REMINGTON OIL & GAS CORP - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

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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, 2001

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

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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 identification no.)
incorporation or organization)
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. [ ]

The aggregate market value of voting stock held by non-affiliates of the
registrant on March 18, 2002, was $315,063,669. On that date, the number of
outstanding shares, $0.01 par value, was 22,776,412.

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

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

REMINGTON OIL AND GAS CORPORATION

TABLE OF CONTENTS

1

PART I

ITEM 1. BUSINESS.

GENERAL

Remington Oil and Gas Corporation

- Incorporated -- 1991, Delaware

- Address -- 8201 Preston Road, Suite 600, Dallas, Texas 75225-6211

- Telephone number -- (214) 210-2650

- 28 employees on December 31, 2001

We began operations in 1981 as OKC Limited Partnership. In 1992, the
limited partnership was converted into a corporation named Box Energy
Corporation. In 1997, we changed the name of the company to Remington Oil and
Gas Corporation. We restructured our two classes of common stock into a single
class of voting common stock when we merged with S-Sixteen Holding Company in
December 1998.

Our primary business operation is the exploration, development, and
production of oil and gas reserves in the offshore Gulf of Mexico and onshore
Gulf Coast areas.

LONG-TERM STRATEGY

Our long-term strategy is to increase our oil and gas reserves and
production while keeping our finding and development costs and operating costs
competitive with our industry peers.

ACTIVITIES AND OPERATIONS

We identify prospective oil and gas properties primarily by using 3-D
seismic technology. After acquiring an interest in a prospective property, we
drill one or more exploratory wells. If the exploratory wells find commercial
oil and/or gas, we complete the wells and begin producing the oil or gas.
Because most of our operations are located in the offshore Gulf of Mexico, we
must install facilities such as offshore platforms and gathering pipelines in
order to produce and deliver the oil and gas to our various markets. Certain
properties require us to drill additional wells to fully develop the oil and gas
reserves on our discoveries. In order to increase our oil and gas reserves and
production, we continually reinvest the net cash flow from our operations into
new or existing exploration, development and acquisition activities.

We share ownership in many of our in oil and gas properties with various
industry partners. We currently operate 45 of our offshore properties, while
others operate the remainder of our properties. As operator, we are able to
maintain a greater degree of control over timing and amount of capital
expenditures.

RISKS INVOLVED IN EXPLORATION, DEVELOPMENT, AND PRODUCTION

Exploration, development, and production operations can be very risky. Each
time we drill a well, there is a risk that the well will not find oil or gas
reserves. Even if we find reserves in a well, there is the risk that we will not
be able to produce enough oil or gas to return a profit on the amount invested
in the well. We attempt to reduce these risks by using 3-D seismic data or other
applied technology to identify and define the parameters prior to drilling,
although this does not guarantee successful results. Our success depends upon
the quality of the information used to determine drilling locations and the
abilities and experience of our management, technical, and service personnel.

Additional operating risks include mechanical failure, title risk,
blowouts, environmental pollution, and personal injury. We maintain both general
liability insurance and activity specific insurance against major production
losses, blowouts, redrilling, and many other operating hazards, including
certain pollution risks. Uninsured losses or losses and liabilities that exceed
the limits of our insurance could adversely affect our financial condition.

2

COMPETITION IN THE OIL AND GAS INDUSTRY

We compete with:

- Large integrated oil and gas companies

- Independent exploration and production companies

- Private individuals

- Sponsored drilling programs

We compete for:

- Operational, technical, and support staff

- Options and/or leases on properties

- Sales of oil and gas production

- Access to capital

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

MARKETS FOR OIL AND GAS PRODUCTION

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

- Changes in supply and demand

- Changes in refinery utilization

- Levels of economic activity throughout the country

- Seasonal or extraordinary weather patterns

- Political developments throughout the world

We have no real ability to influence or predict the market prices.
Therefore, we normally sell our oil and gas production based on posted market
prices, spot market indices, or prices derived from the posted price or index.
At times we will lock in a fixed price for a portion of our future gas
production to be delivered as it is produced. An independent marketing company
sells almost all of our gas production and a small quantity of our oil
production from the Gulf of Mexico. The revenue from the sale of oil and gas by
this marketing company accounted for approximately 65% of our total oil and gas
revenues in 2001. In addition, we sold approximately 56% of our total oil
production to one company during the year, which accounted for approximately 14%
of our total oil and gas revenues in 2001.

GOVERNMENTAL REGULATION OF OIL AND GAS OPERATIONS AND ENVIRONMENTAL
REGULATIONS

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

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

Our oil and gas operations are subject to stringent federal, state, and
local environmental laws and regulations. Environmental laws and regulations are
complex, change frequently, and have tended to become more stringent over time.
Many environmental laws require permits from governmental authorities before
construction on a project may be commenced or before wastes or other materials
may be discharged into the environment. The process for obtaining necessary
permits can be lengthy and complex, and can sometimes result in the
establishment of permit conditions that make the project or activity for which
the permit was sought either unprofitable or otherwise unattractive. Even where
permits are not required, compliance with environmental laws and regulations can
require significant capital and operating expenditures, and we may be required
to incur costs to remediate contamination from past releases of wastes into the
environment. Failure to comply with these statutes, rules and regulations may
result in the assessment of administrative, civil and even criminal penalties.
The most significant environmental obligations applicable to our operations
relate to compliance with the federal Oil Pollution Act and the Clean Water Act.
The Oil Pollution Act and its implementing regulations (OPA) establish
requirements for the prevention of oil spills and impose liability for damages
resulting from spills into waters of the United States. OPA also requires
operators of offshore oil production facilities, such as our facilities in the
Gulf of Mexico, to demonstrate to the U.S. Minerals Management Service that they
possess at least $35 million in financial resources that are available to pay
for costs that may be incurred in responding to an oil spill. The Clean Water
Act and its implementing regulations impose restrictions and strict controls on
the discharge of wastes into waters of the United States, including discharges
of oil, produced water and sand, drilling fluids, drill cuttings, and other
wastes typically generated by the oil and gas industry. Although we believe that
we are in compliance with the requirements of OPA, the Clean Water Act and other
statutes governing the discharge of materials into the environment, the cost of
compliance with this federal and state legislation could have a significant
impact on our financial ability to carry out our oil and gas operations.

