REMINGTON OIL & GAS CORP - 10-K Annual Report

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UNITED STATES 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, 2003

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 (I.R.S. employer
incorporation 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 $379,990,179. On March 10, 2004, the number
of outstanding shares of common stock, $0.01 par value, was 27,042,398.
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REMINGTON OIL AND GAS CORPORATION

TABLE OF CONTENTS

PART I.................................................................. 2
Item 1. Business.................................................... 2
Item 2. Properties.................................................. 5
Item 3. Legal Proceedings........................................... 7
Item 4. Submission of Matters to a Vote of Security Holders......... 7

PART II................................................................. 8
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 8
Item 6. Selected Financial Data..................................... 10
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 11
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 20
Item 8. Financial Statements and Supplementary Data................. 22
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 48
Item 9A. Controls and Procedures..................................... 48

PART III................................................................ 48
Item 10. Directors and Executive Officers of the Registrant.......... 48
Item 11. Executive Compensation...................................... 48
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 48
Item 13. Certain Relationships and Related Transactions.............. 48
Item 14. Principal Accountant Fees and Services...................... 49

PART IV................................................................. 49
Item 15. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 49
Signatures............................................................ 52
Certifications

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. Further, our website contains our corporate
governance documents including our Code of Business Conduct and Ethics
that applies to all directors and employees including our Chief Executive
Officer, Principal Financial Officer, and Principal Accounting Officer.
Persons may obtain free of charge a copy of the reports listed above and
our corporate governance documents by written request to the Secretary of
the Company.

- 33 employees on December 31, 2003

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. We will implement this strategy through
drilling exploratory and development wells from an inventory of available
prospects that we have evaluated for geologic and mechanical risk and future
reserve or resource potential. Our drilling program will contain some high
risk/high reserve potential opportunities as well as some lower risk/lower
reserve potential opportunities, in order to achieve a balanced program of
reserve and production growth. Success of this strategy is contingent on various
risk factors, as discussed in our filings with the Securities and Exchange
Commission.

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.

2

We share ownership in our oil and gas properties with various industry
participants. We currently operate the majority of our offshore 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 risky. These
risks fall into two broad categories. First there is the risk that each time we
drill a well, the well will not find oil or gas reserves. Even 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 try to mitigate these
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. Much of 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.

Second is the broad category of operating risks. 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

- Markets for the sale 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 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. We use an independent company to market almost
all of our offshore gas production and a portion

3

of our offshore oil production. Because oil and gas are homogenous commodities
and other customers and marketers are readily available, we believe that the
loss of any of our current customers or our independent marketing company would
not be detrimental to our operations nor have a material effect on our revenues.

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.

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 and associated regulations governing the discharge of
materials into the environment, the cost of compliance with this federal and
state legislation could have a significant impact on our financial ability to
carry out our oil and gas operations.

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

4

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" and "Consolidated Financial Statements and
Notes to Consolidated Financial Statements." 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 oil and gas property as of December 31, 2003, was
as follows:

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

PROVED OIL AND GAS RESERVES

Net proved oil and gas reserves at December 31, 2003, as calculated in a
full review of 100% of our properties 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.

5

In 2003 our standardized measure of discounted future net cash flows was
$486.3 million. We used December 31, 2003, West Texas Intermediate posted price
of $29.25 per barrel and a Gulf Coast spot market price of $5.97 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.

Our offshore Gulf of Mexico properties account for approximately 81% of our
oil production and approximately 96% of our gas production. In addition, total
revenues from offshore Gulf of Mexico oil and gas production during 2003
accounted for approximately 92% of our total oil and gas revenues. We owned
varying working interests (5% to 100%) in 113 offshore Gulf of Mexico blocks at
December 31, 2003, and currently produce from 36 of these blocks. Seven
additional blocks are currently under development. We operate a majority of
these 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 2003 we successfully drilled and completed 15 exploratory wells on
13 different properties in the offshore Gulf of Mexico. In addition, we, as
operator, constructed and installed or will install 9 production platforms and
drilled and completed 3 development wells on 3 different properties.

Our onshore Gulf Coast area properties are principally located in the State
of Mississippi and along the Texas Gulf Coast. In 2003, these properties
accounted for approximately 19% of our oil production and approximately 4% of
our gas production. We drilled a total of 6 wells on our onshore properties
during 2003 and completed 4 wells as producers. Our working interests in these
wells range from 15% to 100%.

6

DRILLING ACTIVITIES

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

We had an interest in 3 wells (2.10 net) in progress at December 31, 2003,
1 well (0.25 net) in progress at December 31, 2002, and 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

7

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 10, 2004, the last reported sales price for our common stock was
$19.60 per share. On that date, there were 622 stockholders of record, including
45 stockholders of record of class A common stock and 83 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.

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

The following table presents information about our equity compensation
plans at December 31, 2003:

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

- Shares awarded based on annual base salary as of June 17, 1999, or in the
case of non-employee directors $100,000, divided by $4.19 (the closing
price on June 17, 1999).

- In order for the grants to become effective, our common stock had to
close at or above $10.42 per share for 20 consecutive trading days within
5 years of the grant date (the "trigger event").

8

- The trigger event was achieved on January 24, 2001.

- 686,472 shares were awarded. As of December 31, 2003, 385,989 shares have
vested, and 40,847 shares have been forfeited. Of the remaining 259,636
shares, 65,563 shares vest on June 17, 2004, and 194,073 shares vest 1/3
on each successive January 17 beginning on January 17, 2004.

- Each employee and director must remain an employee or director during
his/her respective vesting schedule in order to receive the shares.

- In the event of death or a change of control, an employee's or director's
shares will fully vest. In the event of the long-term disability of an
employee, or the employee reaching the retirement age of 65, the shares
will fully vest.

9

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 2003 include charges of $4.4 million and for 2002
include charges of $8.1 million 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.

(2) The quantities of proved oil and gas reserves 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 the standardized measure of future discounted net cash flows on
year-end prices and costs. Any changes in future prices, costs, regulations,
technology, or other unforeseen factors could significantly increase or
decrease the proved reserve estimates.

