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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
---------------------
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 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
---------------------
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:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
COMMON STOCK, $0.01 PAR VALUE PACIFIC EXCHANGE, INC.
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
PAGE
----
PART I................................................................ 2
Item 1. Business.................................................... 2
Item 2. Properties.................................................. 4
Item 3. Legal Proceedings........................................... 6
Item 4. Submission of Matters to a Vote of Security Holders......... 6
PART II............................................................... 7
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 7
Item 6. Selected Financial Data..................................... 8
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 9
Item 7A. Quantitative and Qualitative Disclosures about Market
Risk........................................................ 15
Item 8. Financial Statements and Supplementary Data................. 17
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 38
PART III.............................................................. 38
Item 10. Directors and Executive Officers of the Registrant.......... 38
Item 11. Executive Compensation...................................... 43
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 51
Item 13. Certain Relationships and Related Transactions.............. 52
PART IV............................................................... 52
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 52
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.
3
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.
4
LEASEHOLD ACREAGE
Our leasehold acreage of proved and unproved properties at December 31,
2001, was as follows:
UNDEVELOPED DEVELOPED
----------------- ----------------
GROSS NET GROSS NET
------- ------- ------- ------
Offshore........................................ 214,969 106,864 132,268 53,224
Onshore......................................... 110,100 35,250 29,620 8,560
------- ------- ------- ------
Total........................................... 325,069 142,114 161,888 61,784
======= ======= ======= ======
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.
NET OIL NET GAS PRE-TAX
RESERVES RESERVES PRESENT VALUE
BARRELS MCF DISCOUNTED @10%
-------- -------- ---------------
(IN THOUSANDS)
Offshore Gulf of Mexico............................ 9,817 101,290 $206,279
Onshore Gulf Coast................................. 4,048 10,630 $ 32,590
------ ------- --------
Total.............................................. 13,865 111,920 $238,869
====== ======= ========
PRODUCING PROPERTIES
The table below summarizes our ownership in producing wells at the end of
the last three years.
AT DECEMBER 31,
---------------------------------------------
2001 2000 1999
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Oil wells
Offshore Gulf of Mexico................. 21 6.72 14 3.57 18 4.87
Onshore Gulf Coast...................... 34 12.87 29 11.13 45 17.88
--- ----- --- ----- --- -----
Total..................................... 55 19.59 43 14.70 63 22.75
=== ===== === ===== === =====
Gas wells
Offshore Gulf of Mexico................. 38 11.02 29 7.68 26 5.02
Onshore Gulf Coast...................... 107 25.94 85 20.92 85 16.59
--- ----- --- ----- --- -----
Total..................................... 145 36.96 114 28.60 111 21.61
=== ===== === ===== === =====
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.
5
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.
FOR THE YEARS ENDED DECEMBER 31,
-------------------------------------------------------------------------------------
2001 2000 1999
-------------------------- --------------------------- --------------------------
GROSS NET GROSS NET GROSS NET
----------- ------------ ------------ ------------ ----------- ------------
PROD. DRY PROD. DRY PROD. DRY PROD. DRY PROD. DRY PROD. DRY
----- --- ----- ---- ----- ---- ----- ---- ----- --- ----- ----
Exploratory
Offshore Gulf of Mexico...... 13 2 4.77 0.91 12 -- 5.45 -- 5 1 1.73 0.33
Onshore Gulf Coast........... 9 3 2.81 0.90 18 6 4.40 2.27 22 6 5.91 1.63
-- -- ---- ---- -- ---- ---- ---- -- -- ---- ----
Total.......................... 22 5 7.58 1.81 30 6 9.85 2.27 27 7 7.64 1.96
== == ==== ==== == ==== ==== ==== == == ==== ====
Development
Offshore Gulf of Mexico...... 2 -- 0.58 -- 3 -- 1.05 -- 1 -- 0.33 --
Onshore Gulf Coast........... 5 2 1.11 0.55 2 -- 0.89 -- 2 -- 0.89 --
-- -- ---- ---- -- ---- ---- ---- -- -- ---- ----
Total.......................... 7 2 1.69 0.55 5 -- 1.94 -- 3 -- 1.22 --
== == ==== ==== == ==== ==== ==== == == ==== ====
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
6
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.
COMMON STOCK
------------------
HIGH LOW
------- -------
2002
First Quarter through March 18, 2002...................... $19.550 $15.100
2001
Fourth Quarter............................................ 18.350 13.03
Third Quarter............................................. 17.060 11.44
Second Quarter............................................ 19.190 12.12
First Quarter............................................. 16.250 11.62
2000
Fourth Quarter............................................ 13.375 8.00
Third Quarter............................................. 10.438 5.87
Second Quarter............................................ 7.500 3.50
First Quarter............................................. 4.188 2.81
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.
