REMINGTON OIL & GAS CORP - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-K

(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-11516

REMINGTON OIL AND GAS CORPORATION
(Exact name of registrant as specified in its charter)

DELAWARE 75-2369148
(State or other jurisdiction of incorporation (I.R.S. employer
or organization) Identification No.)

8201 PRESTON ROAD, SUITE 600, DALLAS, TEXAS 75225-6211
(Address of principal executive offices) (Zip code)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(214) 210-2650

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

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

COMMON STOCK, $0.01 PAR VALUE
(Title of Class)

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

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

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [X] No [ ]

The aggregate market value of common stock held by non-affiliates of the
registrant as of the last business day of the registrant's most recently
completed second fiscal quarter, was $401,219,317. On March 27, 2003, the number
of outstanding shares of common stock, $0.01 par value, was 26,399,437.

Registrant's Registration Statement filed on Form S-4 effective November
27, 1998, is incorporated by reference in Part IV of this Form 10-K.

Registrant's Registration Statement filed on Form S-3 effective April 9,
2001, is incorporated by reference in Part IV of this Form 10-K.
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REMINGTON OIL AND GAS CORPORATION

TABLE OF CONTENTS

1

PART I

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

- Website -- www.remoil.net -- Our Annual Reports on Form 10-K, Quarterly
Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to
those reports filed or furnished pursuant to Section 13(a) or 15(d) of
the Securities Exchange Act of 1934 are available on our website under
the link "SEC Filings" as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the Securities
and Exchange Commission.

- 29 employees on December 31, 2002

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

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 the oil and gas and deliver it to the marketplace. Certain
properties require additional drilling to fully develop the oil and gas reserves
and maximize the production from a particular discovery. In order to increase
our oil and gas reserves and production, we continually reinvest our net
operating cash flow into new or existing exploration, development and
acquisition activities.

We share ownership in our oil and gas properties with various industry
partners. We currently operate 66 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 the 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. If a well does find reserves, it is possible that the well will not
produce enough oil or gas to return a profit on the amount invested in the well.
We mitigate exploration and drilling risks by using 3-D seismic data and 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

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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: We compete for:
- - Large integrated oil and gas companies - Operational, technical, and support staff
- - Independent exploration and production - Options and/or leases on properties
companies
- - Private individuals - Sales of oil and gas production
- - Sponsored drilling programs - 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 market prices for
these commodities fluctuate significantly. Purchasers adjust prices for quality,
refined product yield, geographic proximity to refineries or major market
centers, and the availability of transportation pipelines or facilities. Outside
factors beyond our control combine to influence the market prices. Some of the
more critical factors that affect oil and gas commodity prices include the
following:

- 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 production to
be delivered as it is produced. An independent marketing company sells
approximately 91% of our gas production. The revenue from the sale of gas by
this marketing company accounted for approximately 54% of our total oil and gas
revenues in 2002. In addition, we sold approximately 86% of our total oil
production to two companies during the year, which accounted for approximately
36% of our total oil and gas revenues in 2002. Because other customers and
marketers are available, we believe that the loss of any of these companies
would not be detrimental to our operations nor have a material effect on our
revenues.

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

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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 $35.0 million in financial resources that are available to pay
for costs that may be incurred in responding to an oil spill. The Clean Water
Act and its implementing regulations impose restrictions and strict controls on
the discharge of wastes into the waters of the United States, including
discharges of oil, produced water and sand, drilling fluids, drill cuttings, and
other wastes typically generated by the oil and gas industry. Although we
believe that we are in compliance with the requirements of 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. 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 18 and
"Consolidated Financial Statements and Notes to Consolidated Financial
Statements" found on pages 26 through 41. 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.
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LEASEHOLD ACREAGE

Our leasehold acreage of oil and gas properties at December 31, 2002, was
as follows:

PROVED OIL AND GAS RESERVES

Net proved oil and gas reserves at December 31, 2002, as evaluated by
independent reserve engineers, Netherland, Sewell & Associates, Inc., are
summarized below. The quantities of proved oil and gas reserves discussed in
this section include only the amounts which we reasonably expect to recover in
the future from known oil and gas reservoirs under the current economic and
operating conditions. Proved reserves include only quantities that we expect to
recover commercially using current prices, costs, existing regulatory practices
and technology. Therefore, any changes in future prices, costs, regulations,
technology or other unforeseen factors could materially increase or decrease the
proved reserve estimates.

