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

 

 

 

 

Form 10-K

 

 

 

 

 

Commission file number 1-32747

 

 

 

 

MARINER ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

 

 

 

One BriarLake Plaza, Suite 2000

2000 West Sam Houston Parkway South

Houston, Texas 77042

(Address of principal executive offices and zip code)

 

(713) 954-5500

(Registrant’s telephone number, including area code)

 

 

 

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

Securities registered pursuant to section 12(g) of the Act:

None

 

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

 

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

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act 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 o     No þ

 

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 the 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.  þ

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o     Accelerated filer o     Non-accelerated filer þ

 

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

 

The aggregate market value of voting stock held by nonaffiliates of the registrant as of March 17, 2006, based on the closing price of the common stock on the New York Stock Exchange on such date ($20.05 per share), was $1,621,766,425. The number of shares of common stock of the registrant issued and outstanding on March 17, 2006 was 86,100,994.

 

 

TABLE OF CONTENTS

 

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

 

Various statements in this Annual Report, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. Our forward-looking statements are generally accompanied by words such as “may,” “will,” “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. The forward-looking statements in this Annual Report speak only as of the date of this Annual Report; we disclaim any obligation to update these statements unless required by law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. We disclose important factors that could cause our actual results to differ materially from our expectations described in Items 1A and 7 and elsewhere in this Annual Report. These risks, contingencies and uncertainties relate to, among other matters, the following:

 

 

 

Unless the context otherwise requires or indicates, references to “Mariner,” “we,” “our,” “ours,” and “us” refer to Mariner Energy, Inc. and its subsidiaries collectively. Certain oil and natural gas industry terms used in this Annual Report are defined in the “Glossary of Oil and Natural Gas Terms” set forth in Items 1 and 2 of this Annual Report. References to “pro forma” and “on a pro forma basis” mean on a pro forma basis, giving effect to our merger with Forest Energy Resources, Inc. as if it had been consummated at the applicable date or at the beginning of the period referenced. The merger was consummated on March 2, 2006. The unaudited pro forma information contained in this Annual Report has been derived from the historical consolidated financial statements of Mariner and the statements of revenues and direct operating expenses of the Forest Gulf of Mexico operations. The pro forma information is for illustrative purposes only. The financial results may have been different had the Forest Gulf of Mexico operations been an independent company and had the companies always been combined. You should not rely on the pro forma financial information as being indicative of the historical results that would have been achieved had the merger occurred in the past or the future financial results that Mariner will achieve after the merger.

 

General

 

We are an independent oil and gas exploration, development and production company with principal operations in the Gulf of Mexico, both shelf and deepwater, and in the Permian Basin in West Texas. Our management has significant expertise and a successful operating track record in these areas. In the three-year period ended December 31, 2005, we added approximately 280 Bcfe of proved reserves and produced approximately 100 Bcfe, while deploying approximately $475 million of capital on acquisitions, exploration and development.

 

Our primary operating strategy is to generate high-quality exploration and development projects, which enables us to add value through the drill bit. Our expertise in project generation also facilitates our participation in high-quality projects generated by other operators. We will also pursue acquisitions of producing assets that have the potential to provide acceptable risk-adjusted rates of return and further reserve additions through exploration, exploitation, and development opportunities. We target a balanced exposure to development, exploitation and exploration opportunities, both offshore and onshore and seek to maintain a moderate risk profile.

 

On March 2, 2006, we completed a merger transaction with Forest Energy Resources, Inc., which we refer to as Forest Energy Resources. As a result of this merger, we acquired the offshore Gulf of Mexico operations of Forest Oil Corporation (NYSE: FST), which we refer to as the Forest Gulf of Mexico operations. We refer to Forest Oil Corporation as Forest.

 

As of December 31, 2005, we had 338 Bcfe of estimated proved reserves, of which approximately 62% were natural gas and 38% were oil and condensate. Pro forma for the merger transaction, as of December 31, 2005, we had 644 Bcfe of estimated proved reserves, of which approximately 68% were natural gas and 32% were oil and condensate. Our production for 2005 was approximately 29 Bcfe, or 80 MMcfe per day on average, and 95 Bcfe, or 260 MMcfe per day on average, pro forma for the merger, including the negative impact of approximately 15-20 Bcfe of production lost due to Hurricanes Katrina and Rita.

 

The following table sets forth certain information with respect to our estimated proved reserves, production and acreage by geographic area as of December 31, 2005. Reserve volumes and values were determined under the method prescribed by the SEC which requires the application of period-end prices and costs held constant throughout the projected reserve life. Proved reserve estimates do not include any value for probable or possible reserves which may exist, nor do they include any value for undeveloped acreage. The proved reserve estimates represent our net revenue interest in our properties. The reserve information for

Mariner as of December 31, 2005 is based on estimates made in a reserve report prepared by Ryder Scott Company, L.P., independent petroleum engineers (“Ryder Scott”).

 

 

 

 

The following table sets forth certain information with respect to our pro forma estimated proved reserves, production and acreage by geographic area as of December 31, 2005. The reserve information as of December 31, 2005 for the Forest Gulf of Mexico operations is based on estimates made by internal staff engineers of Forest, which estimates were audited by Ryder Scott. This information is presented on a pro forma basis, giving effect to our merger with Forest Energy Resources as though it had been consummated on December 31, 2005. We consummated the merger on March 2, 2006.

 

 

 

 

We were incorporated in August 1983 as a Delaware corporation. We have three subsidiaries, Mariner Energy Resources, Inc., a Delaware corporation, Mariner LP LLC, a Delaware limited liability company, and Mariner Energy Texas LP, a Delaware limited partnership. Our principal executive office is located at One BriarLake Plaza, Suite 2000, 2000 West Sam Houston Parkway South, Houston, Texas 77042. Our telephone number is (713) 954-5500.

 

Our Strategy

 

The principal elements of our operating strategy include:

 

Generate and pursue high-quality prospects.  We expect to continue our strategy of growth through the drill bit by continuing to identify and develop high-impact shelf, deep shelf and deepwater projects in the Gulf of Mexico. Our technical team has significant expertise and a successful track record of achieving growth by generating prospects internally, and selectively participating in prospects generated by other operators. We

believe the Gulf of Mexico is an area that offers substantial growth opportunities, and our acquisition of the Forest Gulf of Mexico operations has more than doubled our existing undeveloped acreage position in the Gulf, providing numerous additional exploration, exploitation and development opportunities.

 

Maintain a moderate risk profile.  We seek to manage our risk profile by targeting a balanced exposure to development, exploitation and exploration opportunities. For example, we intend to continue to develop and seek to expand our West Texas assets, which contribute stable cash flows and long-lived reserves to our portfolio as a counterbalance to our high-impact, high-production Gulf of Mexico assets. We also seek to mitigate and diversify our risk in drilling projects by selling partial or entire interests in projects to industry partners or by entering into arrangements with industry partners in which they agree to pay a disproportionate share of drilling costs and to compensate us for expenses incurred in prospect generation. We also enter into trades or farm-in transactions whereby we acquire interests in third-party generated prospects, thereby gaining exposure to a greater number of prospects. We expect more opportunities to participate in these prospects in the future, as a result of the scale and increased cash flow from the Forest Gulf of Mexico operations.