(3) We have not entered into any financial hedges for oil or gas prices during
any of the years presented, therefore, the average sales prices represent
actual sales revenue per barrel or Mcf.
10

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

CRITICAL ACCOUNTING POLICIES

We prepare our consolidated financial statements in this report using
accounting principles that are generally accepted in the United States ("GAAP").
GAAP represents a comprehensive set of accounting and disclosure rules and
requirements. We must make judgments, estimates, and in certain circumstances,
choices between acceptable GAAP alternatives as we apply these rules and
requirements. The most critical estimates and accounting policies include
estimates of proved oil and gas reserves, the related standardized measure of
discounted future net cash flows, and the use of successful efforts accounting
method for oil and gas expenditures. The calculation of depreciation, depletion
and amortization of our oil and gas properties and the impairment of those
properties are affected by the estimated oil and gas reserves and the successful
efforts method of accounting. In addition, we use multiple estimated data to
compute and record our asset retirement obligations. Finally, our general and
administrative expenses are affected by the method in which we measure and
record stock based compensation expense and, to a lesser extent, assumptions
related to our defined benefit pension plans. We have included a more detailed
discussion of these critical estimates and accounting policies in the following
sections of this item: Long-Term Strategy and Business Developments, Liquidity
and Capital Resources, and Results of Operations. Our Notes to Consolidated
Financial Statements included in this report also have a more comprehensive
discussion of our significant accounting policies.

11

LONG-TERM STRATEGY AND BUSINESS DEVELOPMENTS

Our long-term strategy is to increase our oil and gas reserves and
production while keeping our finding and development costs and operating costs
(on a per Mcf equivalent (Mcfe) basis) competitive with our industry peers. We
will implement this strategy through drilling exploratory and development wells
from our inventory of available prospects that we have evaluated for geologic
and mechanical risk and future reserve or resource potential. Our drilling
program will contain some high risk/high reserve potential opportunities as well
as some lower risk/lower reserve potential opportunities, in order to achieve a
balanced program of reserve and production growth. Success of this strategy is
contingent on various risk factors, as discussed in our filings with the
Securities and Exchange Commission. Over the last three years, we have invested
$339.8 million in oil and gas properties, found 158.2 Bcfe of proved reserves
and replaced 173% of our production at an average finding and development cost
of $2.15 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 and development costs include acquisition, development and
exploration costs (including exploration costs such as seismic acquisition
costs).

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

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

Operating costs on a Mcfe produced basis have increased slightly over the
past three years from $0.56 to $0.60 or approximately 7%. Finding and
development costs have increased from $1.68 per Mcfe in 2000 to $2.69 per Mcfe
in 2003. These increased costs reflect the difficulty of finding new reserves in
the offshore Gulf of Mexico shelf environment. These higher costs also reflect
negative reserve revisions that have occurred in 2002 and 2003. These negative
revisions were the result of certain reservoirs performing at rates lower than
anticipated by our independent reserve engineers. If the reserve revisions are
removed from the finding and development cost calculations, annual finding and
development costs and percentage of production replaced would have been as
follows:

12

Although we and our independent reservoir engineers utilize accepted engineering
techniques to evaluate the future performance of reservoirs, variations in these
estimates can and will occur.

PROVED RESERVE ESTIMATES

While parts of our long-term strategy (such as increased production or
operating costs per Mcfe) can be accurately measured by reference to actual
data, other measurements (such as an increase in oil and gas reserves or finding
costs per Mcfe) rely heavily on estimated information, subject to later
revisions. In addition, the standardized measure of discounted future net cash
flows relies on these estimates of oil and gas reserves using commodity prices
and costs at year end.

Independent reserve engineers prepare the estimates of our oil and gas
reserves 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.

In our 2003 year-end reserve report we used December 31, 2003, West Texas
Intermediate posted price of $29.25 per barrel and a Gulf Coast spot market
price of $5.97 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. Future global economic and political events will most
likely result in significant fluctuations in future oil prices. In addition,
cold weather during December 2003 and into the first quarter of 2004 in the
United States has resulted in significant fluctuations in natural gas prices.

LIQUIDITY AND CAPITAL RESOURCES

Cash flow provided by operations for the year ended December 31, 2003,
increased by $81.8 million, or 115%, compared to the prior year primarily due to
a 25% increase in production and an increase in oil and gas prices throughout
the entire year. We expect our cash flow provided by operations for 2004 to
increase because of higher projected production from new properties, combined
with oil and gas prices consistent with 2003 and steady operating, general and
administrative, interest and financing costs per Mcfe.

Excluding the effects of significant unforeseen expenses or other income,
our cash flow from operations fluctuates primarily because of variations in oil
and gas production and prices or changes in working capital accounts. Our oil
and gas production will vary based on actual well performance but may be
curtailed due to factors beyond our control. Hurricanes in the Gulf of Mexico
will shut down our production for the duration of the storm's presence in the
Gulf, or as in the case of Hurricane Lili in 2002, damage production facilities
so that we cannot produce from a particular property for an extended amount of
time. In addition, downstream activities on major pipelines in the Gulf of
Mexico can also cause us to shut-in production for various lengths of time.

Our realized oil and gas prices vary due to world political events, supply
and demand of products, product storage levels, and weather patterns. We sell
the vast majority of our production at spot market prices. Accordingly, product
price volatility will affect our cash flow from operations. To mitigate price
volatility we sometimes lock in prices for some portion of our production
(usually less than 33%) through the use of forward sale agreements. Currently we
have no such arrangements in place. See additional discussion under Commodity
Price Risk in Item 7A. Quantitative and Qualitative Disclosures about Market
Risk.

Changes in our working capital accounts from 2002 to 2003 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 as a result of increased
operating activities (drilling wells and facilities construction) at year end.
Due to the increase in operating activities our accounts payable balance
increased by $10.7 million which increased our cash flow from operations. Cash
flow provided by

13

operations also increased due to a decrease in prepaid expenses and other
current assets primarily because of a decrease in prepaid drilling costs on
non-operated properties.