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

OTHER BUSINESS INFORMATION

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

ITEM 2. PROPERTIES.

We concentrate our principal operations in the federal waters of the Gulf
of Mexico and its coastal regions. In addition to the information below, we
encourage you to read "Management's Discussion and Analysis of Financial
Condition and Results of Operations" found on pages 9 through 15 and
"Consolidated Financial Statements and Notes to Consolidated Financial
Statements" found on pages 17 through 37. Note 2 -- Oil and Gas Properties and
Note 9 -- Oil and Gas Reserves and Present Value Disclosures in our Notes to
Consolidated Financial Statements provide detailed information concerning costs
incurred, proved oil and gas reserves, and discounted future net revenue for
proved reserves.
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LEASEHOLD ACREAGE

Our leasehold acreage of proved and unproved properties at December 31,
2001, was as follows:

PROVED OIL AND GAS RESERVES

Net proved oil and gas reserves at December 31, 2001, as evaluated by
Netherland, Sewell, & Associates, Inc., are summarized below on the following
table. The quantities of proved oil and gas reserves discussed in this section
include only the amounts which we reasonably expect to recover in the future
from known oil and gas reservoirs under the current economic and operating
conditions. Proved reserves include only quantities that we expect to recover
commercially using current prices, costs, existing regulatory practices and
technology. Therefore, any changes in future prices, costs, regulations,
technology or other unforeseen factors could materially increase or decrease the
proved reserve estimates.

PRODUCING PROPERTIES

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

Our offshore Gulf of Mexico properties account for approximately 64% of our
oil production and approximately 89% of our gas production. In addition, total
revenues from offshore Gulf of Mexico oil and gas production during 2001
accounted for approximately 84% of our total oil and gas revenues. We owned
varying working interests (5% to 100%) in 72 offshore Gulf of Mexico blocks at
December 31, 2001, and currently produce from 20 of these blocks with 8
additional blocks currently under development. We operate 10 of the total 28
producing blocks. All of these blocks are located in water depths of less than
600 feet on the outer continental shelf of the Gulf of Mexico. In addition, we
have invested in long-term 3-D seismic licensing agreements covering
approximately 2,700 blocks in this area. Our agreements combined with our
computer technology, provide our technical team immediate in-house access to
these seismic data.
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During 2001 we successfully drilled and completed 13 exploratory wells on
12 different properties in the offshore Gulf of Mexico. In addition, we, as
operator, constructed and installed or will install eight production platforms
and drilled and completed two development wells on two different properties.

Our onshore Gulf Coast area properties are principally located in the state
of Mississippi and along the Texas gulf coast. In 2001, these properties
accounted for approximately 36% of our oil production and approximately 11% of
our gas production. We drilled a total of 19 wells on our onshore properties
during 2001 and completed 14 wells as producers. Our working interests in these
wells range from 15% to 50%.

DRILLING ACTIVITIES

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

We had an interest in 2 wells (0.80 net) in progress at December 31, 2001,
2 wells (0.65 net) in progress at December 31, 2000, and 7 wells (2.73 net) in
progress at December 31, 1999.

OTHER PROPERTY AND OFFICE LEASE

We own several non-contiguous tracts of land covering approximately 3,500
surface acres in Southern Louisiana and Southern Mississippi. Outside parties
lease several of the tracts for farming, grazing, timber, sand and gravel,
camping, hunting, and other purposes. Gross revenues from these real estate
properties in 2001 totaled $134,000. We lease approximately 17,000 square feet
of office space in Dallas, Texas. The lease on this office space expires in
April 2008.

ITEM 3. LEGAL PROCEEDINGS.

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

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

None

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PART II

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

Our common stock trades on the Nasdaq National Market under the symbol ROIL
and on the Pacific Exchange under the symbol REM.P. The following table sets
forth the high and low last sales price per share as reported by Nasdaq for the
periods indicated.

On March 18, 2002, the last reported sales price for our common stock was
$18.85 per share. On that date, there were 771 stockholders of record, including
123 stockholders of record of class A common stock and 254 stockholders of
record of class B common stock who had not yet surrendered their old stock for
the new common stock to which they are entitled.

We have not declared or paid any cash dividends during the past nine years.
Our credit facility agreements prohibit our paying dividends. The determination
of future cash dividends, if any, will depend upon, among other things, our
financial condition, cash flow from operating activities, the level of our
capital and exploration expenditure needs, future business prospects, and
renegotiations of our line of credit.

7

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 2001 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, for 2000 include $12.5 million gain
on sale of certain South Texas properties, and for 1998 include $49.8
million in other income from the termination of our gas sales contract and
an $18.0 million charge recorded for the Phillips Petroleum judgment. The
net loss in 1997 includes a $14.6 million deferred income tax expense that
we recorded when we increased the valuation allowance against the deferred
income tax asset originally recorded in 1992.

(2) The quantities of proved oil and gas reserves discussed in this table
include only the amounts which we reasonably expect to recover in the future
from known oil and gas reservoirs under the current economic and operating
conditions. Proved reserves include only quantities that we can commercially
recover using current prices, costs, existing regulatory practices and
technology. Therefore, any changes in future prices, costs, regulations,
technology, or other unforeseen factors could significantly increase or
decrease the proved reserve estimates.

8

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.

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

LONG-TERM STRATEGY AND BUSINESS DEVELOPMENTS

Our long-term strategy is to increase our oil and gas production and
reserves while keeping our operating costs and our finding and development costs
competitive with our industry peers. Over the last three years, we have invested
$224.8 million in oil and gas properties, found 190.0 Bcfe of proved reserves
and replaced 265% of our production at a finding and development cost of $1.18
per Mcfe. The following table reflects our results during the last three years.