 

Pursue opportunistic acquisitions.  Until 2005, we grew our reserves primarily through the drill bit. However, in 2005 we added significant proved reserves through onshore acquisitions in West Texas. As part of our growth strategy, we will seek to continue to acquire producing assets that have the potential to provide acceptable risk-adjusted rates of return and further reserve additions through exploration, exploitation and development opportunities.

 

Our Competitive Strengths

 

We believe our core resources and strengths include:

 

Our high-quality assets with geographic and geological diversity.  Our assets and operations are diversified among the Gulf of Mexico, including shelf, deep shelf and deepwater, and the Permian Basin in West Texas. Our asset portfolio provides a balanced exposure to long-lived West Texas reserves, Gulf of Mexico shelf growth opportunities and high-impact deepwater prospects.

 

Our large inventory of prospects.  We believe we have significant potential for growth through the development of our existing asset base. The acquisition of the Forest Gulf of Mexico operations more than doubled our existing undeveloped acreage position in the Gulf of Mexico to approximately 450,000 net acres and increased our total net leasehold acreage offshore to nearly one million acres, providing numerous exploration, exploitation and development opportunities. We currently have an inventory of more than 1,000 drilling locations in West Texas, which we believe would require at least seven years to drill. Our 110 Bcfe of undeveloped estimated proved reserves in West Texas includes 441 locations.

 

Our successful track record of finding and developing oil and gas reserves.  We have demonstrated our expertise in finding and developing additional proved reserves. In the three-year period ended December 31, 2005, we deployed approximately $475 million of capital on acquisitions, exploration and development, while adding approximately 280 Bcfe of proved reserves and producing approximately 100 Bcfe.

 

Our depth of operating experience.  Our team of 36 geoscientists, engineers, geologists and other technical professionals and landmen average more than 20 years of experience in the exploration and production business (including extensive experience in the Gulf of Mexico), much of it with major oil companies. The addition of experienced Forest personnel to Mariner’s team of technical professionals has further enhanced our ability to generate and maintain an inventory of high-quality drillable prospects and to further develop and exploit our assets. Mariner’s technical team has also proven to be an effective and efficient operator in West Texas, as evidenced by our successful production and reserve growth there in recent years.

 

Our technology and production techniques.  Our team of geoscientists currently has access to seismic data from multiple, recent vintage 3-D seismic databases covering more than 6,600 blocks in the Gulf of Mexico that we intend to continue to use to develop prospects on acreage being evaluated for leasing and to develop and further refine prospects on our expanded acreage position. We also have extensive experience and a successful track record in the use of subsea tieback technology to connect offshore wells to existing production facilities. This technology facilitates production from offshore properties without the necessity of

fabrication and installation of more costly platforms and top side facilities that typically require longer lead times. We believe the use of subsea tiebacks in appropriate projects enables us to bring production online more quickly, makes target prospects more profitable and allows us to exploit reserves that may otherwise be considered non-commercial because of the high cost of infrastructure. In the Gulf of Mexico, in the three years ended December 31, 2005, we were directly involved in 14 projects (five of which we operated) utilizing subsea tieback systems in water depths ranging from 475 feet to more than 6,700 feet.

 

Recent Developments

 

Forest Gulf of Mexico Merger

 

On March 2, 2006, we completed a merger transaction with Forest Energy Resources. Prior to the consummation of the merger, Forest transferred and contributed the assets and certain liabilities associated with its offshore Gulf of Mexico operations to Forest Energy Resources. Immediately prior to the merger, Forest distributed all of the outstanding shares of Forest Energy Resources to Forest shareholders on a pro rata basis. Forest Energy Resources then merged with a newly formed subsidiary of Mariner, and became a new wholly owned subsidiary of Mariner. Immediately following the merger, approximately 59% of the Mariner common stock was held by shareholders of Forest and approximately 41% of Mariner common stock was held by the pre-merger stockholders of Mariner.

 

Forest Energy Resources had approximately 306 Bcfe of estimated proved reserves as of December 31, 2005, of which approximately 76% were natural gas and 24% were oil and condensate. The reserves and operations acquired from Forest are concentrated in the shelf and deep shelf of the Gulf of Mexico and represent a significant addition to Mariner’s asset portfolio in those areas of operation.

 

We believe our acquisition of the Forest Gulf of Mexico operations and the scale they bring to our business has further moderated our risk profile, provided many exploration, exploitation and development opportunities, enhanced our ability to participate in prospects generated by other operators, and added a significant cash flow generating resource that has improved our ability to compete effectively in the Gulf of Mexico and to provide funding for exploration and acquisitions. We believe we are well-positioned to optimize the Forest Energy Resources assets through aggressive and timely exploitation.

 

Hurricanes Katrina and Rita

 

Our operations were adversely affected by one of the most active and severe hurricane seasons in recorded history. As of December 31, 2005 we had approximately 5 MMcfe per day of net production shut-in as a result of Hurricanes Katrina and Rita, and approximately 56 MMcfe per day on a pro forma basis. We estimate that as of March 15, 2006, approximately 42 MMcfe per day remains shut in. Additionally, we experienced delays in the startup of four of our deepwater projects primarily as a result of Hurricane Katrina. Two of the projects have commenced production, and two are anticipated to commence production in the second quarter of 2006. For the period September through December 2005, we estimate that approximately 6-8 Bcfe of production (approximately 15-20 Bcfe on a pro forma basis) was deferred because of the hurricanes. We also estimate that an additional 8 Bcfe of pro forma production will be deferred in 2006 before repairs to offshore and onshore infrastructure are fully completed, allowing return of full production from our fields. However, the actual volumes deferred in 2006 will vary based on circumstances beyond our control, including the timing of repairs to both onshore and offshore platforms, pipelines and facilities, the actions of operators on our fields, availability of service equipment, and weather.

 

We estimate the costs to repair damage caused by the hurricanes to our platforms and facilities will total approximately $50 million. However, until we are able to complete all the repair work this estimate is subject to significant variance. For the insurance period covering the 2005 hurricane activity, we carried a $3 million annual deductible and a $0.5 million single occurrence deductible for the Mariner assets. Insurance covering the Forest Gulf of Mexico properties carried a $5 million deductible for each occurrence. Until the repairs are completed and we submit costs to our insurance underwriters for review, the full extent of our insurance recoveries and the resulting net cost to us for Hurricanes Katrina and Rita will be unknown. However, we expect the total costs not covered by the combined insurance policies to be less than $15 million.

