UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

Form 10-K

 

 

Commission file number 1-11516

 

REMINGTON OIL AND GAS CORPORATION

(Exact name of registrant as specified in its charter)

 

 

Registrant’s telephone number, including area code:

(214) 210-2650

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

 

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

Common Stock, $0.01 Par Value

(Title of Class)

 

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

 

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

 

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

 

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

 

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

 

The aggregate market value of common stock held by non-affiliates of the registrant as of June 30, 2005 was $834,848,249. On March 10, 2006, the number of outstanding shares of common stock, $0.01 par value, was 28,842,084.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

 

FORM 10-K

 

REMINGTON OIL AND GAS CORPORATION

 

TABLE OF CONTENTS

 

 

General

 

Remington Oil and Gas Corporation

 

 

Our primary business operation is exploration, development, and production of oil and gas reserves in the offshore Gulf of Mexico and onshore Gulf Coast areas. All of our assets are located in these areas and all of our revenues and expenses are generated in these same regions of the United States.

 

Proposed Merger with Helix Energy Solutions Group, Inc.

 

On January 22, 2006, we entered into a merger agreement with Helix Energy Solutions Group, Inc. under which Helix will acquire us. Upon the consummation of the merger, our shareholders will receive $27.00 in cash and 0.436 of a share of Helix common stock for each share of our stock held. The merger is subject to the approval of our stockholders and clearance by certain governmental authorities. We and Helix will file a proxy statement/prospectus and other relevant documents concerning the proposed merger and the special meeting of our stockholders which will be called seeking approval of the transaction.

 

Long-Term Strategy

 

Our long-term strategy is to increase our oil and gas reserves and production while keeping our finding and development costs and operating costs competitive with our industry peers. We implement this strategy through drilling exploratory and development wells from an inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve potential. Our drilling program will contain some high risk/high reserve potential opportunities as well as some lower risk/lower reserve potential opportunities, in order to attempt to deliver a balanced program of reserve and production growth. Success of this strategy is contingent on various risk factors as discussed in our filings with the SEC.

 

Activities and Operations

 

We identify prospective oil and gas properties primarily by using 3-D seismic technology. After acquiring an interest in a prospective property, we drill one or more exploratory wells. If the exploratory wells find commercial oil and/or gas, we complete the wells and begin producing the oil or gas. Because most of our operations are located in the offshore Gulf of Mexico, we must install facilities such as offshore platforms and gathering pipelines in order to produce the oil and gas and deliver it to the marketplace. Certain properties require additional drilling to fully develop the oil and gas reserves and maximize the production from a particular discovery. In order to increase our

oil and gas reserves and production, we continually reinvest our net operating cash flow into new or existing exploration, development, and acquisition activities.

 

We share ownership in our oil and gas properties with various industry participants. We currently operate the majority of our offshore properties. An operator is generally able to maintain a greater degree of control over the timing and amount of capital expenditures than can a non-operating interest owner.

 

Competition in the Oil and Gas Industry

 

We compete with:

 

We compete for:

 

 

Many of our competitors may have significantly more financial, personnel, technological, and other resources available. In addition, some of the larger integrated companies may be better able to respond to industry changes including price fluctuations, oil and gas demands, and governmental regulations.

 

Markets for Oil and Gas Production

 

Oil and gas are generally homogenous commodities, and the market prices for these commodities fluctuate significantly. Purchasers adjust prices for quality, refined product yield, geographic proximity to refineries or major market centers, and the availability of transportation pipelines or facilities. Outside factors beyond our control combine to influence the market prices. Some of the more critical factors that affect oil and gas commodity prices include the following:

 

 

We have no real ability to influence or predict the market prices. Therefore, we normally sell our oil and gas production based on posted market prices, spot market indices, or prices derived from the posted price or index. At times we will lock in a fixed price for a portion of our future production to be delivered as it is produced. We use an independent company to market almost all of our offshore gas production and a portion of our offshore oil production. Because oil and gas are homogenous commodities and other customers and marketers are readily available, we believe that the loss of any of our current customers or our independent marketing company would not be detrimental to our operations nor have a material effect on our revenues.

 

Securities Regulation and Corporate Governance

 

We are a publicly traded company with our common stock listed for trading on The New York Stock Exchange. Because our securities are traded in the public markets, we are subject to regulation by governmental and private organizations such as the SEC and The New York Stock Exchange. This regulatory oversight imposes on us the responsibility for establishing and maintaining disclosure controls and procedures. The objective of those controls and procedures is to ensure that material information relating to us is made known to our management and that the financial statements and other information included in this Form 10-K and other reports and documents filed with the SEC do not contain any untrue statement of material fact, or omit to state a material fact, necessary to make the statements made in this Form 10-K and those other reports and documents not misleading. Our compliance with the increasing scope of regulation has significantly increased our audit and internal control costs.

 

Seven members serve on our Board of Directors. Five of these members are independent outside directors while the other two are our Chairman and Chief Executive Officer, and our President and Chief Operating Officer. We have a lead independent director whose responsibilities are set forth in our corporate governance documents.

The Board has established four standing committees: Audit, Compensation, Nominating and Corporate Governance, and Executive. The members of the Audit, Compensation, and Nominating and Corporate Governance Committees are all independent directors. Two of the three members of the Executive Committee are independent directors. Each standing committee is governed by its own charter.

 

Upon consummation of the proposed merger, our stock will cease to be traded. Shares of Helix common stock are traded on the Nasdaq National Market System.

 

Governmental Regulation, Including Environmental Regulation of Oil and Gas Operations

 

Numerous federal and state regulations affect our oil and gas operations. Current regulations are constantly reviewed by the various agencies at the same time that new regulations are being considered and implemented. In addition, because we hold federal leases, the federal government requires us to comply with numerous regulations that focus on government contractors. The regulatory burden upon the oil and gas industry increases the cost of doing business and consequently affects our profitability.

 

State regulations relate to virtually all aspects of the oil and gas business including drilling permits, bonds, and operation reports. In addition, many states have regulations relating to pooling of oil and gas properties, maximum rates of production, and spacing and plugging and abandonment of wells.