2001(1) 2000(1) 1999 1998(1) 1997(1)
---------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PRICES, VOLUMES, AND PER SHARE DATA)
FINANCIAL
Total revenue.................. $ 116,068 $100,100 $ 45,430 $ 87,689 $ 61,053
Net income (loss).............. $ 8,344 $ 45,044 $ (3,703) $ 13,617 $(26,790)
Basic income (loss) per
share........................ $ 0.38 $ 2.10 $ (0.17) $ 0.67 $ (1.31)
Diluted income (loss) per
share........................ $ 0.35 $ 1.99 $ (0.17) $ 0.66 $ (1.31)
Total assets................... $ 240,432 $192,474 $119,326 $130,229 $ 98,515
8 1/4% convertible subordinated
notes........................ $ -- $ 5,880 $ 5,950 $ 38,371 $ 38,371
Other bank debt................ $ 71,000 $ 27,428 $ 30,028 $ 3,500 $ 6,000
Stockholders' equity........... $ 125,338 $102,708 $ 56,054 $ 59,699 $ 44,287
Total shares outstanding....... 22,651 21,564 21,285 21,247 20,306
Cash Flow
Net cash flow from
operations................ $ 99,025 $ 69,963 $ 19,180 $ 54,040 $ 27,546
Net cash flow from
investing................. $(119,242) $(57,511) $(25,911) $(38,149) $(11,820)
Net cash flow from
financing................. $ 21,463 $ 1,323 $ (7,931) $ (1,425) $(14,171)
OPERATIONAL
Proved reserves(2)
Oil (MBbls).................. 13,865 10,370 7,177 5,519 4,451
Gas (MMcf)................... 111,920 88,650 65,508 52,709 36,543
Future discounted net
revenue(2)
Before estimated income
taxes..................... $ 238,869 $670,476 $163,665 $ 70,118 $108,698
After estimated income
taxes..................... $ 199,983 $458,649 $126,868 $ 63,467 $ 93,838
Average sales price
Oil (per Bbl)................ $ 22.93 $ 27.11 $ 15.48 $ 10.99 $ 17.79
Gas (per Mcf)................ $ 3.99 $ 3.97 $ 2.42 $ 3.22 $ 5.06
Average production (net sales
volume)
Oil (Bbls per day)........... 3,423 3,336 3,242 3,411 3,280
Gas (Mcf per day)............ 58,448 35,340 27,229 17,488 19,496
---------------
(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.
% INCREASE % INCREASE
2001 (DECREASE) 2000 (DECREASE) 1999
------- ---------- ------- ---------- -------
Production:
Oil MBbls......................... 1,249 2% 1,221 3% 1,183
Gas MMcf.......................... 21,334 65% 12,934 30% 9,939
------- -- ------- -- -------
Total MMcfe(1)...................... 28,828 42% 20,260 19% 17,037
======= == ======= == =======
Proved reserves:
Oil MBbls......................... 13,865 34% 10,370 44% 7,177
Gas MMcf.......................... 111,920 26% 88,650 35% 65,508
------- -- ------- -- -------
Total MMcfe(1)...................... 195,110 29% 150,870 39% 108,570
======= == ======= == =======
Production costs per Mcfe(2)........ $ 0.53 2% $ 0.52 0% $ 0.52
Finding costs per Mcfe(3)........... $ 1.68 73% $ 0.97 41% $ 0.69
Percentage of production replaced... 253% 309% 234%
---------------
(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
9
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
10
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.
PAYMENTS DUE BY PERIOD
-------------------------------------------------------------
LESS THAN
TOTAL 1 YEAR 1-3 YEARS 4-5 YEARS AFTER 5 YEARS
------- ----------- --------- --------- -------------
(IN THOUSANDS)
Contractual obligations
Bank debt....................... $71,000 $ -- $71,000 $ -- $ --
Other long-term payables........ $ 6,966 $3,208 $ 3,758 $ -- $ --
Office lease.................... $ 2,909 $ 441 $ 882 $971 $615
------- ------ ------- ---- ----
Total $80,875 $3,649 $75,640 $971 $615
======= ====== ======= ==== ====
Other commercial commitments
Standby letter of credit........ $ -- $ -- $ -- $ -- $ --
(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.
11
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
12
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.
% INCREASE % INCREASE
2001 (DECREASE) 2000 (DECREASE) 1999
------- ---------- ------- ---------- -------
Oil production volume (MBbls)............... 1,249 2% 1,221 3% 1,183
Oil sales revenue........................... $28,637 (13)% $33,106 81% $18,316
Price per Bbl............................... $ 22.93 (15)% $ 27.11 75% $ 15.48
Increase (decrease) in oil sales revenue due
to:
Change in prices............................ $(5,104) $13,760
Change in production volume................. 635 1,030
------- -------
Total increase (decrease) in oil sales
revenue................................... $(4,469) $14,790
======= =======
Gas production volume (MMcf)................ 21,334 65% 12,934 30% 9,939
Gas sales revenue........................... $85,032 66% $51,291 113% $24,028
Price per Mcf............................... $ 3.99 1% $ 3.97 64% $ 2.42
Increase (decrease) in gas sales revenue due
to:
Change in prices............................ $ 259 $15,405
Change in production volume................. 33,482 11,858
------- -------
Total increase (decrease) in gas sales
revenue................................... $33,741 $27,263
======= =======
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
AT DECEMBER 31,
---------------------
2001 2000
--------- ---------
(IN THOUSANDS,
EXCEPT SHARE DATA)
ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 19,377 $ 18,131
Restricted cash and cash equivalents...................... -- 2,592
Accounts receivable....................................... 19,445 21,142
Prepaid expenses and other current assets................. 1,487 2,375
--------- ---------
TOTAL CURRENT ASSETS........................................ 40,309 44,240
--------- ---------
PROPERTIES
Oil and gas properties (successful-efforts method)........ 433,988 336,558
Other properties.......................................... 3,023 2,701
Accumulated depreciation, depletion and amortization...... (237,661) (201,506)
--------- ---------
TOTAL PROPERTIES............................................ 199,350 137,753
--------- ---------
OTHER ASSETS
Cash collateral for Phillips judgment..................... -- 9,000
Other assets.............................................. 773 1,481
--------- ---------
TOTAL OTHER ASSETS........................................ 773 10,481
--------- ---------
TOTAL ASSETS................................................ $ 240,432 $ 192,474
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses..................... $ 34,232 $ 25,273
Short-term notes payable and current portion of long-term
note payable........................................... 3,253 7,229
--------- ---------
TOTAL CURRENT LIABILITIES................................... 37,485 32,502
--------- ---------
LONG-TERM LIABILITIES
Phillips judgment......................................... -- 19,733
Notes payable............................................. 71,000 24,685
Convertible subordinated notes payable.................... -- 5,880
Other long-term payables.................................. 3,758 6,966
Deferred income taxes..................................... 2,851 --
--------- ---------
TOTAL LONG-TERM LIABILITIES................................. 77,609 57,264
--------- ---------
TOTAL LIABILITIES........................................... 115,094 89,766
--------- ---------
COMMITMENTS AND CONTINGENCIES (NOTE 4)
STOCKHOLDERS' EQUITY
Preferred stock, $0.01 par value, 25,000,000 shares
authorized
Shares issued -- none
Common stock, $.01 par value, 100,000,000 shares
authorized, 22,685,240 shares issued and 22,650,881
shares outstanding in 2001, 21,598,605 shares issued
and 21,564,246 shares outstanding in 2000.............. 227 216
Additional paid-in capital................................ 56,698 45,897
Restricted common stock................................... 8,055 --
Unearned compensation..................................... (4,581) --
Retained earnings......................................... 64,939 56,595
--------- ---------
TOTAL STOCKHOLDERS' EQUITY................................ 125,338 102,708
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $ 240,432 $ 192,474
========= =========
See accompanying Notes to Consolidated Financial Statements.