We incurred capital and exploration expenditures totaling $116.4 million
during 2003. The capital expenditures included $3.8 million for leasehold
acquisition, $54.1 million for exploration costs, $58.5 million for development
costs including platform and facilities construction. During the year, we built
and installed, or will install in 2004, 9 offshore platforms and facilities. In
addition, in 2003 we drilled 25 exploration wells and 7 development wells and
had 3 wells in progress at year end.

We expect to continue to make significant capital expenditures over the
next several years as part of our long-term growth strategy. We have budgeted
$104.0 million for capital and exploration expenditures in 2004. Our 2004
capital and exploration budget includes $56.0 million for 29 exploratory wells.
We project that we will spend $47.6 million on 22 wells in the Gulf of Mexico
and $8.4 million on 7 onshore wells in South Texas and Mississippi. The budget
also includes $21.0 million for platforms and development drilling. The
remaining $27.0 million will be allocated to leasehold acquisitions, seismic
acquisitions, and workovers.

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

Effective May 1, 2003, we agreed with our lenders to increase our borrowing
base from $75.0 million to $100.0 million and to extend the maturity of the loan
facility from May 3, 2004 to May 3, 2006. As of December 31, 2003, we had $18.0
million borrowed under the facility. The banks review the borrowing base
semi-annually and, at their discretion, may decrease or propose an increase to
the borrowing base relative to a redetermined estimate of proved oil and gas
reserves. Our oil and gas properties are pledged as collateral for the line of
credit. Additionally, we have agreed not to pay dividends. 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. If we do not comply with these covenants on a continuing
basis, 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 June 19, 2003, we filed a shelf registration statement to issue up to
$200.0 million of common stock, debt securities, preferred stock, and or
warrants. The Securities and Exchange Commission declared the shelf registration
statement effective December 18, 2003.

The following table summarizes our contractual obligations and commercial
commitments as of December 31, 2003.

On December 31, 2003, our current assets exceeded our current liabilities
by $18.9 million. Our current ratio was 1.32 to 1.00.

14

RESULTS OF OPERATIONS

In 2003, we achieved net income totaling $42.9 million or $1.61 basic
income per share, and $1.53 diluted income per share, compared to a net income
of $11.3 million or $0.45 basic income per share and $0.42 diluted income per
share in 2002. The increase in net income resulted primarily from increased oil
and gas production and sales prices. In addition to oil and gas production and
prices, certain accounting policies discussed below can cause our net income to
vary significantly from period to period because of events or circumstances
which trigger recognition of expenses for unsuccessful wells or impairments of
properties. Further, we calculated certain expenses using estimates of oil and
gas reserves that can vary significantly.

OIL AND GAS SALES REVENUE

The following table discloses the net oil and gas production volumes,
sales, and sales prices for each of the three years ended December 31, 2003,
2002, and 2001.

Oil sales revenue during 2003 increased by $10.3 million, or 24%, compared
to 2002 because average oil prices increased by $5.16 per barrel, or 21% and oil
production increased by 46,000 barrels, or 3%. During 2002, oil sales revenue
increased by $13.3 million, or 46%, compared to 2001 because oil production
increased by 496,000 barrels, or 40%, and average oil prices increased by $0.98
or 4%. The increase in oil production came primarily from new properties in the
offshore Gulf of Mexico partially offset by natural depletion of the existing
producing properties in the Gulf Coast area and the sale of certain properties
in South Texas in April 2002.

Gas sales revenue during 2003 increased by $71.9 million or 123% compared
to 2002 because of higher average gas prices and increased production. Average
gas prices increased from $3.35 per Mcf in 2002 to $5.40 per Mcf, or 61%, in
2003, causing gas sales revenues to increase by $35.8 million. Production
increased by 6.7 Bcf, or 38%, primarily because of gas production from new
properties in the offshore Gulf of Mexico. During 2002, gas sales revenue
decreased by $27.1 million, or 32% because of lower average gas prices and lower
production. Average gas prices decreased from $4.02 per Mcf in 2001 to $3.35 per
Mcf, or 17%, in 2002, causing gas sales revenues to decrease by $14.2 million.
Production decreased by 3.8 Bcf, or 18%, primarily because of lower gas
production from the offshore Gulf of Mexico. During the fourth quarter of 2001
we lost

15

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
in production from this property was partially offset by increased gas
production from new offshore properties.

During 2002, we sold certain South Texas properties at a $4.1 million gain.
This gain in 2002 accounts for the decrease in other income during 2003 when
compared to 2002 and the increase in 2002 when compared to 2001.

OPERATING COSTS AND EXPENSES

Total operating costs during 2003 increased by $4.8 million, or 29%,
compared to 2002, due to the increase in the number of operating properties.
However, operating costs per Mcfe increased by only $0.02 to $0.60 during 2003.
The following table presents the major components of our operating costs on a
per Mcfe basis.

EXPLORATION EXPENSES -- 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 expenses when incurred and capitalize the costs of
successful exploration wells as oil and gas properties. Entities that follow the
full cost method capitalize all drilling and exploration costs including dry
hole costs into one pool of total oil and gas property costs.

We use the successful-efforts method because we believe that it more
accurately 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.

During 2003, exploration expenses increased by $9.8 million, or 63%,
compared to 2002 primarily because of a $9.2 million increase in dry hole costs.
In addition, geological and geophysical expenses increased by $628,000 because
of higher seismic expenses in 2003 compared to 2002. Exploration expenses for
2002 increased by $2.5 million, or 19%, because of increased dry hole costs
compared to 2001, partially offset by a $2.7 million decrease in seismic
expenses in 2002. 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 75 exploration wells, of which 20 were considered dry
holes resulting in a 73% success ratio on exploratory wells. Our dry hole costs
charged to expense during this period totaled $48.4 million out of total
exploratory drilling costs of $146.3 million. It is impossible to accurately
predict specific dry holes; however, based on past experience, we estimate that
between 20% and 30% of our exploration wells and exploration drilling costs will
be dry holes.

