. Carter is a director of Brigham Exploration Company and Abraxas Petroleum Corp., public oil and gas companies, a director of Longview Energy Company, a privately held oil and gas company, and former president of Sabine Corporation, an independent oil and gas exploration company.

Enoch L. Dawkins, age 69, has been a director since January 2004. Mr. Dawkins retired from Murphy Exploration and Production Co., where he served as president from 1991 until 2003. From 1964 until 1991, Mr. Dawkins held various operational, marketing and managerial positions at Ocean Drilling and Exploration Company, including president from 1989 until its acquisition by Murphy Oil Corporation in 1991. He is also a director of Superior Energy Services, Inc.

Dr. Norman C. Francis, age 75, has been a director since May 2005. Dr. Francis has served as the President of Xavier University of Louisiana since 1968. Dr. Francis is the chairman of the board for the Southern Education Foundation and for Liberty Bank and Trust, a member of the board of directors of the American Council on Education and a Fellow of The American Academy of Arts and Sciences (inducted 1993).

Robert D. Gershen, age 53, has been a director since May 1998. Mr. Gershen is president of Associated Energy Managers, LLC, an investment management firm specializing in private equity investments in the energy sector. In addition, Mr. Gershen serves as the President of Longview Energy Company, a privately held oil and gas company. Since 1989, Mr. Gershen has managed, through Associated Energy Managers, LLC, three funds that invest in energy companies in the United States.

Phillip A. Gobe, age 54, has been a director since November 2005. Mr. Gobe joined the Company in December 2004 as chief operating officer and became president in May 2005. Mr. Gobe has over 31 years of energy industry experience and was with Nuevo Energy Company as chief operating officer from February 2001 until its acquisition by Plains Exploration & Production Company in May 2004. Mr. Gobe’s primary responsibilities were managing Nuevo’s domestic and international exploitation and exploration operations. Prior to his position with Nuevo, Mr. Gobe had been the Senior Vice President of Production for Vastar Resources, Inc. since 1997. From 1976 to 1997, Mr. Gobe worked for Atlantic Richfield Company and its subsidiaries in positions of increasing responsibility, primarily in the Gulf of Mexico and Alaska.

William R. Herrin, Jr., age 72, has been a director since May 2005. Mr. Herrin served in a number of capacities for Chevron Corporation, most recently as Vice President and General Manager, Gulf of Mexico Production Business Unit, Chevron U.S.A. Production Co. from July 1992 until his retirement in 1998.

William O. Hiltz, age 55 has been a director since November 2000. Mr. Hiltz is a senior managing director of Evercore Partners and has been since joining that firm in October 2000. From April 1995 until October 2000, Mr. Hiltz was a managing director and head of the global energy group for UBS Warburg LLC and its predecessor firms, SBC Warburg Dillon Read and Dillon, Read & Co. Inc.

John G. Phillips, age 84, has been a director since May 1998. Since 1995, Mr. Phillips has been an independent financial consultant. Mr. Phillips is former chairman, president and chief executive officer of LL&E and, since 1972, continues to serve as a director of the Whitney National Bank and Whitney Holding Corporation. Mr. Phillips retired from LL&E in 1985.

MANAGEMENT DISCUSSION FROM LATEST 10K

Overview

We were incorporated in January 1998 and operate in a single segment as an independent oil and natural gas exploration and production company. Our current operations are concentrated in the Shelf and deepwater Gulf of Mexico as well as the Gulf Coast onshore region, with a focus on our core properties and surrounding acreage in our Central and Eastern offshore areas.

We continue to strive towards implementing our long-term growth strategy to increase our oil and natural gas reserves and production while keeping our finding and development costs and operating costs competitive with our industry peers. We are implementing this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve or resource potential. We also evaluate acquisition opportunities outside of our core focus area as a complement to the drilling and development activities we have budgeted for that area. We also consider strategic divestiture opportunities from time to time. Our drilling program is predominately comprised of moderate risk, higher or moderate reserve potential opportunities, as well as some high risk, higher reserve potential opportunities and low risk, lower reserve potential opportunities, in order to achieve a balanced program of reserve and production growth.

We use the successful efforts method of accounting for our investment in oil and natural gas properties. Under this method, we capitalize lease acquisition costs, costs to drill and complete exploration wells in which proven reserves are discovered and costs to drill and complete development wells. Exploratory drilling costs are charged to expense if and when the well is determined not to have found reserves in commercial quantities. Seismic, geological and geophysical, and delay rental expenditures are expensed as incurred. We conduct many of our exploration and development activities jointly with others and, accordingly, recorded amounts for our oil and natural gas properties reflect only our proportionate interest in such activities.

Our revenue, profitability and future growth rate depend on a number of factors beyond our control, such as tropical weather, economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices historically have been volatile and may fluctuate widely in the future. Sustained periods of low prices for oil and natural gas could materially and adversely affect our financial position, our results of operations, the quantities of oil and natural gas reserves that we can economically produce and our access to capital. See “Risk Factors” in Item 1A for a more detailed discussion of these risks.

We continue to generate prospects and strive to maintain an extensive inventory of drillable prospects in-house, and we are being exposed to new opportunities through relationships with industry partners. Our policy is to fund our exploration and development expenditures with internally generated cash flow, which allows us to preserve our balance sheet to finance acquisitions and other capital projects. However, from time to time during 2006 and 2007, we have used our bank credit facility to fund working capital needs as further discussed below.