19
REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31,
-----------------------------
2001 2000 1999
-------- -------- -------
(IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
REVENUES
Oil sales................................................. $ 28,637 $ 33,106 $18,316
Gas sales................................................. 85,032 51,291 24,028
Interest income........................................... 975 1,442 724
Other income.............................................. 1,424 14,261 2,362
-------- -------- -------
TOTAL REVENUES.............................................. 116,068 100,100 45,430
-------- -------- -------
COSTS AND EXPENSES
Operating costs and expenses.............................. 14,644 8,778 7,307
Net profits interest expense.............................. 751 1,753 1,492
Exploration expenses...................................... 13,100 6,833 6,725
Depreciation, depletion, and amortization................. 38,263 20,976 20,780
Impairment of oil and gas properties...................... 10,616 859 1,883
General and administrative................................ 5,713 5,611 6,099
Settlements expense....................................... 13,524 5,416 442
Stock based compensation.................................. 3,696 174 156
Interest and financing expense............................ 3,829 4,561 4,552
-------- -------- -------
TOTAL COSTS AND EXPENSES.................................... 104,136 54,961 49,436
-------- -------- -------
INCOME (LOSS) BEFORE TAXES.................................. 11,932 45,139 (4,006)
Income taxes.............................................. 3,588 100 (273)
Minority interest......................................... -- (5) (30)
-------- -------- -------
NET INCOME (LOSS)........................................... $ 8,344 $ 45,044 $(3,703)
======== ======== =======
BASIC INCOME (LOSS) PER SHARE............................... $ 0.38 $ 2.10 $ (0.17)
======== ======== =======
DILUTED INCOME (LOSS) PER SHARE............................. $ 0.35 $ 1.99 $ (0.17)
======== ======== =======
See accompanying Notes to Consolidated Financial Statements.
20
REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
COMMON
STOCK ADDITIONAL RESTRICTED
$0.01 PAR PAID IN COMMON UNEARNED RETAINED
VALUE CAPITAL STOCK COMPENSATION EARNINGS
--------- ---------- ---------- ------------ --------
(IN THOUSANDS)
Balance December 31, 1998............... $213 $ 44,117 $ -- $ -- $15,369
Net income (loss)....................... (3,703)
Common stock issued..................... 156
Dividends paid to minority
stockholders.......................... (98)
---- -------- ------ ------- -------
Balance December 31, 1999............... 213 44,273 -- -- 11,568
---- -------- ------ ------- -------
Net income.............................. 45,044
Common stock issued..................... 3 1,624
Dividends paid to minority
stockholders.......................... (17)
---- -------- ------ ------- -------
Balance December 31, 2000............... 216 45,897 -- -- 56,595
---- -------- ------ ------- -------
Net income.............................. 8,344
Contingent stock grant.................. 8,055 (5,623)
Amortization of unearned compensation... 1,042
Common stock issued..................... 22 31,434
Common stock repurchased and retired
(Note 6).............................. (11) (20,633)
---- -------- ------ ------- -------
Balance December 31, 2001............... $227 $ 56,698 $8,055 $(4,581) $64,939
==== ======== ====== ======= =======
See accompanying Notes to Consolidated Financial Statements.