In our 2002 year-end reserve report we used December 31, 2002, West Texas
Intermediate posted price of $28.00 per barrel and a Gulf Coast spot market
price of $4.74 per MMBtu adjusted by property for energy content, quality,
transportation fees, and regional price differentials. We estimated the costs
based on the prior year costs incurred for individual properties or similar
properties if a particular property did not produce during the prior year.

PRODUCING PROPERTIES

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

The decline in the gross number of wells from 2001 to 2002 is attributable
to the sale of 8 wells and the discontinuance of production from a number of
marginal wells.

5

Our offshore Gulf of Mexico properties account for approximately 80% of our
oil production and approximately 92% of our gas production. In addition, total
revenues from offshore Gulf of Mexico oil and gas production during 2002
accounted for approximately 89% of our total oil and gas revenues. We owned
varying working interests (5% to 100%) in 94 offshore Gulf of Mexico blocks at
December 31, 2002, and currently produce from 30 of these blocks. Three
additional blocks are currently under development. We operate 17 of these 33
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 2002 we successfully drilled and completed 11 exploratory wells on 8
different properties in the offshore Gulf of Mexico. In addition, we, as
operator, constructed and installed or will install 6 production platforms and
drilled and completed 2 development wells on 2 different properties.

Our onshore Gulf Coast area properties are principally located in the State
of Mississippi and along the Texas gulf coast. In 2002, these properties
accounted for approximately 20% of our oil production and approximately 8% of
our gas production. We drilled a total of 9 wells on our onshore properties
during 2002 and completed 6 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 1 well (0.25 net) in progress at December 31, 2002, 2
wells (0.80 net) in progress at December 31, 2001, and 2 wells (0.65 net) in
progress at December 31, 2000.

OTHER PROPERTY AND OFFICE LEASE

We own several non-contiguous tracts of land covering approximately 2,500
surface acres in Southern Louisiana and Southern Mississippi. We lease
approximately 17,000 square feet of office space in Dallas, Texas. The lease on
this office space expires in April 2008.

ITEM 3. LEGAL PROCEEDINGS.

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

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

None

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PART II

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

Our common stock trades on the New York Stock Exchange under the symbol
REM. Prior to June 20, 2002, we traded 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 closing price per share for the periods
indicated.

On March 27, 2003, the last reported sales price for our common stock was
$17.16 per share. On that date, there were 726 stockholders of record, including
92 stockholders of record of class A common stock and 107 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 ten years.
Our credit facility agreement prohibits our paying dividends. The determination
of future cash dividends, if any, will depend upon, among other things, our
financial condition, cash flow from operating activities, the level of our
capital and exploration expenditure needs, future business prospects, and
renegotiation of our line of credit.

The remaining information called for by this item relating to "Securities
Authorized for Issuance under Equity Compensation Plans" is reported in Item 12,
Security Ownership of Certain Beneficial Owners and Management, beginning on
page 57 of this report.

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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.
below.

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(1) Financial results for 2002 include an $8.1 million charge for impairment of
long-lived properties. For 2001 financial results include a $13.5 million
charge for the final settlement of the Phillips Petroleum litigation and a
$10.6 million charge for impairment of long-lived properties. The results
for 2000 include $12.5 million gain on sale of certain South Texas
properties, and for 1998 include $49.8 million in other income from the
termination of our gas sales contract and an $18.0 million charge recorded
for the Phillips Petroleum judgment.

(2) The quantities of proved oil and gas reserves discussed in this table
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, and existing regulatory practices and
technology. We base future discounted net revenues on year-end prices. Any
changes in future prices, costs, regulations, technology, or other
unforeseen factors could significantly increase or decrease the proved
reserve estimates.

8

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
$297.7 million in oil and gas properties, found 191.8 Bcfe of proved reserves
and replaced 249% of our production at an average finding and development cost
of $1.55 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 (Mcfe) at the ratio of 1
barrel of oil equals 6 Mcf of gas.

