ITEM 1. BUSINESS.
GENERAL
Remington Oil and Gas Corporation
- Incorporated -- 1991, Delaware
- Address -- 8201 Preston Road, Suite 600, Dallas, Texas 75225-6211
- Telephone number -- (214) 210-2650
- 28 employees on December 31, 2001
We began operations in 1981 as OKC Limited Partnership. In 1992, the limited partnership was converted into a corporation named Box Energy Corporation. In 1997, we changed the name of the company to Remington Oil and Gas Corporation. We restructured our two classes of common stock into a single class of voting common stock when we merged with S-Sixteen Holding Company in December 1998.
Our primary business operation is the exploration, development, and production of oil and gas reserves in the offshore Gulf of Mexico and onshore Gulf Coast areas.
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.
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 and deliver the oil and gas to our various markets. Certain properties require us to drill additional wells to fully develop the oil and gas reserves on our discoveries. In order to increase our oil and gas reserves and production, we continually reinvest the net cash flow from our operations into new or existing exploration, development and acquisition activities.
We share ownership in many of our in oil and gas properties with various industry partners. We currently operate 45 of our offshore properties, while others operate the remainder of our properties. As operator, we are able to maintain a greater degree of control over timing and amount of capital expenditures.
RISKS INVOLVED IN EXPLORATION, DEVELOPMENT, AND PRODUCTION
Exploration, development, and production operations can be very risky. Each time we drill a well, there is a risk that the well will not find oil or gas reserves. Even if we find reserves in a well, there is the risk that we will not be able to produce enough oil or gas to return a profit on the amount invested in the well. We attempt to reduce these risks by using 3-D seismic data or other applied technology to identify and define the parameters prior to drilling, although this does not guarantee successful results. Our success depends upon the quality of the information used to determine drilling locations and the abilities and experience of our management, technical, and service personnel.
Additional operating risks include mechanical failure, title risk, blowouts, environmental pollution, and personal injury. We maintain both general liability insurance and activity specific insurance against major production losses, blowouts, redrilling, and many other operating hazards, including certain pollution risks. Uninsured losses or losses and liabilities that exceed the limits of our insurance could adversely affect our financial condition.
COMPETITION IN THE OIL AND GAS INDUSTRY
We compete with:
- Large integrated oil and gas companies
- Independent exploration and production companies
- Private individuals
- Sponsored drilling programs
We compete for:
- Operational, technical, and support staff
- Options and/or leases on properties
- Sales of oil and gas production
- Access to capital
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 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:
- Changes in supply and demand
- Changes in refinery utilization
- Levels of economic activity throughout the country
- Seasonal or extraordinary weather patterns
- Political developments throughout the world
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 gas production to be delivered as it is produced. An independent marketing company sells almost all of our gas production and a small quantity of our oil production from the Gulf of Mexico. The revenue from the sale of oil and gas by this marketing company accounted for approximately 65% of our total oil and gas revenues in 2001. In addition, we sold approximately 56% of our total oil production to one company during the year, which accounted for approximately 14% of our total oil and gas revenues in 2001.
GOVERNMENTAL REGULATION OF OIL AND GAS OPERATIONS AND ENVIRONMENTAL REGULATIONS
Numerous federal and state regulations affect our oil and gas operations. Current regulations are constantly reviewed by 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.
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 stringent 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. 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 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 into 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 OPA, the Clean Water Act and other statutes 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, and 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.
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.
ITEM 2.
ITEM 2. PROPERTIES.
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 "Management's Discussion and Analysis of Financial Condition and Results of Operations" found on pages 9 through 15 and "Consolidated Financial Statements and Notes to Consolidated Financial Statements" found on pages 17 through 37. Note 2 -- Oil and Gas Properties and Note 9 -- 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 proved and unproved properties at December 31, 2001, was as follows:
PROVED OIL AND GAS RESERVES
Net proved oil and gas reserves at December 31, 2001, as evaluated by Netherland, Sewell, & Associates, Inc., are summarized below on the following table. 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.
PRODUCING PROPERTIES
The table below summarizes our ownership in producing wells at the end of the last three years.
Our offshore Gulf of Mexico properties account for approximately 64% of our oil production and approximately 89% of our gas production. In addition, total revenues from offshore Gulf of Mexico oil and gas production during 2001 accounted for approximately 84% of our total oil and gas revenues. We owned varying working interests (5% to 100%) in 72 offshore Gulf of Mexico blocks at December 31, 2001, and currently produce from 20 of these blocks with 8 additional blocks currently under development. We operate 10 of the total 28 producing blocks. All of these blocks are located in water depths of less than 600 feet on the outer continental shelf of the Gulf of Mexico. In addition, we have invested in long-term 3-D seismic licensing agreements covering approximately 2,700 blocks in this area. Our agreements combined with our computer technology, provide our technical team immediate in-house access to these seismic data.
During 2001 we successfully drilled and completed 13 exploratory wells on 12 different properties in the offshore Gulf of Mexico. In addition, we, as operator, constructed and installed or will install eight production platforms and drilled and completed two development wells on two different properties.
Our onshore Gulf Coast area properties are principally located in the state of Mississippi and along the Texas gulf coast. In 2001, these properties accounted for approximately 36% of our oil production and approximately 11% of our gas production. We drilled a total of 19 wells on our onshore properties during 2001 and completed 14 wells as producers. Our working interests in these wells range from 15% to 50%.
DRILLING ACTIVITIES
The following is a summary of our exploration and development drilling activities for the past three years.
We had an interest in 2 wells (0.80 net) in progress at December 31, 2001, 2 wells (0.65 net) in progress at December 31, 2000, and 7 wells (2.73 net) in progress at December 31, 1999.
OTHER PROPERTY AND OFFICE LEASE
We own several non-contiguous tracts of land covering approximately 3,500 surface acres in Southern Louisiana and Southern Mississippi. Outside parties lease several of the tracts for farming, grazing, timber, sand and gravel, camping, hunting, and other purposes. Gross revenues from these real estate properties in 2001 totaled $134,000. We lease approximately 17,000 square feet of office space in Dallas, Texas. The lease on this office space expires in April 2008.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
We are not a party to any material legal proceedings at this time.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Our common stock trades on the Nasdaq National Market under the symbol ROIL and on the Pacific Exchange under the symbol REM.P. The following table sets forth the high and low last sales price per share as reported by Nasdaq for the periods indicated.
On March 18, 2002, the last reported sales price for our common stock was $18.85 per share. On that date, there were 771 stockholders of record, including 123 stockholders of record of class A common stock and 254 stockholders of record of class B common stock who had not yet surrendered their old stock for the new common stock to which they are entitled.
We have not declared or paid any cash dividends during the past nine years. Our credit facility agreements prohibit 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 renegotiations of our line of credit.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
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" included in Item 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
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 the financial statements, and the related notes to 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.
LONG-TERM STRATEGY AND BUSINESS DEVELOPMENTS
Our long-term strategy is to increase our oil and gas production and reserves while keeping our operating costs and our finding and development costs competitive with our industry peers. Over the last three years, we have invested $224.8 million in oil and gas properties, found 190.0 Bcfe of proved reserves and replaced 265% of our production at a finding and development cost of $1.18 per Mcfe. The following table reflects our results during the last three years.
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(1) Barrels of oil are converted to Mcf equivalents at the ratio of 1 barrel of oil equals 6 Mcf of gas.
(2) Production costs include operating, transportation and Net Profits expense.
(3) Finding costs include acquisition, development and exploration costs (including exploration costs such as seismic acquisition costs).
CRITICAL ACCOUNTING POLICIES
We prepare our consolidated financial statements for inclusion in this report using accounting principles that are generally accepted in the United States ("GAAP"). Our Notes to Consolidated Financial Statements included on pages 23 through 37 in this report have a more comprehensive discussion of our significant accounting policies. 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.
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 as an expense on the income statement 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.
We use the successful efforts method because we believe that it more conservatively reflects on our balance sheet historical costs that have future value. However, using successful-efforts often causes our income statement to fluctuate significantly between reporting periods based on our success or failure during the periods.
Proved Reserve Estimates
Unaffiliated reserve engineers prepare our oil and gas reserve estimates using guidelines put forth under GAAP and by the Securities and Exchange Commission. The quality and quantity of data, the interpretation of the data, and the accuracy of mandated economic assumptions combined with the judgment exercised by the reserve engineers affect the accuracy of the estimated reserves. In addition, drilling or production results after the date of the estimate may cause material revisions to the reserve estimates. You should not assume that the present value of the future net cash flow disclosed in this report reflects the current market value of the oil and gas reserves. In accordance with the Securities and Exchange Commission's guidelines, we use prices and costs determined on the date of the estimate and a 10% discount rate to determine the present value of future net cash flow. Actual prices and costs may vary significantly and the discount rate may or may not be appropriate based on outside economic conditions.