21
REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31,
-------------------------------
2001 2000 1999
--------- -------- --------
(IN THOUSANDS)
CASH FLOW PROVIDED BY OPERATIONS
NET INCOME (LOSS)........................................... $ 8,344 $ 45,044 $ (3,703)
ADJUSTMENTS TO RECONCILE NET INCOME
Depreciation, depletion, and amortization................. 38,263 20,976 20,780
Deferred income tax expense............................... 3,600 -- --
Amortization of deferred charges.......................... 172 334 752
Deferred net profits expense.............................. 1,270 -- --
Impairment of oil and gas properties...................... 10,616 859 1,883
Dry hole costs............................................ 9,589 5,557 5,187
Cash paid for dismantlement and restoration liability..... (622) -- --
Minority interest in net income of subsidiaries........... -- (5) (30)
Stock issued to directors and employees for
compensation........................................... 3,696 174 156
Royalty settlement........................................ -- 5,416 --
(Gain) on sale of properties.............................. (201) (12,640) (218)
CHANGES IN WORKING CAPITAL
Decrease (increase) in accounts receivable................ 1,580 (14,745) (3,230)
Decrease (increase) in prepaid expenses and other current
assets................................................. 526 344 (183)
Increase in accounts payable and accrued expenses......... 10,600 19,199 78
Decrease (increase) in restricted cash.................... 11,592 (550) (2,292)
--------- -------- --------
NET CASH FLOW PROVIDED BY OPERATIONS........................ 99,025 69,963 19,180
--------- -------- --------
CASH FROM INVESTING ACTIVITIES
Payments for capital expenditures......................... (119,673) (72,678) (26,209)
Proceeds from property sales.............................. 431 15,167 298
--------- -------- --------
NET CASH (USED IN) INVESTING ACTIVITIES..................... (119,242) (57,511) (25,911)
--------- -------- --------
CASH FROM FINANCING ACTIVITIES
Proceeds from notes payable and long-term accounts
payable................................................ 51,500 10,630 30,628
Payments on notes payable and long-term accounts
payable................................................ (12,464) (9,811) (37,933)
Purchase common stock issued in Phillips Petroleum
settlement............................................. (20,644) -- --
Commitment fee on line of credit.......................... (307) -- (528)
Common stock issued....................................... 3,378 521 --
Dividends paid to minority interest holders............... -- (17) (98)
--------- -------- --------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES......... 21,463 1,323 (7,931)
--------- -------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ 1,246 13,775 (14,662)
Cash and cash equivalents at beginning of period.......... 18,131 4,356 19,018
--------- -------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD.................. $ 19,377 $ 18,131 $ 4,356
========= ======== ========
Cash paid for interest...................................... $ 2,925 $ 4,338 $ 2,577
========= ======== ========
Cash paid (received) for taxes.............................. $ (12) $ 100 $ (327)
========= ======== ========
Non-cash issuance of common stock (Note 6).................. $ 21,250 $ -- $ --
========= ======== ========
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.
FOR YEARS ENDED DECEMBER 31,
-----------------------------
2001 2000 1999
------- -------- --------
(IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
Net income (loss) available for basic income per share... $8,344 $45,044 $(3,703)
Interest expense on the Notes (net of tax)(1).......... 188 318 --
------ ------- -------
Net income (loss) available for diluted income per
share.................................................. $8,532 $45,362 $(3,703)
====== ======= =======
Basic income (loss) per share............................ $ 0.38 $ 2.10 $ (0.17)
====== ======= =======
Diluted income (loss) per share.......................... $ 0.35 $ 1.99 $ (0.17)
====== ======= =======
Weighted average common shares for basic income (loss)
per share.............................................. 21,979 21,435 21,326
Dilutive stock options outstanding (treasury stock
method)(1).......................................... 1,453 784 --
Common stock grant..................................... 663 -- --
Shares assumed issued by conversion of the Notes(1).... 319 540 --
------ ------- -------
Total common shares for diluted income (loss) per
share.................................................. 24,414 22,759 21,326
====== ======= =======
Potential increase to net income for diluted income per
share Interest expense on Notes (net of tax)........... $ -- $ -- $ 581
Potential issues of common stock for diluted income per
share Weighted average stock options granted........... -- -- 1,677
Weighted average shares from warrant issued in
merger.............................................. -- 200 200
Weighted average shares issued assuming conversion of
Notes............................................... -- -- 985
---------------
(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.
AT DECEMBER 31,
-------------------------------------------------------------------
2001 2000
-------------------------------- --------------------------------
PROVED UNPROVED TOTAL PROVED UNPROVED TOTAL
--------- -------- --------- --------- -------- ---------
(IN THOUSANDS)
Onshore.................. $ 55,190 $ 3,189 $ 58,379 $ 46,618 $ 2,125 $ 48,743
Offshore................. 357,137 18,472 375,609 272,680 15,135 287,815
--------- ------- --------- --------- ------- ---------
Total.................... 412,327 21,661 433,988 319,298 17,260 336,558
Accumulated depreciation,
depletion and
amortization........... (235,428) -- (235,428) (199,451) -- (199,451)
--------- ------- --------- --------- ------- ---------
Net oil and gas
properties............. $ 176,899 $21,661 $ 198,560 $ 119,847 $17,260 $ 137,107
========= ======= ========= ========= ======= =========
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.
FOR THE YEARS ENDED
DECEMBER 31,
----------------------------
2001 2000 1999
-------- ------- -------
(UNAUDITED, IN THOUSANDS)
Unproved acquisition costs............................. $ 9,885 $13,057 $ 2,732
Proved acquisition costs............................... 5,000 1,779 379
Exploration costs...................................... 46,825 38,224 17,535
Development costs...................................... 61,145 21,249 7,007
-------- ------- -------
Total.................................................. $122,855 $74,309 $27,653
======== ======= =======
We recognized impairment expenses as follows in the table below:
FOR THE YEARS ENDED
DECEMBER 31,
-----------------------
2001 2000 1999
------- ---- ------
(IN THOUSANDS)
Unproved properties......................................... $ 616 $811 $ 794
Proved properties........................................... 10,000 48 1,089
------- ---- ------
Total impairment expense.................................... $10,616 $859 $1,883
======= ==== ======
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.
AT DECEMBER 31,
-----------------
2001 2000
------- -------
(IN THOUSANDS)
Borrowing base.............................................. $75,000 $35,000
Outstanding balance (including current maturities).......... 71,000 27,428
------- -------
Available amount............................................ $ 4,000 $ 7,572
======= =======
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.