(2) Finding costs include acquisition, development and exploration costs
(including exploration costs such as seismic acquisition costs).

(3) Reserves sold (5.5 Bcfe in 2002 and 14.4 Bcfe in 2000) are excluded from
this calculation.

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 26 through 41 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

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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 drilling success
or failure during the periods.

It is typical for companies that drill a significant number of exploration
wells, as we do, to incur dry hole costs. During the last three years we have
drilled 86 exploration wells, of which 18 were considered dry holes. Our dry
hole costs charged to expense during this period totaled $30.0 million out of
total exploratory drilling costs of $124.8 million. It is impossible to predict
future dry holes; however we estimate that between 20% and 30% of our
exploration wells and exploration drilling costs will be dry holes, based on
past experience.

PROVED RESERVE ESTIMATES

Independent 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.

In our 2002 year-end reserve report we used December 31, 2002, West Texas
Intermediate posted price of $28.00 per barrel and a Gulf Coast spot market
price of $4.74 per MMBtu adjusted by property for energy content, quality,
transportation fees, and regional price differentials. We estimated the costs
based on the prior year costs incurred for individual properties or similar
properties if a particular property did not have production during the prior
year. While we believe that future costs can be reasonably estimated, future
prices are difficult to estimate since the market prices are influenced by
events beyond our control. Current world political events have caused oil prices
to increase significantly since December 31, 2002. Future global economic and
political events will most likely result in significant fluctuations in future
oil prices. In addition, cold weather during the first quarter of 2003 in the
United States has resulted in significant fluctuations in natural gas prices.

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 our net
income; likewise, material upward revisions lower the DD&A per unit and increase
our net income.

IMPAIRMENT OF OIL AND GAS PROPERTIES

Because we account for our proved 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
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on a particular property. We base our assessment of possible impairment using
our best estimate of future prices, costs and expected net cash flow generated
by a property. We estimate future prices based on NYMEX 12 month strips,
adjusted for basis differential and escalate both the prices and the costs for
inflation if appropriate. If these estimates indicate an impairment, we measure
the impairment expense as the difference between the net book value of the asset
and its estimated fair value measured by discounting the future net cash flow
from the property at an appropriate rate. Actual prices, costs, discount rates,
and net cash flow may vary from our estimates.

In 2002, we adopted Statement of Financial Accounting ("SFAS") Standards
No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," which
superseded SFAS 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 adoption of this statement did not have a
material effect on our balance sheet or income statement in 2002.

We recognized impairment expenses during the last three years as follows:

Through December 31, 2001, we assessed the capitalized costs of unproved
properties periodically to estimate whether their value has been impaired below
the capitalized costs, recognizing a loss to the extent such impairment was
indicated. In making these estimations, we considered factors such as
exploratory drilling results, future drilling plans and lease expiration terms.
Effective January 1, 2002, we estimate the amount of individually insignificant
unproved properties which will prove unproductive by amortizing the balance of
our individually immaterial unproved property costs (adjusted by an anticipated
rate of future successful development) over an average lease term. The effect of
this change in estimate was not material to our results of operations.
Individually significant properties will continue to be evaluated periodically
on a separate basis for impairment. We will transfer the original cost of an
unproved property to proved properties when we find commercial oil and gas
reserves sufficient to justify full development of the property. The impairment
of unproved properties for the prior two years primarily resulted from the
actual (due to unsuccessful exploration results) or impending forfeiture of
leaseholds.

We impaired proved properties for 2002 and 2001 because of insufficient
future net cash flows based on the proved developed reserves as determined by
our independent reserve engineers. The properties impaired in 2002, included two
properties in the Gulf of Mexico which totaled $3.5 million and two in the
onshore Gulf Coast which totaled $2.9 million. During 2001, we impaired three
proved properties in the offshore Gulf of Mexico that accounted for $8.7 million
and one proved property in South Texas that accounted for $1.3 million of the
total $10.0 million. The impairment expense on proved properties for 2000
resulted form insufficient oil and gas reserves on a small property in Alabama.