16

DEPLETION, DEPRECIATION, AND AMORTIZATION OF OIL AND GAS PROPERTIES AND ASSET
RETIREMENT OBLIGATIONS

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. Downward
revisions in reserves increase the DD&A per unit and reduce our net income;
likewise, upward revisions lower the DD&A per unit and increase our net income.
Depreciation, depletion and amortization expense recorded in 2003 increased by
$17.2 million, or 45%, compared to the prior year. On a per Mcfe basis,
depreciation, depletion and amortization per Mcfe increased to $1.60 in 2003
from $1.38 in 2002 reflecting the increased costs for finding reserves in the
Gulf of Mexico and some negative revisions in our oil and gas reserves.
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 and
depreciation, depletion and amortization per Mcfe increased to $1.38 from $1.33
in 2001.

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

Prior to this adoption, we accrued an estimated dismantlement, restoration
and abandonment liability using the unit of production method over the life of a
property and included the accrued amount in depreciation, depletion and
amortization expense. The total accrued liability ($5.5 million at December 31,
2002) was reflected as additional accumulated depreciation, depletion and
amortization of oil and gas properties on our balance sheet.

In conformity with the new statement we recorded the cumulative effect of
this accounting change as of January 1, 2003, as if we had used this method in
the prior years. At January 1, 2003, we increased our oil and gas properties by
$9.0 million, recorded $11.8 million as an Asset Retirement Obligation liability
and reduced our accumulated depreciation by $2.8 million ($5.5 million accrued
dismantlement in prior years less accumulated depreciation, depletion and
amortization of $2.7 million on the increased property costs). The adoption of
the new standard had no material effect on our net income. The following pro
forma data summarizes our net income and net income per share for the years
ended December 31, 2003, 2002 and 2001 as if we had adopted the provisions of
SFAS 143 on January 1, 2001, including aggregate pro forma asset retirement
obligations on that date:

17

IMPAIRMENT OF OIL AND GAS PROPERTIES

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

The impairment of unproved leasehold costs includes an amortization of the
aggregate individually insignificant properties (adjusted by an estimated rate
of future successful development) over an average lease term and the specific
impairment of individually significant properties. During 2003 and 2002 the
amortization of the individually insignificant properties totaled $917,000 and
$1.1 million, respectively. The remaining impairments in these two years
resulted from impairment of significant properties due to unsuccessful drilling
results. In 2001, prior to our adoption of this amortization method, the
impairment expense resulted from the actual (due to unsuccessful exploration
results) or impending forfeiture of leaseholds. The effect of the change in
estimating our impairment of unproved properties was not material to our
financial statements.

We analyze our proved properties for impairment indicators based on the
proved reserves as determined by our independent reserve engineers. The
properties impaired in 2003 primarily consisted of two properties in the Gulf of
Mexico which totaled $2.4 million and one property in the onshore Gulf Coast
totaling $855,000, and 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 impairments
resulted primarily from wells depleting sooner than originally estimated or
capital costs in excess of those anticipated.

GENERAL AND ADMINISTRATIVE -- ACCOUNTING FOR STOCK BASED COMPENSATION AND
DEFINED BENEFIT PENSION PLAN

General and administrative expenses during 2003 increased by $1.5 million,
or 22% compared to 2002. General and administrative expenses increased by $0.04
per Mcfe to $0.29 in 2003 from $0.25 in 2002. General and administrative expense
in 2002 decreased by $2.5 million due to a reduction in stock based
compensation. Stock based compensation expense which is included in general and
administrative expense totaled $1.3 million in 2003, $1.4 million in 2002 and
$3.5 million in 2001.

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 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

18

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, $1.4 million in 2002, and $1.3 million in 2003
as stock based compensation expense related to the grants. At December 31, 2003,
$1.7 million of the unearned compensation remained unamortized and will be
amortized as the shares vest during the next two 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.

Total assets at fair market value (public market prices for equity and
fixed income mutual funds) for our two defined benefit pension plans were $6.0
million which exceeded the total accumulated benefit obligation as of December
31, 2003. We recorded $542,000 in pension expense and contributed $850,000 to
the plans during 2003. 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 target asset
allocation of equities (75%) and fixed income securities (25%). If however, we
reduced the assumed rate of return by 50 basis points, our 2003 pension plan
expense would have increased by approximately $21,000 and our net income would
have decreased 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 6.5% in 2002 to 6.0% in 2003 and
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 had decreased by another 50 basis points, our 2003 pension
expense would have increased by approximately $268,000 and our net income would
have decreased by approximately $174,000.

19

SETTLEMENTS EXPENSE AND INTEREST AND FINANCING EXPENSE

During the second quarter of 2001, we settled the Phillips litigation and
charged $13.5 million to settlement expense. Interest and financing expense
decreased during the past two years because of lower interest rates and lower
outstanding debt.

INCOME TAXES

During 2003, income taxes increased by $17.5 million compared to 2002 and
increased by $2.5 million during 2002 compared to 2001 as a result of increased
income before taxes. The effective tax rate increased slightly in 2003 due to an
increase in state taxes.

NEW ACCOUNTING PRONOUNCEMENTS

SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and
Intangible Assets" became effective for us on July 1, 2001, and January 1, 2002,
respectively. SFAS No. 141 requires all business combinations initiated after
June 30, 2001, to be accounted for using the purchase method. Additionally, SFAS
No. 141 requires companies to disaggregate and report separately from goodwill
certain intangible assets. SFAS No. 142 establishes new guidelines for
accounting for goodwill and other intangible assets. Under SFAS No. 142,
goodwill and certain other intangible assets are not amortized, but rather are
reviewed annually for impairment. The appropriate application of SFAS Nos. 141
and 142 to oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves is unclear.
Depending on how the accounting and disclosure literature is clarified, these
oil and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves for both undeveloped and
developed leaseholds may be classified separately from oil and gas properties,
as intangible assets on our balance sheets. Additional disclosures required by
SFAS Nos. 141 and 142 would be included in the notes to financial statements.
Historically, we, like many other oil and gas companies, have included these oil
and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves as part of the oil and gas
properties, even after SFAS Nos. 141 and 142 became effective.