YEAR RENT
---- --------
1999...................................................... $407,000
2000...................................................... $407,000
2001...................................................... $433,000
2002...................................................... $441,000
2003...................................................... $441,000
2004...................................................... $441,000
2005...................................................... $479,000
2006...................................................... $492,000
Remaining commitment...................................... $615,000
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:
AT DECEMBER 31,
------------------------------------------------------------------
2001 2000 1999
-------------------- -------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- -------- --------- -------- --------- --------
Outstanding at
beginning of year.... 2,581,503 $ 5.28 1,761,000 $6.12 1,175,500 $6.15
Granted................ 345,000 $15.33 979,000 $3.89 614,000 $6.22
Exercised.............. (327,803) $ 4.39 (33,497) $3.66 --
Forfeited.............. -- $ -- (125,000) $6.87 (28,500) $9.63
--------- ------ --------- ----- --------- -----
Outstanding at end of
year................. 2,598,700 $ 6.72 2,581,503 $5.28 1,761,000 $6.12
========= ====== ========= ===== ========= =====
Options exercisable at
year-end............. 1,441,384 $ 6.13 1,097,860 $6.72 653,682 $6.78
Weighted-average fair
value of options
Granted during the
year................. $11.55 $2.92 $2.88
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.
FOR YEARS ENDED DECEMBER 31,
-----------------------------
2001 2000 1999
------- -------- --------
(IN THOUSANDS)
Net income (loss)........................... As reported $8,344 $45,044 $(3,703)
Pro forma $6,498 $43,866 $(4,719)
Basic income (loss) per share............... As reported $ 0.38 $ 2.10 $ (0.17)
Pro forma $ 0.30 $ 2.05 $ (0.22)
Diluted income (loss) per share............. As reported $ 0.35 $ 1.99 $ (0.17)
Pro forma $ 0.27 $ 1.94 $ (0.22)
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:
FOR YEARS ENDED
DECEMBER 31,
-----------------------
2001 2000 1999
----- ----- -----
Expected life (years)....................................... 10 10 10
Interest rate............................................... 5.13% 6.18% 5.88%
Volatility.................................................. 62.56% 59.01% 56.74%
Dividend yield.............................................. 0% 0% 0%
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 benefit obligation,
plan assets, and funded status for the pension plans.
AT DECEMBER 31,
---------------
2001 2000
------ ------
RECONCILIATION OF THE CHANGE IN BENEFIT OBLIGATION
Beginning benefit obligation.............................. $3,103 $2,850
Service cost........................................... 151 119
Interest cost.......................................... 221 226
Actuarial loss (gain).................................. 59 156
Benefits paid.......................................... (229) (248)
------ ------
Ending benefit obligation................................. $3,305 $3,103
====== ======
RECONCILIATION OF THE CHANGE IN PLAN ASSETS
Beginning market value.................................... $3,090 $3,501
Actual return on plan assets........................... (282) (163)
Employer contributions................................. 187 --
Benefit payments....................................... (229) (248)
------ ------
Ending market value....................................... $2,766 $3,090
====== ======
FUNDED STATUS AND AMOUNTS RECOGNIZED IN THE BALANCE SHEET
Funded status............................................. $ (539) $ (13)
Unrecognized net actuarial loss (gain).................... 813 233
Effect of the settlement.................................. -- --
------ ------
Adjusted prepaid (accrued) benefit cost................... $ 274 $ 220
====== ======
The net periodic pension cost recognized in our income statements include
the following components:
FOR YEARS ENDED
DECEMBER 31,
------------------
2001 2000 1999
---- ---- ----
(IN THOUSANDS)
COMPONENTS OF NET PERIODIC PENSION COST
Service cost.............................................. $151 $119 $101
Interest cost on projected benefit obligation............. 221 226 217
Expected return on plan assets............................ (239) (273) (264)
Net amortization and deferrals............................ -- (2) --
---- ---- ----
Net periodic pension cost................................. 133 70 54
Special recognition due to curtailment and lump sum
settlements............................................ -- -- (32)
---- ---- ----
Net periodic pension cost................................... $133 $ 70 $ 22
==== ==== ====
WEIGHTED AVERAGE ASSUMPTIONS
Discount rate............................................. 7.25% 7.50% 7.75%
Expected return on plan assets............................ 8.00% 8.00% 8.00%
Rate of compensation increase............................. 3.00% 3.00% 3.00%
32
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CONTINGENT STOCK GRANT
In June 1999, the Board of Directors approved a contingent stock grant to
our employees and directors. In order for the grant to become effective, the
price of our stock had to increase from $4.19 per share to a trigger price of
$10.42 per share and close at or above $10.42 per share for 20 consecutive
trading days.
On January 24, 2001, the stock price closed above the trigger price for the
twentieth consecutive trading day. On that date, we measured the total
compensation cost at $8.1 million which was the total number of shares granted
multiplied by the market price on that date. We recorded $8.1 million as
restricted common stock, $5.7 million as unearned compensation reported as a
separate reduction in stockholders' equity on the balance sheet, and $2.4
million as stock based compensation expense. The $2.4 million stock based
compensation expense recorded in the first quarter of 2001 included a "catch up"
amortization from the date of the grant to the measurement date of the total
compensation cost. During the last three quarters of 2001 we amortized an
additional $1.0 million. The remaining unearned compensation expenses will be
amortized over the next five years as the shares vest. The total compensation
expense may decrease if an employee fails to vest because he is no longer
employed for any reason other than death, disability, or normal retirement, or
if a director no longer serves for any reason other than death.
EMPLOYEE SEVERANCE PLAN, POST RETIREMENT BENEFITS AND POST EMPLOYMENT BENEFITS
Our employee severance plan provides severance benefits ranging from 2
months to 18 months of the employee's base salary if the employee is terminated
involuntarily. The plan incorporates the provisions and terms of any individual
contract or agreement that an employee may have with the company. Certain of the
executive officers have individual employment contracts with the company.