Under the above critical accounting policies our net income can vary
significantly from period to period because 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 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 contingent stock grants to
our employees and directors. In order for the grants 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. Further, the

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trigger price had to be achieved within 5 years of the grant date. This increase
from $4.19 per share to $10.42 per share represented a compound annual rate of
return of 20% for 5 years. On the grant date 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 grants, 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 recorded $3.5 million in 2001 and $1.4 million in 2002 as stock based
compensation expense related to the grants. At December 31, 2002, $3.2 million
of the unearned compensation remained unamortized and will be amortized as the
shares vest during the next three years. 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 ("APB") No. 25 rather than apply an alternative method
permitted by SFAS No. 123. Under APB No. 25, at the time of grant 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 SFAS
No. 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 No. 25 method because we believe that the true cost of
options is reflected under this method. If and when the market price of the
stock exceeds the option exercise price, the potential dilution is reflected in
diluted earnings per share. We believe this dilution is the only true cost of
the option. Further, we believe that also including a theoretical or estimated
dollar expense in the income statement amounts to double-counting in calculating
diluted income per share -- subtracting an amount from the numerator and adding
an amount to the denominator to reflect the same non-cash item.

DEFINED BENEFIT PENSION PLAN

Total assets at fair market value (public market prices for equity and
fixed income mutual funds) for our two defined benefit pension plans were $4.5
million which exceeded the total accumulated benefit obligation as of December
31, 2002. We recorded $396,000 in pension expense and contributed $2.3 million
to the plans during 2002. We have consistently used an 8% estimate for our
long-term rate of return on plan assets and believe that this remains
appropriate based on our plans' historical rates of return and on long-term
historical rates of return for indices similar to our current plan asset
allocation of equities (75%) and fixed income securities (25%). If however, we
reduced the assumed rate of return by 50 basis points, our projected 2003
pension plan expense would increase by approximately $21,000 and our net income
would decrease by approximately $14,000.

The discount rate is another critical assumption in determining pension
liabilities and expenses. We are required to use a rate that approximates the
market rate for high quality, long-term fixed income investments. Accordingly,
we reduced our discount rate assumption from 7.25% in 2001 to 6.5% in 2002. A
lower discount rate increases the calculated present value of benefit
obligations and increases pension expense. If the discount rate decreases by 50
basis points, our projected 2003 pension expense would increase by approximately
$268,000, and our net income would decrease by approximately $174,000.
12

LIQUIDITY AND CAPITAL RESOURCES

The following table summarizes our contractual obligations and commercial
commitments as of December 31, 2002.

On December 31, 2002, our current assets exceeded our current liabilities
by $3.2 million. Our current ratio was 1.07 to 1.00.

Cash flow provided by operations before changes in working capital accounts
for the year ended December 31, 2002, increased by $1.6 million, or 2%, compared
to the prior year. We expect that our cash flow provided by operations before
changes in working capital accounts for 2003 to increase because of higher
projected oil and gas prices, increased production from new properties, and
consistent operating, general and administrative and interest and financing
costs per Mcf equivalent (Mcfe). The table below reflects our revenue and cost
structure on an Mcfe basis for the primary components of our cash flow provided
by operations before changes in working capital for the past three years.

Our cash flow from operations before changes in working capital fluctuates
primarily because of our oil and gas sales, excluding the effects of significant
unforeseen expenses or other income. Our oil and gas production will vary based
on actual well performance or may be curtailed due to factors beyond our
control. Hurricanes in the Gulf of Mexico will shut down our production for the
duration of the storm, or as in the case of Hurricane Lili in 2002, damage
production facilities so that we cannot produce a particular property for an
extended amount of time. In addition, downstream activities on major pipelines
in the Gulf of Mexico can also cause us to shut-in production for various
lengths of time. Oil and gas prices will also vary significantly due to world
political events, supply and demand of products, or weather patterns in the
geographical United States. We sell the vast majority of our production at spot
market prices. Accordingly, product price volatility can significantly affect
our cash flow. To mitigate affects of this volatility, we sometimes lock in
prices for some

13

portion of our production (usually less than 33%) through the use of forward
sale agreements. See additional discussion under Commodity Price Risk in Item
7A. Quantitative and Qualitative Disclosures about Market Risk.