Insurance

 

Effective March 2, 2006, Mariner has been accepted as a member of OIL Insurance, Ltd. or OIL, an industry insurance cooperative, through which the assets of both Mariner and the Forest Gulf of Mexico operations are insured. The coverage contains a $5 million annual per-occurrence deductible for the combined assets and a $250 million per-occurrence loss limit. However, if a single event causes losses to OIL insured assets in excess of $1 billion in the aggregate (effective June 1, 2006, such amount will be reduced to $500 million), amounts covered for such losses will be reduced on a pro rata basis among OIL members. Pending review of our insurance program, we have maintained our commercially underwritten insurance coverage for the pre-merger Mariner assets, which coverage expires on September 30, 2006. This coverage contains a $3 million annual deductible and a $500,000 occurrence deductible, $150 million of aggregate loss limits, and limited business interruption coverage. While the coverage remains in effect, it will be primary to the OIL coverage for the pre-merger Mariner assets.

 

Credit Agreement

 

On March 2, 2006, Mariner and Mariner Energy Resources, Inc. entered into a $500 million senior secured revolving credit facility, and an additional $40 million senior secured letter of credit facility. The revolving credit facility will mature on March 2, 2010, and the $40 million letter of credit facility will mature on March 2, 2009. We used borrowings under the revolving credit facility to facilitate the merger and to retire existing debt, and we may use borrowings in the future for general corporate purposes. The $40 million letter of credit facility has been used to obtain a letter of credit in favor of Forest to secure our performance of our obligations under an existing drill-to-earn program. The outstanding principal balance of loans under the revolving credit facility may not exceed the borrowing base, which initially has been set at $400 million. If the borrowing base falls below the outstanding balance under the revolving credit facility, we will be required to prepay the deficit, pledge additional unencumbered collateral, repay the deficit and cash collateralize certain letters of credit, or effect some combination of such prepayment, pledge, and repayment and collateralization.

 

Summary Reserve and Operating Data

 

The following tables present certain information with respect to our estimated proved oil and natural gas reserves at year end and operating data for the periods presented. The 2005 information is also presented on a pro forma basis, giving effect to our merger with Forest Energy Resources as though it had been consummated on January 1, 2005. We consummated the merger on March 2, 2006.

 

Estimated Proved Reserves

 

The reserve information in the table below for Mariner is based on estimates made in reserve reports prepared by Ryder Scott. The reserve information as of December 31, 2005 for the Forest Gulf of Mexico operations is based on estimates made by internal staff engineers at Forest, which estimates were audited by Ryder Scott. Accordingly, the pro forma reserve information presented below includes both reserves that were estimated by Ryder Scott and reserves that were estimated by internal staff engineers at Forest and audited by Ryder Scott.

 

 

 

Operating Data

 

The following table presents certain information with respect to our production and operating data for the periods presented.

 

 

 

Properties

 

We currently own oil and gas properties, producing and non-producing, onshore in Texas and offshore in the Gulf of Mexico, primarily in federal waters. Our largest properties (including the largest properties we acquired in our merger with Forest Energy Resources), based on the present value of estimated future net proved reserves as of December 31, 2005, are shown in the following table.

 

 

 

 

 

West Texas Permian Basin

 

Aldwell Unit.  We operate and own working interests in individual wells ranging from 33% to 84% (with an average working interest of approximately 66.5%), in the 18,500-acre Aldwell Unit. The field is located in the heart of the Spraberry geologic trend southeast of Midland, Texas, and has produced oil and gas since 1949. We began our recent redevelopment of the Aldwell Unit by drilling eight wells in the fourth quarter of 2002, 43 wells in 2003, 54 wells in 2004 and 65 wells in 2005. As of December 31, 2005, there were a total of 249 wells producing or capable of producing in the field.

 

We have completed construction of our own oil and gas gathering system and compression facilities in the Aldwell Unit. We began flowing gas production through the new facilities on June 1, 2005. We have also entered into new contracts with third parties to provide processing of our natural gas and transportation of our oil produced in the unit. The new gas arrangement also provides us with the option to sell our gas to one of four firm or five interruptible sales pipelines versus a single outlet under the former arrangement. These arrangements have improved the economics of production from the Aldwell Unit.

 

Tamarack/Spraberry Properties.  Effective in October 2005, we entered into an agreement covering approximately 33,000 acres in West Texas, pursuant to which, upon closing, we acquired an approximate 35% working interest in approximately 200 existing producing wells effective November 1, 2005, and committed to drill an additional 150 wells within a four year period, while funding $36.5 million of our partner’s share of drilling costs for such 150-well drilling program. We will obtain an assignment of an approximate 35% working interest in the entire committed acreage upon completion of the 150-well program. During 2005, we drilled 13 new wells under this agreement.

 

Other Projects and Activity.  In December 2004, we acquired an approximate 50% working interest in two Permian Basin fields containing approximately 4,000 acres. We believe the fields contain more than twenty 80-acre infill drilling locations and that either or both may also have 40-acre infill drilling opportunities. We have commenced drilling operations in one of the fields. In February 2005, we acquired five producing wells located in Howard County, Texas, approximately 50 miles north of our Aldwell Unit. The purchase price was $3.5 million.

 

In December 2005, we acquired an interest in approximately 5,500 acres with an average 84% working interest and 64% net revenue interest in the Spraberry trend area 5-10 miles southwest of our Aldwell Unit. The purchase price was $5.5 million with an effective date of August 1, 2005 and included 34 producing wells with the potential to drill 68 40-acre wells.

 

During 2005, our aggregate net capital expenditures for the West Texas Permian Basin were approximately $86 million, and we added 97.2 Bcfe of proved reserves, while producing 6.6 Bcfe.

Production

 

The following table presents certain information with respect to net oil and natural gas production attributable to our properties, average sales price received and expenses per unit of production during the periods indicated. The 2005 information is also presented on a pro forma basis, giving effect to our merger with Forest Energy Resources as though it had been consummated on January 1, 2005. We consummated the merger on March 2, 2006.

 

 

 

 

Productive Wells

 

The following table sets forth the number of productive oil and gas wells in which we owned a working interest at December 31, 2005 and December 31, 2004 and on a pro forma basis at December 31, 2005.

 

 

Acreage

 

The following table sets forth certain information with respect to actual and pro forma developed and undeveloped acreage as of December 31, 2005. The pro forma information gives effect to our merger with Forest Energy Resources as though it had been consummated on December 31, 2005. We consummated the merger on March 2, 2006.

 

 

 

 

The following table sets forth Mariner’s offshore undeveloped acreage as of December 31, 2005 that is subject to expiration during the three years ended December 31, 2008. The amount of onshore undeveloped acreage subject to expiration is not material.

 

Drilling Activity

 

Certain information with regard to our drilling activity during the years ended December 31, 2005, 2004 and 2003 is set forth below.

 

 

We were in the process of drilling nine gross (4.46 net) wells as of December 31, 2005.