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(1) Barrels of oil are converted to Mcf equivalents at the ratio of 1 barrel of
oil equals 6 Mcf of gas.

(2) Production costs include operating, transportation and Net Profits expense.

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

CRITICAL ACCOUNTING POLICIES

We prepare our consolidated financial statements for inclusion in this
report using accounting principles that are generally accepted in the United
States ("GAAP"). Our Notes to Consolidated Financial Statements included on
pages 23 through 37 in this report have a more comprehensive discussion of our
significant accounting policies. GAAP represents a comprehensive set of
accounting and disclosure rules and requirements. We must make judgments,
estimates, and in certain circumstances, choices between acceptable GAAP
alternatives as we apply these rules and requirements.

Successful Efforts Method of Accounting

Oil and gas exploration and production companies choose one of two
acceptable accounting methods -- successful-efforts or full cost. The most
significant difference between the two methods relates to the

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accounting treatment of drilling costs for unsuccessful exploration wells ("dry
holes") and exploration costs. Under the successful efforts method, we recognize
exploration costs and dry hole costs as an expense on the income statement when
incurred and capitalize the costs of successful exploration wells as oil and gas
properties. Entities that follow the full cost method capitalize all drilling
and exploration costs including dry hole costs into one pool of total oil and
gas property costs.

We use the successful efforts method because we believe that it more
conservatively reflects on our balance sheet historical costs that have future
value. However, using successful-efforts often causes our income statement to
fluctuate significantly between reporting periods based on our success or
failure during the periods.

Proved Reserve Estimates

Unaffiliated reserve engineers prepare our oil and gas reserve estimates
using guidelines put forth under GAAP and by the Securities and Exchange
Commission. The quality and quantity of data, the interpretation of the data,
and the accuracy of mandated economic assumptions combined with the judgment
exercised by the reserve engineers affect the accuracy of the estimated
reserves. In addition, drilling or production results after the date of the
estimate may cause material revisions to the reserve estimates. You should not
assume that the present value of the future net cash flow disclosed in this
report reflects the current market value of the oil and gas reserves. In
accordance with the Securities and Exchange Commission's guidelines, we use
prices and costs determined on the date of the estimate and a 10% discount rate
to determine the present value of future net cash flow. Actual prices and costs
may vary significantly and the discount rate may or may not be appropriate based
on outside economic conditions.

Depletion, Depreciation, and Amortization of Oil and Gas Properties

We calculate depletion, depreciation, and amortization expense ("DD&A")
using the estimates of proved oil and gas reserves. We segregate the costs for
individual or contiguous properties or projects and record DD&A of these
property costs separately using the units of production method. Material
downward revisions in reserves increase the DD&A per unit and reduce net income;
likewise, material upward revisions lower the DD&A per unit and increase net
income.

Impairment of Oil and Gas Properties

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

The above critical accounting policies can cause our net income to vary
significantly from period to period as events or circumstances which trigger
recognition as an expense for unsuccessful wells or impaired properties cannot
be accurately forecast. In addition, selling prices for our oil and gas
fluctuate significantly. Therefore, to manage the company we focus more on cash
flow from operations and on controlling our finding and development, operating,
administration, and financing costs.

Accounting for Stock Based Compensation

In June 1999, the Board of Directors approved a contingent stock grant to
our employees and directors. In order for the grant to become effective, the
price of our stock had to increase from $4.19 per share to a trigger price of
$10.42 per share and close at or above $10.42 per share for 20 consecutive
trading days. When the
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Board of Directors approved the grant we did not record any amounts for expense,
liability, or equity because the measurement date for determining the
compensation cost depended on the occurrence of an event after the date of
grant. Therefore, we could not be sure that we would incur any expense as a
result of the grant, and we could not reasonably estimate the amount of possible
expense.

January 24, 2001, became the measurement date when the stock price closed
above the trigger price for the twentieth consecutive trading day. On that date,
we measured the total compensation cost at $8.1 million which was the total
number of shares granted multiplied by the market price on that date. We
recorded $8.1 million as restricted common stock, $5.7 million as unearned
compensation reported as a separate reduction in stockholders' equity on the
balance sheet, and $2.4 million as stock based compensation expense. The $2.4
million stock based compensation expense recorded in the first quarter of 2001
included a "catch up" amortization from the date of the grant to the measurement
date of the total compensation cost because the cost should be recognized over
the time period in which the stock grant vested to the employees or directors.
We will amortize the remaining $5.7 million compensation expense over the next
five years as the shares vest. The vesting period could accelerate in the event
of a change in control of the company or the death or permanent disability of an
employee. A shorter vesting period would accelerate the amortization period.
Except as noted above, the shares will be issued only to the extent the
employees and directors remain with the company through the vesting dates.

In accounting for stock options granted to employees and directors, we have
chosen to continue to apply the accounting method promulgated by Accounting
Principles Board Opinion No. 25 ("APB 25") rather than apply an alternative
method permitted by Statement of Financial Accounting Standards No. 123 ("FAS
123"). Under APB 25, we do not record compensation expense on our income
statement for stock options granted to employees or directors. If we applied an
alternative method permitted by FAS 123, our net income would be lower than
actually reported. We disclose in our Notes to Consolidated Financial Statements
the pro-forma effect on our income statement if we were to record the estimated
fair value of stock options on the date granted and amortize the expense over
the expected vesting of the grant. We chose the APB 25 method because we believe
that the use of the APB 25 method makes our financial presentation easier to
compare to the financial presentations of other publicly held companies, most of
whom we believe also use the APB 25 method.

LIQUIDITY AND CAPITAL RESOURCES

The following table summarizes our contractual obligations and commercial
commitments as of December 31, 2001.

(A letter of credit in the amount of $536,000 was issued against our bank
credit facility on March 15, 2002.)

On December 31, 2001, our current assets exceeded our current liabilities
by $2.8 million. Our current ratio was 1.08 to 1.00.