 

Our oil and gas operations are subject to stringent federal, state, and local environmental laws and regulations. Environmental laws and regulations are complex, change frequently, and have tended to become more restrictive over time. Many environmental laws require permits from governmental authorities before construction on a project may be commenced or before wastes or other materials may be discharged into the environment. The process for obtaining necessary permits can be lengthy and complex, and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought either unprofitable or otherwise unattractive. Even where permits are not required, compliance with environmental laws and regulations can require significant capital and operating expenditures, and we may be required to incur costs to remediate contamination from past releases of wastes into the environment. Failure to comply with these statutes, rules and regulations may result in the assessment of administrative, civil and even criminal penalties. The most significant environmental obligations applicable to our operations relate to compliance with the federal Oil Pollution Act and the Clean Water Act. The Oil Pollution Act and its implementing regulations (“OPA”) establish requirements for the prevention of oil spills and impose liability for damages resulting from spills into waters of the United States. The OPA also requires that operators of offshore oil production facilities, such as our facilities in the Gulf of Mexico, demonstrate to the U.S. Minerals Management Service that they possess at least $35.0 million in financial resources available to pay for costs that may be incurred in responding to an oil spill. The Clean Water Act and its implementing regulations impose restrictions and strict controls on the discharge of wastes into the waters of the United States, including discharges of oil, produced water and sand, drilling fluids, drill cuttings, and other wastes typically generated by the oil and gas industry. Although we believe that we are in compliance with the requirements of the OPA and Clean Water Act, as well as the other statutes and associated regulations governing the discharge of materials into the environment, the cost of compliance with this federal and state legislation could have a significant impact on our financial ability to carry out our oil and gas operations.

 

Our operations are also subject to environmental laws and regulations that impose requirements for remediation of soil and groundwater contamination. In many cases, these laws apply retroactively to previous waste disposal practices regardless of fault, legality of the original activities, or ownership or control of sites. A company could be subject to severe fines and cleanup costs if found liable under these laws. We have never been a liable party under these laws nor have we been named a potentially responsible party for waste disposal at any site. However, we do own and operate onshore properties that were previously owned and operated by companies whose waste disposal practices, while legal and standard within the industry at the time they occurred, may have resulted in on-site contamination that may require remedial action under current standards. There can be no assurance that we will not be required to undertake remedial actions for such instances of contamination in connection with our ownership and operation of these properties, or that the costs associated with such remedial actions will be fully covered by insurance.

Other Business Information

 

Except for our oil and gas leases with third parties and licenses to acquire or use seismic data, we have no material patents, licenses, franchises, or concessions that we consider significant to our oil and gas operations. We do not have any “backlog” of products, customer orders, or inventory. We have not been a party to any bankruptcy, reorganization, adjustment or similar proceeding except in the capacity as a creditor.

 

Not completing the merger could negatively impact our stock price and future results

 

Although our board of directors will, subject to fiduciary exceptions, recommend that our stockholders approve and adopt the merger agreement, there is no assurance that the merger agreement and the merger will be approved, and there is no assurance that the other conditions to the completion of the merger will be satisfied. If the merger is not completed, we will be subject to several risks, including the following:

 

 

In addition, we would not realize any of the expected benefits of having completed the merger. If the merger is not completed, these risks may materialize and materially adversely affect our business, financial results, financial condition and stock price.

 

Natural gas and oil prices are volatile, which makes future revenue uncertain.

 

Our financial condition and results of operations depend on the prices we receive for the oil and gas we produce. The market prices for oil and gas are subject to fluctuation in response to events beyond our control, such as:

 

 

Oil and gas prices have historically been volatile, and such volatility is likely to continue. Our ability to estimate the value of producing properties for acquisition and to budget and project the financial return of exploration and development projects is made more difficult by this volatility. A dramatic decline in such prices could have a substantial and material effect on:

 

 

 

A resulting significant decline in our cash flows from operations could cause us to fail to meet our operational obligations, thus requiring us to modify our capital expenditure program which could then affect our ability to find and develop reserves and our level of production. Moreover, such a decline could affect the measure of the discounted future net cash flow of reserves, which could then affect our borrowing base and may increase the likelihood that we will incur impairment charges on our oil and gas properties for financial accounting purposes.

 

Our future success depends on our ability to economically increase our reserves and production, which historically have had relatively short production lives.

 

Our future success will depend on our ability to find, develop or acquire additional economically recoverable oil and gas reserves and convert these reserves to production. Because our proved reserves will normally decline as they are produced, we must maintain successful exploration and development activities in order to replace reserves depleted through production. We may not be able to replace our reserves in an economically viable manner.

 

Our forward sales decisions regarding some of our production may reduce our potential gains from increases in oil and gas prices.

 

Oil and gas prices can fluctuate significantly and have a direct impact on our reserves. To manage our exposure to the risks inherent in such a volatile market, from time to time, we have forward sold for future physical delivery an amount, not more than half, of our future production. This means that a portion of our production is sold at a fixed price as a shield against dramatic price declines that could occur in the market. We may from time to time engage in other hedging activities that limit our upside potential from price increases. These sales activities may limit our benefit from dramatic price increase. The merger agreement requires that prior to the consummation of the merger and upon request from Helix that we enter into limited forward sales of our production in instances when both we and Helix believe that such sales are reasonably prudent to Helix’s acquisition economics and our expected economics.

 

Our actual drilling results may differ from our estimates of proved reserves.

 

Our estimates of the quantities of proved reserves and our projections of both future production rates and the timing of development expenditures are uncertain. Any downward revisions of these estimates could adversely affect our financial condition and could reduce our borrowing base under our credit facility.

 

Netherland, Sewell & Associates, Inc., our independent reservoir engineers, audit our estimate of our reserves. The accuracy of these reserve estimates depends in large part on the quality of available data and on the engineering and geological interpretation of reservoir engineers. Because they are estimates, they are subject to revision based on the results of actual drilling, testing, and production and will often differ from the quantities of oil and gas we ultimately recover.

 

Further, the estimate of our future net cash flows contained in our reserve report depends upon numerous assumptions including the amount of the reserves actually produced, the cost and timing of producing those reserves, and the price received for the production. To the extent these assumptions prove inaccurate, material changes to our estimates of our future net cash flows and our reserves could results.

 

We are dependent on other operators who influence our productivity.

 

We have limited influence over operations, including limited control over the maintenance of both safety and environmental standards, on properties we do not operate. The operators of those properties may, depending on the terms of the applicable joint operating agreement:

 

 

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

 

Adverse changes in the financial condition of our joint interest partners due to price declines, industry conditions, or events specific to a partner may affect our ability to carry out our program.

 

Some of our working interest owners may experience liquidity and cash flow problems caused by, among other things, a decline in oil and gas prices. These problems may lead to their attempting to delay the pace of drilling or development in order to conserve cash. Any such delay may be detrimental to our projects and the planned timing thereof.

 

The oil and gas industry is highly competitive.

 

Our quest to discover additional oil and gas reserves and acquire additional properties occurs in competition with some of the largest oil and gas companies in the world. These companies may be able to devote significantly greater financial resources to exploration and production projects and federal lease sales than we can. Moreover, if these companies operate projects in which we are joint interest owners, they may propose exploration and development programs in which we may not be able to participate due to financial constraints. This could cause us to lose our interest, at least for a time, in a particular lease or project. In addition, we compete with these companies in the hiring and retention of talented technical employees.