Depletion, Depreciation, and Amortization of Oil and Gas Properties
We calculate depletion, depreciation, 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. Material downward revisions in reserves increase the DD&A per unit and reduce net income; likewise, material upward revisions lower the DD&A per unit and increase net income.
Impairment of Oil and Gas Properties
Because we account for our oil and gas properties separately, we 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 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 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. We base our assessment of possible impairment using our best estimate of future prices, costs and expected net cash flow generated by a property. Actual prices, costs, discount rates, and net cash flow may vary from our estimates.
The above critical accounting policies can cause our net income to vary significantly from period to period as events or circumstances which trigger recognition as an expense for unsuccessful wells or impaired properties cannot be accurately forecast. In addition, selling prices for our oil and gas fluctuate significantly. Therefore, to manage the company we focus more on cash flow from operations and on controlling our finding and development, operating, administration, and financing costs.
Accounting for Stock Based Compensation
In June 1999, the Board of Directors approved a contingent stock grant to our employees and directors. In order for the grant to become effective, the price of our stock had to increase from $4.19 per share to a trigger price of $10.42 per share and close at or above $10.42 per share for 20 consecutive trading days. When the
Board of Directors approved the grant we did not record any amounts for expense, liability, or equity because the measurement date for determining the compensation cost depended on the occurrence of an event after the date of grant. Therefore, we could not be sure that we would incur any expense as a result of the grant, and we could not reasonably estimate the amount of possible expense.
January 24, 2001, became the measurement date when the stock price closed above the trigger price for the twentieth consecutive trading day. On that date, we measured the total compensation cost at $8.1 million which was the total number of shares granted multiplied by the market price on that date. We recorded $8.1 million as restricted common stock, $5.7 million as unearned compensation reported as a separate reduction in stockholders' equity on the balance sheet, and $2.4 million as stock based compensation expense. The $2.4 million stock based compensation expense recorded in the first quarter of 2001 included a "catch up" amortization from the date of the grant to the measurement date of the total compensation cost because the cost should be recognized over the time period in which the stock grant vested to the employees or directors. We will amortize the remaining $5.7 million compensation expense over the next five years as the shares vest. The vesting period could accelerate in the event of a change in control of the company or the death or permanent disability of an employee. A shorter vesting period would accelerate the amortization period. Except as noted above, the shares will be issued only to the extent the employees and directors remain with the company through the vesting dates.
In accounting for stock options granted to employees and directors, we have chosen to continue to apply the accounting method promulgated by Accounting Principles Board Opinion No. 25 ("APB 25") rather than apply an alternative method permitted by Statement of Financial Accounting Standards No. 123 ("FAS 123"). Under APB 25, we do not record compensation expense on our income statement for stock options granted to employees or directors. If we applied an alternative method permitted by FAS 123, our net income would be lower than actually reported. We disclose in our Notes to Consolidated Financial Statements the pro-forma effect on our income statement if we were to record the estimated fair value of stock options on the date granted and amortize the expense over the expected vesting of the grant. We chose the APB 25 method because we believe that the use of the APB 25 method makes our financial presentation easier to compare to the financial presentations of other publicly held companies, most of whom we believe also use the APB 25 method.
LIQUIDITY AND CAPITAL RESOURCES
The following table summarizes our contractual obligations and commercial commitments as of December 31, 2001.
(A letter of credit in the amount of $536,000 was issued against our bank credit facility on March 15, 2002.)
On December 31, 2001, our current assets exceeded our current liabilities by $2.8 million. Our current ratio was 1.08 to 1.00.
Cash flow from operations for the year ended December 31, 2001, before changes in working capital, increased by $9.0 million, or 14%, compared to the prior year primarily because of increased gas revenues partially offset by the $13.5 million expense for the Phillips Petroleum settlement and increased production costs from new properties. Gas sales increased by $33.7 million, or 66%, because of a 65% increase in gas production and a slight increase in the average price.
We incurred capital and exploration expenditures totaling $122.8 million during 2001. The capital expenditures included $46.8 million for exploration costs, $61.1 million for development costs and $14.9 million for the acquisition of properties including the South Pass 89 net profits interest from Phillips Petroleum. During the year, we built and installed, or will install in 2002, eight offshore platforms and facilities. In addition, we drilled 15 exploration wells and 2 development wells in the Gulf of Mexico and 12 exploration wells and 7 development wells in Mississippi and South Texas.
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 $75.0 million for capital expenditures in 2002. Our 2002 capital and exploration budget includes $37.0 million for 26 exploratory wells. We project that we will spend $32.0 million on 16 wells in the Gulf of Mexico and $5.0 million on 10 onshore wells in South Texas and Mississippi. The budget also includes $20.0 million for platforms and development drilling on operated discoveries at Eugene Island 302, South Marsh Island 93, East Cameron 179/184, West Cameron 417, and one non-operated development at Eugene Island 397. The remaining $18.0 million will be allocated to leasing, seismic acquisitions, and workovers. We expect that our cash, estimated future cash flow from operations, and available bank line of credit will be adequate to fund these expenditures for the remainder of 2002.
If our exploratory drilling results in significant new discoveries, we will have to acquire additional capital in order to finance 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 acquire sufficient additional capital through additional bank financing and/or offerings of debt or equity.
As of December 31, 2001, our amended credit facility has a borrowing base of $75.0 million. As of March 18, 2002, we had $71.0 million borrowed under the facility, and an additional $536,000 of credit availability was utilized to issue a letter of credit. The banks review the borrowing base semi-annually and may increase or decrease the borrowing base at their discretion relative to the new estimate of proved oil and gas reserves. The next redetermination is scheduled for April 2002. Our oil and gas properties are pledged as collateral for the line of credit. Additionally, we have agreed not to pay dividends. Unless renewed or extended, the line of credit expires on May 3, 2004, when all principal becomes due.
The most significant financial covenants in the line of credit include, among others, maintaining a minimum current ratio of 1.0 to 1.0, a minimum tangible net worth of $85.0 million plus 50% of future net income and 100% of any non-redeemable preferred or common stock offerings, and interest coverage of 3.0 to 1.0. We are currently in compliance with these financial covenants in all material respects. If we don't comply with these covenants, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.
On May 22, 2001, we settled the litigation with Phillips Petroleum Company and acquired Phillips' Net Profits Interest in South Pass block 89, offshore Louisiana. We paid $21.3 million cash and issued 1,189,344 shares of our common stock as consideration for the settlement and assignment of the net profits interest. Subsequently, Phillips sold 33,900 shares on the open market, and we purchased the remaining 1,155,444 shares at a total cost of $20.6 million.
The shares issued to Phillips were issued under a $110.0 million shelf registration filed with the Securities and Exchange Commission, the proceeds of which may be used for general corporate purposes. A substantial majority of the shares available under the shelf registration are unissued and are subject to being drawn down at the discretion of the company based on market prices and conditions.
During 2001, holders of $5.785 million face amount of the 8 1/4% convertible notes due December 1, 2002, converted their notes into common stock at the prescribed conversion ratio of one share of common stock for
each $11.00 of principal amount of notes. We redeemed the remaining $95,000 of the notes for cash at a call price of 101.65%.
RESULTS OF OPERATIONS
In 2001, we recorded net income totaling $8.4 million or $0.38 basic income per share, and $0.35 diluted income per share, compared to a net income of $45.0 million or $2.10 basic income per share and $1.99 diluted income per share in 2000. The decrease in net income resulted primarily from the settlement expense related to the Phillips Petroleum litigation and higher dry hole and impairment costs. In addition, net income for 2000 includes a $12.5 million gain for the sale of certain South Texas properties.
The following table discloses the net oil and gas production volumes, sales, and sales prices for each of the three years ended December 31, 2001, 2000, and 1999. The table is an integral part of the following discussion of results of operations for the periods 2001 compared to 2000 and 2000 compared to 1999.
2001 compared to 2000
Oil production increased by 2% in 2001 compared to the prior year because of a 15% increase in offshore Gulf of Mexico production partially offset by lower oil production from Mississippi and South Texas. Oil production from the Gulf of Mexico increased because of new wells that began producing in 2001. Average oil prices decreased 15% during 2001 which in turn caused oil revenues to be $5.1 million lower.
Gas revenue increased by $33.7 million or 66% because of a 65% increase in production compared to 2000. Production from the offshore Gulf of Mexico increased by 8.6 Bcf, or 83%, while gas production from South Texas decreased by 0.4 Bcf, or 7%. Five offshore properties began to produce for the first time during 2001 and three additional offshore properties increased their production significantly either from new wells drilled and completed or because 2001 was their first full year of production. We expected the decrease in production from South Texas after we sold certain properties in 2000. The change in average prices did not affect total gas revenues significantly.