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Cash flow from operations for the year ended December 31, 2001, before
changes in working capital, increased by $9.0 million, or 14%, compared to the
prior year primarily because of increased gas revenues partially offset by the
$13.5 million expense for the Phillips Petroleum settlement and increased
production costs from new properties. Gas sales increased by $33.7 million, or
66%, because of a 65% increase in gas production and a slight increase in the
average price.

We incurred capital and exploration expenditures totaling $122.8 million
during 2001. The capital expenditures included $46.8 million for exploration
costs, $61.1 million for development costs and $14.9 million for the acquisition
of properties including the South Pass 89 net profits interest from Phillips
Petroleum. During the year, we built and installed, or will install in 2002,
eight offshore platforms and facilities. In addition, we drilled 15 exploration
wells and 2 development wells in the Gulf of Mexico and 12 exploration wells and
7 development wells in Mississippi and South Texas.

We expect to continue to make significant capital expenditures over the
next several years as part of our long-term growth strategy. We have budgeted
$75.0 million for capital expenditures in 2002. Our 2002 capital and exploration
budget includes $37.0 million for 26 exploratory wells. We project that we will
spend $32.0 million on 16 wells in the Gulf of Mexico and $5.0 million on 10
onshore wells in South Texas and Mississippi. The budget also includes $20.0
million for platforms and development drilling on operated discoveries at Eugene
Island 302, South Marsh Island 93, East Cameron 179/184, West Cameron 417, and
one non-operated development at Eugene Island 397. The remaining $18.0 million
will be allocated to leasing, seismic acquisitions, and workovers. We expect
that our cash, estimated future cash flow from operations, and available bank
line of credit will be adequate to fund these expenditures for the remainder of
2002.

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

As of December 31, 2001, our amended credit facility has a borrowing base
of $75.0 million. As of March 18, 2002, we had $71.0 million borrowed under the
facility, and an additional $536,000 of credit availability was utilized to
issue a letter of credit. The banks review the borrowing base semi-annually and
may increase or decrease the borrowing base at their discretion relative to the
new estimate of proved oil and gas reserves. The next redetermination is
scheduled for April 2002. Our oil and gas properties are pledged as collateral
for the line of credit. Additionally, we have agreed not to pay dividends.
Unless renewed or extended, the line of credit expires on May 3, 2004, when all
principal becomes due.

The most significant financial covenants in the line of credit include,
among others, maintaining a minimum current ratio of 1.0 to 1.0, a minimum
tangible net worth of $85.0 million plus 50% of future net income and 100% of
any non-redeemable preferred or common stock offerings, and interest coverage of
3.0 to 1.0. We are currently in compliance with these financial covenants in all
material respects. If we don't comply with these covenants, the lenders have the
right to refuse to advance additional funds under the facility and/or declare
all principal and interest immediately due and payable.

On May 22, 2001, we settled the litigation with Phillips Petroleum Company
and acquired Phillips' Net Profits Interest in South Pass block 89, offshore
Louisiana. We paid $21.3 million cash and issued 1,189,344 shares of our common
stock as consideration for the settlement and assignment of the net profits
interest. Subsequently, Phillips sold 33,900 shares on the open market, and we
purchased the remaining 1,155,444 shares at a total cost of $20.6 million.

The shares issued to Phillips were issued under a $110.0 million shelf
registration filed with the Securities and Exchange Commission, the proceeds of
which may be used for general corporate purposes. A substantial majority of the
shares available under the shelf registration are unissued and are subject to
being drawn down at the discretion of the company based on market prices and
conditions.

During 2001, holders of $5.785 million face amount of the 8 1/4%
convertible notes due December 1, 2002, converted their notes into common stock
at the prescribed conversion ratio of one share of common stock for
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each $11.00 of principal amount of notes. We redeemed the remaining $95,000 of
the notes for cash at a call price of 101.65%.

RESULTS OF OPERATIONS

In 2001, we recorded net income totaling $8.4 million or $0.38 basic income
per share, and $0.35 diluted income per share, compared to a net income of $45.0
million or $2.10 basic income per share and $1.99 diluted income per share in
2000. The decrease in net income resulted primarily from the settlement expense
related to the Phillips Petroleum litigation and higher dry hole and impairment
costs. In addition, net income for 2000 includes a $12.5 million gain for the
sale of certain South Texas properties.

The following table discloses the net oil and gas production volumes,
sales, and sales prices for each of the three years ended December 31, 2001,
2000, and 1999. The table is an integral part of the following discussion of
results of operations for the periods 2001 compared to 2000 and 2000 compared to
1999.

2001 compared to 2000

Oil production increased by 2% in 2001 compared to the prior year because
of a 15% increase in offshore Gulf of Mexico production partially offset by
lower oil production from Mississippi and South Texas. Oil production from the
Gulf of Mexico increased because of new wells that began producing in 2001.
Average oil prices decreased 15% during 2001 which in turn caused oil revenues
to be $5.1 million lower.

Gas revenue increased by $33.7 million or 66% because of a 65% increase in
production compared to 2000. Production from the offshore Gulf of Mexico
increased by 8.6 Bcf, or 83%, while gas production from South Texas decreased by
0.4 Bcf, or 7%. Five offshore properties began to produce for the first time
during 2001 and three additional offshore properties increased their production
significantly either from new wells drilled and completed or because 2001 was
their first full year of production. We expected the decrease in production from
South Texas after we sold certain properties in 2000. The change in average
prices did not affect total gas revenues significantly.

Interest income decreased by $467,000, or 32% because of lower rates earned
on our short-term investments and because we used the $9.0 million of restricted
cash previously set aside for the Phillips Petroleum judgment in the settlement
of that litigation in May 2001. Other income decreased because we had a
non-recurring $12.5 million gain from the sale of South Texas properties in
2000.