 

Government regulation may affect our ability to conduct operations, and the nature of our business exposes us to environmental liability.

 

Numerous federal and state regulations affect our oil and gas operations. Current regulations are constantly reviewed by the various agencies at the same time that new regulations are being considered and implemented. In addition, because we hold federal leases, the federal government requires us to comply with numerous additional regulations that focus on government contractors. The regulatory burden upon the oil and gas industry increases the cost of doing business and consequently affects our profitability.

 

Our oil and gas operations are subject to stringent federal, state, and local environmental laws and regulations. Environmental laws and regulations are complex, change frequently, and have tended to become more stringent over time. Many environmental laws require permits from governmental authorities before construction on a project may commence or before wastes or other materials may be discharged into the environment. The process for obtaining necessary permits can be lengthy and complex, and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought either unprofitable or otherwise unattractive. Even where permits are not required, compliance with environmental laws and regulations can require significant capital and operating expenditures, and we may be required to incur costs to remediate contamination from past releases of wastes into the environment. Failure to comply with these statues, rules and regulations may result in the assessment of administrative, civil and even criminal penalties. The most significant environmental obligations applicable to our operations relate to compliance with the federal Oil Pollution Act and the Clean Water Act. The Oil Pollution Act and its implementing regulations (“OPA”) establish requirements for the prevention of oil spills and impose liability for damages resulting from spills into waters of the United States. OPA also requires operators of offshore oil production facilities, such as our facilities in the Gulf of Mexico, to demonstrate to the U.S. Minerals Management Service that they possess at least $35.0 million in financial resources that are available to pay for costs that may be incurred in responding to an oil spill. The Clean Water Act and its implementing regulations impose restrictions and strict controls on the discharge of wastes typically generated by the oil and gas industry. The cost of compliance with this federal and state legislation could have a significant impact on our financial ability to carry out our oil and gas operations.

 

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

 

 

 

Environmental discharges may move through the soil to water supplies or to adjoining properties, giving rise to additional liabilities. Some laws and regulations could result in liability for failure to obtain the proper permits for, to control the use of, or to notify the proper authorities of a hazardous discharge. Such liability could substantially reduce our net income and could cause us to suspend operations.

 

Our operations are also subject to environmental laws and regulations that impose requirements for remediation of soil and groundwater contamination. In many cases, these laws apply retroactively to previous waste disposal practices regardless of fault, legality of the original activities, or ownership or control of sites. A company could be subject to severe fines and cleanup costs of found liable under these laws. We own and operate properties previously owned and operated by companies whose waste disposal practices may have resulted in on-site contamination that may require remedial action under current standards. We may be required to undertake remedial actions for contamination in those properties.

 

 

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

 

Our drilling operations involve risks from high pressures in the wells and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. Our offshore properties involve higher exploration and drilling risks that include the cost of constructing platforms and pipeline interconnections as well as weather delays and other risks.

 

Our insurance may not cover the full extent of all losses. This insurance coverage includes, among other things, comprehensive general liability, business interruption and limited coverage for sudden environmental damage. We do not believe that insurance that fully covers all environmental damage that occurs over time or all sudden environmental damage is available at a reasonable cost. The occurrence of an event that is not fully covered by insurance could materially increase our operating expenses and decrease our net income.

 

We undertake significant operational risks connected with our business.

 

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

 

Another risk of our operations is the difficulty in marketing our oil and gas production. The proximity of our reserves to pipelines and the available capacity of pipelines and other transportation, processing and refining facilities also affect the marketing efforts. Even if we discover hydrocarbons in commercial quantities, a substantial period of time may elapse before we begin commercial production. If pipeline facilities in an area are insufficient, we may have to arrange for, and possibly bear the cost of, the construction or expansion of pipeline capacity before our production from that area can be marketed. Furthermore, if any of the major facilities into which we deliver our product become non-operational for any reason, our revenues will decline.

 

None.

 

We concentrate our principal operations in the federal waters of the Gulf of Mexico and its coastal regions. In addition to the information below, we encourage you to read the discussion in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the notes to our consolidated financial statements in Item 8, “Financial Statements and Supplementary Data,” below. Note 2 — Oil and Gas Properties and Note 11 — Oil and Gas Reserves and Present Value Disclosures in our Notes to Consolidated Financial Statements provide detailed information concerning costs incurred, proved oil and gas reserves, and discounted future net revenue for proved reserves.

 

Leasehold Acreage

 

Our leasehold acreage of oil and gas property as of December 31, 2005, was as follows:

 

 

The current terms of leases on undeveloped acreage are scheduled to expire as shown in the table below. The term of a lease may be extended by drilling and production operations.

 

 

Proved Oil and Gas Reserves

 

Net proved oil and gas reserves at December 31, 2005, as audited by independent reserve engineers, Netherland, Sewell & Associates, Inc., are summarized below. The quantities of proved oil and gas reserves discussed in this section include only the amounts which we reasonably expect to recover in the future from known oil and gas reservoirs under the current economic and operating conditions. Proved reserves include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices, and technology. Therefore, any changes in future prices, costs, regulations, technology or other unforeseen factors could materially increase or decrease the proved reserve estimates.

 

 

In 2005, our standardized measure of discounted future net cash flows was $1.2 billion. We used the December 31, 2005, West Texas Intermediate posted price of $57.75 per barrel and Henry Hub spot market price of $10.08 per MMBtu, adjusted by property for energy content, quality, transportation fees, and regional price differentials. We estimated the costs based on the prior year costs incurred for individual properties or similar properties if a particular property did not produce during the prior year.

 

The present value of future net cash flows attributable to estimated net proved reserves, discounted at 10% per annum, (“PV10”) is a computation of the standardized measure of discounted future net cash flows on a pre-tax

basis. The table below provides a reconciliation of PV10 to the standardized measure of discounted future net cash flows. PV10 may be considered a non-GAAP financial measure as defined by the SEC’s Regulation G. We believe PV10 to be an important measure for evaluating the relative significance of our natural gas and oil operations. PV10 is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting income taxes. We further believe investors and creditors may utilize our PV10 as a basis for comparison of the relative size and value of our reserves to other companies. However, PV10 is not a substitute for the standardized measure. Our PV10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our natural gas and oil reserves.

 

 

Producing Properties

 

The table below summarizes our ownership in producing wells at the end of each of the last three years.

 

 

Our offshore Gulf of Mexico properties account for approximately 85% of our oil production and approximately 98% of our gas production. In addition, total revenues from offshore Gulf of Mexico oil and gas production during 2005 accounted for approximately 95% of our total oil and gas revenues. We owned varying working interests (5% to 100%) in 162 offshore Gulf of Mexico blocks at December 31, 2005, and currently produce from 54 of these blocks. Three additional blocks are currently under development. We operate a majority of these blocks.