Interest income decreased by $467,000, or 32% because of lower rates earned on our short-term investments and because we used the $9.0 million of restricted cash previously set aside for the Phillips Petroleum judgment in the settlement of that litigation in May 2001. Other income decreased because we had a non-recurring $12.5 million gain from the sale of South Texas properties in 2000.
Operating costs and expenses increased by $4.9 million, or 46%, because of new producing properties. However, operating expenses per Mcfe increased to $0.53 from $0.52, or less than 2%. Exploration expenses increased by $5.4 million, or 70%, because of increased dry hole costs for two offshore and one onshore well compared to six onshore wells in 2000. Offshore wells typically are significantly more costly than the onshore wells. The impairment expense for 2001 primarily resulted from insufficient future net cash flow for three offshore Gulf of Mexico properties, which accounted for $8.7 million, one South Texas property which accounted for $1.3 million, and one unproved offshore Gulf of Mexico property lease that was forfeited in 2002 which accounted for $616,000. Depreciation, depletion and amortization expense increased by $17.3 million because of production from new properties.
General and administrative expenses have remained substantially level with prior year amounts. Stock based compensation expense includes $3.5 million for amortization of compensation costs related to the contingent stock grant and $246,000 for stock based directors fees.
On May 22, 2001, we settled the litigation with Phillips Petroleum Company. Of the total $42.5 million settlement, we had previously recorded $20.2 million as an accrued liability. We recorded $12.3 million of the remaining $22.3 million as additional settlement expense and capitalized $10.0 million as the cost for our purchase of the net profits interest. In addition, we charged the remaining $1.2 million deferred net profits expense related to a royalty settlement in 2000 to the settlement expense. During 2000, we reached two separate agreements with the Minerals Management Service concerning the royalties due on offshore Gulf of Mexico properties. Because of the agreements, we recorded expenses of $5.4 million during 2000.
Interest and financing costs decreased 16% because of lower interest rates applicable to our outstanding debt and because we are no longer accruing interest on the Phillips judgment.
During 2001, we recorded income tax expense totaling $3.6 million, all of which is deferred. We fully utilized our net deferred income tax benefit during 2000 and the first quarter of 2001.
2000 compared to 1999
Oil production increased slightly compared to 1999 because of increased production from Mississippi partially offset by lower oil production from the Gulf of Mexico. Oil production from Mississippi increased by 179,000 barrels, or 79%, during 2000 because of several new successful wells drilled during the year. The average oil price increased by 75% during 2000 compared to the prior year.
Gas production increased by 30% during 2000 compared to 1999 primarily from gas produced from the Gulf of Mexico and South Texas. Gas production from the Gulf of Mexico increased by 2.1 Bcf, or 26%, and gas production from South Texas increased by 714,000 Mcf, or 42%, during 2000. The increase resulted from several successful wells drilled during the year. The average gas price increased by 64% during 2000 compared to 1999.
Other income increased by $11.9 million because we recorded a $12.4 million gain on the sale of certain South Texas properties in August 2000, partially offset by lower oil trading income.
Operating expenses increased during the year 2000 compared to 1999, mainly due to the increased number of producing properties and an increase in workover expenses mostly related to West Cameron 170 and Eugene Island 135. Exploration expense increased by $108,000 during 2000 primarily because of slightly higher dry hole costs in 2000. Depreciation, depletion, and amortization expense increased by $196,000 during 2000 compared to the prior year largely as a result of increased production partially offset by lower finding costs per unit during the last three years. Impairment expense for the year 2000 primarily includes the costs for expired unproved properties compared to impairment expense for the year 1999 that included additional impairments for Main Pass 262 and two small onshore properties.
Legal expenses decreased $780,000, or 53%, because we settled both the Minerals Management Service issues and the minority stockholders litigation during the year, and we incurred lower costs related to the Phillips litigation. During 2000, we reached two separate accords with the Minerals Management Service concerning the alleged underpayment of oil and gas royalties. The first agreement reached in May 2000,
concerned additional royalties asserted to be due on the settlement of litigation related to a 1990 gas sales contract. Because of this agreement, we recorded an expense of $3.2 million in the first quarter of 2000. As to the second accord, we reached an agreement in October 2000 to settle the issues concerning oil transportation charges and oil exchange contracts for $2.2 million.
NEW ACCOUNTING PRONOUNCEMENTS
On January 1, 2001, we adopted Statement of Financial Accounting Standards 133 "Accounting for Derivative Instruments and Hedging Activities" which requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in fair value be recorded currently in net income unless specific hedge accounting criteria are met. The definition of derivative contracts has also been expanded to include contracts that require physical delivery of oil and gas if the contract allows for net cash settlement. We do not utilize any derivative instruments that fall under the criteria defined in the accounting standard and therefore the adoption of this statement did not have any effect on our reported financial statements or disclosures.
Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations" will be effective for years beginning after June 15, 2002. 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 period in which the asset is first placed in service. Currently we accrue the estimated liability for dismantlement and abandonment over the life of the property using a unit of production method. Because of this new standard, effective January 1, 2003, we must increase both our recorded assets and liabilities by the estimated cost of the ultimate asset retirement obligation. For properties owned at December 31, 2001, we estimate that amount to be $10.6 million. We will then discount the amount to present value, and on a periodic basis record the accretion of discount. We will also amortize the cost into depletion, depreciation, and amortization expense. The charges to the income statement will not be materially different under this standard as compared to our present method.
In August 2001, Financial Accounting Standards Board issued the Statement of Financial Accounting Standards No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" which supercedes Statement of Financial Accounting Standards No. 121 "Accounting for Impairment of Long-Lived Assets." The Statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. The statement is effective for periods beginning after December 15, 2001. We do not believe that the adoption of this statement will have a material effect on our balance sheet or income statement.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
INTEREST RATE RISK
Our market risk sensitive instrument at December 31, 2001, is a revolving bank line of credit. At December 31, 2001, the unpaid principal balance under the line was $71.0 million which approximates its fair value. The interest rate on this debt is based on a premium of 150 to 225 basis points over the London Interbank Offered Rate ("Libor"). The rate is reset periodically, usually every three months. If on December 31, 2001, Libor changed by one full percentage point (100 basis points) the fair value of our revolving debt would change by approximately $175,000. We have not entered into any interest rate hedging contracts.
COMMODITY PRICE RISK
Occasionally we sell forward portions of our production under physical product 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. For the period January 1, 2002, through June 30, 2002, we have physical delivery contracts in place to sell approximately
20,000 MMBtu of gas per day (approximately 1/3 of our projected gas production for that six month period) at a price of approximately $2.77 per MMBtu.
A vast majority of our production is sold on the spot markets. Accordingly, we are at risk for the volatility in the commodity prices inherent in the oil and gas industry.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Stockholders and Board of Directors of Remington Oil and Gas Corporation
We have audited the accompanying balance sheets of Remington Oil and Gas Corporation ("the Company"), a Delaware corporation, as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholders' equity and cash flows for the three years in the period ended December 31, 2001. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Remington Oil and Gas Corporation as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas March 15, 2002
REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED BALANCE SHEETS
See accompanying Notes to Consolidated Financial Statements.
REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
See accompanying Notes to Consolidated Financial Statements.
REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
See accompanying Notes to Consolidated Financial Statements.
REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to Consolidated Financial Statements.
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
Remington Oil and Gas Corporation, formerly Box Energy Corporation, is an independent oil and gas exploration and production company incorporated in Delaware. We have working interest ownership rights in properties in the offshore Gulf of Mexico and onshore Gulf Coast. We own the following subsidiaries: CKB Petroleum, Inc., CKB & Associates, Inc., Box Brothers Realty Investments Company, CB Farms, Inc., and Box Resources, Inc. We eliminated all inter-company transactions and account balances for the periods of consolidation. The primary operating subsidiary, CKB Petroleum, Inc., owns an undivided interest in a pipeline that transports oil from our South Pass blocks, offshore Gulf of Mexico, to Venice Louisiana.
USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS
Management prepares the financial statements in conformity with accounting principles generally accepted in the United States. This requires estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported periods. Some of the more significant estimates include oil and gas reserves, useful lives of assets, impairment of oil and gas properties, and future dismantlement and restoration liabilities. Actual results could differ from those estimates. We make certain reclassifications to prior year financial statements in order to conform to the current year presentation.
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH
Cash equivalents consist of highly liquid investments that mature within three months or less when purchased. Our cash equivalents include investment grade commercial paper and institutional money market funds. We record cash equivalents at cost, which approximates their market value at the balance sheet date.
On December 31, 2000, we had $9.0 million set aside as restricted cash with a surety company as collateral for the suspensive appeal bond for the Phillips litigation. After the Phillips Petroleum settlement in May 2001, the surety company returned the $9.0 million to us.