We have never paid postretirement benefits other than pensions and have not
obligated ourselves to pay such benefits in the future. Future obligations for
postemployment benefits are immaterial. Therefore, we have not recognized any
liability for either.
NOTE 8 -- INCOME TAXES
The following table provides a summary of our income tax expense or
(benefit):
FOR YEARS ENDED
DECEMBER 31,
---------------------
2001 2000 1999
------ ---- -----
(IN THOUSANDS)
Current income tax expense (benefit)........................ $ (12) $100 $(256)
Deferred income tax expense (benefit)....................... 3,600 -- (17)
------ ---- -----
Total income tax expense (benefit).......................... $3,588 $100 $(273)
====== ==== =====
Total income tax expense (benefit) differs from the amount computed by
applying the federal income tax rate to net income (loss) before income taxes as
follows:
FOR YEARS ENDED DECEMBER 31,
-----------------------------
2001 2000 1999
------- -------- --------
(IN THOUSANDS)
Federal income tax expense (benefit) at statutory rate... $4,175 $15,799 $(1,402)
Net adjustment to valuation allowance.................... (575) (15,799) 1,402
Other.................................................... (12) 100 (273)
------ ------- -------
Total income tax expense (benefit)....................... $3,588 $ 100 $ (273)
====== ======= =======
33
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table reflects the significant components of our deferred tax
asset.
AT DECEMBER 31,
-------------------
2001 2000
-------- --------
(IN THOUSANDS)
Asset (liability) from difference in book and tax basis of
oil and gas properties.................................... $(14,777) $(12,181)
Asset (liability) from difference in book and tax basis of
other assets.............................................. 826 (939)
Asset from difference in book and tax basis of accrued
liabilities............................................... 2,923 5,723
Federal income tax operating loss carry-forward............. 7,761 7,483
Federal capital loss carry-forwards......................... -- --
Alternative minimum tax credit carry-forward................ 416 489
-------- --------
Total deferred tax (liability) asset........................ (2,851) 575
Valuation allowance......................................... -- (575)
-------- --------
Net deferred tax (liability) asset.......................... $ (2,851) $ --
======== ========
The unused federal income tax operating loss carry-forward of $22.2 million
will expire during the years 2007 through 2020 if not utilized sooner.
NOTE 9 -- OIL AND GAS RESERVES AND PRESENT VALUE DISCLOSURES (UNAUDITED)
The estimates of oil and gas reserves were prepared by the independent
engineering and consulting firms of Netherland, Sewell & Associates, Inc. for
the years 2001 and 2000 and by Netherland, Sewell & Associates, Inc. and Miller
and Lents, Ltd for 1999. The determination of these reserves is a complex and
interpretative process that is subject to continued revision as additional
information becomes available. In many cases, a relatively accurate
determination of reserves may not be possible for several years due to the time
necessary for development drilling, testing and studies of the reservoirs.
The quantities of proved oil and gas reserves presented below include only
the amounts which we reasonably expect to recover in the future from known oil
and gas reservoirs under the current economic and operating conditions. Proved
reserves include only quantities that we can commercially recover using current
prices, costs, existing regulatory practices and technology. Therefore, any
changes in future prices, costs, regulations, technology or other unforeseen
factors could significantly increase or decrease proved reserve estimates. The
following table presents our net ownership interest in proved oil and gas
reserves.
AT DECEMBER 31,
-----------------------------------------------------
2001 2000 1999
---------------- ---------------- ---------------
OIL OIL OIL GAS
BBLS GAS MCF BBLS GAS MCF BBLS MCF
------ ------- ------ ------- ------ ------
(IN THOUSANDS)
Beginning of period............. 10,370 88,650 7,177 65,508 5,519 52,709
Revisions of previous
estimates.................. 1,237 (1,347) 111 1,070 1,173 3,340
Extensions, discoveries and
other...................... 3,507 45,951 5,028 44,528 1,668 19,580
Reserves purchased............ -- -- 35 294 -- --
Reserves sold................. -- -- (760) (9,816) -- (182)
Production.................... (1,249) (21,334) (1,221) (12,934) (1,183) (9,939)
------ ------- ------ ------- ------ ------
End of period................... 13,865 111,920 10,370 88,650 7,177 65,508
====== ======= ====== ======= ====== ======
Proved developed reserves....... 6,690 60,756 5,345 71,995 5,593 56,742
34
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The proved developed and undeveloped reserves and standardized measure of
discounted future net cash flows associated with South Pass block 89 were
burdened by a 33% net profits interest for the years ended December 31, 2000 and
1999. In May 2001, we purchased the net profits interest from Phillips
Petroleum. The reserves included in the above table for the two previous years
include our full net ownership interest without any reduction for the net
profits interest. We treated the net profit interest as an operating expense
rather than a reduction in proved reserves.
The following tables represent value-based information about our proved oil
and gas reserves. The standardized measure of discounted future net cash flows
result from the application of specific criteria applicable to the value-based
disclosures of all oil and gas reserves in the industry. Due to the imprecise
nature of estimating oil and gas reserve quantities and the uncertainty of
future economic conditions, we cannot make any representation about
interpretations that may be made or what degree of reliance that may be placed
on this method of evaluating proved oil and gas reserves.
We compute future cash revenue by multiplying the year-end commodity prices
or contractual pricing if applicable, by the proved oil and gas reserves. Future
production and development costs include the estimated costs to produce or
develop the proved reserves based primarily on historical costs. We calculated
the future net profits expense by multiplying the net profit percentage by the
future revenue less production and development costs on South Pass block 89.