On June 22, 2006, we entered into a Merger Agreement (the “Merger Agreement”) with Stone Energy Corporation (“Stone”), pursuant to which a wholly-owned subsidiary would acquire all of the shares of Stone for a combination of cash and stock valued at approximately $2.1 billion. Prior to entering into the Merger Agreement, Stone terminated its then existing merger agreement with Plains Exploration Company (“Plains”) on the same day. Under the terms of the terminated merger agreement between Stone and Plains, Plains was entitled to a termination fee of $43.5 million, which was advanced by us to Plains and was included in other assets in the Consolidated Balance Sheet at June 30, 2006. On August 28, 2006, Woodside Petroleum, Ltd. (“Woodside”) announced its intention to commence a tender offer (the “Woodside Tender Offer”), through its U.S. subsidiary ATS Inc., for all of our outstanding shares of common stock for $23.00 per share in cash subject to, among other conditions, our stockholders voting down the proposed Stone acquisition. The Woodside Tender Offer was commenced on August 31, 2006. On September 13, 2006, our board of directors (the “Board”), after review with our independent financial and legal advisors, rejected as inadequate the unsolicited conditional offer by Woodside and recommended that our stockholders not tender their shares. On October 12, 2006 we announced that we had terminated the Merger Agreement with Stone and that the Board had directed us, assisted by our financial advisors, to explore strategic alternatives to maximize stockholder value, including the possible sale of our Company. The Woodside Tender Offer expired in November 2006. On March 12, 2007 we announced that we had completed our strategic alternatives process and that we intended to initiate a self-tender offer for 8,700,000 of our common shares, refinance our bank credit facility and repurchase our 8.75% senior notes (the “Senior Notes”) through a concurrent debt tender and consent solicitation offer (the “Transactions”). In order to fund the Transactions, we undertook a placement of $450 million of Senior Unsecured Notes and entered into a new bank credit facility. In addition, we announced our plans to divest selected properties the proceeds from which would be used to reduce debt following the completion of the Transactions. In conjunction with the termination of the Merger Agreement, we paid $8.0 million to Stone, which was included in general and administrative expenses in the fourth quarter of 2006. In addition, the $43.5 million termination fee that was advanced to Plains in June 2006 on behalf of Stone was expensed in 2006 along with other merger and strategic alternatives related costs of $15.0 million. We incurred an additional $9.4 million of legal and financial advisory fees for the year ended December 31, 2007 related to the exploration of strategic alternatives and the tender offers.

On April 23, 2007 we refinanced our bank credit facility with a new $300 million revolving credit facility (the “bank credit facility”) with an initial availability of $225 million and a borrowing base of $200 million. Concurrently with the June 2007 sale of assets described below, the availability under the bank credit facility was automatically reduced to the $200 million borrowing base amount. At December 31, 2007, we had a borrowing base of $200 million and $30 million outstanding under the bank credit facility. The borrowing base remains subject to redetermination based on the proved reserves of the oil and natural gas properties that serve as collateral for the bank credit facility as set out in the reserve report delivered to the banks each April 1 and October 1.

On April 23, 2007 we completed an offering of $450 million aggregate principal amount of senior unsecured notes (the “Senior Unsecured Notes”), consisting of $300 million aggregate principal amount of 9.75% senior notes due 2014 (the “Fixed Rate Notes”), with interest payable semi-annually on April 15 and October 15 beginning on October 15, 2007, and $150 million aggregate principal amount of senior floating rate notes due 2013 (the “Floating Rate Notes”). The interest rate on the Floating Rate Notes for a particular interest period will be an annual rate equal to the three-month LIBOR plus 5.125%. Interest on the Floating Rate Notes is payable quarterly on January 15, April 15, July 15 and October 15, beginning in July of 2007. We may redeem the Senior Unsecured Notes, in whole or in part, prior to their maturity at specific redemption prices including premiums ranging from 4.875% to 0% from 2011 to 2013 and thereafter for the Fixed Rate Notes and premiums ranging from 2% to 0% from 2008 to 2010 and thereafter for the Floating Rate Notes. The indenture governing the Senior Unsecured Notes contains covenants, including but not limited to a covenant limiting the creation of liens securing indebtedness. The Senior Unsecured Notes are not subject to any sinking fund requirements. In November 2007 we consummated an exchange offer pursuant to which we exchanged registered senior unsecured notes having substantially identical terms as the privately placed Senior Unsecured Notes.

On May 4, 2007, we completed a cash tender offer for our $150 million 8.75% senior notes due 2010 (the “Senior Notes”). Approximately $145.5 million of these Senior Notes were repurchased and substantially all of their covenants have been removed.

On June 12, 2007, we sold substantially all of our onshore South Louisiana producing assets for $72.0 million in cash. After giving effect to closing adjustments, the net cash proceeds received totaled approximately $68.6 million. We used the proceeds to pay down a portion of our revolving credit facility. The estimated proved reserves of the disposed properties were approximately 2.1 Mmboe. The Company recorded a gain of $6.5 million on the sale. We have included the results of operations from the onshore South Louisiana assets sold in our consolidated financial statements through the closing date.

Effective April 2, 2007, we elected to discontinue hedge accounting on our existing contracts and elected not to designate any additional hedging contracts that were entered into subsequent to that date as cash flow hedges under Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities,” (“Statement 133”) as amended. Derivative contracts are carried at their fair value on the consolidated balance sheet as Fair value of commodity derivative instruments and all unrealized gains and losses are recorded in Gain (loss) on derivative instruments in Other income (expense) in the Statement of Operations and realized gains and losses related to contract settlements subsequent to April 2, 2007 will also be recognized in the same line in Other income (expense) in the Consolidated Statement of Operations.