PROPERTY AND EQUIPMENT
We follow the successful-efforts method to account for oil and gas exploration and development expenditures. Under this method, we capitalize expenditures for leasehold acquisitions, drilling costs for productive wells and unsuccessful development wells. We amortize the capitalized costs using the units-of-production method, converting to gas equivalent units by using the ratio of 6 barrels of oil equal to one thousand cubic feet of gas. Future dismantlement, restoration and abandonment costs include the estimated costs to dismantle, restore, and abandon our offshore platforms, wells, and related facilities. We accrue for the liability over the life of the property using the units-of-production method and record the expense as a component of depreciation, depletion and amortization expense. As of December 31, 2001, the total estimated liability of our future dismantlement and restoration costs is $10.6 million. The accrued liability at December 31, 2001 and 2000, was $4.3 million and $4.6 million, respectively. We record expenditures for geological, geophysical or other prospecting costs as exploration expenses on the income statement when incurred.
Periodically, if there is a large decrease in oil and gas reserves or production on a property, or if a dry hole is drilled on or near one of our properties we will review the properties for impairment. In addition, significant decreases in long-term oil and gas prices may also indicate that a property has become impaired. If the net book value of a property is greater than the estimated undiscounted future net cash flow from the same property, the property is considered impaired. We base our assessment of possible impairment using our best estimate of future prices, costs and expected net cash flow generated by a property. The impairment expense is
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
equal to the difference between the net book value and the fair value of the asset. We estimate fair value by discounting, at an appropriate rate, the future net cash flows from the property. In addition, we assess the capitalized costs of unproved properties periodically to determine whether their value has been impaired below the capitalized costs. We recognize a loss to the extent that such impairment is indicated. In making these assessments, we consider factors such as exploratory drilling results, future drilling plans, and lease expiration terms.
Other properties include improvements on the leased office space and office computers and equipment. The company depreciates these assets using the straight-line method over their estimated useful lives that range from 3 to 12 years.
OTHER ASSETS
Other assets include the net unamortized credit facility origination fees and a long-term account receivable. The origination fees are amortized on a straight-line basis over the term of the debt. We charge the amortized amount to interest and financing costs. The long-term account receivable totaling $354,000 is CKB Petroleum's claim under Collateral Assignment Split Dollar Insurance Agreements among CKB Petroleum and Don D. Box (an officer and director) and two of his brothers.
OIL AND GAS REVENUES
We recognize oil and gas revenue in the month of actual production. Our actual sales have not been materially different from our entitled share of production and we do not have any significant gas imbalances. In 2001, sales by a gas marketing company accounted for approximately 65% of our total oil and gas revenue. In addition, we sold approximately 56% of our total oil production to one company during the year, which accounted for approximately 14% of our total oil and gas revenues in 2001. We do not believe that the risk of losing services or sales from either of these companies would have a material adverse effect on us.
STOCK OPTIONS
We continue to apply the accounting provisions of Accounting Principles Board Opinion 25, entitled "Accounting for Stock Issued to Employees," and related interpretations to account for stock-based compensation. Accordingly, we measure compensation cost for stock options as the excess, if any, of the quoted market price of our stock at the date of the grant over the amount an employee must pay to acquire the stock. All of our options are granted with exercise prices at or above the quoted market price on the date of grant.
SEGMENT REPORTING
We operate in only one business segment.
ADOPTED AND NEW ACCOUNTING POLICIES
On January 1, 2001, we adopted Statement of Financial Accounting Standards 133 "Accounting for Derivative Instruments and Hedging Activities" which requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in fair value be recorded currently in net income unless specific hedge accounting criteria are met. The definition of derivative contracts has also been expanded to include contracts that require physical delivery of oil and gas if the contract allows for net cash settlement. We do not utilize any derivative instruments that fall under the criteria defined in the accounting standard and therefore the adoption of this statement did not have any effect on our reported financial statements or disclosures.
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations" will be effective for years beginning after June 15, 2002. 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 period in which the asset is first placed in service. Currently we accrue the estimated liability for dismantlement and abandonment over the life of the property using a unit of production method. Because of this new standard, effective January 1, 2003, we must increase both our recorded assets and liabilities by the estimated cost of the ultimate asset retirement obligation. For properties owned at December 31, 2001, we estimate that amount to be $10.6 million. We will then discount the amount to present value, and on a periodic basis record the accretion of discount. We will also amortize the cost into depletion, depreciation, and amortization expense. The charges to the income statement will not be materially different under this standard as compared to our present method.
In August 2001, Financial Accounting Standards Board issued the Statement of Financial Accounting Standards No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" which supercedes Statement of Financial Accounting Standards No. 121 "Accounting for Impairment of Long-Lived Assets." The Statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. The statement is effective for periods beginning after December 15, 2001. We do not believe that the adoption of this statement will have a material effect on our balance sheet or income statement.
GENERAL AND ADMINISTRATIVE EXPENSES
We report our general and administrative expenses net of reimbursed overhead costs that we allocate to working interest owners of the oil and gas properties that we operate.
INCOME TAXES
Income tax expense or benefit includes both the current income taxes and deferred income taxes. Current income tax expense or benefit equals the amount calculated on our income tax return for that year. Deferred income tax expense or benefit equals the change in the net deferred income tax asset or liability from the beginning of the year to the end of the year. We determine the amount of our deferred income tax asset or liability by multiplying the enacted tax rate by the temporary differences, net operating or capital loss carry-forwards plus any tax credit carry-forwards. The tax rate used is the effective rate applicable for the year in which we expect the temporary differences or carry-forwards to reverse. A valuation allowance offsets deferred income tax assets that are not expected to reverse in future years.
INCOME PER COMMON SHARE
We compute basic income per share by dividing net income by the weighted average number of common shares outstanding for the period. Diluted income per share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock or resulted
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
in the issuance of common stock that then shares in the net income of the company. The following table presents our calculation of basic and diluted income per share.
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(1) Non dilutive in 1999.
NOTE 2 -- OIL AND GAS PROPERTIES
The following table summarizes the capitalized costs on our oil and gas properties, all of which are located in the United States.
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table presents a summary of our oil and gas expenditures during the last three years.
We recognized impairment expenses as follows in the table below:
The impairment of unproved properties for each of the three years primarily resulted from the actual or impending forfeiture of leaseholds.
The impairment expense on proved properties for 2001 primarily resulted from insufficient future net cash flows based on the proved developed reserves as determined by our independent oil and gas engineers. In order to determine the amount of impairment on certain properties, we used NYMEX 12 month strip prices adjusted for location and basis differences for our estimate of the future prices and escalated both the prices and the costs at 3% per year. Three proved properties in the offshore Gulf of Mexico accounted for $8.7 million and one proved property in South Texas accounted for $1.3 million of the total $10.0 million. The impairment expense on proved properties for 2000 resulted from insufficient oil and gas reserves on one small property in Alabama and in 1999 included $852,000 for a platform located on Main Pass 262 in the Gulf of Mexico.
NOTE 3 -- NOTES PAYABLE AND OTHER LONG-TERM PAYABLES
CONVERTIBLE NOTES
During 2001, holders of $5.785 million face amount of the 8 1/4% convertible notes due December 1, 2002, converted their notes into common stock at the prescribed conversion ratio of one share of common stock for each $11.00 of principal amount of notes. We redeemed the remaining $95,000 of the notes for cash at a call price of 101.65%.
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
BANK CREDIT FACILITY
As of December 31, 2001, our amended credit facility of $150.0 million has a borrowing base of $75.0 million. The following schedule reflects certain information about the line of credit for the last two years.
We pledged our oil and gas properties as collateral for this line of credit. We accrue and pay interest at varying rates based on premiums ranging from 1.5 to 2.25 percentage points over the London Interbank Offered Rates. Interest only is payable quarterly through May 3, 2004, at which time the line expires and all principal becomes due, unless the line is extended or renegotiated.
The most significant financial covenants in the line of credit include, among others, maintaining a minimum current ratio of 1.0 to 1.0, a minimum tangible net worth of $85.0 million plus 50% of future net income and 100% of any non-redeemable preferred or common stock offerings, and interest coverage of 3.0 to 1.0.
The banks review the borrowing base semi-annually and may increase or decrease the borrowing base at their discretion relative to the new estimate of proved oil and gas reserves. The next redetermination is scheduled for April 2002.
OTHER
Other long-term payables include a note payable to the Minerals Management Service and certain vendor financing arrangements.
FAIR VALUE OF INDEBTEDNESS
We estimate that the fair value of our long-term indebtedness, including the current maturities of such obligations, is approximately $78.0 million at December 31, 2001 and $34.0 million at December 31, 2000. We based the fair value on broker estimates for our convertible notes and on current rates available for our bank debt. The book value of our other long-term indebtedness approximates fair value.
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4 -- COMMITMENTS AND CONTINGENT LIABILITIES
We lease approximately 17,000 square feet of office space in Dallas Texas. The non-cancelable operating lease expires in April 2008. The following table reflects our rent payments for the past three years and the commitment for the future minimum rental payments.