Future income tax expense was determined by applying the current tax rate to the
estimated future net cash flow from all properties. Finally, we discounted the
future net cash flow, after tax, by 10% per year to arrive at the standardized
measure of discounted future net cash flows presented below.
AT DECEMBER 31,
---------------------------------
2001 2000 1999
--------- ---------- --------
(IN THOUSANDS)
Oil and natural gas revenues....................... $ 542,193 $1,111,238 $308,063
Production costs................................... (107,586) (96,847) (47,243)
Development costs.................................. (84,561) (75,995) (25,603)
Net Profits expense................................ -- (15,059) (7,267)
Income tax expense................................. (53,020) (287,959) (49,843)
--------- ---------- --------
Net cash flow...................................... 297,026 635,378 178,107
10% annual discount................................ (97,043) (176,729) (51,239)
--------- ---------- --------
Standardized measure of discounted future net cash
flows............................................ $ 199,983 $ 458,649 $126,868
========= ========== ========
35
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes the principal sources of change in the
standardized measure of discounted future net cash flows from year to year.
AT DECEMBER 31
--------------------------------
2001 2000 1999
--------- --------- --------
(IN THOUSANDS)
Standardized measure of discounted cash flows at
beginning of year................................ $ 458,649 $ 126,868 $ 63,467
Sales and transfers of oil and natural gas
produced, net of production costs and net profits
expense.......................................... (98,274) (73,866) (33,393)
Net changes in prices and production costs......... (486,774) 268,139 50,133
Net changes in estimated development costs......... (28,388) (7,973) 1,746
Net changes in estimated net profits expense....... 10,510 (7,139) (5,306)
Net changes in income tax expense.................. 172,708 (175,031) (28,504)
Extensions, discoveries and improved recovery less
related costs.................................... 89,048 314,747 44,823
Proved oil and gas reserves purchased.............. -- 2,888 --
Proved oil and gas reserves sold................... -- (26,016) (111)
Development costs incurred during the year......... 61,145 21,249 7,007
Revisions of previous quantity estimates........... 13,356 8,274 25,122
Other changes...................................... (37,861) (6,178) (4,463)
Accretion of discount.............................. 45,864 12,687 6,347
--------- --------- --------
Standardized measure of discounted future net cash
flows end of year................................ $ 199,983 $ 458,649 $126,868
========= ========= ========
36
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 10 -- QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
FOR YEARS ENDING
DECEMBER 31,
---------------------
2001 2000
--------- ---------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
FIRST QUARTER
Net sales................................................. $39,222 $15,868
Gross profit.............................................. $25,968 $ 8,785
Net income................................................ $14,657 $ 3,784
Basic net income per share................................ $ 0.68 $ 0.18
Diluted net income per share.............................. $ 0.60 $ 0.18
SECOND QUARTER
Net sales................................................. $33,395 $18,823
Gross profit.............................................. $17,495 $ 9,462
Net income................................................ $ 1,241 $ 7,758
Basic net income per share................................ $ 0.06 $ 0.36
Diluted net income per share.............................. $ 0.05 $ 0.35
THIRD QUARTER
Net sales................................................. $22,407 $22,012
Gross profit.............................................. $ 2,133 $13,847
Net income................................................ $ 383 $22,704
Basic net income per share................................ $ 0.02 $ 1.06
Diluted net income per share.............................. $ 0.02 $ 0.98
FOURTH QUARTER
Net sales................................................. $18,645 $27,693
Gross profit.............................................. $(9,301) $13,099
Net income................................................ $(7,936) $10,798
Basic net income per share................................ $ (0.35) $ 0.50
Diluted net income per share.............................. $ (0.35) $ 0.46
---------------
(1) Net sales include only oil and gas sales revenue.
(2) Gross profit is net sales less operating costs, transportation expense, net
profits expense, exploration expense, depreciation, depletion and
amortization, and impairment of oil and gas properties.
(3) Net income during the third quarter of 2000 includes a $12.5 million gain on
sale of certain South Texas properties.
37
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The following information relates to the members of our board of directors
or executive officers during 2001. Each director holds office until his
successor is elected and qualified or until his resignation or removal.
Executive officers hold their respective offices at the pleasure of the board of
directors.
DON D. BOX Age 51
Positions with us:
- Director since March 1991
- Executive Vice President since October 1997
- Chairman of the Board January 1994-October 1997
- Chief Executive Officer August 1996-October 1997
- President August 1996-March 1997
Positions with our affiliates:
- CKB Petroleum, Inc.
- Vice President since September 1997
- Director August 1982-September 1997
- President August 1982-September 1997
- CKB & Associates, Inc.
- Vice President since May 1981
- Director May 1981-September 1997
- S-Sixteen Holding Company
- Director December 1981-September 1997
- President December 1981-February 1996, April 1997-September 1997
- Vice President February 1996-April 1997, September 1997-December 1998
Outside directorships
- Authoriszer, Inc.
Education
- Bachelor of Arts-University of Pennsylvania
- Bachelor of Science in Economics-The Wharton School of the University of
Pennsylvania
- Masters of Business Administration-Southern Methodist University
JOHN E. GOBLE, JR., CPA Age:
55
Positions with us:
- Director since April 1997
- Member-Audit Committee
Employment:
- Byrd Investments-Investment and financial advisor since 1986
Outside Directorships:
- Miracle of Pentecost Foundation
Education:
- Bachelor of Business Administration-Southern Methodist University
38
WILLIAM E. GREENWOOD Age: 63
Positions with us:
- Director since April 1997
- Member-Audit Committee
- Member-Compensation Committee
Employment:
- Consultant since 1995
- Director and Chief Operating Officer-Burlington Northern Railroad Corporation
from 1990 until 1994
Outside Directorships:
- Iowa-Pacific Corp.