 

In addition, through our entry into 3-D seismic licensing agreements with various vendors, we have access to 3-D seismic data covering approximately 3,600 blocks in the Gulf of Mexico. The duration and coverage of the three most significant agreements are as follows:

 

 

These agreements, combined with our computer technology, provide our technical team with immediate access to the seismic data covered by the agreements.

During 2005, we successfully drilled 13 out of 19 exploratory wells and 4 out of 5 development wells in the offshore Gulf of Mexico. In addition, we constructed and installed 3 production platforms, 1 subsea wellhead, and 4 associated pipelines.

 

Our onshore Gulf Coast area properties are principally located in the State of Mississippi and along the Texas Gulf Coast. In 2005, these properties accounted for approximately 15% of our oil production and approximately 2% of our gas production. Our working interests in these wells range from 15% to 100%.

 

Drilling Activities

 

The following is a summary of our exploration and development wells drilled for the past three years.

 

 

We had an interest in 2 wells (1.50 net) in progress at December 31, 2005, 1 well (0.75 net) in progress at December 31, 2004, and 3 wells (2.10 net) in progress at December 31, 2003.

 

Other Property and Office Lease

 

We own several non-contiguous tracts of land covering approximately 2,500 surface acres in southern Louisiana and southern Mississippi. We currently lease approximately 19,000 square feet of office space in Dallas, Texas and have commitments to lease an additional 6,000 square feet in the same building in 2006. The lease on our office space expires in March 2012.

 

We are not a party to any material legal proceedings at this time.

 

We did not submit any matters to a vote of securityholders during the fourth quarter of 2005.

 

Our common stock trades on the New York Stock Exchange under the symbol REM. The following table sets forth the high and low closing price per share for the periods indicated as reported in the NYSE composite transactions.

 

 

On March 10, 2006, the last reported sales price for our common stock was $41.41 per share. On that date, there were 443 stockholders of record.

 

No dividends have ever been paid on our common stock. Our credit facility agreement prohibits our paying dividends. The determination of future cash dividends, if any, will depend upon, among other things, our financial condition, cash flow from operating activities, the level of our capital and exploration expenditure needs, future business prospects, and renegotiation of our line of credit.

The following table presents information about our equity compensation plans at December 31, 2005.

 

 

The information above regarding equity compensation plans not approved by the stockholders includes contingent one-time stock grants made in 1999 to all employees and directors, which include the following significant attributes:

 

 

The selected consolidated financial data should be read in conjunction with our consolidated financial statements and notes to the consolidated financial statements. In addition, you should also read our “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 below.

 

 

 

 

The following discussion will assist you in understanding our financial position, liquidity, and results of operations. The information below should be read in conjunction with our consolidated financial statements, and the notes to our consolidated financial statements. Our discussion contains both historical and forward-looking information. We assess the risks and uncertainties about our business, long-term strategy, and financial condition before we make any forward-looking statements, but we cannot guarantee that our assessment is accurate or that our goals and projections can or will be met. Statements concerning results of future exploration, exploitation, development, and acquisition expenditures as well as expense and reserve levels are forward-looking statements. We make assumptions about commodity prices, drilling results, production costs, administrative expenses, and interest costs that we believe are reasonable based on currently available information.

 

Critical Estimates and Accounting Policies

 

We prepare our consolidated financial statements in this report using accounting principles that are generally accepted in the United States (“GAAP”). GAAP represents a comprehensive set of accounting and disclosure rules and requirements. We must make judgments, estimates, and in certain circumstances, choices between acceptable GAAP alternatives as we apply these rules and requirements. The most critical estimate we make is the engineering estimate of proved oil and gas reserves. This estimate affects the application of the successful-efforts method of accounting, the calculation of depreciation, depletion, and amortization of oil and gas properties, and the estimate of the impairment of our oil and gas properties. It also affects the estimated lives used to determine asset retirement obligations. In addition, the estimates of proved oil and gas reserves are the basis for the related standardized measure of discounted future net cash flows.

 

Estimated Proved Oil and Gas Reserves

 

The evaluation of our oil and gas reserves is critical to the management of our operations and ultimately our economic success. Decisions such as whether development of a property should proceed and what technical methods are available for development are based on an evaluation of reserves. These oil and gas reserve quantities are also used as the basis for calculating the unit-of-production rates for depreciation, depletion, and amortization, evaluating impairment and estimating the life of our producing oil and gas properties in our asset retirement obligations. Our proved reserves are classified as either proved developed or proved undeveloped. Proved developed reserves are those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves include reserves expected to be recovered from new wells from undrilled proven reservoirs or from existing wells where a significant major expenditure is required for completion and production. Since a significant amount of our drilling is ongoing exploration activity, our oil and gas reserve estimates in our year-end reports include significant proved undeveloped reserves because of new discoveries that are waiting for platform or pipeline facilities to be completed in order for production to commence. These proved undeveloped reserves are subject to higher uncertainty because the estimates for the reserves do not include any production history.

 

We prepare and independent reserve engineers audit the estimates of our oil and gas reserves presented in this report based on guidelines promulgated under GAAP and in accordance with the rules and regulations of the SEC. The audit of our reserves by the independent reserve engineers involves their rigorous examination of our technical evaluation and extrapolations of well information such as flow rates and reservoir pressure declines as well as other technical information and measurements. Our internal reservoir engineers interpret these data to determine the nature of the reservoir and ultimately the quantity of proved oil and gas reserves attributable to a specific property. Our proved reserves in this report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes of proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir, or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices, or production equipment/facility capacity.

Standardized Measure of Discounted Future Net Cash Flows

 

The standardized measure of discounted future net cash flows relies on these estimates of oil and gas reserves using commodity prices and costs at year-end. In our 2005 year-end reserve report we used the December 31, 2005, West Texas Intermediate posted price of $57.75 per barrel and Henry Hub spot market price of $10.08 per MMBtu adjusted by property for energy content, quality, transportation fees, and regional price differentials. We estimated the costs based on the prior year costs incurred for individual properties or similar properties if a particular property did not have production during the prior year. Future global economic and political events will most likely result in significant fluctuations in future oil prices.

 

Successful-Efforts Method of Accounting

 

Oil and gas exploration and production companies choose one of two acceptable accounting methods, successful-efforts or full cost. The most significant difference between the two methods relates to the accounting treatment of drilling costs for unsuccessful exploration wells (“dry holes”) and exploration costs. Under the successful-efforts method, we recognize exploration costs and dry hole costs (the primary uncertainty affecting this method) as expenses when incurred and capitalize the costs of successful exploration wells as oil and gas properties. Entities that follow the full cost method capitalize all drilling and exploration costs including dry hole costs into one pool of total oil and gas property costs.