On August 29, 2005 Hurricane Katrina made landfall south of New Orleans causing catastrophic damage throughout portions of the Gulf of Mexico and to portions of Alabama, Louisiana and Mississippi, including New Orleans. As a result of the devastating effects of the storm on New Orleans and surrounding areas, we established temporary headquarters at our Houston, Texas office. On September 24, 2005 Hurricane Rita made landfall in the United States on the Texas/Louisiana border between Sabine Pass, Texas and Johnson’s Bayou, Louisiana. This hurricane caused extensive damage throughout portions of the region, particularly to third party infrastructure such as pipelines and processing plants.

As a result of these two major hurricanes and three other hurricanes (the “Tropical Weather”) that traversed the Gulf of Mexico and adjacent land areas in 2005, nearly all of our production was shut in at one time or another during the third quarter of 2005 and into 2006. We have recognized a total of $62.6 million for business interruption recoveries of which $32.9 million and $20.6 million were recorded in the statement of operations in 2006 and fourth quarter of 2005, respectively and an additional $9.1 million was recorded in the first quarter of 2007 upon the final settlement of the Hurricane Katrina claim. All insurance receivables related to these hurricanes have been collected.

On March 8, 2005, we closed the acquisition of the remaining 50% gross working interest in South Timbalier 26 above approximately 13,000 feet subsea that we did not already own for approximately $19.6 million after closing adjustments. As a result of the acquisition, we now own a 100% gross working interest in the producing horizons in this field. The acquisition expands our interest in our core Greater Bay Marchand area and has given us additional flexibility in undertaking the future development of the South Timbalier 26 field.

On January 20, 2005, we closed an acquisition of properties and reserves in south Louisiana for $149.6 million in cash, after adjustments for the exercise of preferential rights by third parties and closing adjustments. The entire purchase price was allocated to property and equipment. The terms of the acquisition did not contain any contingent consideration, options or future commitments. The acquisition was composed of nine fields, four of which were producing at the time of the closing through 14 wells with proved reserves in the southern portions of Terrebone, Lafourche and Jefferson Parishes in Louisiana.

We have included the results of operations from the acquisitions discussed above from their respective closing dates and the disposition through its closing date. We experienced substantial revenue and production fluctuations as a result of these acquisitions through the period prior to the tropical weather discussed above. We experienced a production decrease in 2007 from the previously discussed asset divestiture. For the foregoing reasons these activities will affect the comparability of our historical results of operations with future periods.

Results of Operations

Revenues and Net Income

Our oil and natural gas revenues increased to $454.3 million in 2007 from $449.2 million in 2006. Although production decreased primarily due to the sale of substantially all of our onshore South Louisiana assets in June 2007 (approximately 3,175 Boe per day) combined with natural reservoir declines, we had a slight increase in oil production which had a higher price than natural gas on an equivalent basis, during the year as well as an increase in both oil and natural gas prices as illustrated in the above tables.

Our oil and natural gas revenues increased to $449.2 million in 2006 from $402.0 million in 2005. The increase in revenue for this period is primarily due to production levels restored from Tropical Weather related damage which adversely affected 2005 production, combined with increased oil prices as well as the commencement of production from new fields and additional wells in our South Timbalier 41 field. These increases were partially offset by natural reservoir declines as well as a decline in natural gas prices. Also included in 2006 income from operations was $32.9 million of business interruption insurance recoveries from deferred production at one of our fields resulting from Hurricane Katrina.

We had a net loss of $80.0 million in 2007 compared to a net loss of $50.4 million in 2006. The increased loss was largely due to higher lease operating expenses, exploration expenditures including dry hole costs and impairments, loss on derivative instruments and financing costs discussed below. This increased net loss was partially offset by general and administrative expense that was lower than for the year ended December 31, 2006, which included one time expensed costs of $54.5 million relating to the terminated Merger Agreement with Stone, and the $6.5 million gain recorded in 2007 on the sale of substantially all of our onshore South Louisiana assets in 2007.

We had a net loss of $50.4 million in 2006 compared to net income of $73.1 million in 2005. The decrease was due to impairments of $84.7 million combined with substantially higher general and administrative expenses due to the expensing of costs resulting from the termination of the merger agreement between Stone and Plains, the termination of the Merger Agreement as well as the additional legal and financial advisory costs associated with the unsolicited tender offer by Woodside to acquire all of our outstanding common stock and costs associated with our process of exploring strategic alternatives.

Operating Expenses

Operating expenses were impacted by the following:


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Lease operating expense increased $11.1 million to $69.9 million in 2007. The increase is primarily a result of an increase in new wells coming on stream in new fields ($1.4 million), workover, maintenance and pipeline repair costs and equipment mobilization costs ($7.0 million), and various increases at fields with increased production. These increases were partially offset by the sale of our onshore Louisiana assets ($1.5 million decrease). Contributing to the increase on a per Boe basis were production declines from existing fields with fixed costs and the workover, maintenance and pipeline repair costs discussed.

Lease operating expense increased $8.4 million to $58.8 million in 2006. The increase is primarily a result of a general increase in production from new wells coming on stream in new fields, the continued increase in the cost of oilfield industry services combined with workover costs and uninsured repairs made during 2006. Also contributing to the increase was a gradual restart of storm shut-in production throughout 2006.


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Exploration expenditures and dry hole costs increased $46.5 million to $98.2 million in 2007. The increase is primarily due to our decreased success rate and the increased average dollars expended on each exploratory well. The expense in 2007 is comprised of $87.1 million of costs for 11 exploratory wells or portions thereof which were found to be not commercially productive and $11.1 million of seismic expenditures and delay rentals.