This interpretation of SFAS Nos. 141 and 142 would affect only our balance
sheet classification of oil and gas leaseholds. Our results of operations and
cash flows would not be affected, since these oil and gas mineral rights held
under lease and other contractual arrangements representing the right to extract
such reserves would continue to be amortized in accordance with accounting rules
for oil and gas companies provided in SFAS No. 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies."

At December 31, 2003, we had net leaseholds cost of approximately $34.8
million. If we applied the interpretation currently being deliberated, this
classification would require us to make the disclosures set forth under SFAS No.
142 related to these interests. We will continue to classify our oil and gas
leaseholds as oil and gas properties until further guidance is provided.

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, 2003, the unpaid principal balance under the line was
$18.0 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, 2003, and December 31, 2002, Libor had changed by one
full percentage point (100 basis points) the fair value of our revolving debt
would have changed by approximately $45,000 and $93,000 respectively. We have
not entered into any interest rate hedging contracts.

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.

20

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. We currently have no such arrangements in place.

21

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

INDEX TO FINANCIAL STATEMENTS

Report of Independent Public Accountants.................... 23

Report of Independent Public Accountants (2001)............. 24

Consolidated Balance Sheets as of December 31, 2003 and
2002...................................................... 25

Consolidated Statements of Income for 2003, 2002, and
2001...................................................... 26

Consolidated Statements of Stockholders' Equity for 2003,
2002, and 2001............................................ 27

Consolidated Statements of Cash Flows for 2003, 2002, and
2001...................................................... 28

Notes to Consolidated Financial Statements.................. 29

22

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 sheets of Remington
Oil and Gas Corporation ("the Company"), a Delaware corporation, as of December
31, 2003, and 2002 and the related consolidated statements of income,
stockholders' equity and cash flows for the years then ended. 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 year then ended 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 consolidated financial position of
Remington Oil and Gas Corporation as of December 31, 2003 and 2002, and the
consolidated results of their operations and their cash flows for the years then
ended, in conformity with accounting principles generally accepted in the United
States.

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

As discussed above, the consolidated financial statements of Remington Oil
and Gas Corporation as of December 31, 2001, and for the year then ended, 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 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 (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 in Note 1 are appropriate. However, we were not engaged to audit,
review, or apply any procedures to the 2001 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 financial
statements taken as a whole.

/s/ ERNST & YOUNG LLP

Dallas, Texas
March 5, 2004

23

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 years ended December 31, 2002
and December 31, 2003, 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 sheets as of December 31, 2000 and
December 31, 2001, and the consolidated statements of income, stockholders'
equity, and cash flows for the years ended December 31, 1999 and December 31,
2000, have not been included in the accompanying financial statements.

24

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

See accompanying Notes to Consolidated Financial Statements.
25

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

See accompanying Notes to Consolidated Financial Statements.
26

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

See accompanying Notes to Consolidated Financial Statements.
27

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying Notes to Consolidated Financial Statements.
28

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 acquired the following
subsidiaries in 1998: CKB Petroleum, Inc., CKB & Associates, Inc., Box Brothers
Realty Investments Company, CB Farms, Inc., and Box Resources, Inc. We
consolidate 100% of the assets, liabilities, equity, income and expense of the
subsidiaries and eliminate all inter-company transactions and account balances
for the periods of consolidation. We own 100% of the outstanding capital stock
of all of the subsidiaries. The primary operating subsidiary, CKB Petroleum,
Inc., owns an undivided interest in a pipeline that transports our oil from our
South Pass blocks, offshore Gulf of Mexico, to Venice, Louisiana. We account for
our undivided interests in properties using the proportionate consolidation
method, whereby our share of assets, liabilities, revenues and expenses are
included in our financial statements.

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 AND CASH EQUIVALENTS

Cash equivalents consist of highly liquid investments that mature within
three months or less when purchased. Our cash equivalents consist primarily of
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 $31.3
million and $14.8 million at December 31, 2003 and 2002, respectively. At
December 31, 2003, 3 companies accounted for approximately 65% of the total
accounts receivable and at December 31, 2002, 3 companies accounted for
approximately 58% of the total accounts receivable. Oil and gas are fungible
commodities in high demand from numerous customers; however, during 2003 we sold
oil and gas to four major customers who accounted for 17%, 16%, 14% and 13% of
our total revenues. The sale of oil and gas to three major customers accounted
for 54%, 23% and 11% of our total oil and gas revenues in 2002. We do not
believe that the loss of any of these customers would have a material adverse
effect on our financial position or results of operations because we believe
that they can be replaced due to the high demand for oil and gas.

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 expense unsuccessful exploration wells and
geological and geophysical costs when incurred. We amortize the capitalized
costs using the units-of-production method, converting to gas equivalent units
by using the ratio of 1 barrel of oil equal to 6 Mcf of gas.

29

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

We review our oil and gas properties for impairment whenever events or
circumstances indicate that the net book value of the assets may not be
recoverable. 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.

The impairment of unproved leasehold costs includes an amortization of the
aggregate individually insignificant properties (adjusted by an estimated rate
of future successful development) over an average lease term and, if events or
circumstances indicate, a specific impairment of individually significant
properties.

Other properties include improvements on the leased office space and office
computers and equipment. We depreciate these assets using the straight-line
method over their estimated useful lives, which 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 the long-term
portion of 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 $376,000, which is CKB
Petroleum's claim under Collateral Assignment Split Dollar Insurance Agreements
among CKB Petroleum and Don D. Box (a former officer and director) and two of
his brothers.

ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses were as follows:

OIL AND GAS REVENUES

When oil and gas is produced, we sell it immediately. Consequently, we
recognize oil and gas revenue in the month of actual production based on our
share of the revenues. Our actual sales have not been materially different from
our entitled share of production, and we do not have any significant gas
imbalances.

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REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

TRANSPORTATION COSTS

We include transportation costs in operating costs and expenses. During the
years ended December 31, 2003, 2002, and 2001, we incurred transportation costs
totaling $2.3 million, $2.1 million and $1.6 million, respectively.