 

It is typical for companies that drill a significant number of exploration wells, as we do, to incur dry hole costs. During the last three years we have drilled 69 exploration wells, of which 22 were considered dry holes resulting in a 68% success ratio on exploratory wells. It is impossible to accurately predict specific dry holes; however, based on past experience, we estimate that between 25% and 35% of our exploration wells and associated exploration drilling costs, will be dry holes. Because we cannot predict the timing and the magnitude of dry holes, quarterly and annual net income can vary dramatically.

 

The calculation of depreciation, depletion and amortization of capitalized costs under the successful-efforts method of accounting differs from that calculation under the full cost method in that the successful-efforts method requires us to calculate depreciation, depletion and amortization expense on individual properties rather than on one pool of costs. In addition, under the successful-efforts method, we asses our oil and gas properties individually for impairment compared to the assessment of one pool of costs under the full cost method.

 

Depreciation, Depletion and Amortization of Oil and Gas Properties

 

The application of the unit-of-production method of depreciation, depletion and amortization of oil and gas properties under the successful-efforts method of accounting is applied pursuant to the simple multiplication of units produced by the costs per unit associated with a property. The cost per unit is calculated by dividing the total costs associated with a property by the estimated proved oil and gas reserves on that property. The volumes or units produced and asset costs are known, and while the proved reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. The factors which create this variability are included in the discussion of estimated proved oil and gas reserves above.

 

Impairment of Oil and Gas Properties

 

Like depreciation, depletion and amortization, we test for impairment of our oil and gas properties based on estimates of proved reserves. Proved oil and gas properties held and used by us are reviewed for impairment whenever events or circumstances indicate that the carrying amount may not be recoverable. We estimate the future undiscounted net cash flows of the affected properties to judge the recoverability of the carrying amounts. Initially this analysis is based on proved reserves. However, when we believe that a property contains oil and gas reserves that do not meet the defined parameters of proved reserves, an appropriately risk adjusted amount of these reserves may be included in the impairment evaluation. These reserves are subject to much greater risk of ultimate recovery. An asset would be impaired if the future undiscounted net cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.

Impairment analysis is performed on an ongoing basis. In addition to using estimates of oil and gas reserve volumes in conducting impairment analysis, it is also necessary to estimate future oil and gas prices. The impairment evaluation triggers include a significant long-term decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and current negative operating losses. Although we evaluate future oil and gas prices as part of the impairment analysis, we do not view short-term decreases in prices, even if significant, as impairment triggering events.

 

Exploratory Drilling Costs

 

The costs of drilling an exploratory well are capitalized as uncompleted wells pending the determination of whether the well has found proved reserves. If proved reserves are not found, these capitalized costs are charged to expense. On the other hand, the determination that proved reserves have been found results in the continued capitalization of the drilling costs of the well and its reclassification as a well containing proved reserves. At times, it may be determined that an exploratory well may have found hydrocarbons at the time drilling is completed, but it may not be possible to classify the reserves at that time. In this case, we may continue to capitalize the drilling costs as an uncompleted well beyond one year when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project, or the reserves are deemed to be proved. At that time the well is either reclassified as a proved well or is considered impaired and its costs, net of any salvage value, are charged to expense.

 

Occasionally, we may choose to salvage a portion of an unsuccessful exploratory well in order to continue exploratory drilling in an effort to reach the target geological structure/formation. In such cases, we charge only the unusable portion of the well bore to dry hole expense, and we continue to capitalize the costs associated with the salvageable portion of the well bore and add the costs to the new exploratory well. In certain situations, the well bore may be carried for more than one year beyond the date drilling in the original well bore was suspended. This may be due to the need to obtain, and/or analyze the availability of, equipment or crews or other activities necessary to pursue the targeted reserves or evaluate new or reprocessed seismic and geographic data. If, after we analyze the new information and conclude that we will not reuse the well bore or if the new exploratory well is determined to be unsuccessful after we complete drilling, we will charge the capitalized costs to dry hole expense.

 

Asset Retirement Obligations

 

We adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003. The statement requires that we estimate the fair value for our asset retirement obligations (dismantlement and abandonment of oil and gas wells and offshore platforms) in the periods the assets are first placed in service. We then adjust the current estimated obligation for estimated inflation and market risk contingencies to the projected settlement date of the liability. The result is then discounted to a present value from the projected settlement date to the date the asset was first placed in service. We record the present value of the asset retirement obligation as an additional property cost and as an asset retirement liability. We record a combination of the amortization of the additional property cost (using the unit-of-production method) and the accretion of the discounted liability as a component of our depreciation, depletion and amortization of oil and gas properties.

 

We base our initial liability on estimates of current costs to dismantle and abandon our existing platforms and wells on historical experience, industry practice, and external estimates of the cost to abandon similar platforms and wells subject to federal and state regulatory requirements. We increase the current liability estimate using a 3% annual inflation factor over the estimated productive life of the individual property and further increase the inflated liability by 5% for market cost risk. The liability is discounted using United States Treasury Securities with constant maturities that approximate the number of years of productive life for the property plus a 2.5% adjustment for credit risk. Revisions to the liability could occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding abandonment of wells.

 

Prior to our adoption of SFAS No. 143, we accrued an estimated dismantlement, restoration and abandonment liability using the unit-of-production method over the life of a property and included the accrued amount in

depreciation, depletion and amortization expense. The total accrued liability ($5.5 million at December 31, 2002) was reflected as additional accumulated depreciation, depletion and amortization of oil and gas properties on our balance sheet.

 

In conformity with SFAS 143 we recorded the cumulative effect of this accounting change as of January 1, 2003, as if we had used this method in the prior years. At January 1, 2003, we increased our oil and gas properties by $9.0 million, recorded $11.8 million as an Asset Retirement Obligation liability and reduced our accumulated depreciation by $2.8 million ($5.5 million accrued dismantlement in prior years less accumulated depreciation, depletion and amortization of $2.7 million on the increased property costs). The adoption of the new standard had no material effect on our net income. The following pro forma data summarize our net income and net income per share for the year ended December 31, 2003, as if we had adopted the provisions of SFAS 143 on January 1, 2001, including aggregate pro forma asset retirement obligations on that date:

 

 

3D Seismic Data License Agreements

 

The 3-D seismic agreements we have entered into allow us access to, but do not give us ownership of, 3-D seismic data. Prior to the 3-D seismic agreement we entered into in May of 2004, we had entered into two other significant 3-D seismic licensing agreements. The agreement entered into in 1998 covered approximately 1,100 blocks in the Gulf of Mexico and has a 99 year term while the agreement entered into in 2000 covers approximately 1,000 blocks in the Gulf of Mexico and is for an indefinite term.