13

Operating costs and expenses increased by $4.9 million, or 46%, because of
new producing properties. However, operating expenses per Mcfe increased to
$0.53 from $0.52, or less than 2%. Exploration expenses increased by $5.4
million, or 70%, because of increased dry hole costs for two offshore and one
onshore well compared to six onshore wells in 2000. Offshore wells typically are
significantly more costly than the onshore wells. The impairment expense for
2001 primarily resulted from insufficient future net cash flow for three
offshore Gulf of Mexico properties, which accounted for $8.7 million, one South
Texas property which accounted for $1.3 million, and one unproved offshore Gulf
of Mexico property lease that was forfeited in 2002 which accounted for
$616,000. Depreciation, depletion and amortization expense increased by $17.3
million because of production from new properties.

General and administrative expenses have remained substantially level with
prior year amounts. Stock based compensation expense includes $3.5 million for
amortization of compensation costs related to the contingent stock grant and
$246,000 for stock based directors fees.

On May 22, 2001, we settled the litigation with Phillips Petroleum Company.
Of the total $42.5 million settlement, we had previously recorded $20.2 million
as an accrued liability. We recorded $12.3 million of the remaining $22.3
million as additional settlement expense and capitalized $10.0 million as the
cost for our purchase of the net profits interest. In addition, we charged the
remaining $1.2 million deferred net profits expense related to a royalty
settlement in 2000 to the settlement expense. During 2000, we reached two
separate agreements with the Minerals Management Service concerning the
royalties due on offshore Gulf of Mexico properties. Because of the agreements,
we recorded expenses of $5.4 million during 2000.

Interest and financing costs decreased 16% because of lower interest rates
applicable to our outstanding debt and because we are no longer accruing
interest on the Phillips judgment.

During 2001, we recorded income tax expense totaling $3.6 million, all of
which is deferred. We fully utilized our net deferred income tax benefit during
2000 and the first quarter of 2001.

2000 compared to 1999

Oil production increased slightly compared to 1999 because of increased
production from Mississippi partially offset by lower oil production from the
Gulf of Mexico. Oil production from Mississippi increased by 179,000 barrels, or
79%, during 2000 because of several new successful wells drilled during the
year. The average oil price increased by 75% during 2000 compared to the prior
year.

Gas production increased by 30% during 2000 compared to 1999 primarily from
gas produced from the Gulf of Mexico and South Texas. Gas production from the
Gulf of Mexico increased by 2.1 Bcf, or 26%, and gas production from South Texas
increased by 714,000 Mcf, or 42%, during 2000. The increase resulted from
several successful wells drilled during the year. The average gas price
increased by 64% during 2000 compared to 1999.

Other income increased by $11.9 million because we recorded a $12.4 million
gain on the sale of certain South Texas properties in August 2000, partially
offset by lower oil trading income.

Operating expenses increased during the year 2000 compared to 1999, mainly
due to the increased number of producing properties and an increase in workover
expenses mostly related to West Cameron 170 and Eugene Island 135. Exploration
expense increased by $108,000 during 2000 primarily because of slightly higher
dry hole costs in 2000. Depreciation, depletion, and amortization expense
increased by $196,000 during 2000 compared to the prior year largely as a result
of increased production partially offset by lower finding costs per unit during
the last three years. Impairment expense for the year 2000 primarily includes
the costs for expired unproved properties compared to impairment expense for the
year 1999 that included additional impairments for Main Pass 262 and two small
onshore properties.

Legal expenses decreased $780,000, or 53%, because we settled both the
Minerals Management Service issues and the minority stockholders litigation
during the year, and we incurred lower costs related to the Phillips litigation.
During 2000, we reached two separate accords with the Minerals Management
Service concerning the alleged underpayment of oil and gas royalties. The first
agreement reached in May 2000,

14

concerned additional royalties asserted to be due on the settlement of
litigation related to a 1990 gas sales contract. Because of this agreement, we
recorded an expense of $3.2 million in the first quarter of 2000. As to the
second accord, we reached an agreement in October 2000 to settle the issues
concerning oil transportation charges and oil exchange contracts for $2.2
million.

NEW ACCOUNTING PRONOUNCEMENTS

On January 1, 2001, we adopted Statement of Financial Accounting Standards
133 "Accounting for Derivative Instruments and Hedging Activities" which
requires that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded on the balance sheet as
either an asset or liability measured at its fair value. The statement requires
that changes in fair value be recorded currently in net income unless specific
hedge accounting criteria are met. The definition of derivative contracts has
also been expanded to include contracts that require physical delivery of oil
and gas if the contract allows for net cash settlement. We do not utilize any
derivative instruments that fall under the criteria defined in the accounting
standard and therefore the adoption of this statement did not have any effect on
our reported financial statements or disclosures.

Statement of Financial Accounting Standards No. 143 "Accounting for Asset
Retirement Obligations" will be effective for years beginning after June 15,
2002. The statement requires that we estimate the fair value for our asset
retirement obligations (dismantlement and abandonment of oil and gas wells and
offshore platforms) in the period in which the asset is first placed in service.
Currently we accrue the estimated liability for dismantlement and abandonment
over the life of the property using a unit of production method. Because of this
new standard, effective January 1, 2003, we must increase both our recorded
assets and liabilities by the estimated cost of the ultimate asset retirement
obligation. For properties owned at December 31, 2001, we estimate that amount
to be $10.6 million. We will then discount the amount to present value, and on a
periodic basis record the accretion of discount. We will also amortize the cost
into depletion, depreciation, and amortization expense. The charges to the
income statement will not be materially different under this standard as
compared to our present method.

In August 2001, Financial Accounting Standards Board issued the Statement
of Financial Accounting Standards No. 144 "Accounting for the Impairment or
Disposal of Long-Lived Assets" which supercedes Statement of Financial
Accounting Standards No. 121 "Accounting for Impairment of Long-Lived Assets."
The Statement addresses financial accounting and reporting for the impairment or
disposal of long-lived assets. The statement is effective for periods beginning
after December 15, 2001. We do not believe that the adoption of this statement
will have a material effect on our balance sheet or income statement.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

INTEREST RATE RISK

Our market risk sensitive instrument at December 31, 2001, is a revolving
bank line of credit. At December 31, 2001, the unpaid principal balance under
the line was $71.0 million which approximates its fair value. The interest rate
on this debt is based on a premium of 150 to 225 basis points over the London
Interbank Offered Rate ("Libor"). The rate is reset periodically, usually every
three months. If on December 31, 2001, Libor changed by one full percentage
point (100 basis points) the fair value of our revolving debt would change by
approximately $175,000. We have not entered into any interest rate hedging
contracts.