Exploration expenditures and dry hole costs decreased $13.2 million to $51.7 million in 2006. The decrease is primarily due to our increased success rate and the decreased average dollars expended on each exploratory well. The expense in 2006 is comprised of $37.5 million of costs for six exploratory wells or portions thereof which were found to be not commercially productive and $14.2 million of seismic expenditures and delay rentals.

Our exploration expenditures, including dry hole charges, will vary depending on the amount of our capital budget dedicated to exploration activities and the level of success we achieve in exploratory drilling activities.


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Impairments of properties of $114.9 million were taken throughout 2007. The expense was taken in 17 fields. Eight fields with a net book value of $79.4 million experienced mechanical difficulties or facility requirements and it was determined that significant capital would be needed to extend their economic lives and with our decreased capital budget in 2008 it was decided that this capital would be better deployed to projects with more potential. Another six fields with a net book value of $15.9 million underperformed and have fully depleted earlier than anticipated. The remaining three fields were determined to have future projected cash flows of less than their net book values due to performance issues and reserve revisions and therefore an impairment charge of $19.6 million was recorded to write down the assets to their fair value during 2007.

Impairments of properties of $84.7 million were taken during 2006. Substantially all of the expense was taken in eight fields, four of which were onshore assets acquired during an acquisition in January 2005. Three of these onshore fields along with three offshore fields experienced downward revisions of recoverable reserves at December 31, 2006. These revisions along with decreased oil and natural gas prices resulted in impairments of $52.1 million on these assets. The Company elected to release the lease on the remaining onshore field and one other offshore field experienced mechanical difficulties; it was determined that significant capital would be needed to extend its economic life and that this capital would be better deployed to projects with more potential. The net book value of these assets of $27.0 million was therefore written off during 2006.


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Depreciation, depletion and amortization (“DD&A”) decreased $28.1 million to $170.1 million in 2007. The decrease was primarily due to the sale of substantially all of our onshore South Louisiana assets in June 2007 ($55.1 million) partially offset by increased DD&A our Greater Bay Marchand area are due to increased production and capital expenditures in 2007 ($31.8 million). There were other individually small fluctuations both positive and negative. Some fields carry a higher depreciation burden than others and fields in which more recent exploration and development activity has taken place reflect the effect of rising costs of oilfield industry services and capital goods; therefore, changes in the sources of our production will directly impact this expense.

Depreciation, depletion and amortization increased $98.7 million to $198.2 million in 2006. The increase was primarily due to increased production volumes ($14.5 million), a shift in the production contribution from our various fields causing a higher expense per Boe which translates into a $59.3 million increase as well as reserve revisions taken in several of our onshore properties at the end of 2005 that increased the depreciation burden from those fields on a total expense ($24.9 million) and per Boe basis. Some fields carry a higher depreciation burden than others and fields in which more recent exploration and development activity has taken place reflect the effect of rising costs of oilfield industry services and capital goods; therefore, changes in the sources of our production will directly impact this expense.


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General and administrative expenses decreased $58.4 million to $61.7 million in 2007. The overall decrease was primarily attributable to one time expensed costs of $54.5 million incurred during 2006 relating to the terminated Merger Agreement with Stone as well as legal and financial advisory costs of $15.0 million in 2006 associated with the unsolicited Woodside offer and the ensuing strategic alternatives process. In 2007 we expensed approximately $9.4 million relating to financial and legal advisory fees related to the exploration of strategic alternatives and the unsolicited Woodside offer. In addition, included in this expense is stock based compensation of $9.4 million and $10.7 million in the years ended December 31, 2007 and 2006, respectively.

General and administrative expenses increased $76.9 million to $120.1 million in 2006. This increase was attributable to $43.5 million related to the fee advanced by us to Plains on behalf of Stone to terminate their merger agreement as well as $8.0 million we paid to Stone to terminate our Merger Agreement. Also contributing to the increase were legal and financial advisory costs of $15.0 million associated with the Merger Agreement and its subsequent termination, the unsolicited Woodside offer and the ongoing strategic alternatives process. In addition, included in this expense is stock based compensation of $10.7 million and $6.8 million in the years ended December 31, 2006 and 2005, respectively. Stock based compensation expense increased due to the adoption of the fair-value recognition provisions of Statement of Financial Standards No. 123 (R), “ Share Based Payment” (“Statement 123(R”)) during 2006.


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Taxes, other than on earnings, decreased $3.7 million to $9.9 million in 2007. This decrease was due to the sale of substantially all of our onshore South Louisiana assets in June 2007 partially offset by a sharp increase in oil prices during the year. Taxes, other than on earnings, increased $3.2 million to $13.6 million in 2006. This increase was due to the increase in oil prices during the year as well as an increase in the rate charged in 2006 compared to 2005. These taxes are expected to fluctuate from period to period depending on our production volumes from non-federal leases and the commodity prices received.

Other Income and Expense

Interest expense increased $21.6 million to $46.2 million in 2007. The increase is primarily attributable to the net increase in the average borrowings due to the issuance of the $450 million in aggregate principal amount of Senior Unsecured Notes in April 2007 offset by the repurchase of $145.5 million in aggregate principal amount of the $150 million 8.75% Senior Notes completed in May 2007 and combined with borrowings on our bank credit facility. Also included in the expense is a $2.3 million commitment fee paid in April 2007 for the availability of a bridge loan to facilitate the refinancings which was not utilized.

A loss on early extinguishment of debt for the refinancing of the bank credit facility and the repurchase of the Senior Notes of approximately $10.8 million was recorded during the year ended December 31, 2007. This loss includes the write-off of unamortized deferred financing costs related to the bank credit facility and the Senior Notes as well as the consent fees relating to the tender for the 8.75% Senior Notes.