 

Property Dispositions

 

When appropriate, we consider the sale of discoveries that are not yet producing or have recently begun producing when we believe we can obtain acceptable returns on our investment without holding the investment through depletion. Such sales enable us to maintain and redeploy the proceeds to activities that we believe have a higher potential financial return. No property dispositions of producing properties were made during the three years ended December 31, 2005. However, we sold working interests totaling 50% in each of our non-producing deepwater Falcon and Harrier projects in two separate sales for $48.8 million in 2002 and $121.6 million in 2003.

 

Marketing and Customers

 

We market substantially all of the oil and natural gas production from the properties we operate as well as the properties operated by others where our interest is significant. The majority of our natural gas, oil and condensate production is sold to a variety of purchasers under short-term (less than 12 months) contracts at

market-based prices. The following table lists customers accounting for more than 10% of our total revenues for the year indicated.

 

 

 

 

Title to Properties

 

Substantially all of our properties currently are subject to liens securing our credit facility and obligations under hedging arrangements with members of our bank group. In addition, our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other typical burdens and encumbrances. We do not believe that any of these burdens or encumbrances materially interferes with the use of such properties in the operation of our business. Our properties may also be subject to obligations or duties under applicable laws, ordinances, rules, regulations and orders of governmental authorities.

 

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. Title investigation is made usually only before commencement of drilling operations. We believe that title issues generally are not as likely to arise with respect to offshore oil and gas properties as with respect to onshore properties.

 

Competition

 

We believe that our leasehold acreage, exploration, drilling and production capabilities, large 3-D seismic database and technical and operational experience generally enable us to compete effectively. However, our competitors include major integrated oil and natural gas companies and numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our larger competitors possess and employ financial and personnel resources substantially greater than those available to us. Such companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future is dependent upon our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position.

Royalty Relief

 

The Outer Continental Shelf Deep Water Royalty Relief Act, or RRA, signed into law on November 28, 1995, provides that all tracts in the Gulf of Mexico west of 87 degrees, 30 minutes West longitude in water more than 200 meters deep offered for bid within five years after the RRA was enacted will be relieved from normal federal royalties as follows:

 

 

Leases offered for bid within five years after the RRA was enacted are referred to as “post-Act leases.” The RRA also allows mineral interest owners the opportunity to apply for discretionary royalty relief for new production on leases acquired before the RRA was enacted, or pre-Act leases, and on leases acquired after November 28, 2000, or post-2000 leases. If the Minerals Management Service, or MMS, determines that new production under a pre-Act lease or post-2000 lease would not be economical without royalty relief, then the MMS may relieve a portion of the royalty to make the project economical.

 

In addition to granting discretionary royalty relief, the MMS has elected to include automatic royalty relief provisions in many post-2000 leases, even though the RRA no longer applies. For each post-2000 lease sale that has occurred to date, the MMS has specified the water depth categories and royalty suspension volumes applicable to production from leases issued in the sale.

 

In 2004, the MMS adopted additional royalty relief incentives for production of natural gas from reservoirs located deep under shallow waters of the Gulf of Mexico. These incentives apply to gas produced in water depths of less than 200 meters and from deep gas accumulations located at depths of greater than 15,000 feet below the shelf. Drilling of qualified wells must have started on or after March 26, 2003, and production must begin prior to January 26, 2009.

 

The impact of royalty relief can be significant. The normal royalty due for leases in water depths of 400 meters or less is 16.7% of production, and the normal royalty for leases in water depths greater than 400 meters is 12.5% of production. Royalty relief can substantially improve the economics of projects located in deepwater or in shallow water and involving deep gas.

 

Many of our leases from the MMS contain language suspending royalty relief if commodity prices exceed predetermined threshold levels for a given calendar year. As a result, royalty relief for a lease in a particular calendar year may be contingent upon average commodity prices staying below the threshold price specified for that year. In 2000, 2001, 2003, 2004 and 2005 natural gas prices exceeded the applicable price thresholds for a number of our projects, and we have been required to pay royalties for natural gas produced in those years. However, we have contested the MMS authority to include price thresholds in two of our post-Act leases, Black Widow and Garden Banks 367. We believe that post-Act leases are entitled to automatic royalty relief under the RRA regardless of commodity prices, and have pursued administrative and judicial remedies in this dispute with the MMS. For more information concerning the contested royalty payments and the MMS’s demands, see Item 3 of this Annual Report.

 

Regulation

 

Our operations are subject to extensive and continually changing regulation affecting the oil and natural gas industry. Many departments and agencies, both federal and state, are authorized by statute to issue, and have issued, rules and regulations binding on the oil and natural gas industry and its individual participants. The failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. We do not believe that we are affected in a significantly different manner by these regulations than are our competitors.

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, the Natural Gas Policy Act of 1978 and the regulations promulgated thereunder by the Federal Energy Regulatory Commission, or FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the Natural Gas Policy Act of 1978. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act of 1938 and Natural Gas Policy Act of 1978 price and non-price controls affecting producer sales of natural gas effective January 1, 1993. Congress could, however, re-enact price controls in the future. The FERC regulates interstate natural gas pipeline transportation rates and service conditions, which affect the marketing of gas produced by us and the revenues received by us for sales of such natural gas. The FERC requires interstate pipelines to provide open-access transportation on a non-discriminatory basis for all natural gas shippers. The FERC frequently reviews and modifies its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry. In addition, with respect to production onshore or in state waters, the intra-state transportation of natural gas would be subject to state regulatory jurisdiction as well.

 

In August, 2005, Congress enacted the Energy Policy Act of 2005, or EP Act 2005. Among other matters, EP Act 2005 amends the Natural Gas Act, or NGA, to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as Mariner and Forest, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. On January 19, 2006, the FERC issued regulations implementing this provision. The regulations make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EP Act 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas.

 

Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. We cannot predict when or if any such proposals might become effective or their effect, if any, on our operations. The natural gas industry historically has been closely regulated; thus, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue indefinitely into the future.

 

Regulation of Production

 

The production of oil and natural gas is subject to regulation under a wide range of state and federal statutes, rules, orders and regulations. State and federal statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Texas and Louisiana, 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 rates of production from oil and natural gas wells, the spacing of wells, and the plugging and abandonment of wells and removal of related production equipment. Texas and Louisiana also restrict production to the market demand for oil and natural gas and several states have indicated interests in revising applicable regulations. These regulations can limit the amount of oil and natural gas we can produce from our wells, limit the number of wells, or limit the locations at which we can conduct drilling operations. Moreover, each state generally imposes a production or

severance tax with respect to production and sale of crude oil, natural gas and gas liquids within its jurisdiction.

 

Most of our offshore operations are conducted on federal leases that are administered by the MMS. Such leases require compliance with detailed MMS regulations and orders pursuant to the Outer Continental Shelf Lands Act that are subject to interpretation and change by the MMS. Among other things, we are required to obtain prior MMS approval for our exploration plans and development and production plans at each lease. MMS regulations also impose construction requirements for production facilities located on federal offshore leases, as well as detailed technical requirements for plugging and abandonment of wells, and removal of platforms and other production facilities on such leases. The MMS requires lessees to post surety bonds, or provide other acceptable financial assurances, to ensure all obligations are satisfied on federal offshore leases. The cost of these surety bonds or other financial assurances can be substantial, and there is no assurance that bonds or other financial assurances can be obtained in all cases. We are currently in compliance with all MMS financial assurance requirements. Under certain circumstances, the MMS is authorized to suspend or terminate operations on federal offshore leases. Any suspension or termination of operations on our offshore leases could have an adverse effect on our financial condition and results of operations.