 

Until the third quarter of 2003, our accounting policy was to capitalize a discounted total of the required payments under the agreements over an assumed useful life of four years using the straight line method. In the fourth quarter of 2003, we completed a review of our accounting policies in relation to the contracts and determined that as of the fourth quarter 2003, we would charge exploration expense as invoices are paid. This change did not have a material effect on our current or prior financial statements.

 

In May 2004, we entered into a 3-D seismic licensing agreement covering an additional approximately 1,200 blocks in deeper water trends in the Gulf of Mexico. The license has a term of 20 years with an option to renew for an additional 20 years. An initial payment followed by a series of quarterly invoices through July 2008 is provided for in the agreement. There are no contingent payments. The license agreement is an executory contract under which both parties have certain ongoing rights and obligations. If we wish to continue using the data, we are required to make the payments as invoiced and comply with certain confidentiality provisions. The vendor’s ongoing obligations include warranty and indemnity responsibilities as to intellectual property matters. We believe that the contract provides us with termination rights and therefore under our accounting policy, we recognize the liabilities as they become due and payable within the terms of the contract. In the event of an enforceable finding that we do not have a right of termination prior to the full contract price being due and payable, we would re-assess our accounting policy with respect to this agreement.

General and Administrative Expenses

 

Our general and administrative expenses are affected by the method in which we measure and record stock based compensation expense and, to a lesser extent, assumptions related to our defined benefit pension plans. We have included a further discussion of these critical estimates and accounting policies in the following sections of this item: Long-Term Strategy and Business Developments, Liquidity and Capital Resources and Results of Operations. Our Notes to Consolidated Financial Statements included in this report also have a more comprehensive discussion of our significant accounting policies.

 

New Accounting Pronouncements

 

In April 2005, the FASB issued Staff Position No. FAS 19-1, “Accounting for Suspended Well Costs,” (“FSP 19-1”). FSP 19-1 amends SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies,” (“SFAS 19”) to allow continued capitalization of exploratory well costs beyond one year from the completion of drilling under circumstances where the wells have found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP 19-1 also amends SFAS 19 to require enhanced disclosures of suspended exploratory well costs in the notes to the financial statements for annual and interim periods when there has been a significant change from the previous disclosure. The guidance in FSP 19-1 was effective for the first reporting period beginning after April 4, 2005. Accordingly, we adopted the new requirements and have included the required disclosures in footnote 1. The adoption of FSP 19-1 did not impact our financial position or results of operations.

 

In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), which is a revision of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). SFAS 123R supersedes Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) and amends Statement of Financial Accounting Standards No. 95, “Statement of Cash Flows”. Generally, the approach in SFAS 123R is similar to the approach described in SFAS 123. However, SFAS 123R will require all share-based payments to employees, including grants of employee stock options, to be recognized in our Consolidated Statements of Income based on their fair values. Pro forma disclosure is no longer an alternative. SFAS 123R must be adopted no later than January 1, 2006 and permits us to adopt its requirements using one of two methods:

 

A “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS 123R for all share-based payments granted after the effective date and based on the requirements of SFAS 123 for all awards granted to employees prior to the adoption date of SFAS 123R that remain unvested on the adoption date.

 

A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures.

 

We have elected to adopt the provisions of SFAS 123R on January 1, 2006, using the modified prospective method. As permitted by SFAS 123, we currently account for share-based payments to employees using the intrinsic value method prescribed by APB 25 and related interpretations. Therefore, we do not recognize compensation expenses associated with employee stock options. Currently, since all of our outstanding stock options have vested prior to the adoption of SFAS 123R, we will not recognize any expenses associated with these prior stock option grants. However, the adoption of SFAS 123R fair value method could have a significant impact on our future results of operations for future stock or stock option grants but no impact on our overall financial position. Had we adopted SFAS 123R in prior periods, the impact would have approximated the impact of SFAS 123 as described in the pro forma net income and income per share disclosures in Notes to Consolidated Financial Statements, Note 1 — Summary of Significant Accounting Policies — Stock Options. The adoption of SFAS 123R will have no effect on our outstanding stock grant awards.

SFAS 123R also requires the tax benefits of tax deductions in excess of recognized compensation expenses to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement may reduce our future cash provided by operating activities and increase future cash provided by financing activities, to the extent of associated tax benefits that may be realized in the future. While we cannot estimate what those amounts will be in the future (because they depend on, among other things, when employees exercise stock options), the amount of operating cash flows from such excess tax deductions was $5.4 million during the year ended December 31, 2005.

 

In March 2005, the FASB issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” The interpretation clarifies the requirement to record abandonment liabilities stemming from legal obligations when the retirement depends on a conditional future event. FIN No. 47 requires that the uncertainty about the timing or method of settlement of a conditional retirement obligation be factored into the measurement of the liability when sufficient information exists. We adopted FIN No. 47 as of December 31, 2005. There was no material impact on our results of operations, financial condition, or cash flows.

 

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statements No. 3” (“SFAS 154”). SFAS 154 requires retrospective application to prior period financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS 154 also requires that retrospective application of a change in accounting principle be limited to the direct effects of the change. Indirect effects of a change in accounting principle should be recognized in the period of the accounting change. SFAS 154 will become effective on January 1, 2006. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but we do not currently expect SFAS 154 to have a material impact on our results of operations, financial condition, or cash flows.

 

Long-Term Strategy and Business Developments

 

Our long-term strategy is to increase our oil and gas reserves and production while keeping our finding and development costs and operating costs (on a per Mcf equivalent (Mcfe) basis) competitive with our industry peers. We will implement this strategy through drilling exploratory and development wells from our inventory of available prospects that we have evaluated for geologic and mechanical risk and future reserve potential. Our drilling program will contain some high risk/high reserve potential opportunities as well as some lower risk/lower reserve potential opportunities, in order to attempt to achieve a balanced program of reserve and production growth. Success of this strategy is contingent on various risk factors, as discussed in our filings with the SEC. Over the last three years, we have invested $492.9 million in oil and gas properties and found 179.8 Bcfe of proved reserves. The following tables reflect our results during the last three years.

 

 

 

Operating costs on a Mcfe produced basis have increased over the past three years from $0.60 to $0.90 or approximately 50% (or 25% per annum). This is the result of rising material and labor costs experienced during a period of increasing activity in our sphere of operations.

 

 

The implementation of our long-term strategy requires that we continually incur significant capital expenditures in order to replace current production and find and develop new oil and gas reserves. In order to finance our capital and exploration program, we depend on cash flow from operations or bank debt and equity offerings as discussed below in Liquidity and Capital Resources.