Interest expense increased $6.5 million to $24.6 million in 2006. The increase was a result of an increase in the interest rate as well as the average borrowings under our bank credit facility in the year ended December 31, 2006 compared to the same period of 2005.

A loss on derivative instruments of $13.1 million representing both realized and unrealized losses was recognized in 2007 as compared to none recognized in 2006 due to the change in our method of accounting for derivatives during the second quarter of 2007.

Financial Condition, Liquidity and Capital Resources

The trend of increased revenues we have experienced through 2007 has continued to provide strong cash flows from operations, which totaled $293.9 million in 2007. We intend to fund our exploration and development expenditures from internally generated cash flows, which we define as cash flows from operations before consideration of changes in working capital plus total exploration expenditures. Our cash on hand at December 31, 2007 was $8.9 million. Our future internally generated cash flows will depend on our ability to maintain production and offset production declines in producing fields through our exploration and development program or acquisitions, as well as the prices of oil and natural gas. We may from time to time use the availability of our bank credit facility to balance working capital needs.

On April 23, 2007 we completed a refinancing of our bank credit facility with a new $300 million revolving credit facility (the “bank credit facility”) with an initial availability of $225 million and a borrowing base of $200 million. Concurrently with the sale of assets described previously, the availability under the bank credit facility was automatically reduced to the $200 million borrowing base amount. The bank credit facility is secured by substantially all of our assets. The bank credit facility permits both prime rate borrowings and London InterBank Offered Rate (“LIBOR”) borrowings plus a floating spread. The spread will float up or down based on our utilization of the bank credit facility. The spread can range from 1.00% to 2.5% above LIBOR and 0% to 0.50% above prime. In addition we pay an annual fee on the unused portion of the bank credit facility ranging between 0.25% to 0.50% based on utilization. The bank credit facility contains customary events of default and various financial covenants, which require us to: (i) maintain a minimum current ratio, as defined by our bank credit facility, of 1.0x, (ii) maintain a minimum Consolidated EBITDAX to interest ratio, as defined by our bank credit facility, of 2.5x, and (iii) maintain a ratio of long-term debt to Consolidated EBITDAX below 3.5x, which decreases to 3.0x after April 1, 2008. The borrowing base remains subject to redetermination based on the proved reserves of the oil and natural gas properties that serve as collateral for the bank credit facility as set out in the reserve report delivered to the banks each April 1 and October 1. On April 30, 2007 we borrowed $70 million under our bank credit facility to fund a portion of the equity self-tender offer and have since repaid a portion. As of February 25, 2008, we had a borrowing base of $200 million and $35 million outstanding under our bank credit facility. We were in compliance with the bank credit facility covenants as of December 31, 2007. We expect our borrowing base to decrease on the next determination date due to our reduction in proved reserves in 2007.

Also on April 23, 2007 we completed an offering of $450 million aggregate principal amount of Senior Unsecured Notes, consisting of $300 million aggregate principal amount of 9.75% Fixed Rate Notes due 2014, with interest payable semi-annually on April 15 and October 15 beginning on October 15, 2007, and $150 million aggregate principal amount of Floating Rate Notes due 2013. The interest rate on the Floating Rate Notes for a particular interest period will be an annual rate equal to the three-month LIBOR plus 5.125%. Interest on the Floating Rate Notes are payable quarterly on January 15, April 15, July 15 and October 15, beginning in July of 2007. We may redeem the Senior Unsecured Notes, in whole or in part, prior to their maturity at specific redemption prices including premiums ranging from 4.875% to 0% from 2011 to 2013 and thereafter for the Fixed Rate Notes and premiums ranging from 2% to 0% from 2008 to 2010 and thereafter for the Floating Rate Notes. The indenture governing the Senior Unsecured Notes contains covenants, including but not limited to, a covenant limiting the creation of liens securing indebtedness. The Senior Unsecured Notes are not subject to any sinking fund requirements. In November 2007 we consummated an exchange offer pursuant to which we exchanged registered senior unsecured notes having substantially identical terms as the privately placed Senior Unsecured Notes.

On May 4, 2007, we completed a cash tender offer for our Senior Notes. Approximately $145.5 million of these $150 million 8.75% Senior Notes were repurchased and substantially all of their covenants have been removed.

Net cash of $244.4 million used in investing activities in 2007 consisted primarily of oil and natural gas exploration and development expenditures offset by proceeds of $68.6 million from the sale of onshore South Louisiana oil and natural gas assets in June 2007 and proceeds of $19.6 million from the settlement of our Hurricane Rita insurance claim in March 2007. Exploration expenditures incurred are excluded from operating cash flows and included in investing activities, unless the expenditures do not result in the acquisition of an asset, such as geological and geophysical costs, costs of carrying and retaining undeveloped properties, and dry hole costs. During 2007, we completed 23 drilling projects and 26 recompletion/workover projects, 36 of which were successful. During 2006, we completed 28 drilling projects and 35 recompletion/workover projects, 49 of which were successful and two of which are under evaluation.

Our 2008 capital exploration and development budget is focused on moderate risk exploratory activities on undeveloped leases and our proved properties combined with exploitation and development activities on our proved properties, and does not include acquisitions. We continue to manage our portfolio in order to maintain an appropriate risk balance between low risk development and exploitation activities, moderate risk exploration opportunities and higher risk, higher potential exploration opportunities. Our exploration and development budget for 2008 is currently approved for up to $200 million. During 2007, capital and exploration expenditures were approximately $322.9 million inclusive of $5.6 million in asset retirement obligations. The level of our budget is based on many factors, including results of our drilling program, oil and natural gas prices, availability of operating cash flows, industry conditions, participation by other working interest owners and the costs of drilling rigs and other oilfield goods and services. Should actual conditions differ materially from expectations, some projects may be accelerated or deferred and, consequently, may increase or decrease total 2008 capital expenditures.