COMMODITY PRICE RISK

Occasionally we sell forward portions of our production under physical
product delivery contracts that by their terms cannot be settled in cash or
other financial instruments. Such contracts are not subject to the provisions of
Statement of Financial Accounting Standards No. 133 "Accounting for Derivative
Instruments and Hedging Activities." Accordingly we do not provide sensitivity
analysis for such contracts. For the period January 1, 2002, through June 30,
2002, we have physical delivery contracts in place to sell approximately

15

20,000 MMBtu of gas per day (approximately 1/3 of our projected gas production
for that six month period) at a price of approximately $2.77 per MMBtu.

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

16

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

INDEX TO FINANCIAL STATEMENTS

Report of Independent Public Accountants.................... 18
Consolidated Balance Sheets as of December 31, 2001 and
2000...................................................... 19
Consolidated Statements of Income for 2001, 2000, and
1999...................................................... 20
Consolidated Statements of Stockholders' Equity for 2001,
2000, and 1999............................................ 21
Consolidated Statements of Cash Flows for 2001, 2000, and
1999...................................................... 22
Notes to Consolidated Financial Statements.................. 23

17

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

18

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED BALANCE SHEETS

See accompanying Notes to Consolidated Financial Statements.
19

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

See accompanying Notes to Consolidated Financial Statements.
20

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

See accompanying Notes to Consolidated Financial Statements.
21

REMINGTON OIL AND GAS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying Notes to Consolidated Financial Statements.
22

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION

Remington Oil and Gas Corporation, formerly Box Energy Corporation, is an
independent oil and gas exploration and production company incorporated in
Delaware. We have working interest ownership rights in properties in the
offshore Gulf of Mexico and onshore Gulf Coast. We own the following
subsidiaries: CKB Petroleum, Inc., CKB & Associates, Inc., Box Brothers Realty
Investments Company, CB Farms, Inc., and Box Resources, Inc. We eliminated all
inter-company transactions and account balances for the periods of
consolidation. The primary operating subsidiary, CKB Petroleum, Inc., owns an
undivided interest in a pipeline that transports oil from our South Pass blocks,
offshore Gulf of Mexico, to Venice Louisiana.

USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS

Management prepares the financial statements in conformity with accounting
principles generally accepted in the United States. This requires estimates and
assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reported periods. Some of the more significant estimates
include oil and gas reserves, useful lives of assets, impairment of oil and gas
properties, and future dismantlement and restoration liabilities. Actual results
could differ from those estimates. We make certain reclassifications to prior
year financial statements in order to conform to the current year presentation.

CASH, CASH EQUIVALENTS, AND RESTRICTED CASH

Cash equivalents consist of highly liquid investments that mature within
three months or less when purchased. Our cash equivalents include investment
grade commercial paper and institutional money market funds. We record cash
equivalents at cost, which approximates their market value at the balance sheet
date.

On December 31, 2000, we had $9.0 million set aside as restricted cash with
a surety company as collateral for the suspensive appeal bond for the Phillips
litigation. After the Phillips Petroleum settlement in May 2001, the surety
company returned the $9.0 million to us.

PROPERTY AND EQUIPMENT

We follow the successful-efforts method to account for oil and gas
exploration and development expenditures. Under this method, we capitalize
expenditures for leasehold acquisitions, drilling costs for productive wells and
unsuccessful development wells. We amortize the capitalized costs using the
units-of-production method, converting to gas equivalent units by using the
ratio of 6 barrels of oil equal to one thousand cubic feet of gas. Future
dismantlement, restoration and abandonment costs include the estimated costs to
dismantle, restore, and abandon our offshore platforms, wells, and related
facilities. We accrue for the liability over the life of the property using the
units-of-production method and record the expense as a component of
depreciation, depletion and amortization expense. As of December 31, 2001, the
total estimated liability of our future dismantlement and restoration costs is
$10.6 million. The accrued liability at December 31, 2001 and 2000, was $4.3
million and $4.6 million, respectively. We record expenditures for geological,
geophysical or other prospecting costs as exploration expenses on the income
statement when incurred.

Periodically, if there is a large decrease in oil and gas reserves or
production on a property, or if a dry hole is drilled on or near one of our
properties we will review the properties for impairment. In addition,
significant decreases in long-term oil and gas prices may also indicate that a
property has become impaired. If the net book value of a property is greater
than the estimated undiscounted future net cash flow from the same property, the
property is considered impaired. We base our assessment of possible impairment
using our best estimate of future prices, costs and expected net cash flow
generated by a property. The impairment expense is
23

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

equal to the difference between the net book value and the fair value of the
asset. We estimate fair value by discounting, at an appropriate rate, the future
net cash flows from the property. In addition, we assess the capitalized costs
of unproved properties periodically to determine whether their value has been
impaired below the capitalized costs. We recognize a loss to the extent that
such impairment is indicated. In making these assessments, we consider factors
such as exploratory drilling results, future drilling plans, and lease
expiration terms.

Other properties include improvements on the leased office space and office
computers and equipment. The company depreciates these assets using the
straight-line method over their estimated useful lives that range from 3 to 12
years.

OTHER ASSETS

Other assets include the net unamortized credit facility origination fees
and a long-term account receivable. The origination fees are amortized on a
straight-line basis over the term of the debt. We charge the amortized amount to
interest and financing costs. The long-term account receivable totaling $354,000
is CKB Petroleum's claim under Collateral Assignment Split Dollar Insurance
Agreements among CKB Petroleum and Don D. Box (an officer and director) and two
of his brothers.