 

In 2000, the MMS issued a final rule that governs the calculation of royalties and the valuation of crude oil produced from federal leases. That rule amended the way that the MMS values crude oil produced from federal leases for determining royalties by eliminating posted prices as a measure of value and relying instead on arm’s-length sales prices and spot market prices as indicators of value. On May 5, 2004, the MMS issued a final rule that changed certain components of its valuation procedures for the calculation of royalties owed for crude oil sales. The changes include changing the valuation basis for transactions not at arm’s-length from spot to NYMEX prices adjusted for locality and quality differentials, and clarifying the treatment of transactions under a joint operating agreement. We believe that the changes will not have a material impact on our financial condition, liquidity or results of operations.

 

Environmental Regulations

 

Our operations are subject to numerous stringent and complex laws and regulations at the federal, state and local levels governing the discharge of materials into the environment or otherwise relating to human health and environmental protection. These laws and regulations may, among other things:

 

 

Failure to comply with these laws and regulations or to obtain or comply with permits may result in the assessment of administrative, civil and criminal penalties, imposition of remedial requirements and the imposition of injunctions to force future compliance. Offshore drilling in some areas has been opposed by environmental groups and, in some areas, has been restricted. Our business and prospects could be adversely affected to the extent laws are enacted or other governmental action is taken that prohibits or restricts our exploration and production activities or imposes environmental protection requirements that result in increased costs to us or the oil and natural gas industry in general.

 

Spills and Releases.  The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the “owner” and “operator” of the site where the release occurred, past owners and operators of the site, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Responsible parties under CERCLA may be liable for the costs of cleaning up hazardous substances that have been released into the environment and for damages to natural resources. Additionally, it is not uncommon for neighboring landowners and other third parties to file tort

claims for personal injury and property damage allegedly caused by the release of hazardous substances 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 currently own, lease or operate, and have in the past owned, leased or operated, numerous properties that for many years have been used for the exploration and production of oil and gas. Many of these properties have been operated by third parties whose actions with respect to the treatment and disposal or release of hydrocarbons or other wastes were not under our control. It is possible that hydrocarbons or other wastes may have been disposed of or released on or under such properties, or on or under other locations where such wastes may have been taken for disposal. These properties and wastes disposed thereon may be subject to CERCLA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial plugging operations to prevent future contamination, or to pay the costs of such remedial measures. Although we believe we have utilized operating and disposal practices that are standard in the industry, during the course of operations hydrocarbons and other wastes have been released on some of the properties we own, lease or operate. We are not presently aware of any pending clean-up obligations that could have a material impact on our operations or financial condition.

 

The Oil Pollution Act.  The Oil Pollution Act of 1990, or OPA, and regulations thereunder impose strict, joint and several liability on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the U.S. 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 establishes a liability limit for onshore facilities of $350 million, while the liability limit for offshore facilities is equal to all removal costs plus up to $75 million in other damages. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up.

 

The OPA also requires the lessee or permittee of an offshore area in which a covered offshore facility is located to provide financial assurance in the amount of $35 million to cover liabilities related to an oil spill. The amount of financial assurance required under the OPA may be increased up to $150 million depending on the risk represented by the quantity or quality of oil that is handled by a facility. The failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. We are not aware of any action or event that would subject us to liability under the OPA, and we believe that compliance with the OPA’s financial assurance and other operating requirements will not have a material impact on our operations or financial condition.

 

Water Discharges.  The Federal Water Pollution Control Act of 1972, also known as the Clean Water Act, imposes restrictions and controls on the discharge of produced waters and other oil and gas pollutants into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions may be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System, or NPDES, program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the oil and gas industry into certain coastal and offshore water. The Clean Water Act provides for civil, criminal and administrative penalties for unauthorized discharges of oil and other pollutants, and imposes liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. Comparable state statutes impose liabilities and authorize penalties in the case of an unauthorized discharge of petroleum or its derivatives, or other pollutants, into state waters.

 

In furtherance of the Clean Water Act, the EPA promulgated the Spill Prevention, Control, and Countermeasure, or SPCC, regulations, which require facilities that possess certain threshold quantities of oil that could impact navigable waters or adjoining shorelines to prepare SPCC plans and meet specified

construction and operating standards. The SPCC regulations were revised in 2002 and required the amendment of SPCC plans before February 18, 2006, if necessary, and requires compliance with the implementation of such amended plans by August 18, 2006. We may be required to prepare SPCC plans for some of our facilities where a spill or release of oil could reach or impact jurisdictional waters of the U.S.

 

Air Emissions.  The Federal Clean Air Act, and associated state laws and regulations, restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. We believe that compliance with the Clean Air Act and analogous state laws and regulations will not have a material impact on our operations or financial condition.

 

Waste Handling.  The Resource Conservation and Recovery Act, or RCRA, and analogous state and local laws and regulations govern the management of wastes, including 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. RCRA specifically excludes from the definition of hazardous waste drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil and natural gas. 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. However, these wastes may be regulated by EPA or state agencies as solid waste. In addition, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated under RCRA as hazardous waste. We do not believe the current costs of managing our wastes, as they are presently classified, to be significant. However, any repeal or modification of the oil and natural gas exploration and production exemption, or modifications of similar exemptions in analogous state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses.

 

Employees

 

As of March 2, 2006, we had 196 full-time employees. Our employees are not represented by any labor unions. We consider relations with our employees to be satisfactory. We have never experienced a work stoppage or strike.

 

Insurance Matters

 

In September 2004, we incurred damage from Hurricane Ivan that affected our Mississippi Canyon 66 (Ochre) and Mississippi Canyon 357 fields. Production from Mississippi Canyon 357 was shut-in until March 2005, when necessary repairs were completed and production recommenced. Production from Ochre is currently shut-in awaiting rerouting of umbilical and flow lines to another host platform. Prior to Hurricane Ivan, this field was producing at a net rate of approximately 6.5 MMcfe per day. Production from Ochre is expected to recommence in the second quarter of 2006. In addition, a semi-submersible rig on location at Mariner’s Viosca Knoll 917 (Swordfish) field was blown off location by the hurricane and incurred damage. Until we are able to complete all the repair work and submit costs to the insurance underwriters for review, the full extent of our insurance recovery and the resulting net cost to Mariner is unknown. For the insurance period ending September 30, 2004, we carried an annual deductible of $1.25 million and a single occurrence deductible of $.375 million.