We have no material pending legal proceedings.
NOTE 5 -- COMMON STOCK, PREFERRED STOCK AND DIVIDENDS
In 1998, we increased the number of authorized common stock shares to 100.0 million and authorized 25.0 million shares of "blank check" preferred stock. The par value of the common stock and preferred stock is $0.01 per share. The board of directors can approve the issue of multiple series of preferred stock and set different terms, voting rights, conversion features, and redemption rights for each distinct series of the preferred stock.
We have reserved approximately 4.0 million shares of common stock for our stock option plan and for our non-employee director stock purchase plan, which are discussed in more detail in Note 7 -- Employee and Director Benefit Plans. Dividend payments are currently prohibited by our line of credit agreement.
NOTE 6 -- SETTLEMENTS EXPENSE
On May 22, 2001, we settled the litigation with Phillips Petroleum Company and acquired Phillips' Net Profits Interest in South Pass block 89, offshore Louisiana. We paid $21.25 million cash and issued 1,189,344 shares of our common stock as consideration for the settlement and assignment of the net profits interest.
Of the total $42.5 million settlement, we had previously recorded $20.2 million as an accrued liability. We recorded $12.3 million of the remaining $22.3 million as additional settlement expense and capitalized $10.0 million as the cost for our purchase of the net profits interest. In addition, we charged the remaining $1.2 million deferred net profits expense related to a royalty settlement in 2000 to the settlement expense.
We agreed to purchase up to 100,000 shares per week from Phillips at $17.867 per share in the event that Phillips was unable to sell the shares at or above that price. Subsequently, Phillips sold 33,900 shares on the open market, and we purchased the remaining 1,155,444 shares at a total cost of $20.6 million.
The Minerals Management Service is the grantor of all leases in the federal waters offshore Louisiana. When production is established, they collect a 16.67% royalty from all hydrocarbons produced from the lease. After a routine audit of our royalty payments, the Minerals Management Service issued orders to pay additional royalty on three separate claims regarding our South Pass 89 lease complex. We settled all three of those claims in 2000 for a total of $5.4 million.
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Two individuals owned a combined 5.8824% in two of our subsidiaries, CKB Petroleum, Inc. and CKB & Associates, Inc. The two subsidiaries were acquired when we merged with S-Sixteen Holding Company in December 1998. The minority interest liability reflects their percentage of the total combined equity in the two subsidiaries. In February 2000, we reached an agreement to settle the litigated claims by the minority interest owners and purchased their minority interest in the two subsidiaries. In connection with the settlement of their lawsuit, we recorded $442,000 as a settlement expense in December 1999.
NOTE 7 -- EMPLOYEE AND DIRECTOR BENEFIT PLANS
STOCK OPTION PLAN
A committee that includes two or more outside non-employee directors administers the 1997 Stock Option Plan. The committee has the discretion to determine the participants, the number of shares granted to each person, the purchase price of the common stock covered by each option, and most other terms of the option. Options granted under the plan may be either incentive stock options or non-qualified stock options. The committee may issue options for up to 3.75 million shares of common stock, but no more than 937,500 shares to any individual. Forfeited options are available for future issuance.
A summary of our stock option plans as of December 31, 2001, 2000, and 1999, and changes during the years ending on those dates is presented below:
The options outstanding at December 31, 2001 have a weighted-average remaining contractual life of 7.62 years and an exercise price ranging from $2.75 to $16.78 per share.
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The table below reflects the effect on our net income or loss if we recorded the estimated compensation costs for the stock options using the estimated fair value as determined by applying the Black-Scholes option pricing model.
The fair value of each option grant for the years ended December 31, 2001, 2000, and 1999 is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions:
NON-EMPLOYEE DIRECTOR STOCK PURCHASE PLAN
The non-employee director stock purchase plan allows the non-employee directors to receive their directors' fees in shares of restricted common stock instead of cash. The number of shares received will be equal to 150% of the cash fees divided by the closing market price of the common stock on the day that the cash fees would otherwise be paid. The director cannot transfer the common stock until one year after issuance or the termination of a director resulting from death, disability, removal, or failure to be nominated for an additional term. The director can vote the shares of restricted stock and receive any dividend paid.
PENSION PLAN
Remington and CKB Petroleum, Inc. each have a noncontributory defined benefit pension plan. The retirement benefits available are generally based on years of service and average earnings. We fund the plans with annual contributions at least equal to the minimum funding provisions of the Employee Retirement Income Security Act of 1974, as amended, but no more than the maximum tax deductible contribution
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
allowed. Plan assets consist primarily of equity and fixed income securities. The following table sets forth the reconciliation of the benefit obligation, plan assets, and funded status for the pension plans.
The net periodic pension cost recognized in our income statements include the following components:
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONTINGENT STOCK GRANT
In June 1999, the Board of Directors approved a contingent stock grant to our employees and directors. In order for the grant to become effective, the price of our stock had to increase from $4.19 per share to a trigger price of $10.42 per share and close at or above $10.42 per share for 20 consecutive trading days.
On January 24, 2001, the stock price closed above the trigger price for the twentieth consecutive trading day. On that date, we measured the total compensation cost at $8.1 million which was the total number of shares granted multiplied by the market price on that date. We recorded $8.1 million as restricted common stock, $5.7 million as unearned compensation reported as a separate reduction in stockholders' equity on the balance sheet, and $2.4 million as stock based compensation expense. The $2.4 million stock based compensation expense recorded in the first quarter of 2001 included a "catch up" amortization from the date of the grant to the measurement date of the total compensation cost. During the last three quarters of 2001 we amortized an additional $1.0 million. The remaining unearned compensation expenses will be amortized over the next five years as the shares vest. The total compensation expense may decrease if an employee fails to vest because he is no longer employed for any reason other than death, disability, or normal retirement, or if a director no longer serves for any reason other than death.
EMPLOYEE SEVERANCE PLAN, POST RETIREMENT BENEFITS AND POST EMPLOYMENT BENEFITS
Our employee severance plan provides severance benefits ranging from 2 months to 18 months of the employee's base salary if the employee is terminated involuntarily. The plan incorporates the provisions and terms of any individual contract or agreement that an employee may have with the company. Certain of the executive officers have individual employment contracts with the company.
We have never paid postretirement benefits other than pensions and have not obligated ourselves to pay such benefits in the future. Future obligations for postemployment benefits are immaterial. Therefore, we have not recognized any liability for either.
NOTE 8 -- INCOME TAXES
The following table provides a summary of our income tax expense or (benefit):
Total income tax expense (benefit) differs from the amount computed by applying the federal income tax rate to net income (loss) before income taxes as follows:
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table reflects the significant components of our deferred tax asset.
The unused federal income tax operating loss carry-forward of $22.2 million will expire during the years 2007 through 2020 if not utilized sooner.
NOTE 9 -- OIL AND GAS RESERVES AND PRESENT VALUE DISCLOSURES (UNAUDITED)
The estimates of oil and gas reserves were prepared by the independent engineering and consulting firms of Netherland, Sewell & Associates, Inc. for the years 2001 and 2000 and by Netherland, Sewell & Associates, Inc. and Miller and Lents, Ltd for 1999. The determination of these reserves is a complex and interpretative process that is subject to continued revision as additional information becomes available. In many cases, a relatively accurate determination of reserves may not be possible for several years due to the time necessary for development drilling, testing and studies of the reservoirs.
The quantities of proved oil and gas reserves presented below 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 can commercially recover using current prices, costs, existing regulatory practices and technology. Therefore, any changes in future prices, costs, regulations, technology or other unforeseen factors could significantly increase or decrease proved reserve estimates. The following table presents our net ownership interest in proved oil and gas reserves.
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The proved developed and undeveloped reserves and standardized measure of discounted future net cash flows associated with South Pass block 89 were burdened by a 33% net profits interest for the years ended December 31, 2000 and 1999. In May 2001, we purchased the net profits interest from Phillips Petroleum. The reserves included in the above table for the two previous years include our full net ownership interest without any reduction for the net profits interest. We treated the net profit interest as an operating expense rather than a reduction in proved reserves.
The following tables represent value-based information about our proved oil and gas reserves. The standardized measure of discounted future net cash flows result from the application of specific criteria applicable to the value-based disclosures of all oil and gas reserves in the industry. Due to the imprecise nature of estimating oil and gas reserve quantities and the uncertainty of future economic conditions, we cannot make any representation about interpretations that may be made or what degree of reliance that may be placed on this method of evaluating proved oil and gas reserves.