 

Liquidity and Capital Resources

 

Cash flow provided by operations for the year ended December 31, 2005, decreased by $27.8 million, or 14.7%, compared to the prior year primarily due to increases in working capital accounts in addition to a 18.5% decrease in production offset partially by a $2.25/Mcfe, or 36.7% increase in oil and gas prices. The decrease in our production during 2005 compared to 2004 was primarily the direct result of Hurricanes Katrina and Rita which shut-in much of our production for the entire fourth quarter of 2005. We expect our cash flow provided by operations for 2006 to increase because of higher projected production from new properties, combined with oil and gas prices consistent with 2005, and steady operating, general and administrative, interest and financing costs per Mcfe.

 

Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control. Hurricanes in the Gulf of Mexico will shut down our production for the duration of the storm’s presence in the Gulf, and may damage our production facilities so that we cannot produce from a particular property for an extended amount of time. In addition, downstream activities on major pipelines in the Gulf of Mexico can also cause us to shut-in production for various lengths of time, as was exemplified by pipeline and other infrastructure disruptions caused by Hurricanes Katrina and Rita in 2005. Further, Hurricane Rita destroyed two third party drill rigs working under contract on two of our exploration wells. The loss of the two drill rigs caused us to push our drilling plans into the future at a slower pace. Due to the limited availability of drill rigs, the rate of finding and developing new oil and gas reserves in the Gulf of Mexico may be slower.

Our realized oil and gas prices vary significantly due to world political events, supply and demand of products, production storage levels, and weather patterns. We sell the vast majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility we sometimes lock in prices for some portion of our production (usually less than 33%) through the use of forward sale agreements. See additional discussion under Commodity Price Risk in Item 7A — Quantitative and Qualitative Disclosures about Market Risk.

 

Changes in our working capital accounts from 2004 to 2005 include an increase in our accounts receivable (a decrease in our cash flow provided by operations) due to increased balances due from our joint interest participants as a result of increased operating activities (drilling wells and facilities construction) at year end and from hurricane related insurance receivables and income tax receivables. In addition, accounts payable decreased by $15.3 million which decreased our cash flow from operations.

 

On January 22, 2006, we entered into a merger agreement with Helix Energy Solutions Group, Inc. (formerly Cal Dive International Inc.). Consideration for the offer from Helix will be $27.00 in cash and 0.436 shares of Helix stock for each of our shares. Completion of the merger is subject to customary conditions to closing, including without limitation, approval by our stockholders. Under the terms of the merger agreement, we may be required to pay Helix the sum of (i) Helix’s documented out of pocket fees and expenses incurred or paid by or on behalf of Helix in connection with the merger or the consummation of any of the transactions contemplated by the merger agreement, including all regulatory filing fees, fees and expenses of counsel, commercial banks, investment banking firms, accountants, experts, environmental consultants, and other consultants to Helix, up to a maximum amount not to exceed $2 million, and (ii) $45 million if the merger agreement is terminated under certain circumstances and we enter into or complete an alternative transaction. We believe that with our credit facility and other financial resources that we will be able to make such payments if required.

 

We incurred capital and exploration expenditures totaling $220.7 million during 2005. The capital expenditures included $12.0 million for leasehold acquisition, $111.4 million for exploration costs, $94.5 million for development costs, including platform and facilities construction and $2.8 million for asset retirement costs. During the year, we built and installed 6 offshore platforms and facilities. In addition, in 2005 we drilled 19 offshore exploration wells and 5 offshore development wells and had 2 wells in progress at year end.

 

We expect to continue to make significant capital expenditures over the next several years as part of our long-term growth strategy. We have budgeted $293 million for capital and exploration expenditures in 2006. Our 2006 capital and exploration budget includes $146 million for 28 exploratory wells. We project that we will spend $141 million on 26 wells in the Gulf of Mexico and $5 million on 2 onshore wells in Mississippi. The budget also includes $112 million for platforms and development drilling. Additional development expenditures beyond the budgeted amount will be required throughout the year; the amount of such additional expenditures being dependent upon our success with our 2006 exploration and development program. The remaining $35 million will be allocated to leasehold acquisitions, seismic acquisitions, and workovers. If our exploratory drilling results in significant new discoveries, we will have to expend additional capital in order to finance the completion, development, and potential additional opportunities generated by our success. We believe that, because of the additional reserves resulting from the exploratory success and our record of reserve growth in recent years, we will be able to access sufficient additional capital through available cash on hand and/or additional bank financing and/or offerings of debt or equity securities.

 

On September 9, 2005, we increased our credit facility from $150 million to $200 million and the associated borrowing base from $100 million to $150 million. Interest only is payable quarterly through September 2009, at which time the line expires and all principle becomes due, unless the line is extended or renegotiated. As of December 31, 2005, there were no borrowings outstanding under this facility. The most significant financial covenants in the line of credit include, among others, maintaining a minimum current ratio (as defined in the facility agreement) of 1.0 to 1.0, a minimum tangible net worth of $175 million plus 50% of net income (accumulated from the closing date of the facility agreement) and 75% of the net proceeds of any corporate equity offering, and interest coverage of 2.5 to 1.0. We are currently in compliance with these financial covenants. If we do not comply with these covenants, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principle and interest immediately due and payable. The merger agreement prohibits us from incurring more than $50 million in debt under the credit facility pending consummation of the transaction.

On June 19, 2003, we filed a shelf registration statement to issue up to $200.0 million of common stock, debt securities, preferred stock, and of warrants. The SEC declared the shelf registration statement effective December 18, 2003. We have not drawn on the shelf offering.

 

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2005.

 

 

 

On December 31, 2005, our current assets exceeded our current liabilities by $62.6 million. Our current ratio was 1.81 to 1.00.

 

Results of Operations

 

In 2005, we achieved net income totaling $70.6 million or $2.48 basic income per share, and $2.37 diluted income per share, compared to a net income of $61.0 million or $2.23 basic income per share and $2.14 diluted income per share in 2004. The increase in net income resulted primarily from increased oil and gas sales prices offset partially by a decrease in oil and gas production. During the third quarter of 2005, damage to our production platforms and pipelines, as well as third party pipelines and facilities, caused us to lose a significant amount of our production during the fourth quarter of 2005. In addition to oil and gas sales prices and production, certain accounting policies discussed below can cause our net income to vary significantly from period to period because of events or circumstances which trigger recognition of expenses for unsuccessful wells or impairments of properties. Further, we calculate certain expenses using estimates of oil and gas reserves that can vary significantly.

Oil and Gas Sales Revenue

 

The following table discloses the net oil and gas production volumes, sales, and sales prices for each of the three years ended December 31, 2005, 2004, and 2003.

 

 

Oil sales revenue during 2005 increased by $10.1 million, or 15%, compared to 2004 because average oil prices increased by $11.87 per barrel, or 30%, which more than offset a 191,000 barrel (11%) decline in oil production. During 2004, oil sales revenue increased by $13.7 million, or 26%, compared to 2003 because average oil prices increased by $9.94 per barrel, or 34%, which more than offset a 100,000 barrel (6%) decline in oil production.