In June 2007, we sold substantially all of our onshore South Louisiana assets for $68.6 million after closing adjustments. We have used the proceeds to pay down a portion of our bank credit facility. We have also been marketing selected offshore assets but can give no assurance of the occurrence or timing of any such sale or sales of the assets being so marketed or to the value we may receive.

In addition, the Board authorized an open market share repurchase program of up to $50 million through April 2008, subject to business and market conditions and any debt covenants restricting such repurchases. We may use borrowings under our bank credit facility to fund the repurchase program. As of February 25, 2008, 59,500 shares had been purchased for $0.8 million pursuant to this authorization.

We currently have on file a universal shelf registration statement which allows us to issue an aggregate of $300 million in common stock, preferred stock, senior debt and subordinated debt in one or more separate offerings with a size, price and terms to be determined at the time of sale. We have no immediate plans to enter into transactions under this registration statement, but plan to use the proceeds of any future offering under this registration statement for general corporate purposes, which may include debt repayment, acquisitions, expansion and working capital.

We have experienced and expect to continue to experience substantial working capital requirements, primarily due to our active exploration and development program and merger and acquisition related fees. We believe that internally generated cash flows will be sufficient to meet our budgeted capital requirements for at least the next twelve months. Availability under the bank credit facility will continue to be used to balance short-term fluctuations in working capital requirements. We may use excess available cash flow to reduce our outstanding borrowings, including the redemption when permitted or the repurchase in the marketplace or in privately negotiated transactions of Senior Unsecured Notes; however, additional financing may be required in the future to fund our growth.

MANAGEMENT DISCUSSION FOR LATEST QUARTER

RESULTS OF OPERATIONS

REVENUES AND NET INCOME

Our oil and natural gas revenues increased to $110.3 million in the third quarter of 2007 from $107.4 million in the third quarter of 2006. During the quarter oil and natural gas prices increased but this increase was partially offset by decreased natural gas production due primarily to the sale of substantially all of our onshore South Louisiana assets on June 12, 2007 combined with natural reservoir declines and offset by production from new wells.

Our oil and natural gas revenues increased to $340.3 million in the first nine months of 2007 from $337.6 million in the first nine months of 2006. Although total production decreased due to the reasons mentioned above, the increase in revenue was largely due to an increase in oil production during the period as well as a slight increase in natural gas prices yielding a higher price per Boe.

We recognized a net loss of $4.0 million in the third quarter of 2007 compared to a net loss of $25.2 million in the third quarter of 2006. The overall change from period to period was primarily attributable to one time expensed costs of $46.5 million incurred during the third quarter of 2006 relating to the terminated Merger Agreement with Stone offset by changes in operating costs discussed below.

We recognized a net loss of $6.5 million in the first nine months of 2007 compared to net income of $2.1 million in the first nine months of 2006. The overall change was largely due to higher lease operating expenses, exploration expenditures including dry hole costs and impairments and financing costs discussed below. This was partially offset by one time expensed costs of $46.5 million incurred during the nine months ended September 30, 2006 relating to the terminated Merger Agreement with Stone and the gain on sale of substantially all of our onshore South Louisiana assets.

OPERATING EXPENSES

Operating expenses during the three and nine month periods ended September 30, 2007 and 2006 were affected by the following:


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Lease operating expense (“Loe”) increased to $19.0 million in the third quarter of 2007 compared with $15.2 million in the third quarter of 2006. Loe increased to $53.2 million in the first nine months of 2007 compared with $44.7 million in the first nine months of 2006. Loe also increased on a Boe basis for both the three and nine month periods ended September 30, 2007. These increases are primarily a result of a general increase in new wells coming on stream in new fields combined with production declines from existing fields with fixed costs and workover, maintenance and pipeline repair costs. Also contributing to the increase in the first nine months of 2007 was the gradual restart of storm shut-in production throughout 2006.


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Taxes, other than on earnings, were $2.4 million in the third quarter of 2007 compared with $5.8 million in the third quarter of 2006. Taxes, other than on earnings, decreased to $7.4 million in the first nine months of 2007 from $10.9 million in the first nine months of 2006. The decrease is due to lower natural gas production volumes within the state of Louisiana which is largely the result of the sale of onshore Louisiana assets in June 2007. These taxes are expected to fluctuate from period to period depending on our remaining production volumes from non-federal leases and the commodity prices received.


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Exploration expenditures, including dry hole costs and impairments, increased to $22.7 million in the third quarter of 2007 from $12.1 million in the third quarter of 2006. The expense in the third quarter of 2007 is comprised of $13.4 million of costs for three exploratory wells or portions thereof which were found to be not commercially productive, $7.6 million from the impairment of properties at two of our fields which had reached the end of their economic lives sufficient future cashflows from reserves and $1.7 million of seismic expenditures and delay rentals. The expense in the third quarter of 2006 was comprised of $7.1 million of costs for exploratory wells or portions thereof which were found to be not commercially productive, $1.8 million from the impairment of properties and $3.2 million of seismic expenditures and delay rentals.