We compute future cash revenue by multiplying the year-end commodity prices or contractual pricing if applicable, by the proved oil and gas reserves. Future production and development costs include the estimated costs to produce or develop the proved reserves based primarily on historical costs. We calculated the future net profits expense by multiplying the net profit percentage by the future revenue less production and development costs on South Pass block 89. Future income tax expense was determined by applying the current tax rate to the estimated future net cash flow from all properties. Finally, we discounted the future net cash flow, after tax, by 10% per year to arrive at the standardized measure of discounted future net cash flows presented below.
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes the principal sources of change in the standardized measure of discounted future net cash flows from year to year.
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 10 -- QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
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(1) Net sales include only oil and gas sales revenue.
(2) Gross profit is net sales less operating costs, transportation expense, net profits expense, exploration expense, depreciation, depletion and amortization, and impairment of oil and gas properties.
(3) Net income during the third quarter of 2000 includes a $12.5 million gain on sale of certain South Texas properties.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The following information relates to the members of our board of directors or executive officers during 2001. Each director holds office until his successor is elected and qualified or until his resignation or removal. Executive officers hold their respective offices at the pleasure of the board of directors.
DON D. BOX Age 51
Positions with us: - - Director since March 1991 - - Executive Vice President since October 1997 - - Chairman of the Board January 1994-October 1997 - - Chief Executive Officer August 1996-October 1997 - - President August 1996-March 1997
Positions with our affiliates: - - CKB Petroleum, Inc. - Vice President since September 1997 - Director August 1982-September 1997 - President August 1982-September 1997 - - CKB & Associates, Inc. - Vice President since May 1981 - Director May 1981-September 1997 - - S-Sixteen Holding Company - Director December 1981-September 1997 - President December 1981-February 1996, April 1997-September 1997 - Vice President February 1996-April 1997, September 1997-December 1998
Outside directorships - - Authoriszer, Inc.
Education - - Bachelor of Arts-University of Pennsylvania - - Bachelor of Science in Economics-The Wharton School of the University of Pennsylvania - - Masters of Business Administration-Southern Methodist University
JOHN E. GOBLE, JR., CPA Age:
Positions with us: - - Director since April 1997 - - Member-Audit Committee
Employment: - - Byrd Investments-Investment and financial advisor since 1986
Outside Directorships: - - Miracle of Pentecost Foundation
Education: - - Bachelor of Business Administration-Southern Methodist University
WILLIAM E. GREENWOOD Age: 63
Positions with us: - - Director since April 1997 - - Member-Audit Committee - - Member-Compensation Committee
Employment: - - Consultant since 1995 - - Director and Chief Operating Officer-Burlington Northern Railroad Corporation from 1990 until 1994
Outside Directorships: - - Iowa-Pacific Corp. - - Transport Dynamics, Inc. - - President-Mendota Museum and Historical Society
Education: - - Bachelor of Science-Marquette University
DAVID H. HAWK Age: 57
Positions with us: - - Director since September 1997 - - Chairman of the Board since October 1997 - - Member-Executive Committee
Employment: - - J.R. Simplot Company-Director, Energy Natural Resources since 1984 - - Previously employed with Atlantic Richfield Company and Tenneco Inc. as an Exploration Geologist - - Prior executive positions with IGC Production Company, Sundance Oil Company and Horn Resources Corporation
Education: - - Bachelor of Science in Geology and Distinguished Graduate Medalist-University of Idaho - - Master of Science in Geology-University of Oklahoma
JAMES ARTHUR LYLE, CCIM Age:
Current positions with us: - - Director since September 1997 - - Member-Compensation Committee
Employment: - - Owner-James Arthur Lyle & Associates, Inc., a commercial, industrial and investment real estate firm, since 1976
Outside directorships: - - Director, Chief Operating Officer and President since 1984-Hueco Mountain Estates, Inc., a 10,500 acre multi-use real estate development located in El Paso County, Texas
Education: - - Bachelor of Science in Industrial Management-Georgia Institute of Technology
DAVID E. PRENG Age: 55
Position with us: - - Director since April 1997 - - Chairman-Compensation Committee
Employment:
- - Chief Executive Officer and President since 1980-Preng and Associates, Inc., an international executive search firm specializing in the energy industry
Outside directorships: - - Director-Community National Bank - - Fellow-Institute of Directors
Education: - - Bachelor of Science in Business Administration-Marquette University - - Master of Business Administration-DePaul University
THOMAS W. ROLLINS Age: 71
Positions with us: - - Director since July 1996 - - Member-Executive Committee
Employment: - - Chief Executive Officer since 1985-Rollins Resources, a natural gas and oil consulting firm - - Previously held executive positions and/or directorships with Shell Oil Company, Pennzoil Company, Florida Gas Transmission Company, Pogo Producing Company, Magma Copper Company and Felmont Oil Corporation.
Outside directorships: - - Director-Pheasant Ridge Winery - - Director-The Teaching Company - - Director-Nature Conservancy of Texas
Education: - - Geological Engineering Degree and Distinguished Graduate Medalist-The Colorado School of Mines
ALAN C. SHAPIRO Age: 56
Positions with us: - - Director since May 1994 - - Chairman-Audit Committee
Employment: - - The Ivadelle and Theodore Johnson Professor of Banking and Finance in the Department of Finance and Business Economics, Marshall School of Business, University of Southern California, since 1992 - - Previously Chairman of the Department of Finance and Business Economics, University of Southern California, 1993-1998 - - Frequent consultant and expert witness to business and government
Publications: - - Multinational Financial Management, a best selling textbook used in MBA programs worldwide - - Numerous other books and articles
Education: - - Bachelor of Arts in Mathematics-Rice University - - Ph.D. in Economics-Carnegie Mellon University
JAMES A. WATT Age: 52
Positions with us: - - Chief Executive Officer since February 1998 - - President since March 1997 - - Director since September 1997 - - Member-Executive Committee
Positions with our Affiliates: - - CKB Petroleum, Inc. - Director and President since January 1999 - - CKB & Associates, Inc. - Director and President since January 1999
Previous employment highlights: - - Vice President/Exploration-Seagull E&P, Inc., 1993-1997 - - Vice President/Exploration and Exploitation-Nerco Oil & Gas, Inc., 1991-1993
Outside Directorships: - - Director -- Suzuki Institute of Dallas
Education: - - Bachelor of Science in Physics-Rensselaer Polytechnic Institute
ROBERT P. MURPHY Age: 43
Positions with us: - - Chief Operating Officer since October 2000 and Senior Vice President/Exploration & Production since July 1999 - - Vice President/Exploration, January 1998-June 1999
Previous employment: - - Director-Cairn Energy USA, Inc., May 1996-November 1997 - - Vice President-Exploration-Cairn Energy USA, March 1993-January 1998 - - Exploration Geologist-Cairn Energy USA, 1990-March 1993 - - Exploration Geologist-Enserch Exploration, 1984-1990
Education: - - Bachelor of Science in Geology-The University of Texas at Austin - - Master of Science in Geosciences-The University of Texas at Dallas
STEVEN J. CRAIG Age: 50
Positions with us: - - Senior Vice President/Planning and Administration since April 1997
Positions with our affiliates: - - CKB Petroleum, Inc. - Director and Vice President since January 1999 - Vice President and Assistant Treasurer, March 1997-October 1997 - Director, March 1997-August 1997 - - CKB & Associates, Inc. - Director and Vice President since January 1999 - Vice President and Assistant Treasurer, March 1997-October 1997 - Director, March 1997-August 1997 - - S-Sixteen Holding Company - Vice President and Assistant Treasurer, March 1997-October 1997 - Director, March 1997-August 1997
Education: - - Bachelor of Arts in Economics-Southern Methodist University - - Master of Business Administration in Finance and Quantitative Analysis-Southern Methodist University
J. BURKE ASHER Age: 61
Positions with us: - - Vice President/Finance since December 1997 - - Secretary since October 1996 - - Chief Accounting Officer, September 1996-December 1997
Positions with our affiliates: - - CKB Petroleum - Treasurer and Assistant Secretary since March 1997 - Director, March 1997-April 1997 - - CKB & Associates - Treasurer and Assistant Secretary since March 1997 - Director, March 1997-August 1997 - - S-Sixteen Holding Company - Treasurer and Assistant Secretary, March 1997-December 1998 - Director, March 1997-August 1997
Education: - - Bachelor of Science in Economics-The Wharton School of the University of Pennsylvania
EDWARD V. HOWARD, CPA Age: 39
Positions with us: - - Vice President/Controller since March 1992 - - Assistant Secretary since October 1997
Education: - - Bachelor of Business Administration-West Texas State University
Except for Mr. Rollins' consulting practice, no director has a significant personal interest in the exploration, development or production of oil and gas. Mr. Rollins is required to abstain on matters in which there may be a conflict of interest between us and one of his clients.