Significant changes in our working capital accounts from 2001 to 2002
include an increase in our accounts receivable (a decrease in our cash flow
provided by operations) due to higher oil and gas prices, increased production
and increased balances due from our joint interest participants due to an
increase in operating activities (drilling wells and facilities construction) at
year end. Cash flow provided by operations decreased due to an increase in
prepaid expenses and other current assets because of an increase in prepaid
drilling costs on non-operated properties and increased pension plan
contributions. In addition, due to the increase in operating activities our
accounts payable increased by $13.3 million.

We incurred capital and exploration expenditures totaling $100.5 million
during 2002. The capital expenditures included $4.2 million for leasehold
acquisition, $45.4 million for exploration costs, $50.9 million for development
costs including platform and facilities construction. During the year, we built
and installed, or will install in 2003, 6 offshore platforms and facilities. In
addition, in 2002 we drilled 23 exploration wells and 3 development wells.

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
$96.1 million for capital expenditures in 2003. Our 2003 capital and exploration
budget includes $51.3 million for 30 exploratory wells. We project that we will
spend $45.2 million on 21 wells in the Gulf of Mexico and $6.1 million on 9
onshore wells in South Texas and Mississippi. The budget also includes $25.8
million for platforms and development drilling on operated discoveries at South
Marsh Island block 24, West Cameron blocks 416, 417 and 426, East Cameron block
185, and Eugene Island blocks 299, 302 and 397. The remaining $19.0 million will
be allocated to leasehold acquisitions, 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 2003.

If our exploratory drilling results in significant new discoveries, we will
have to acquire additional capital in order to finance the completion,
development, and potential additional opportunities generated by our success. We
believe that, because of the additional reserves resulting from the exploratory
success and our record of reserve growth in recent years, we will be able to
acquire sufficient additional capital through additional bank financing and /or
offerings of debt or equity securities.

In March 2002 we issued 3.0 million shares of common stock at $18.50 per
share. Net proceeds from the offering totaled approximately $52.8 million. We
used $44.0 million of the net proceeds to reduce outstanding bank debt from
$71.0 million to $27.0 million, and we used the remainder for working capital.

As of December 31, 2002, our amended credit facility has a borrowing base
of $75.0 million. As of March 21, 2003, we had $37.4 million borrowed under the
facility. 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 banks will reevaluate the borrowing base in
April 2003. 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
maintaining a minimum current ratio (as defined in the agreement) of 1.0 to 1.0,
a minimum tangible net worth of $85.0 million plus 50% of net income
(accumulated from the inception of the agreement) 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.

14

RESULTS OF OPERATIONS

In 2002, we recorded net income totaling $11.3 million or $0.45 basic
income per share, and $0.42 diluted income per share, compared to a net income
of $8.4 million or $0.38 basic income per share and $0.35 diluted income per
share in 2001. The increase in net income resulted primarily from lower total
costs and expenses, primarily the $13.5 million settlement expense for Phillips
Petroleum recorded in 2001. In addition, total revenues decreased by 10%
primarily because of lower gas prices.

The following table discloses the net oil and gas production volumes,
sales, and sales prices for each of the three years ended December 31, 2002,
2001, and 2000. The table is an integral part of the following discussion of
results of operations for the periods 2002 compared to 2001 and 2001 compared to
2000.

2002 COMPARED TO 2001

Oil sales revenue increased by $12.9 million, or 45%, because oil
production increased by 479,000 barrels, or 38%, and average oil prices
increased by $1.11 or 5%. Oil production from offshore Gulf of Mexico increased
by 574,000 barrels, or 71%, because of production from new properties. Oil
production from onshore gulf coast properties decreased by 95,000 barrels, or
21%, because of natural depletion of the existing producing properties and the
sale of certain properties in South Texas in April 2002. Average prices
increased from $22.93 in 2001 to $24.04 in 2002, which increased oil revenues by
$1.4 million.