 

Gas sales revenue during 2005 increased by $16.5 million, or 10%, compared to 2004 because average gas prices increased by $2.34 per mcf, or 39%, which more than offset a decrease in production of 5,897 Mmcf, or (21)%. During 2004, gas sales revenue increased by $37.2 million, or 29% because of higher average gas prices and production. Average gas prices climbed from $5.40 per Mcf in 2003 to $5.97 per Mcf, or 11%, in 2004. Production increased by 3.9 Bcf, or 16%, primarily because of gas production from new properties in the offshore Gulf of Mexico.

 

Operating Costs and Expenses

 

Total operating costs during 2005 increased by $3.1 million, or 12.2%, compared to 2004, due to the increase in the number of operating properties. However, operating costs per Mcfe increased by $0.24, or 36.4%, to $0.90 during 2005 due to the decrease in production. The following table presents the major components of our operating costs and operating costs per Mcfe.

 

Exploration Expenses — Successful-Efforts Method of Accounting

 

During 2005, exploration expenses increased by $32.7 million, or 145.1%, compared to 2004 primarily because of a $35.9 million (280.6%) increase in dry hole costs. Dry hole costs for 2005 include the South Pass 87 Aquarius well at a total cost of $22.7 million. Exploration expenses for 2004 decreased by $2.9 million, or 11%, because of an $11.2 million (46.7%) decrease in dry hole costs. During the last three years we have drilled 69 exploration wells, of which 22 were considered dry holes, resulting in a 68% success ratio on exploratory wells. Our dry hole costs charged to expense during this period totaled $48.7 million out of total exploratory drilling costs of $104.8 million.

 

Depreciation, Depletion, and Amortization of Oil and Gas Properties

 

We calculate depreciation, depletion, and amortization expense (“DD&A”) using the estimates of proved oil and gas reserves. We segregate the costs for individual or contiguous properties or projects and record DD&A of these property costs separately using the units-of-production method. Downward revisions in reserves increase the DD&A per unit and reduce our net income; likewise, upward revisions lower the DD&A per unit and increase our net income. Depreciation, depletion and amortization expense recorded in 2005 decreased by $12.5 million, or 17.1%, compared to the prior year. On a per Mcfe basis, depreciation, depletion and amortization per Mcfe increased to $1.94 in 2005 from $1.91 in 2004 reflecting the increased costs for finding reserves in the Gulf of Mexico. Depreciation, depletion and amortization expense increased by $17.1 million, or 31% for the year ended December 31, 2004, compared to the prior year, and depreciation, depletion and amortization per Mcfe increased to $1.91 from $1.60 in 2003 reflecting the increased costs for finding reserves in the Gulf of Mexico.

 

Impairment of Oil and Gas Properties

 

Because we account for our proved oil and gas properties separately, we also assess our assets for impairment property by property rather than in one pool of total oil and gas property costs. This method of assessment is another feature of the successful-efforts method of accounting. Certain unforeseeable events such as significantly decreased long-term oil or gas prices, failure of a well or wells to perform as projected, insufficient data on reservoir performance, and/or unexpected or increased costs may cause us to record an impairment expense on a particular property. We base our assessment of possible impairment using our best estimate of future prices, costs and expected net cash flow generated by a property. We estimate future prices based on NYMEX 12 month strips, adjusted for basis differential and escalate both the prices and the costs for inflation if appropriate. If these estimates indicate impairment, we measure the impairment expense as the difference between the net book value of the asset and its estimated fair value measured by discounting the future net cash flow from the property at an appropriate rate. Actual prices, costs, discount rates, and net cash flow may vary from our estimates. We recognized impairment expenses during the last three years as follows:

 

 

We estimate the amount of individually insignificant unproved properties which will prove unproductive by amortizing the balance of our individual immaterial unproved property costs (adjusted by an anticipated rate of future successful development) over an average lease term. Individually significant properties will continue to be evaluated periodically on a separate basis for impairment. We will transfer the original cost of an unproved property to proved properties when we find commercial oil and gas reserves sufficient to justify full development of the property. The impairment of unproved properties for the prior two years resulted from the actual (due to unsuccessful exploration results) or impending forfeiture of leaseholds.

 

We analyze our proved properties for impairment indicators based on the proved reserves as determined by our internal reserve engineers. No proved properties were impaired during 2005. The properties impaired in 2004

primarily consisted of two properties in the Gulf of Mexico which totaled $4.2 million and two onshore Gulf Coast properties which totaled $5.5 million. During 2003, we impaired two properties in the Gulf of Mexico which totaled $2.4 million and one property in the onshore Gulf Coast which totaled $855,000. The impairments resulted primarily from wells depleting sooner than originally estimated or capital costs in excess of those anticipated.

 

General and Administrative

 

General and administrative expenses during 2005 increased by $7.1 million, or 88.5% compared to 2004. General and administrative expenses increased by $0.28 per Mcfe to $0.49 in 2005 from $0.21 in 2004. General and administrative expenses in 2004 decreased by $355,000. Stock based compensation expense which is included in general and administrative expense totaled $4.6 million in 2005, $1.4 million in 2004 and $1.6 million in 2003.

 

Interest and Financing Expense

 

Interest and financing expense decreased during the past two years because of lower interest rates and lower outstanding debt.

 

Income Taxes

 

During 2005, income taxes increased by $6.1 million compared to 2004 and increased by $9.3 million during 2004 compared to 2003 as a result of increased income before taxes. The effective tax rate increased slightly in 2005 due to an increase in the provision for deferred state income taxes.

 

Commodity Price Risk

 

A vast majority of our production is sold on the spot markets. Accordingly, we are at risk for the volatility of commodity prices inherent in the oil and gas industry.

 

Occasionally we sell forward portions of our production under physical delivery contracts that by their terms cannot be settled in cash or other financial instruments. Such contracts are not subject to the provisions of Statement of Financial Accounting Standards No. 133 “Accounting for Derivative Instruments and Hedging Activities.” Accordingly, we do not provide sensitivity analysis for such contracts. Subsequent to year end, we entered into physical delivery contracts for the period March 2006 through June 2007 as follows:

 

 

INDEX TO FINANCIAL STATEMENTS

 

 

The Board of Directors and Stockholders of

Remington Oil and Gas Corporation:

 

We have audited the accompanying consolidated balance sheets of Remington Oil and Gas Corporation and subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

 

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

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 10, 2006 expressed an unqualified opinion thereon.

 

As discussed in Note 1 to the consolidated financial statements, in 2003 the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”

 

/s/ Ernst & Young LLP

 

Dallas, Texas

March 10, 2006

REMINGTON OIL AND GAS CORPORATION

 

CONSOLIDATED BALANCE SHEETS