 

In 2005 our operations were adversely affected by one of the most active and severe hurricane seasons in recorded history. As of December 31, 2005 we had approximately 5 MMcfe per day of net production shut-in as a result of Hurricanes Katrina and Rita, and approximately 56 MMcfe per day on a pro forma basis. We estimate that as of March 15, 2006 approximately 42 MMcfe per day remains shut in. Additionally, we

experienced delays in the startup of four of our deepwater projects primarily as a result of Hurricane Katrina. Two of the projects have commenced production, and two are anticipated to commence production in the second quarter of 2006. For the period September through December 2005, we estimate that approximately 6-8 Bcfe of production (approximately 15-20 Bcfe on a pro forma basis) was deferred because of the hurricanes. We also estimate that an additional 8 Bcfe of pro forma production will be deferred in 2006 before repairs to offshore and onshore infrastructure are fully completed, allowing return of full production from our fields. However, the actual volumes deferred in 2006 will vary based on circumstances beyond our control, including the timing of repairs to both onshore and offshore platforms, pipelines and facilities, the actions of operators on our fields, availability of service equipment, and weather.

 

We estimate the costs to repair damage caused by the hurricanes to our platforms and facilities will total approximately $50 million. However, until we are able to complete all the repair work this estimate is subject to significant variance. For the insurance period covering the 2005 hurricane activity, we carried a $3 million annual deductible and a $0.5 million single occurrence deductible for the Mariner assets. Insurance covering the Forest Gulf of Mexico properties carried a $5 million deductible for each occurrence. Until the repairs are completed and we submit costs to our insurance underwriters for review, the full extent of our insurance recoveries and the resulting net cost to us for Hurricanes Katrina and Rita will be unknown. However, we expect the total costs not covered by the combined insurance policies to be less than $15 million.

 

Effective March 2, 2006, Mariner has been accepted as a member of OIL Insurance, Ltd., an industry insurance cooperative, through which the assets of both Mariner and the Forest Gulf of Mexico operations are insured. The coverage contains a $5 million annual per-occurrence deductible for the combined assets and a $250 million per-occurrence loss limit. However, if a single event causes losses to OIL insured assets in excess of $1 billion in the aggregate (effective June 1, 2006, such amount will be reduced to $500 million), amounts covered for such losses will be reduced on a pro rata basis among OIL members. Pending review of our insurance program, we have maintained our commercially underwritten insurance coverage for the pre-merger Mariner assets, which coverage expires on September 30, 2006. This coverage contains a $3 million annual deductible and a $500,000 occurrence deductible, $150 million of aggregate loss limits, and limited business interruption coverage. While the coverage remains in effect, it will be primary to the OIL coverage for the pre-merger Mariner assets.

 

Enron Related Matters

 

In 1996, JEDI, an indirect wholly owned subsidiary of Enron Corp., acquired approximately 96% of Mariner Energy LLC, which at the time of acquisition indirectly owned 100% of Mariner Energy, Inc. After JEDI acquired us, we continued our prior business as an independent oil and natural gas exploration, development and production company. In 2001, Enron Corp. and certain of its subsidiaries (excluding JEDI) became debtors in Chapter 11 bankruptcy proceedings. Mariner Energy, Inc. was not one of the debtors in those proceedings. While the bankruptcy proceedings were ongoing, we continued to operate our business as an indirect subsidiary of JEDI. We remained an indirect subsidiary of JEDI until March of 2004 when our former indirect parent company, Mariner Energy LLC, merged with an affiliate of the private equity funds Carlyle/Riverstone Global Energy and Power Fund II, L.P. and ACON Investments LLC. In the merger, all the shares of common stock in Mariner Energy LLC were converted into the right to receive cash and certain other consideration. As a result, since March 2004, JEDI no longer owns any direct or indirect interest in Mariner, and we are no longer affiliated with JEDI or Enron Corp. Also in connection with the merger, warrants to purchase common stock of Mariner Energy LLC that were held by another Enron Corp. affiliate were exercised and the holders received their pro rata portion of the merger consideration, and a term loan owed by Mariner Energy LLC to the same Enron Corp. affiliate was repaid in full.

 

Prior to the merger, we filed two proofs of claim in the Enron Corp. bankruptcy proceedings. These claims, aggregating $10.7 million, were for unpaid amounts owed to us by Enron Corp. subsidiaries under the terms of various physical commodity contracts and hedging contracts entered into prior to the Enron Corp. bankruptcy filing. We assigned these claims to JEDI as part of the merger consideration payable to JEDI under the terms of the merger agreement. Thus, as of this date, we have no claims pending in the Enron Corp. bankruptcy proceedings.

As part of the merger consideration payable to JEDI, we also issued a term promissory note to JEDI in the amount of $10 million. The note bore interest, paid in kind, at a rate of 10% per annum until March 2, 2005, and 12% per annum thereafter unless paid in cash in which event the rate remained at 10% per annum. The JEDI promissory note was secured by a lien on three of our properties located in the Outer Continental Shelf of the Gulf of Mexico. We used a portion of proceeds from the common stock we sold in our March 2005 private equity placement to repay $6 million of the JEDI Note. The note matured on March 2, 2006 and was repaid in full.

 

Under the merger agreement, JEDI and the other former stockholders of our parent company were entitled to receive on or before February 28, 2005, additional contingent merger consideration based upon the results of a five-well drilling program. In September 2004, we prepaid, with a 10% prepayment discount, approximately $161,000 as the additional contingent merger consideration due with respect to the program.

 

Glossary of Oil and Natural Gas Terms

 

The following is a description of the meanings of some of the oil and gas industry terms used in this Annual Report. The definitions of proved developed reserves, proved reserves and proved undeveloped reserves have been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definitions of those terms can be viewed on the website at http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.

 

3-D seismic.  (Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two dimensional seismic data.

 

Appraisal well.  A well drilled several spacing locations away from a producing well to determine the boundaries or extent of a productive formation and to establish the existence of additional reserves.

 

bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

 

Bcf.  Billion cubic feet of natural gas.

 

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

 

Block.  A block depicted on the Outer Continental Shelf Leasing and Official Protraction Diagrams issued by the U.S. Minerals Management Service or a similar depiction on official protraction or similar diagrams issued by a state bordering on the Gulf of Mexico.

 

Btu or British Thermal Unit.  The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

 

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

 

Condensate.  Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

 

Deep shelf well.  A well drilled on the outer continental shelf to subsurface depths greater than 15,000 feet.

 

Deepwater.  Depths greater than 1,300 feet (the approximate depth of deepwater designation for royalty purposes by the U.S. Minerals Management Service).

 

Developed acreage.  The number of acres that are allocated or assignable to productive wells or wells capable of production.

 

Development well.  A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

 

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

Dry hole costs.  Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.

 

Exploitation.  Ordinarily considered to be a form of development within a known reservoir.

 

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

 

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

 

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

 

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

 

Lease operating expenses.  The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and other expenses incidental to production, but not including lease acquisition or drilling or completion expenses.