OIL AND GAS REVENUES

We recognize oil and gas revenue in the month of actual production. Our
actual sales have not been materially different from our entitled share of
production and we do not have any significant gas imbalances. In 2001, sales by
a gas marketing company accounted for approximately 65% of our total oil and gas
revenue. In addition, we sold approximately 56% of our total oil production to
one company during the year, which accounted for approximately 14% of our total
oil and gas revenues in 2001. We do not believe that the risk of losing services
or sales from either of these companies would have a material adverse effect on
us.

STOCK OPTIONS

We continue to apply the accounting provisions of Accounting Principles
Board Opinion 25, entitled "Accounting for Stock Issued to Employees," and
related interpretations to account for stock-based compensation. Accordingly, we
measure compensation cost for stock options as the excess, if any, of the quoted
market price of our stock at the date of the grant over the amount an employee
must pay to acquire the stock. All of our options are granted with exercise
prices at or above the quoted market price on the date of grant.

SEGMENT REPORTING

We operate in only one business segment.

ADOPTED AND NEW ACCOUNTING POLICIES

On January 1, 2001, we adopted Statement of Financial Accounting Standards
133 "Accounting for Derivative Instruments and Hedging Activities" which
requires that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded on the balance sheet as
either an asset or liability measured at its fair value. The statement requires
that changes in fair value be recorded currently in net income unless specific
hedge accounting criteria are met. The definition of derivative contracts has
also been expanded to include contracts that require physical delivery of oil
and gas if the contract allows for net cash settlement. We do not utilize any
derivative instruments that fall under the criteria defined in the accounting
standard and therefore the adoption of this statement did not have any effect on
our reported financial statements or disclosures.

24

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Statement of Financial Accounting Standards No. 143 "Accounting for Asset
Retirement Obligations" will be effective for years beginning after June 15,
2002. The statement requires that we estimate the fair value for our asset
retirement obligations (dismantlement and abandonment of oil and gas wells and
offshore platforms) in the period in which the asset is first placed in service.
Currently we accrue the estimated liability for dismantlement and abandonment
over the life of the property using a unit of production method. Because of this
new standard, effective January 1, 2003, we must increase both our recorded
assets and liabilities by the estimated cost of the ultimate asset retirement
obligation. For properties owned at December 31, 2001, we estimate that amount
to be $10.6 million. We will then discount the amount to present value, and on a
periodic basis record the accretion of discount. We will also amortize the cost
into depletion, depreciation, and amortization expense. The charges to the
income statement will not be materially different under this standard as
compared to our present method.

In August 2001, Financial Accounting Standards Board issued the Statement
of Financial Accounting Standards No. 144 "Accounting for the Impairment or
Disposal of Long-Lived Assets" which supercedes Statement of Financial
Accounting Standards No. 121 "Accounting for Impairment of Long-Lived Assets."
The Statement addresses financial accounting and reporting for the impairment or
disposal of long-lived assets. The statement is effective for periods beginning
after December 15, 2001. We do not believe that the adoption of this statement
will have a material effect on our balance sheet or income statement.

GENERAL AND ADMINISTRATIVE EXPENSES

We report our general and administrative expenses net of reimbursed
overhead costs that we allocate to working interest owners of the oil and gas
properties that we operate.

INCOME TAXES

Income tax expense or benefit includes both the current income taxes and
deferred income taxes. Current income tax expense or benefit equals the amount
calculated on our income tax return for that year. Deferred income tax expense
or benefit equals the change in the net deferred income tax asset or liability
from the beginning of the year to the end of the year. We determine the amount
of our deferred income tax asset or liability by multiplying the enacted tax
rate by the temporary differences, net operating or capital loss carry-forwards
plus any tax credit carry-forwards. The tax rate used is the effective rate
applicable for the year in which we expect the temporary differences or
carry-forwards to reverse. A valuation allowance offsets deferred income tax
assets that are not expected to reverse in future years.

INCOME PER COMMON SHARE

We compute basic income per share by dividing net income by the weighted
average number of common shares outstanding for the period. Diluted income per
share reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised or converted into common stock or
resulted

25

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

in the issuance of common stock that then shares in the net income of the
company. The following table presents our calculation of basic and diluted
income per share.

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

(1) Non dilutive in 1999.

NOTE 2 -- OIL AND GAS PROPERTIES

The following table summarizes the capitalized costs on our oil and gas
properties, all of which are located in the United States.

26

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

We recognized impairment expenses as follows in the table below:

The impairment of unproved properties for each of the three years primarily
resulted from the actual or impending forfeiture of leaseholds.

The impairment expense on proved properties for 2001 primarily resulted
from insufficient future net cash flows based on the proved developed reserves
as determined by our independent oil and gas engineers. In order to determine
the amount of impairment on certain properties, we used NYMEX 12 month strip
prices adjusted for location and basis differences for our estimate of the
future prices and escalated both the prices and the costs at 3% per year. Three
proved properties in the offshore Gulf of Mexico accounted for $8.7 million and
one proved property in South Texas accounted for $1.3 million of the total $10.0
million. The impairment expense on proved properties for 2000 resulted from
insufficient oil and gas reserves on one small property in Alabama and in 1999
included $852,000 for a platform located on Main Pass 262 in the Gulf of Mexico.

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

CONVERTIBLE NOTES

During 2001, holders of $5.785 million face amount of the 8 1/4%
convertible notes due December 1, 2002, converted their notes into common stock
at the prescribed conversion ratio of one share of common stock for each $11.00
of principal amount of notes. We redeemed the remaining $95,000 of the notes for
cash at a call price of 101.65%.

27

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

BANK CREDIT FACILITY

As of December 31, 2001, our amended credit facility of $150.0 million has
a borrowing base of $75.0 million. The following schedule reflects certain
information about the line of credit for the last two years.

We pledged our oil and gas properties as collateral for this line of
credit. We accrue and pay interest at varying rates based on premiums ranging
from 1.5 to 2.25 percentage points over the London Interbank Offered Rates.
Interest only is payable quarterly through May 3, 2004, at which time the line
expires and all principal becomes due, unless the line is extended or
renegotiated.