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 have adopted
the disclosure requirements of SFAS 123 and SFAS 148. 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:

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REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The fair value of each option grant for the years ended December 31, 2003,
2002, and 2001 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. All of our outstanding or previously-exercised options were
granted after 1995.

SEGMENT REPORTING

We operate in only one business segment.

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 current income taxes and
deferred income taxes. Current income tax expense or benefit equals the amount
expected to be calculated on our income tax returns 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 plus
the tax benefit derived from the exercise of employee stock options. We
determine the amount of our deferred income tax asset or liability by
multiplying the enacted tax rates by the temporary differences, net operating or
capital loss carry-forwards plus any tax credit carry-forwards. The tax rates
used are the effective rates applicable for the year in which we expect the
temporary differences or carry-forwards to reverse.

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REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 options or other
contracts to issue common stock were exercised or converted into common stock or
resulted 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.

ADOPTED AND NEW ACCOUNTING POLICIES

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

Prior to this adoption, we accrued an estimated dismantlement, restoration
and abandonment liability using the unit of production method over the life of a
property and included the accrued amount in depreciation, depletion and
amortization expense. The total accrued liability ($5.5 million at December 31,
2002) was reflected as additional accumulated depreciation, depletion and
amortization of oil and gas properties on our balance sheet.

In conformity with the new statement we recorded the cumulative effect of
this accounting change as of January 1, 2003, as if we had used this method in
the prior years. At January 1, 2003, we increased our oil and gas properties by
$9.0 million, recorded $11.8 million as an Asset Retirement Obligation liability
and reduced our accumulated depreciation by $2.8 million ($5.5 million accrued
dismantlement in prior years less accumulated depreciation, depletion and
amortization of $2.7 million on the increased property costs). The adoption of
the new standard had no material effect on our net income. The following pro
forma data summarize our net income and net income per share for the years ended
December 31, 2003, 2002 and 2001
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REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

as if we had adopted the provisions of SFAS 143 on January 1, 2001, including
aggregate pro forma asset retirement obligations on that date:

SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and
Intangible Assets" became effective for us on July 1, 2001 and January 1, 2002,
respectively. SFAS No. 141 requires all business combinations initiated after
June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS
No. 141 requires companies to disaggregate and report separately from goodwill
certain intangible assets. SFAS No. 142 establishes new guidelines for
accounting for goodwill and other intangible assets. Under SFAS No. 142,
goodwill and certain other intangible assets are not amortized, but rather are
reviewed annually for impairment. The appropriate application of SFAS Nos. 141
and 142 to oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves is unclear.
Depending on how the accounting and disclosure literature is clarified, these
oil and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves for both undeveloped and
developed leaseholds may be classified separately from oil and gas properties,
as intangible assets on our balance sheets. Additional disclosures required by
SFAS Nos. 141 and 142 would be included in the notes to financial statements.
Historically, we, like many other oil and gas companies, have included these oil
and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves as part of the oil and gas
properties, even after SFAS Nos. 141 and 142 became effective.

This interpretation of SFAS Nos. 141 and 142 would affect only our balance
sheet classification of oil and gas leaseholds. Our results of operations and
cash flows would not be affected, since these oil and gas mineral rights held
under lease and other contractual arrangements representing the right to extract
such reserves would continue to be amortized in accordance with accounting rules
for oil and gas companies provided in SFAS No. 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies."

At December 31, 2003, we had net leaseholds costs of $34.8 million and at
December 31, 2002, we had net leasehold costs of $35.8 million. If we applied
the interpretation currently being deliberated, this classification would
require us to make the disclosures set forth under SFAS No. 142 related to these
interests. We will continue to classify our oil and gas leaseholds as oil and
gas properties until further guidance is provided.

In January 2003, the Financial Accounting Standards Board issued
Interpretation No. 46, "Consolidation of Variable Interest Entities" ("FIN 46"),
which requires us to consolidate certain entities that are determined to be
variable interest entities. If an entity lacks sufficient equity to carry on its
principal activities, the equity investors of the entity cannot make decisions
about the entity's activities, or the entity's equity investors neither absorbs
losses or benefits from gains, it is considered a variable interest entity. We
have reviewed our financial arrangements and have not identified any such
entities.

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REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

The following table presents a summary of our oil and gas expenditures
during the last three years.

We recognized impairment expenses shown in the table below:

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.

35

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

We analyze proved properties for impairment indicators based on the proved
reserves as determined by our independent reserve engineers. The properties
impaired in 2003 primarily consisted of two properties in the Gulf of Mexico
which totaled $2.4 million and one property in the onshore Gulf Coast, and 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 impairments resulted primarily from
wells depleting sooner than originally estimated or capital costs in excess of
those anticipated.

The following table summarizes our asset retirement obligation on a pro
forma basis as if the provisions of SFAS 143 had been applied when the
properties were placed in service:

NOTE 3 -- NOTES PAYABLE AND OTHER LONG-TERM PAYABLES

BANK CREDIT FACILITY

As of December 31, 2003, our amended credit facility of $150.0 million has
a borrowing base of $100.0 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, 2006, 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 (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. If we do
not comply with these covenants, the lenders have the right to refuse to advance
additional funds under the facility and/or declare all principal and interest
immediately due and payable.

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REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The banks review the borrowing base semi-annually and may decrease or
propose an increase to the borrowing base at their discretion relative to the
new estimate of proved oil and gas reserves.

FAIR VALUE OF INDEBTEDNESS

We estimate that the fair value of our long-term indebtedness, including
the current maturities of such obligations, is approximately $18.0 million at
December 31, 2003 and $40.6 million at December 31, 2002. We based the fair
value on current rates available for our bank debt. The book value of our other
long-term indebtedness approximates fair value.

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

We have 100.0 million shares of common stock and 25.0 million shares of
"blank check" preferred stock authorized. 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 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 previous
royalty settlement to settlement expense.

37

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. These shares were cancelled.