Exploration expenditures, including dry hole costs and impairments, increased to $81.9 million in the first nine months of 2007 from $54.5 million in the first nine months of 2006. The expense in the first nine months of 2007 is comprised of $58.1 million of costs for nine exploratory wells or portions thereof which were found to be not commercially productive, $14.6 million from the impairment of properties at four of our fields which had reached the end of their economic lives sufficient future cashflows from reserves and $9.2 million of seismic expenditures and delay rentals. The expense in the first nine months of 2006 was comprised of $35.1 million of costs for exploratory wells or portions thereof which were found to be not commercially productive, $6.7 million of property impairments and $12.7 million of seismic expenditures and delay rentals.

Our exploration expenditures, including dry hole charges, will vary depending on the amount of our capital budget dedicated to exploration activities, the cost of services to drill wells and the level of success we achieve in exploratory drilling activities.


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Depreciation, depletion and amortization (“DD&A”) decreased to $41.7 million in the third quarter of 2007 from $44.5 million in the third quarter of 2006. DD&A decreased to $133.7 million in the first nine months of 2007 from $139.2 million in the first nine months of 2006. This decrease was due to an overall decrease in production previously mentioned. For the year to date period there is also a decline in DD&A per Boe as there was a higher percentage of production contribution from fields that had lower DD&A burdens. Some fields carry a higher burden than others; therefore, changes in the sources of our production will directly impact this expense.


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General and administrative expenses decreased to $12.5 million in the third quarter of 2007 from $68.5 million in the third quarter of 2006. Included in this expense is stock based compensation of $3.0 million and $3.1 million in the third quarters of 2007 and 2006, respectively. General and administrative expenses decreased to $48.4 million in the first nine months of 2007 from $93.2 million in the first nine months of 2006. Included in this expense is stock based compensation of $7.3 million and $7.7 million in the first nine months of 2007 and 2006, respectively. The overall decrease in both the three and nine month periods was primarily attributable to one time expensed costs of $46.5 million incurred during the third quarter of 2006 relating to the terminated Merger Agreement with Stone as well as legal and financial advisory costs of $8.2 million in the third quarter of 2006 associated with the unsolicited Woodside offer.

OTHER INCOME AND EXPENSE

Interest expense increased to $12.9 million in the third quarter of 2007 from $6.9 million in the third quarter of 2006. Interest expense increased to $33.3 million in the first nine months of 2007 from $17.2 million in the first nine months of 2006. The increase was primarily attributable to the net increase in the average borrowings due to the repurchase of $145.5 million in aggregate principal amount of the $150 million 8.75% Senior Notes completed in May 2007 and the issuance of the $450 million in aggregate principal amount of Senior Unsecured Notes in April 2007 combined with borrowings on our bank credit facility. Also included in the expense for the first nine months of 2007 is a $2.3 million commitment fee paid in April 2007 for the availability of a bridge loan to facilitate the refinancings, had it been needed.

A loss on early extinguishment of debt for the refinancing of the bank credit facility and the repurchase of the Senior Notes of approximately $10.8 million was recorded during the nine months ended September 30, 2007. This loss includes the write-off of unamortized deferred financing costs related to the bank credit facility and the Senior Notes as well as the consent fees relating to the tender for the 8.75% Senior Notes.

LIQUIDITY AND CAPITAL RESOURCES

Our cash flows from operations totaled $229.9 million in the first nine months of the year, which included a $56.4 million change in other receivables as a result of our hurricane insurance collections during the period. In addition, net cash of $38.8 million was used in financing activities during the first nine months of the year resulting from the Transactions previously discussed. While we intend to fund our exploration and development expenditures from internally generated cash flows, which we define as cash flows from operations before changes in working capital plus total exploration expenditures, from time to time, due to such things as commodity price fluctuations and capital requirements from exploration successes, we use our bank credit facility to fund additional working capital needs. Our cash on hand at September 30, 2007 was $14.4 million. Our future internally generated cash flows will depend on our rates of production, including those provided by our exploratory and development drilling program, as well as the prices we receive for oil and natural gas.

On April 23, 2007 we completed a refinancing of our bank credit facility with a new $300 million revolving credit facility (the “bank credit facility”) with an initial availability of $225 million and a borrowing base of $200 million. Concurrently with the sale of assets described previously, the availability under the bank credit facility was automatically reduced to the $200 million borrowing base amount. The bank credit facility is secured by substantially all of our assets. The bank credit facility permits both prime rate borrowings and London InterBank Offered Rate (“LIBOR”) borrowings plus a floating spread. The spread will float up or down based on our utilization of the bank credit facility. The spread can range from 1.00% to 2.5% above LIBOR and 0% to 0.50% above prime. In addition we pay an annual fee on the unused portion of the bank credit facility ranging between 0.25% to 0.50% based on utilization. The bank credit facility contains customary events of default and various financial covenants, which require us to: (i) maintain a minimum current ratio, as defined by our bank credit facility, of 1.0x, (ii) maintain a minimum Consolidated EBITDAX to interest ratio, as defined by our bank credit facility, of 2.5x, and (iii) maintain a ratio of long-term debt to Consolidated EBITDAX below 3.5x, which decreases to 3.0x after April 1, 2008. On April 30, 2007 we borrowed $70.0 million under our bank credit facility to fund a portion of the equity self-tender offer. As of November 5, 2007, we had a borrowing base of $200 million and $145 million available under our bank credit facility. We were in compliance with the bank credit facility covenants as of September 30, 2007.