The most significant financial covenants in the line of credit include,
among others, maintaining a minimum current ratio of 1.0 to 1.0, a minimum
tangible net worth of $85.0 million plus 50% of future net income and 100% of
any non-redeemable preferred or common stock offerings, and interest coverage of
3.0 to 1.0.

The banks review the borrowing base semi-annually and may increase or
decrease the borrowing base at their discretion relative to the new estimate of
proved oil and gas reserves. The next redetermination is scheduled for April
2002.

OTHER

Other long-term payables include a note payable to the Minerals Management
Service and certain vendor financing arrangements.

FAIR VALUE OF INDEBTEDNESS

We estimate that the fair value of our long-term indebtedness, including
the current maturities of such obligations, is approximately $78.0 million at
December 31, 2001 and $34.0 million at December 31, 2000. We based the fair
value on broker estimates for our convertible notes and on current rates
available for our bank debt. The book value of our other long-term indebtedness
approximates fair value.

28

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 4 -- COMMITMENTS AND CONTINGENT LIABILITIES

We lease approximately 17,000 square feet of office space in Dallas Texas.
The non-cancelable operating lease expires in April 2008. The following table
reflects our rent payments for the past three years and the commitment for the
future minimum rental payments.

We have no material pending legal proceedings.

NOTE 5 -- COMMON STOCK, PREFERRED STOCK AND DIVIDENDS

In 1998, we increased the number of authorized common stock shares to 100.0
million and authorized 25.0 million shares of "blank check" preferred stock. The
par value of the common stock and preferred stock is $0.01 per share. The board
of directors can approve the issue of multiple series of preferred stock and set
different terms, voting rights, conversion features, and redemption rights for
each distinct series of the preferred stock.

We have reserved approximately 4.0 million shares of common stock for our
stock option plan and for our non-employee director stock purchase plan, which
are discussed in more detail in Note 7 -- Employee and Director Benefit Plans.
Dividend payments are currently prohibited by our line of credit agreement.

NOTE 6 -- SETTLEMENTS EXPENSE

On May 22, 2001, we settled the litigation with Phillips Petroleum Company
and acquired Phillips' Net Profits Interest in South Pass block 89, offshore
Louisiana. We paid $21.25 million cash and issued 1,189,344 shares of our common
stock as consideration for the settlement and assignment of the net profits
interest.

Of the total $42.5 million settlement, we had previously recorded $20.2
million as an accrued liability. We recorded $12.3 million of the remaining
$22.3 million as additional settlement expense and capitalized $10.0 million as
the cost for our purchase of the net profits interest. In addition, we charged
the remaining $1.2 million deferred net profits expense related to a royalty
settlement in 2000 to the settlement expense.

We agreed to purchase up to 100,000 shares per week from Phillips at
$17.867 per share in the event that Phillips was unable to sell the shares at or
above that price. Subsequently, Phillips sold 33,900 shares on the open market,
and we purchased the remaining 1,155,444 shares at a total cost of $20.6
million.

The Minerals Management Service is the grantor of all leases in the federal
waters offshore Louisiana. When production is established, they collect a 16.67%
royalty from all hydrocarbons produced from the lease. After a routine audit of
our royalty payments, the Minerals Management Service issued orders to pay
additional royalty on three separate claims regarding our South Pass 89 lease
complex. We settled all three of those claims in 2000 for a total of $5.4
million.

29

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Two individuals owned a combined 5.8824% in two of our subsidiaries, CKB
Petroleum, Inc. and CKB & Associates, Inc. The two subsidiaries were acquired
when we merged with S-Sixteen Holding Company in December 1998. The minority
interest liability reflects their percentage of the total combined equity in the
two subsidiaries. In February 2000, we reached an agreement to settle the
litigated claims by the minority interest owners and purchased their minority
interest in the two subsidiaries. In connection with the settlement of their
lawsuit, we recorded $442,000 as a settlement expense in December 1999.

NOTE 7 -- EMPLOYEE AND DIRECTOR BENEFIT PLANS

STOCK OPTION PLAN

A committee that includes two or more outside non-employee directors
administers the 1997 Stock Option Plan. The committee has the discretion to
determine the participants, the number of shares granted to each person, the
purchase price of the common stock covered by each option, and most other terms
of the option. Options granted under the plan may be either incentive stock
options or non-qualified stock options. The committee may issue options for up
to 3.75 million shares of common stock, but no more than 937,500 shares to any
individual. Forfeited options are available for future issuance.

A summary of our stock option plans as of December 31, 2001, 2000, and
1999, and changes during the years ending on those dates is presented below:

The options outstanding at December 31, 2001 have a weighted-average
remaining contractual life of 7.62 years and an exercise price ranging from
$2.75 to $16.78 per share.

30

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The table below reflects the effect on our net income or loss if we
recorded the estimated compensation costs for the stock options using the
estimated fair value as determined by applying the Black-Scholes option pricing
model.

The fair value of each option grant for the years ended December 31, 2001,
2000, and 1999 is estimated on the date of grant using the Black-Scholes
option-pricing model with the following weighted average assumptions:

NON-EMPLOYEE DIRECTOR STOCK PURCHASE PLAN

The non-employee director stock purchase plan allows the non-employee
directors to receive their directors' fees in shares of restricted common stock
instead of cash. The number of shares received will be equal to 150% of the cash
fees divided by the closing market price of the common stock on the day that the
cash fees would otherwise be paid. The director cannot transfer the common stock
until one year after issuance or the termination of a director resulting from
death, disability, removal, or failure to be nominated for an additional term.
The director can vote the shares of restricted stock and receive any dividend
paid.

PENSION PLAN

Remington and CKB Petroleum, Inc. each have a noncontributory defined
benefit pension plan. The retirement benefits available are generally based on
years of service and average earnings. We fund the plans with annual
contributions at least equal to the minimum funding provisions of the Employee
Retirement Income Security Act of 1974, as amended, but no more than the maximum
tax deductible contribution

31

REMINGTON OIL AND GAS CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

allowed. Plan assets consist primarily of equity and fixed income securities.
The following table sets forth the reconciliation of the benefi