NOTE 7 -- EMPLOYEE AND DIRECTOR BENEFIT PLANS

STOCK OPTION PLAN

The compensation committee of the Board of Directors, comprising three
independent directors, administers the 1997 Stock Option Plan. This 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.
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 ("SFAS
123"). Under APB 25, at the time of grant we do not record compensation expense
on our income statement for stock options granted to employees or directors.

A summary of our stock option plans as of December 31, 2003, 2002, and
2001, and changes during the years ending on those dates is presented below:

The options outstanding at December 31, 2003, have a weighted-average
remaining contractual life of 6.76 years and an exercise price ranging from
$3.125 to $20.34 per share. A breakdown of the options outstanding at December
31, 2003 by price range is presented below:

38

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The table below reflects the effect on our net income 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, 2003,
2002, and 2001, 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 the earlier of 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 PLANS

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 contributions at
least equal to the minimum funding provisions of employee benefit and tax laws,
but

39

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

usually no more than the maximum tax deductible contribution allowed. We do not
expect to make a contribution in 2004. Plan assets consist primarily of equity
and fixed income securities. The following tables set forth significant
information about the plans, the reconciliation of the benefit obligation, plan
assets, and funded status for the pension plans.

40

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The net periodic pension cost recognized in our income statements includes
the following components:

To estimate the expected long-term rate of return on pension plan assets,
we consider the current and expected asset allocations, as well as historical
returns on equities and debt securities.

The accumulated benefit obligation represents the present value of the
benefits earned to the measurement date, with benefits computed based on current
compensation levels. The projected benefit obligation is the accumulated benefit
obligation increased to reflect expected future compensation.

Remington's aggregate projected benefit obligation at December 31, 2003,
was $5.4 million and the aggregate fair value of plan assets was $5.2 million.
On December 31, 2003, Remington had a prepaid benefit cost of $2.1 million. CKB
Petroleum's aggregate projected benefit obligation at December 31, 2003, was
$666,000 and the aggregate fair value of plan assets was $806,000. On December
31, 2003, CKB Petroleum had a prepaid benefit cost of $398,000.

PLANS ASSET ALLOCATION (PLANS' ASSETS ARE HELD IN TRUST.)

Money fund balances were disproportionately high at each year end because
we made large contributions to the pension trusts during the last few days of
each year. These funds were allocated to equity and debt securities and utilized
for regular distributions to retirees during the early part of the next year.
See the discussion of our investment policy below.

Plan fiduciaries set investment policies, strategies, and guidelines for
the pension trusts. These include

- Achieve a long-term average annual rate of return of at least 8%.

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REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- Asset allocations ranging from 75% equities and 25% debt securities to
25% equities and 75% debt securities. Recommended long-term average
allocation is 60% equities and 40% debt securities.

- Permissible investments include publicly-traded common and preferred
stocks, convertible bonds, fixed income securities, guaranteed investment
contracts, and money market funds. Transactions are not permitted in
futures contracts or options.

- Plan assets will be well diversified.

Plan fiduciaries have appointed an investment advisor and asset managers. A
Plan Administration Committee, presently comprising three company executive
officers, meets with the investment advisor at least quarterly to review overall
investment performance, investment manager performance, current asset category
allocations, recommended asset category allocations for the coming quarter, and
sources of liquidity for distributions to retirees for the coming quarter.
During the latter part of 2002 the committee, with the assistance of the
investment advisor, set the target allocation at 75% equities and 25% debt
securities and has maintained that target allocation continuously since then.

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 within 5 years of the grant date. 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. During each of the years ended December
31, 2003 and 2002 we amortized $1.3 million and $1.4 million, respectively, to
stock based compensation expense. The remaining unearned compensation expense
will be amortized over the next two 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.

A summary of the stock grant as of December 31, 2003, 2002, and 2001 and
changes during the years ending on those dates is presented below:

42

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 them.

NOTE 8 -- INCOME TAXES

The following table provides a summary of our income tax expense:

Total income tax expense differs from the amount computed by applying the
federal income tax rate to net income before income taxes as follows:

43

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table reflects the significant components of our net deferred
tax liability.

The unused federal income tax operating loss carry-forward of $11.8 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
reserve engineering firm of Netherland, Sewell & Associates, Inc. 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. We do not file reserve estimates with any other
Federal authority or agency.

44

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. Our
proved undeveloped reserves are generally brought on line within 12 months.
Alternatively, they are associated with long life fields where economics dictate
waiting for an existing wellbore available for sidetrack, or waiting to mobilize
a platform rig for operations. Accordingly, proved undeveloped reserves in major
fields may be carried for many years. The following table presents our net
ownership interest in proved oil and gas 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 estimated future production from proved
oil and gas reserves. We use year end West Texas Intermediate posted prices per
barrel and Gulf Coast spot market prices or NYMEX Henry Hub futures price per
MMBtu adjusted by property for energy content, quality, transportation fees, and
regional price differentials.

45

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

We estimated the costs based on the prior year costs incurred for
individual properties, or similar properties if a particular property did not
have production during the prior year. Future income tax expense was determined
by applying the current statutory 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.

- ---------------

(1) Based on Netherland, Sewell & Associates' reserve report for January 1,
2004, we estimate that the amount of capital required to convert proved
undeveloped reserves to proved developed reserves will be $107.1 million of
the $140.2 million of future development costs, including $28.2 million in
2004, $30.6 million in 2005 and $15.4 million in 2006. Our actual
expenditures may differ from these estimates. Capital expenditures incurred
to develop proved undeveloped reserves were $28.4 million in 2003, $28.5
million in 2002 and $19.3 million in 2001.

The following table summarizes the principal sources of change in the
standardized measure of discounted future net cash flows from year to year.

46

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 10 -- QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

- ---------------

(1) Net revenues include only oil and gas sales revenue.

(2) Net income during the second quarter of 2002 included a $4.1 million gain on
sale of certain South Texas properties.

47

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.

As recommended by Remington's Audit Committee, Remington's Board of
Directors on April 17, 2002, dismissed Arthur Andersen LLP ("Andersen") as
Remington's independent public accountants and engaged Ernst & Young LLP to
serve as Remington's independent public accountants for 2002.