Gas sales revenue decreased by $26.9 million, or 32% because of lower
average gas prices and lower production. Average gas prices decreased from $3.99
per Mcf in 2001 to $3.33 per Mcf, or 17%, in 2002, causing gas sales revenues to
decrease by $14.1 million. Production decreased by 4.0 Bcf, or 18%, primarily
because of lower gas production from the offshore Gulf of Mexico. During the
fourth quarter of 2001 we lost production from a well on East Cameron block 364.
The production from this property during 2001 was 3.1 Bcf compared to 0.3 Bcf
during 2002. The decrease from this property was partially offset by increased
gas production from new offshore properties.

Other income increased primarily because of a $4.1 million gain on the sale
of certain immaterial South Texas properties in April 2002.

Total operating costs remained unchanged. However, operating costs per
Mcfe increased from $0.53 to $0.56, or 6% primarily because of new operated
properties in the Gulf of Mexico and fixed platform costs on certain properties
with decreased production (due to natural depletion and hurricanes during
September and October of 2002) partially offset by lower workover costs during
2002 compared to the prior year.

15

Impairment expense for 2002 included a $6.4 million charge for impaired
proved property costs and $1.6 million for amortization of unproved property
costs. During 2001, we recorded $10.0 million for impairment charges of proved
property costs and $616,000 for impairment of unproved property costs.

Exploration expenses increased by $2.5 million, or 19%, because of
increased dry hole costs during 2002 partially offset by a $2.7 million decrease
in seismic expenses in 2002 compared to 2001. Depreciation, depletion and
amortization expense increased by $265,000, or less than 1% for the year ended
December 31, 2002, compared to the prior year. During 2002, depreciation,
depletion and amortization increased to $1.38 per Mcfe from $1.33 per Mcfe in
2001.

General and administrative expenses decreased by $410,000, or 7%, due
primarily to lower legal fees. Stock based compensation expense decreased by
$2.1 million or 56% because in 2001 we included a "catch up" provision related
to the contingent stock grants. The catch up included the period June 1999 (the
date of the grant) to January 2001 (the date of measurement). The grant became
effective in January 2001 when the requirements for the triggering of the stock
grants were achieved. During the second quarter of 2001, we settled the Phillips
litigation and charged $13.5 million to settlement expense. Interest and
financing expense decreased because of lower interest rates and lower
outstanding debt. Income taxes increased by $2.5 million as a result of
increased income before taxes.

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 sales
revenues to be $5.1 million lower.

Gas sales 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
16

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.

NEW ACCOUNTING PRONOUNCEMENTS

SFAS 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 periods the
assets are 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. We will then increase the estimated
obligation amount by contingency and inflation factors, and then discount the
total amount to present value. Further, on a periodic basis we will record the
accretion of the discount. For properties owned at December 31, 2002, we
estimate the undiscounted asset retirement obligation to be approximately $15.0
million. 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 December 2002, the Financial Accounting Standards Board issued SFAS No.
148, "Accounting for Stock-Based Compensation -- Transition and Disclosure."
SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation," to
provide alternative methods of transition to SFAS No. 123's fair value method of
accounting for stock-based employee compensation. SFAS No. 148 also amends the
disclosure provisions of SFAS No. 123 and APB No. 28, "Interim Financial
Reporting," to require disclosure in the summary of significant accounting
policies of the effects of an entity's accounting policy with respect to stock-
based employee compensation on reported net income and earnings per share in
annual and interim financial statements. While SFAS No. 148 does not amend SFAS
No. 123 to require companies to account for employee stock options using the
fair value method, the disclosure provisions of SFAS No. 148 are applicable to
all companies with stock-based employee compensation, regardless of whether they
account for that compensation using the fair value method of SFAS No. 123 or the
intrinsic value method of APB No. 25. 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.

In June 2002, the Financial Accounting Standards Board issued SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146
addresses accounting and financial reporting for costs associated with certain
exit or disposal activities. We do not anticipate initiating any activities that
are subject to this standard.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK

Our revolving bank line of credit is sensitive to changes in interest
rates. At December 31, 2002, the unpaid principal balance under the line was
$37.4 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, 2002, Libor changed by one full percentage point (100
basis points) the fair value of our revolving debt would change by approximately
$93,000. We have not entered into any interest rate hedging contracts.

17

COMMODITY PRICE RISK

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.