NEW EXECUTIVE OFFICER
Effective January 1, 2002, Gregory B. Cox, age 48, was appointed Vice President/Exploration. Mr. Cox joined Remington in 1997 as Exploration Manager. He received his Bachelor of Science in Geology in 1980 from the University of Texas at Arlington. Prior to joining us, he was employed as a geologist and explorationist with several oil and gas exploration and production companies including Getty Oil Company, Enserch Exploration and Cairn Energy USA. On March 18, 2002, he owned none of our Common Stock, but held 63,666 employee stock options exercisable within 60 days.
LITIGATION INVOLVING DIRECTORS AND EXECUTIVE OFFICERS
We know of no reportable litigation involving the directors or executive officers.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Based solely upon the company's review of Forms 3, 4, and 5 received by us for 2001, all persons required by Section 16(a) of the Securities Exchange Act of 1934 ("the Act") to file such forms complied with Section 16(a) of the Act with the following exceptions: James A. Watt filed one late Form 4 reporting one transaction. J. R. Simplot filed two late Forms 4 reporting two transactions on each.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
The following table summarizes the compensation paid by the company during 2001, 2000, and 1999 to the company's Chief Executive Officer and its four most highly compensated executive officers, other than the Chief Executive Officer, whose total annual salary and bonus in 2001 exceeded $100,000.
SUMMARY COMPENSATION TABLE
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(1) No amount is included, as it is less than 10% of the total salary and bonus of the individual for the year.
(2) At December 31, 2001, Mr. Watt held 3,000 restricted shares of common stock with a value of $51,900. The total number of restricted shares awarded effective March 17, 1997, was 15,000, which vest 20% per year from the effective date. If any dividends are paid to holders of common stock, Mr. Watt's restricted shares will be entitled to receive dividends.
(3) These amounts are for group term life insurance premiums paid by the company.
See "Change in Control Arrangements and Employment Contracts" below.
LONG TERM STOCK BASED INCENTIVE PROGRAMS
STOCK OPTIONS
We have stock option plans for our employees and directors because we believe these options act as both an incentive and a reward for the long-term growth of our company. The core of our stock option program is the 1997 stock option plan. Both directors and employees are eligible for options under this plan. Significant attributes of the 1997 plan include the following:
- Administered by the Compensation Committee of our board of directors.
- Subject to adjustments, up to 3,750,000 shares of our common stock may be issued under the plan.
- Up to 25% of issuable shares may be issued to any single individual.
- Both qualified incentive and non-qualified options may be issued.
- The plan terminates December 4, 2007.
The importance of whether an option is granted as a qualified incentive option or a non-qualified option is mainly tax driven. If an option is an incentive option, the exercise price can be no less than the fair market value on the date of grant. Additional details concerning the 1997 stock option plan are contained in the plan itself. For a copy of the plan, call Investor Relations at (214) 210-2650.
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(1) We determined these values using the Black-Scholes option pricing model with the following assumptions: stock price volatility of 62.68%; interest rate based on the yield to maturity of a 10-year Treasury security; exercise in the tenth year; and a dividend rate of zero. We made no adjustments for nontransferability or risk of forfeiture. Our use of this model does not constitute an endorsement or an acknowledgment that such model can accurately determine the value of options. No assurance can be given that the actual value, if any, realized by an executive upon the exercise of these options will approximate the estimated values calculated by using the Black-Scholes model.
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(1) Computed as the number of securities multiplied by the difference between the option exercise prices and the closing price of our common stock on December 31, 2001.
CONDITIONAL STOCK GRANTS
In 1999, the directors approved awards of stock to employees and directors totaling 679,937 shares of our common stock. The number of shares awarded to each employee and director is based on the employee's annual base salary as of June 17,1999, or, in the case of non employee directors, $100,000, divided by $4.19, which was the closing stock price on June 17, 1999. In order for the grant to be effective, our stock had to close above a trigger price of $10.42 for 20 consecutive trading days. This trigger was achieved on January 24, 2001. Recipients of the grant must remain an employee or a director during the vesting schedules in order to receive the shares. Employees and directors individually elected one of two vesting periods. The first vesting schedule has 50% percent of the grant vesting on June 17, 2002, with an additional 25% vesting on June 17, 2003, and the final 25% vesting on June 17, 2004. 267,502 shares are subject to the this vesting schedule. The second vesting option has 20% of the grant vesting on January 17, 2002, with an additional 20% vesting on each successive January 17 through 2006. 395,080 shares are subject to the second vesting schedule. While 679,937 shares of restricted stock were granted in 1999, as of March 12, 2001, 662,592 shares are subject to the grant because a director voluntarily surrendered 23,880 shares, and a new employee was granted
6,535 shares. The number of shares subject to the grant may decrease to the degree that participants fail to remain with us during the vesting period. In the event of a participant's death while employed or serving as a director with us, or reaching the retirement age of 65 or receiving long term disability benefits while employed with us, the grant becomes 100% vested. In addition, the grants can become 100% vested upon a change of control.
PENSION PLANS
Our defined benefit pension plans provide retirement and other benefits to eligible employees upon reaching the "normal retirement age," which is age 65 or after 3 years of service (5 years if employment terminated prior to January 1, 2001), if later. Directors who are not also employees of the company are not eligible to participate in the plans. Employees are eligible to participate on January 1 following the completion of six months of service or the attainment of age 20 1/2, if later. Additional provisions are made for early or late retirement, disability retirement and benefits to surviving spouses. At normal retirement age, an eligible employee will receive a monthly retirement income equal to 35% of his or her average monthly compensation during the three consecutive calendar years in the prior 10 years which provide the highest average compensation, plus 0.65% of such average compensation in excess of the amount shown in the Social Security Covered Compensation Table (as published annually by the Internal Revenue Service) multiplied by his or her years of service, limited to 35 years. If an employee terminates employment (other than by death or disability) before completion of three years of service (five years if employment terminated prior to January 1, 2001), no benefits are payable. If an employee terminates employment after three years of service (five years if employment terminated prior to January 1, 2001), the employee is entitled to all accrued benefits. The following table illustrates the annual pension for plan participants that retire at "normal retirement age" in 2001:
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(1) As of December 31, 2001, the Internal Revenue Code does not allow qualified plan compensation to exceed $170,000 or the benefit payable annually to exceed $140,000. The Internal Revenue Service will adjust these limitations for inflation in future years. When the limitations are raised, the compensation considered and the benefits payable under the pension plans will increase to the level of the new limitations or the amount otherwise payable under the pension plans, whichever amount is lower.
(2) Subject to the above limitations, compensation in this table is generally equal to all of a participant's cash compensation paid in a fiscal year (the total of Salary, Bonus, and Other Annual Compensation in the Summary Compensation Table). Average compensation in this table is the average of a plan participant's compensation during the highest three consecutive years out of the prior 10 years.
(3) The estimated credited service at December 31, 2001, for the executive officers shown in the Summary Compensation Table on page 43 is as follows: James A. Watt (5 years), Robert P. Murphy (4 years), Steven J. Craig (7 years), J. Burke Asher (5 years), and Edward V. Howard (11 years).
(4) The normal form of payment is a life annuity for a single participant or a 50% joint and survivor annuity for a married participant. Such benefits are not subject to a deduction for Social Security or other offset amounts.
COMPENSATION OF DIRECTORS
- Only non-employee directors are compensated for board service
- Compensation includes:
- Annual retainer of $20,000
- $1,000 per board meeting attended (Chairman of the Board receives extra $250 per board meeting attended)
- Unless surrendered, eligible for stock grant (see discussion of grant on page 44)
- Committee meeting fee of $750 per meeting attended by committee members or $1,000 for the committee chairman per meeting attended, if on a different day than a full board meeting
- Directors are entitled to reimbursement of company related out-of-pocket expenses
- We provide directors and officers insurance and indemnification to the full extent allowed by law
- All or part of a director's board compensation may be received in company stock in accordance with the Non-Employee Director Stock Purchase Plan
- There were six board meetings in 2001
- All directors attended at least 75% of the meetings
- During 2001, we paid an entity controlled by director David E. Preng $2,000 for consulting fees.
NON-EMPLOYEE DIRECTOR STOCK PURCHASE PLAN
- This plan was adopted December 4, 1997
- Each non-employee director may, once a year, elect to receive all or part of his board compensation in our common stock
- The number of shares received equals 150% of the cash amount of compensation divided by the closing market price of our common stock on the day the cash fees would be payable
- Shares received under this plan may not be transferred for one year after issuance
- Shares may be transferred earlier than one year based on a director's death, disability or departure from the board
- During the restricted transfer period the director may vote the stock and receive any dividends
- The board may terminate this plan at any time
- Shares received under plan for 2001:
CHANGE IN CONTROL ARRANGEMENTS AND EMPLOYMENT CONTRACTS
All of our full-time regular employees are covered by a severance plan that we adopted in 1997. Under this plan, if an employee is involuntarily terminated, as that term is defined in the plan, the employee will be entitled to a payment of between two months base pay and eighteen months base pay depending on the employee's job and years of experience. If an employee voluntarily quits, is terminated for cause as defined in the plan, dies, leaves due to a disability for which benefits are payable, or the termination is expected to be of short duration, the employee is not eligible for payment under the plan. In addition, under certain circumstances, a change in control could cause immediate vesting and triggering of stock options and contingent stock grants. If the contingent stock grants were vested by a change in control, it would result in the issuance of a maximum aggregate of 662,592 shares to directors and employees.