Andersen's reports on Remington's consolidated financial statements for the
years prior to 2002 did not contain an adverse opinion or disclaimer of opinion,
nor were they qualified or modified as to uncertainty, audit scope or accounting
principles.

During Remington's fiscal year 2001 and through April 17, 2002, there were
no disagreements with Andersen on any matter of accounting principles or
practices, financial statement disclosure, or auditing scope or procedure which,
if not resolved to Andersen's satisfaction, would have caused them to make
reference to the subject matter in connection with their report on Remington's
consolidated financial statements for such years; and there were no reportable
events, as listed in Item 304(a)(1)(v) of Regulation S-K.

ITEM 9A. CONTROLS AND PROCEDURES.

As of the end of the period covered by this report, our management,
including our Chief Executive Officer and our Principal Financial Officer,
evaluated the effectiveness of our disclosure controls and procedures as defined
in Exchange Act Rule 13a-15(e). Based on that evaluation, our management,
including the Chief Executive Officer and the Principal Financial Officer,
concluded that our disclosure controls and procedures were effective as of the
end of the period covered by this report. Further, during the period covered by
this report, there was no significant change in internal controls over financial
reporting that has materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

We have adopted a code of ethics (our "Code of Business Conduct and Ethics"
previously filed with the Commission and accessible on our website) that applies
to all directors and employees including our Chief Executive Officer, Principal
Financial Officer, and Principal Accounting Officer.

The remainder of the information required by Item 10, Directors and
Executive Officers of the Registrant, will be included in our definitive proxy
statement to be filed pursuant to Regulation 14A under the Securities Exchange
Act of 1934 no later than 120 days after the end of the fiscal year covered by
this Form 10-K, and such portion of the proxy statement is hereby incorporated
by reference.

ITEM 11. EXECUTIVE COMPENSATION.

The information required by Item 11, Executive Compensation, will be
included in our definitive proxy statement to be filed pursuant to Regulation
14A under the Securities Exchange Act of 1934 no later than 120 days after the
end of the fiscal year covered by this Form 10-K, and such portion of the proxy
statement is hereby incorporated by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

The information required by Item 12, Security Ownership of Certain
Beneficial Owners and Management, will be included in our definitive proxy
statement to be filed pursuant to Regulation 14A under the Securities Exchange
Act of 1934 no later than 120 days after the end of the fiscal year covered by
this Form 10-K, and such portion of the proxy statement is hereby incorporated
by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

The information required by Item 13, Certain Relationships and Related
Transactions, will be included in our definitive proxy statement to be filed
pursuant to Regulation 14A under the Securities Exchange Act of
48

1934 no later than 120 days after the end of the fiscal year covered by this
Form 10-K, and such portion of the proxy statement is hereby incorporated by
reference.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The information required by Item 14, Principal Accountant Fees and
Services, will be included in our definitive proxy statement to be filed
pursuant to Regulation 14A under the Securities Exchange Act of 1934 no later
than 120 days after the end of the fiscal year covered by this Form 10-K, and
such portion of the proxy statement is hereby incorporated by reference.

PART IV

ITEM 15. 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, 2003 and 2002

(iii) Consolidated Statements of Income for years ended December
31, 2003, 2002 and 2001

(iv) Consolidated Statement of Stockholders' Equity for years ended
December 31, 2003, 2002 and 2001

(v) Consolidated Statements of Cash Flows for the years ended
December 31, 2003, 2002 and 2001

(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.

3. Exhibits

- ---------------

* Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the fiscal year ended December 31, 1997 filed with the Commission on
March 30, 1998.

# Incorporated by reference to the Company's Registration Statement on Form
S-4 (file number 333-61513) filed with the Commission and effective on
November 27, 1998.

+ Incorporated by reference to the Company's Form 10-Q (file number 1-11516)
for the fiscal quarter ended September 30, 1999 filed with the Commission
on November 12, 1999.

** Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the fiscal year ended December 31, 2000 filed with the Commission on
March 16, 2001.

++ Incorporated by reference to the Company's Form 10-Q (file number 1-11516)
for the fiscal quarter ended September 30, 2001 filed with the Commission
and effective on November 9, 2001.

*** Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the fiscal year ended December 31, 2001 filed with the Commission and
effective on March 21, 2002.

### Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the year ended December 31, 2002, filed with the Commission on March
31, 2003.

## Incorporated by reference to the Company's Form 10-Q (file number 1-1156)
for the fiscal quarter ended June 30, 2003, filed with the Commission on
August 11, 2003.

+++ Filed herewith.

50

(b) Reports on Form 8-K:

On October 29, 2003 we filed a form 8-K reporting third quarter
earnings press release under Item 12. Results of Operations and Financial
Condition.

On December 19, 2003, we filed a form 8-K reporting under Item 5.
Other Events, our press release containing information about our $200
million shelf registration being declared effective.

51

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.

REMINGTON OIL AND GAS CORPORATION

By: /s/ JAMES A. WATT
--------------------------------------
James A. Watt
President and Chief Executive Officer

Date: March 11, 2004

Pursuant to the requirements of the Securities Exchange 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:

/s/ JOHN E. GOBLE, JR. /s/ WILLIAM E. GREENWOOD /s/ ROBERT P. MURPHY
- --------------------------------------- --------------------------------------- ---------------------------------------
John E. Goble, Jr. William E. Greenwood Robert P. Murphy
Director Director Director

/s/ DAVID E. PRENG /s/ ALAN C. SHAPIRO
- --------------------------------------- --------------------------------------- ---------------------------------------
David E. Preng Thomas W. Rollins Alan C. Shapiro
Director Director Director

/s/ JAMES A. WATT
- ---------------------------------------
James A. Watt
Director

OFFICERS:

/s/ JAMES A. WATT /s/ J. BURKE ASHER /s/ EDWARD V. HOWARD
- --------------------------------------- --------------------------------------- ---------------------------------------
James A. Watt J. Burke Asher Edward V. Howard
President and Vice President/Finance (Principal Vice President/Controller (Principal
Chief Executive Officer Financial Officer) Accounting Officer)

Date: March 11, 2004

52

EXHIBIT INDEX