Occasionally we sell forward portions of our production under physical
delivery contracts that by their terms cannot be settled in cash or other
financial instruments. Such contracts are not subject to the provisions of
Statement of Financial Accounting Standards No. 133 "Accounting for Derivative
Instruments and Hedging Activities." Accordingly we do not provide sensitivity
analysis for such contracts. For the period January 1, 2003, through March 31,
2003, we did not have any forward sales contracts in place. For the period April
1, 2003, through December 31, 2003, we have physical delivery contracts in place
to sell 21,500 MMBtu of gas per day and 1,200 barrels of oil per day at the
following prices:

18

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

INDEX TO FINANCIAL STATEMENTS

Report of Independent Public Accountants.................... 20
Report of Independent Public Accountants (Prior Years)...... 21
Consolidated Balance Sheets as of December 31, 2002 and
2001...................................................... 22
Consolidated Statements of Income for 2002, 2001, and
2000...................................................... 23
Consolidated Statements of Stockholders' Equity for 2002,
2001, and 2000............................................ 24
Consolidated Statements of Cash Flows for 2002, 2001, and
2000...................................................... 25
Notes to Consolidated Financial Statements.................. 26

19

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To The Stockholders and Board of Directors of
Remington Oil and Gas Corporation

We have audited the accompanying consolidated balance sheet of Remington
Oil and Gas Corporation ("the Company"), a Delaware corporation, as of December
31, 2002, and the related consolidated statements of income, stockholders'
equity and cash flows for the year ended December 31, 2002. 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. The financial statements of Remington Oil and Gas Corporation as of
December 31, 2001, and for the two years in the period ended December 31, 2001
were audited by other auditors who have ceased operations. Those auditors
expressed an unqualified opinion on those financial statements in their report
dated March 15, 2002.

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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Remington
Oil and Gas Corporation as of December 31, 2002, and the results of their
operations and their cash flows for the year ended December 31, 2002, in
conformity with accounting principles generally accepted in the United States.

As discussed above, the consolidated financial statements of Remington Oil
and Gas Corporation as of December 31, 2001, and for the two years in the period
ended December 31, 2001, were audited by other auditors who have ceased
operations. As described in Note 1, these consolidated financial statements have
been revised to include the transitional disclosures required by Statement of
Financial Accounting Standards (Statement) No. 148, Accounting for Stock Based
Compensation -- Transition and Disclosure, which was adopted by the Company as
of December 31, 2002. Our audit procedures with respect to the disclosures in
Note 1 for 2001 and 2000 included (a) agreeing the as reported and proforma net
income, as reported and proforma basic earnings per share, and as reported and
proforma diluted earnings per share to the previously issued financial
statements, (b) agreeing the stock based employee compensation expense
(including any related tax effects) determined under a fair value method for all
awards to the Company's underlying records obtained from management, and (c)
testing the mathematical accuracy of the reconciliation of proforma net income
to reported net income. In our opinion, the disclosures for 2001 and 2000 in
Note 1 are appropriate. However, we were not engaged to audit, review, or apply
any procedures to the 2001 and 2000 consolidated financial statements of the
Company other than with respect to such disclosures and, accordingly, we do not
express an opinion or any other form of assurance on the 2001 and 2000 financial
statements taken as a whole.

/s/ ERNST & YOUNG LLP

Dallas, Texas
March 24, 2003

20

THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.

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

The above is a copy of the Report of Independent Public Accountants issued
by Arthur Andersen LLP in connection with Remington Oil and Gas Corporation's
filing of an annual report on Form 10-K for the year ended December 31, 2001.
Arthur Andersen LLP has not reissued its Report in connection with the filing of
the Company's annual report on Form 10-K for the year ended December 31, 2002,
nor has Arthur Andersen LLP consented to the inclusion of their Report in this
annual report on Form 10-K. Arthur Andersen LLP has ceased practicing before the
Securities and Exchange Commission. See Exhibit 23.2 for further discussion. The
consolidated balance sheet as of December 31, 2000, and the consolidated
statements of income, stockholders' equity, and cash flows for the year ended
December 31, 1999, have not been included in the accompanying financial
statements.