 

Mbbls.  Thousand barrels of crude oil or other liquid hydrocarbons.

 

Mcf.  Thousand cubic feet of natural gas.

 

Mcfe.  Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

 

MMBls.  Million barrels of crude oil or other liquid hydrocarbons.

 

MMBtu.  Million British Thermal Units.

 

MMcf.  Million cubic feet of natural gas.

 

MMcfe.  Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

 

Net acres or net wells.  The sum of the fractional working interests owned in gross acres or wells, as the case may be.

 

Net revenue interest.  An interest in all oil and natural gas produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person’s interest is subject.

 

Payout.  Generally refers to the recovery by the incurring party to an agreement of its costs of drilling, completing, equipping and operating a well before another party’s participation in the benefits of the well commences or is increased to a new level.

 

PV10 or present value of estimated future net revenues.  An estimate of the present value of the estimated future net revenues from proved oil and gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10%, in accordance with the Securities and Exchange Commission’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be

construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.

 

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

 

Prospect.  A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

 

Proved developed non-producing reserves.  Proved developed reserves expected to be recovered from zones behind casing in existing wells.

 

Proved developed producing reserves.  Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.

 

Proved developed reserves.  Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. This definition of proved developed reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.

 

Proved reserves.  The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.

 

Proved undeveloped reserves.  Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X. The entire definition of this term can be viewed on the website at http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.

 

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

 

Shelf.  Areas in the Gulf of Mexico with depths less than 1,300 feet. Our shelf area and operations also includes a small amount of properties and operations in the onshore and bay areas of the Gulf Coast.

 

Subsea tieback.  A method of completing a productive well by connecting its wellhead equipment located on the sea floor by means of control umbilical and flow lines to an existing production platform located in the vicinity.

 

Subsea trees.  Wellhead equipment installed on the ocean floor.

 

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

 

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

 

Risks Relating to the Oil and Natural Gas Industry and Our Business

 

Oil and natural gas prices are volatile, and a decline in oil and natural gas prices would reduce our revenues, profitability and cash flow and impede our growth.

 

Our revenues, profitability and cash flow depend substantially upon the prices and demand for oil and natural gas. The markets for these commodities are volatile and even relatively modest drops in prices can affect significantly our financial results and impede our growth. Oil and natural gas prices are currently at or near historical highs and may fluctuate and decline significantly in the near future. Prices for oil and natural gas fluctuate in response to relatively minor changes in the supply and demand for oil and natural gas, market uncertainty and a variety of additional factors beyond our control, such as:

 

 

Further, oil prices and natural gas prices do not necessarily fluctuate in direct relationship to each other. Because approximately 62% of our estimated proved reserves (68% on a pro forma basis) as of December 31, 2005 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Lower oil and natural gas prices may not only decrease our revenues on a per unit basis but also may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition and results of operations.

 

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will affect materially the quantities and present value of our reserves, which may lower our bank borrowing base and reduce our access to capital.

 

Estimating oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of the available technical data and making many assumptions about future conditions, including price and other economic conditions. In preparing estimates we project production rates and timing of development expenditures. We also analyze the available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. This process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates, perhaps significantly. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of

which are beyond our control. At December 31, 2005, 50% of our estimated proved reserves were proved undeveloped (44% on a pro forma basis).

 

If the interpretations or assumptions we use in arriving at our estimates prove to be inaccurate, the amount of oil and natural gas that we ultimately recover may differ materially from the estimated quantities and net present value of reserves shown in this Annual Report. See “— Estimated Proved Reserves” under Items 1 and 2 for information about our oil and gas reserves.

 

In estimating future net revenues from proved reserves, we assume that future prices and costs are fixed and apply a fixed discount factor. If these assumptions or discount factor are materially inaccurate, our revenues, profitability and cash flow could be materially less than our estimates.

 

The present value of future net revenues from our proved reserves referred to in this Annual Report is not necessarily the actual current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on fixed prices and costs as of the date of the estimate. Actual future prices and costs fluctuate over time and may differ materially from those used in the present value estimate. In addition, discounted future net cash flows are estimated assuming that royalties to the MMS with respect to our affected offshore Gulf of Mexico properties will be paid or suspended for the life of the properties based upon oil and natural gas prices as of the date of the estimate. See “— Royalty Relief” under Items 1 and 2, and “Legal Proceedings” under Item 3. Since actual future prices fluctuate over time, royalties may be required to be paid for various portions of the life of the properties and suspended for other portions of the life of the properties.

 

The timing of both the production and expenses from the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor that we use to calculate the net present value of future net cash flows for reporting purposes in accordance with the SEC’s rules may not necessarily be the most appropriate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor in arriving at an accurate net present value of future net cash flows.

 

If oil and natural gas prices decrease, we may be required to write-down the carrying value and/or the estimates of total reserves of our oil and natural gas properties.

 

Accounting rules applicable to us require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings. We may incur non-cash charges in the future, which could have a material adverse effect on our results of operations in the period taken. We may also reduce our estimates of the reserves that may be economically recovered, which could have the effect of reducing the value of our reserves.

 

We need to replace our reserves at a faster rate than companies whose reserves have longer production periods. Our failure to replace our reserves would result in decreasing reserves and production over time.

 

Unless we conduct successful exploration and development activities or acquire properties containing proven reserves, our proved reserves will decline as reserves are depleted. Producing oil and natural gas reserves are generally characterized by declining production rates that vary depending on reservoir characteristics and other factors. High production rates generally result in recovery of a relatively higher percentage of reserves from properties during the initial few years of production. A significant portion of our current operations are conducted in the Gulf of Mexico, especially since our merger with Forest Energy Resources. Production from reserves in the Gulf of Mexico generally declines more rapidly than reserves from reservoirs in other producing regions. As a result, our need to replace reserves from new investments is relatively greater than those of producers who produce lower percentages of their reserves over a similar time period, such as

those producers who have a portion of their reserves outside of the Gulf of Mexico in areas where the rate of reserve production is lower. If we are not able to find, develop or acquire additional reserves to replace our current and future production, our production rates will decline even if we drill the undeveloped locations that were included in our proved reserves. Our future oil and natural gas reserves and production, and therefore our cash flow and income, are dependent on our success in economically finding or acquiring new reserves and efficiently developing our existing reserves.

 

Approximately 65% of our total estimated proved reserves are developed non-producing or undeveloped (71% on a pro forma basis), and those reserves may not ultimately be produced or developed.

 

As of December 31, 2005, approximately 15% of our total estimated proved reserves were developed non-producing (27% on a pro forma basis) and approximately 50% were undeveloped (44% on a pro forma basis). These reserves may not ultimately be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be ultimately produced at the time periods we have planned, at the costs we have budgeted, or at all. As a result, we may not find commercially viable quantities of oil and natural gas, which in turn may have a material adverse effect on our results of operations.

 

Any production problems related to our Gulf of Mexico properties could reduce our revenue, profitability and cash flow materially.