Also on April 23, 2007 we completed an offering of $450 million aggregate principal amount of senior unsecured notes (the “Senior Unsecured Notes”), consisting of $300 million aggregate principal amount of 9.75% Senior Notes due 2014, with interest payable semi-annually on April 15 and October 15 beginning on October 15, 2007, and $150 million aggregate principal amount of Senior Floating Rate Notes due 2013. The interest rate on the Senior Floating Rate Notes for a particular interest period will be an annual rate equal to the three-month LIBOR plus 5.125%. Interest on the Senior Floating Notes are payable quarterly on January 15, April 15, July 15 and October 15, beginning in July of 2007. We may redeem the Senior Unsecured Notes, in whole or in part, prior to their maturity at specific redemption prices including premiums ranging from 4.875% to 0% from 2011 to 2013 and thereafter for the Fixed Rate Notes and premiums ranging from 2% to 0% from 2008 to 2010 and thereafter for the Floating Rate Notes. The indenture governing the Senior Unsecured Notes contains covenants, including but not limited to, a covenant limiting the creation of liens securing indebtedness. The Senior Unsecured Notes are not subject to any sinking fund requirements. In November 2007 we consummated an exchange offer pursuant to which we exchanged registered senior unsecured notes having substantially identical terms as the privately placed Senior Unsecured Notes.

On May 4, 2007, we completed a cash tender offer for our Senior Notes. Approximately $145.5 million of these Senior Notes were repurchased and substantially all of their covenants have been removed.

Net cash of $179.9 million used in investing activities in the first nine months of 2007 consisted primarily of oil and natural gas exploration and development expenditures offset by proceeds of $67.5 million from the sale of onshore South Louisiana oil and natural gas assets in June 2007 and proceeds of $19.6 million from the settlement of our Hurricane Rita insurance claim in March 2007. Dry hole costs resulting from exploration expenditures are excluded from operating cash flows and included in investing activities. During the first nine months of 2007, we completed 19 drilling operations, 11 of which were successful, and 22 recompletion/workover operations all of which were successful. During the first nine months of 2006, we completed 21 drilling operations, 16 of which were successful, and 32 recompletion/workover operations, 28 of which were successful.

Our 2007 capital exploration and development budget is focused on moderate risk and higher risk exploratory activities on undeveloped leases and our proved properties combined with exploitation and development activities on our proved properties, and does not include acquisitions. We continue to manage our portfolio in order to maintain an appropriate risk balance between low risk development and exploitation activities, moderate risk exploration opportunities and higher risk, higher potential exploration opportunities. Currently, our exploration and development budget for 2007 is $300 million. We are currently reviewing our spending expectations for the remainder of the year and estimate that our total capital expenditures for 2007 could total between $325 million and $350 million to fund development costs as a result of exploration success and to fund leasehold costs for leases that may be awarded prior to year-end as a result of our high bids in the October 2007 MMS lease sale. We do not budget for acquisitions. During the first nine months of 2007, capital and exploration expenditures were approximately $267.5 million. The level of our capital and exploration expenditure budget is based on many factors, including results of our drilling program, oil and natural gas prices, industry conditions, participation by other working interest owners and the costs and availability of drilling rigs and other oilfield goods and services. Should actual conditions differ materially from expectations, some projects may be accelerated or deferred and, consequently, we may change our total 2007 capital expenditures.

On June 12, 2007, one of our wholly owned subsidiaries completed its previously announced sale of substantially all of our onshore South Louisiana assets to Castex Energy 2007, L.P. for $72.0 million in cash. After giving effect to closing adjustments through September 30, 2007, the cash proceeds received totaled approximately $67.5 million. We have used the proceeds to pay down a portion of our revolving credit facility. As of the closing date of June 12, 2007, the estimated proved reserves were approximately 1.9 Mmboe. We have also been marketing selected offshore assets but can give no assurance of the occurrence or timing of any such sale or sales of the assets being so marketed or to the value we may receive.

In addition, the Board has also authorized an open market share repurchase program of up to $50 million through April 2008, subject to business and market conditions. We may use borrowings under our bank credit facility to fund the repurchase program. As of November 5, 2007, 59,500 shares have been purchased for $0.8 million pursuant to this authorization.

We have experienced and expect to continue to experience substantial working capital requirements, primarily due to our active capital expenditure program. We believe that internally generated cash flows combined with temporary borrowings under our bank credit facility will be sufficient to meet our budgeted capital requirements for at least the next twelve months. Availability under the bank credit facility may be used to balance short-term fluctuations in working capital requirements. However, additional financing may be required in the future to fund our growth.

Our annual report on Form 10-K for the year ended December 31, 2006 included a discussion of our contractual obligations. There have been no material changes to that disclosure during the nine months ended September 30, 2007 other than those resulting from the Transactions discussed herein. In addition, we do not maintain any off balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are reasonably likely to have a material current or future effect on our financial condition, changes in financial condition, revenues and expenses, results of operations, liquidity, capital expenditures or capital resources.

NEW ACCOUNTING PRONOUNCEMENTS

In September 2006, the FASB issued Statement of Accounting Standards No. 157, “Fair Value Measurements” (“Statement 157”). Statement 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. Statement 157 applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, Statement 157 does not require any new fair value measurements. However, for some entities, the application of Statement 157 will change current practice. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are currently assessing what impact Statement 157 may have on our financial position, results of operations or cash flows.

In February 2007, the FASB issued Statement of Accounting Standards No. 159, “ The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115” (“Statement 159”). Statement 159 permits entities to choose to measure many financial instruments and certain other items at fair value. Statement 159 is expected to expand the use of fair value measurement, which is consistent with the Board’s long-term measurement objectives for accounting for financial instruments. Statement 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of Statement 157. We are currently assessing what impact Statement 159 may have on our financial position, results of operations or cash flows.


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