21

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

See accompanying Notes to Consolidated Financial Statements.
22

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

See accompanying Notes to Consolidated Financial Statements.
23

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

See accompanying Notes to Consolidated Financial Statements.
24

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying Notes to Consolidated Financial Statements.
25

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.

CONCENTRATION OF CREDIT RISK

Our financial instruments that are potentially subject to a concentration
of credit risk are principally cash and trade receivables. We have cash deposits
at two institutions that exceed the $100,000 federally insured limit by $14.8
million and $19.3 million at December 31, 2002 and 2001, respectively. At
December 31, 2002, 3 companies accounted for approximately 58% of the total
accounts receivable, and at December 31, 2001, 4 companies accounted for
approximately 81% of the total accounts receivable. In 2002, gas sales by a gas
marketing company accounted for approximately 54% of our total oil and gas
revenue. In addition, we sold approximately 86% of our total oil production to
two companies during the year, which accounted for approximately 36% of our
total oil and gas revenues in 2002. The revenue from the sale of oil and gas by
the gas 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. We do not believe that the loss of
services or sales from any of these companies would have a material adverse
effect on 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

26

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

component of depreciation, depletion and amortization expense. As of December
31, 2002, the total estimated liability of our future dismantlement and
restoration costs is approximately $15.0 million. The accrued liability at
December 31, 2002 and 2001, was $5.7 million and $4.3 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 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 long-term portion of prepaid pension expenses (see
Note 7. Employee and Director Benefit Plans -- Pension Plan), and net
unamortized credit facility origination fees. 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. In addition, other assets also include a
long-term account receivable totaling $366,000, which 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.

The amount due CKB Petroleum from Don D. Box under the Collateral
Assignment Split Dollar Insurance Agreement was $140,000 on December 31, 2002,
and $135,000 on December 31, 2001.

ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses were as follows:

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.

27

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

STOCK OPTIONS

In December 2002, the Financial Accounting Standards Board issued SFAS No.
148, "Accounting for Stock-Based Compensation -- Transition and Disclosure."
SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation," to
provide alternative methods of transition to SFAS No. 123's fair value method of
accounting for stock-based employee compensation.

SFAS No. 148 also amends the disclosure provisions of SFAS No. 123 and APB
No. 28, "Interim Financial Reporting," to require disclosure in the summary of
significant accounting policies of the effects of an entity's accounting policy
with respect to stock-based employee compensation on reported net income and
earnings per share in annual and interim financial statements. While SFAS No.
148 does not amend SFAS No. 123 to require companies to account for employee
stock options using the fair value method, the disclosure provisions of SFAS No.
148 are applicable to all companies with stock-based employee compensation,
regardless of whether they account for that compensation using the fair value
method of SFAS No. 123 or the intrinsic value method of APB No. 25.

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 and has adopted
the disclosure requirements of SFAS 123 and SFAS 148 as of December 31, 2002.
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.

The following table summarizes relevant information as to the reported
results under our intrinsic value method of accounting for stock awards, with
supplemental information as if the fair value recognition provision of SFAS No.
123 had been applied:

28

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The fair value of each option grant for the years ended December 31, 2002,
2001, and 2000 is estimated on the date of grant using the Black-Scholes
option-pricing model with the following weighted average assumptions:

As required, the pro-forma disclosures above include options granted since
January 1, 1995. Consequently, the effects of applying SFAS No. 123 for
providing pro-forma disclosures may not be representative of the effects on
reported net income for future years until all options outstanding are included
in the pro-forma disclosures. For purposes of pro-forma disclosures, the
estimated fair value of stock-based compensation plans and other options are
amortized to expense primarily over the vesting period.

SEGMENT REPORTING

We operate in only one business segment.

ADOPTED AND NEW ACCOUNTING POLICIES

In 2002, we adopted Statement of Financial Accounting Standards No. 144
"Accounting for the Impairment or Disposal of Long-Lived Assets," which
superceded Statement of Financial Accounting Standards No. 121 "Accounting for
Impairment of Long-Lived Assets." The Statement addressed financial accounting
and reporting for the impairment or disposal of long-lived assets. The adoption
of this statement did not have a material effect on our balance sheet or income
statement in 2002.

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. We will then increase the estimated obligation am