 

A substantial portion of our exploration and production activities is located in the Gulf of Mexico. This concentration of activity makes us more vulnerable than some other industry participants to the risks associated with the Gulf of Mexico, including delays and increased costs relating to adverse weather conditions such as hurricanes, which are common in the Gulf of Mexico during certain times of the year, drilling rig and other oilfield services and compliance with environmental and other laws and regulations.

 

Our exploration and development activities may not be commercially successful.

 

Exploration activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

 

 

If any of these factors were to occur with respect to a particular project, we could lose all or a part of our investment in the project, or we could fail to realize the expected benefits from the project, either of which could materially and adversely affect our revenues and profitability.

 

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

 

Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of

which are often uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. 3-D seismic data does not enable an interpreter to conclusively determine whether hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies require greater predrilling expenditures than traditional drilling strategies. Because of these factors, we could incur losses as a result of exploratory drilling expenditures. Poor results from exploration activities could have a material adverse effect on our future cash flows, ability to replace reserves and results of operations.

 

Oil and gas drilling and production involve many business and operating risks, any one of which could reduce our levels of production, cause substantial losses or prevent us from realizing profits.

 

Our business is subject to all of the operating risks associated with drilling for and producing oil and natural gas, including:

 

 

If any of these events occurs, 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, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of our operations and repairs to resume operations.

 

Our offshore operations involve special risks that could increase our cost of operations and adversely affect our ability to produce oil and gas.

 

Offshore operations are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties. For more information on the impact of recent hurricanes on our operations, see “ — Recent Developments” under Item 7.

 

Exploration for oil or natural gas in the deepwater of the Gulf of Mexico generally involves greater operational and financial risks than exploration on the shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. Our deepwater wells use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in significant cost overruns. Furthermore, the deepwater operations generally lack the physical and oilfield service infrastructure present in the shallow waters of the Gulf of Mexico. As a result, a significant amount of time may elapse between a deepwater discovery and our marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with

these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the deepwater may never be produced economically.

 

Our hedging transactions may not protect us adequately from fluctuations in oil and natural gas prices and may limit future potential gains from increases in commodity prices or result in losses.

 

We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. These financial arrangements typically take the form of price swap contracts and costless collars. Hedging arrangements expose us to the risk of financial loss in some circumstances, including situations when the other party to the hedging contract defaults on its contract or production is less than expected. During periods of high commodity prices, hedging arrangements may limit significantly the extent to which we can realize financial gains from such higher prices. For example, in calendar year 2005, our hedging arrangements reduced the benefit we received from increases in the prices for oil and natural gas by approximately $49 million. Although we currently maintain an active hedging program, we may choose not to engage in hedging transactions in the future. As a result, we may be affected adversely during periods of declining oil and natural gas prices.

 

We will require additional capital to fund our future activities. If we fail to obtain additional capital, we may not be able to implement fully our business plan, which could lead to a decline in reserves.

 

We depend on our ability to obtain financing beyond our cash flow from operations. Historically, we have financed our business plan and operations primarily with internally generated cash flow, bank borrowings, proceeds from the sale of oil and natural gas properties, exploration arrangements with other parties, the issuance of debt securities, privately raised equity and, prior to the bankruptcy of Enron Corp. (our indirect parent company until March 2, 2004), borrowings from Enron affiliates. In the future, we will require substantial capital to fund our business plan and operations. We expect to be required to meet our needs from our excess cash flow, debt financings and additional equity offerings (subject to certain federal tax limitations during the two-year period following the spin-off). Sufficient capital may not be available on acceptable terms or at all. If we cannot obtain additional capital resources, we may curtail our drilling, development and other activities or be forced to sell some of our assets on unfavorable terms.

 

The issuance of additional debt would require that a portion of our cash flow from operations be used for the payment of interest on our debt, thereby reducing our ability to use our cash flow to fund working capital, capital expenditures, acquisitions and general corporate requirements, which could place us at a competitive disadvantage relative to other competitors. Additionally, if revenues decrease as a result of lower oil or natural gas prices, operating difficulties or declines in reserves, our ability to obtain the capital necessary to undertake or complete future exploration and development programs and to pursue other opportunities may be limited, which could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could result in a decline in our oil and natural gas reserves.

 

Properties we acquire (including the Forest Gulf of Mexico properties) may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities.

 

Properties we acquire, including the Forest Gulf of Mexico properties, may not produce as expected, may be in an unexpected condition and may subject us to increased costs and liabilities, including environmental liabilities. The reviews we conduct of acquired properties prior to acquisition are not capable of identifying all potential adverse conditions. Generally, it is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties or properties with known adverse conditions and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems or permit a buyer to become sufficiently familiar with the properties to assess fully their condition, any deficiencies, and development potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken.

Market conditions or transportation impediments may hinder our access to oil and natural gas markets or delay our production.

 

Market conditions, the unavailability of satisfactory oil and natural gas transportation or the remote location of our drilling operations may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines or trucking and terminal facilities. In deepwater operations, the availability of a ready market depends on the proximity of and our ability to tie into existing production platforms owned or operated by others and the ability to negotiate commercially satisfactory arrangements with the owners or operators. We may be required to shut in wells or delay initial production for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. When that occurs, we are unable to realize revenue from those wells until the production can be tied to a gathering system. This can result in considerable delays from the initial discovery of a reservoir to the actual production of the oil and natural gas and realization of revenues.

 

The unavailability or high cost of drilling rigs, equipment, supplies or personnel could affect adversely our ability to execute on a timely basis our exploration and development plans within budget, which could have a material adverse effect on our financial condition and results of operations.

 

Shortages in availability or the high cost of drilling rigs, equipment, supplies or personnel could delay or affect adversely our exploration and development operations, which could have a material adverse effect on our financial condition and results of operations. An increase in drilling activity in the U.S. or the Gulf of Mexico could increase the cost and decrease the availability of necessary drilling rigs, equipment, supplies and personnel.

 

Competition in the oil and natural gas industry is intense, and many of our competitors have resources that are greater than ours giving them an advantage in evaluating and obtaining properties and prospects.

 

We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel. Many of our competitors are major and large independent oil and natural gas companies, and possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

 

Financial difficulties encountered by our farm-out partners or third-party operators could adversely affect our ability to timely complete the exploration and development of certain prospects.

 

From time to time, we enter into farm-out agreements to fund a portion of the exploration and development costs of our prospects. Moreover, other companies operate some of the other properties in which we have an ownership interest. Liquidity and cash flow problems encountered by our partners and co-owners of our properties may lead to a delay in the pace of drilling or project development that may be detrimental to a project. In addition, our farm-out partners and working interest owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farm-out partner, we may have to obtain alternative funding in order to complete the exploration and development of the prospects subject to the farm-out agreement. In the case of a working interest owner, we may be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary in order to fund either of these contingencies.

We cannot control the timing or scope of drilling and development activities on properties we do not operate, and therefore we may not be in a position to control the associated costs or the rate of production of the reserves.