EMPLOYMENT AGREEMENTS
We have employment agreements with James A. Watt, Robert P. Murphy, Steven J. Craig, and J. Burke Asher. The most significant terms of such agreements are summarized below:
James A. Watt
- Term of three years from January 31, 2000, subject to single year extensions by mutual agreement
- Base salary of $270,000 a year, subject to discretionary increases
- Eligible to receive discretionary performance bonus (targeted at 70% of base salary)
- If terminated prior to a change in control, without cause, he receives his salary plus a pro rata bonus
- He receives 2.99 times the sum of his base salary plus his target bonus if he is terminated within 24 months of a change in control, other than for death, disability or cause, or he leaves for good reason within the 24 month period
Robert P. Murphy
- Term of three years from September 30, 1999, subject to single year extensions by mutual agreement
- Base salary of $175,000 a year, subject to discretionary increases
- Eligible to receive discretionary performance bonus (targeted at 50% of base salary)
- If terminated prior to a change in control, without cause, he receives his salary plus a pro rata bonus
- He receives 2.99 times the sum of his base salary plus his target bonus if he is terminated within twelve months of a change in control, other than for death, disability or cause, or he leaves for good reason within the twelve month period
Steven J. Craig and J. Burke Asher
- Term of two years from September 30, 1999, subject to single year extensions by mutual agreement
- Base salary of $114,200 (Mr. Craig) and $109,200 (Mr. Asher), subject to discretionary increases
- Eligible to receive discretionary performance bonus (targeted at 20% of base salary)
- Severance payments similar to Robert Murphy's, except that Mr. Craig and Mr. Asher each receive 2 times the sum of his annual salary plus target bonus in connection with leaving employment within twelve months of a change in control
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION IN COMPENSATION DECISIONS
David E. Preng, William E. Greenwood, and James Arthur Lyle served on the compensation committee in 2001. No executive officer or employee serves on the compensation committee of the board. None of our executive officers serves on the board of directors of any other entity that has an executive officer serving on our board.
BOARD COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
We believe that employing and retaining highly qualified and high performing executive officers is vital to our achievement of long-term business goals. To this end, the Compensation Committee of the board of directors (the "Committee") developed an executive compensation program which is designed to attract and retain such officers.
The philosophy is to develop a systematic, competitive executive compensation program which recognizes an executive officer's position and responsibilities, takes into account competitive compensation levels payable within the industry by similarly sized companies, and reflects both individual and company performance.
The executive compensation program developed by the Committee is composed of the following three elements: (i) a base salary, (ii) a performance-based annual cash incentive (short-term), and (iii) a stock-based incentive (long-term). Under this program, short-term and long-term incentives are "at risk" and are based on performance of the company versus defined goals.
The Committee compiles data reflecting the compensation practices of a broad range of organizations in the oil and gas industry that are similar to us in size and performance. For both the base salary and annual cash incentives portions of executive compensation discussed below, the Committee adopted a philosophy of paying the executive officers at a level that is competitive and within the ranges reflected by the data compiled.
BASE SALARIES
Base salary is the portion of an executive officer's total compensation package which is payable for performing the specific duties and assuming the specific responsibilities defining the executive's position with the company. The Committee's objective is to provide each executive officer a base salary that is competitive at the desired level.
ANNUAL CASH INCENTIVES
The Committee developed a performance-based annual cash incentive plan covering the executive officers and top managers. The objectives in designing the plan are to reward participants for accomplishing objectives which are generally measurable and increase shareholder value. Under the annual cash incentive plan, the Committee has established a "target" cash incentive award for each executive officer (including the Chief Executive Officer) that is payable based mostly upon the company's achieving certain performance targets and, to a lesser extent, for achieving highly challenging individual performance objectives. The performance targets are increasing reserves and production; controlling finding, development, and production costs; and achieving an overall return on capital; all of which are competitive with a peer group of oil and gas companies. The committee also determined that award levels under the plan should be fiscally prudent.
LONG-TERM STOCK-BASED INCENTIVES
We maintain a stock option plan for officers and other employees. The philosophy is to award stock options to selected plan participants based on their levels within the company and upon individual merit. The plan is to grant stock options which are competitive within the industry for other individuals at the employee's level and which provide the employee a meaningful incentive to remain with the company, to increase performance, and to focus on achieving long-term increases in shareholder value. Other factors the Committee considers in granting stock options include the employee's contributions toward achieving the company's long-term objectives, such as reserve replacements and acquisitions, as well as the employee's contributions in achieving the company's short-term and long-term profitability targets.
COMPENSATION COMMITTEE
David E. Preng William E. Greenwood James Arthur Lyle
PERFORMANCE GRAPH
The following performance graph compares the performance of all classes of our common stock to the Nasdaq indices of United States companies and to a peer group comprising Nasdaq companies listed under the Standard Industrial Classification Codes 1310-1319 for the company's last five fiscal years. Such industrial codes include companies engaged in the oil and gas business. The graph assumes that the value of an investment in our common stock and in each index was $100 at December 31, 1996, and that all dividends were reinvested.
(PERFORMANCE GRAPH)
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(1) The last day of trading for ROILA and ROILB was December 24, 1998. Effective at the opening of trading on December 28, 1998, both former classes of stock were replaced by a new single class of voting common stock (ROIL). The values shown above as of December 31, 1998,1999, and 2000 for ROILA give effect to the 1.15:1 exchange ratio that the former holders of ROILA received in the exchange for the new class of common stock, and the 1:1 exchange ratio that the former holders of ROILB received in the exchange for the new class of common stock.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
As of March 18, 2001, the following persons held shares of the company's common stock in amounts totaling more than 5% of the total shares of common stock outstanding. This information was furnished to us by such persons or statements filed with the Commission.
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(1) Mr. J.R. Simplot is the trustee and beneficiary of the J.R. Simplot Self Declaration of Revocable Trust, an inter vivos revocable trust. The Trust is the manager of JRS Investments, L.L.C. which is the sole holder of the 1% general partnership interest of JRS Properties III, LP ("JRS III"). In addition, the trust holds the 99% limited partnership interest in JRS III. Included in shares of common stock beneficially owned by Mr. Simplot are all of the following, of which Mr. Simplot may be deemed a beneficial owner: 2,785,028 shares owned by JRS III; 2,845,000 shares owned by the Trust; and 1,000 shares owned jointly by Mr. Simplot and his spouse.
OWNERSHIP OF MANAGEMENT
The number of shares of the company's common stock beneficially owned as of March 18, 2001, by directors of the company, each officer listed in the compensation table on page 43, and as a group comprising all directors and executive officers, are set forth in the following table. This information was furnished to the company by such persons.
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* Less than one percent of the outstanding shares.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
A resolution adopted in 1992 by our board of directors authorizes us to enter into a transaction with an affiliate of ours so long as the board of directors determines that such a transaction is fair and reasonable to us and is on terms no less favorable to us than can be obtained from an unaffiliated party in an arms' length transaction.
A long-term receivable in the aggregate amount of $354,000 acquired in the merger reflects CKB Petroleum's claims under Collateral Assignment Split Dollar Insurance Agreements among CKB Petroleum and Don D. Box and two of his brothers.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) Documents filed as part of this report:
1. Financial Statements included in Item 8:
(i) Independent Auditors' Report
(ii) Consolidated Balance Sheets as of December 31, 2001 and 2000
(iii) Consolidated Statements of Income for years ended December 31, 2001, 2000 and 1999
(iv) Consolidated Statement of Stockholders' Equity for years ended December 31, 2001, 2000 and 1999
(v) Consolidated Statements of Cash Flows for the years ended December 31, 2001, 2000 and 1999
(vi) Notes to Consolidated Financial Statements
(vii) Supplemental Oil and Natural Gas Information (Unaudited) (Included in the Notes to Consolidated Financial Statements)
2. Financial Statement Schedules
Financial statement schedules are omitted as they are not applicable, or the required information is included in the financial statements or notes thereto.
(b) Reports on Form 8-K:
We filed no reports on Form 8-K during the three months ended December 31, 2001.
(c) Exhibits:
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: March 21, 2002 REMINGTON OIL AND GAS CORPORATION
By: /s/ JAMES A. WATT ------------------------------------ James A. Watt President and Chief Executive Officer
Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
DIRECTORS:
Date: March 21, 2002
INDEX TO EXHIBITS
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