- Transport Dynamics, Inc.
- President-Mendota Museum and Historical Society
Education:
- Bachelor of Science-Marquette University
DAVID H. HAWK Age: 57
Positions with us:
- Director since September 1997
- Chairman of the Board since October 1997
- Member-Executive Committee
Employment:
- J.R. Simplot Company-Director, Energy Natural Resources since 1984
- Previously employed with Atlantic Richfield Company and Tenneco Inc. as an
Exploration Geologist
- Prior executive positions with IGC Production Company, Sundance Oil Company
and Horn Resources Corporation
Education:
- Bachelor of Science in Geology and Distinguished Graduate Medalist-University
of Idaho
- Master of Science in Geology-University of Oklahoma
JAMES ARTHUR LYLE, CCIM Age:
57
Current positions with us:
- Director since September 1997
- Member-Compensation Committee
Employment:
- Owner-James Arthur Lyle & Associates, Inc., a commercial, industrial and
investment real estate firm, since 1976
Outside directorships:
- Director, Chief Operating Officer and President since 1984-Hueco Mountain
Estates, Inc., a 10,500 acre multi-use real estate development located in El
Paso County, Texas
Education:
- Bachelor of Science in Industrial Management-Georgia Institute of Technology
DAVID E. PRENG Age: 55
Position with us:
- Director since April 1997
- Chairman-Compensation Committee
Employment:
39
- Chief Executive Officer and President since 1980-Preng and Associates, Inc.,
an international executive search firm specializing in the energy industry
Outside directorships:
- Director-Community National Bank
- Fellow-Institute of Directors
Education:
- Bachelor of Science in Business Administration-Marquette University
- Master of Business Administration-DePaul University
THOMAS W. ROLLINS Age: 71
Positions with us:
- Director since July 1996
- Member-Executive Committee
Employment:
- Chief Executive Officer since 1985-Rollins Resources, a natural gas and oil
consulting firm
- Previously held executive positions and/or directorships with Shell Oil
Company, Pennzoil Company, Florida Gas Transmission Company, Pogo Producing
Company, Magma Copper Company and Felmont Oil Corporation.
Outside directorships:
- Director-Pheasant Ridge Winery
- Director-The Teaching Company
- Director-Nature Conservancy of Texas
Education:
- Geological Engineering Degree and Distinguished Graduate Medalist-The Colorado
School of Mines
ALAN C. SHAPIRO Age: 56
Positions with us:
- Director since May 1994
- Chairman-Audit Committee
Employment:
- The Ivadelle and Theodore Johnson Professor of Banking and Finance in the
Department of Finance and Business Economics, Marshall School of Business,
University of Southern California, since 1992
- Previously Chairman of the Department of Finance and Business Economics,
University of Southern California, 1993-1998
- Frequent consultant and expert witness to business and government
Publications:
- Multinational Financial Management, a best selling textbook used in MBA
programs worldwide
- Numerous other books and articles
Education:
- Bachelor of Arts in Mathematics-Rice University
- Ph.D. in Economics-Carnegie Mellon University
JAMES A. WATT Age: 52
Positions with us:
- Chief Executive Officer since February 1998
- President since March 1997
- Director since September 1997
- Member-Executive Committee
40
Positions with our Affiliates:
- CKB Petroleum, Inc.
- Director and President since January 1999
- CKB & Associates, Inc.
- Director and President since January 1999
Previous employment highlights:
- Vice President/Exploration-Seagull E&P, Inc., 1993-1997
- Vice President/Exploration and Exploitation-Nerco Oil & Gas, Inc., 1991-1993
Outside Directorships:
- Director -- Suzuki Institute of Dallas
Education:
- Bachelor of Science in Physics-Rensselaer Polytechnic Institute
ROBERT P. MURPHY Age: 43
Positions with us:
- Chief Operating Officer since October 2000 and Senior Vice
President/Exploration & Production since July 1999
- Vice President/Exploration, January 1998-June 1999
Previous employment:
- Director-Cairn Energy USA, Inc., May 1996-November 1997
- Vice President-Exploration-Cairn Energy USA, March 1993-January 1998
- Exploration Geologist-Cairn Energy USA, 1990-March 1993
- Exploration Geologist-Enserch Exploration, 1984-1990
Education:
- Bachelor of Science in Geology-The University of Texas at Austin
- Master of Science in Geosciences-The University of Texas at Dallas
STEVEN J. CRAIG Age: 50
Positions with us:
- Senior Vice President/Planning and Administration since April 1997
Positions with our affiliates:
- CKB Petroleum, Inc.
- Director and Vice President since January 1999
- Vice President and Assistant Treasurer, March 1997-October 1997
- Director, March 1997-August 1997
- CKB & Associates, Inc.
- Director and Vice President since January 1999
- Vice President and Assistant Treasurer, March 1997-October 1997
- Director, March 1997-August 1997
- S-Sixteen Holding Company
- Vice President and Assistant Treasurer, March 1997-October 1997
- Director, March 1997-August 1997
Education:
- Bachelor of Arts in Economics-Southern Methodist University
- Master of Business Administration in Finance and Quantitative
Analysis-Southern Methodist University
41
J. BURKE ASHER Age: 61
Positions with us:
- Vice President/Finance since December 1997
- Secretary since October 1996
- Chief Accounting Officer, September 1996-December 1997
Positions with our affiliates:
- CKB Petroleum
- Treasurer and Assistant Secretary since March 1997
- Director, March 1997-April 1997
- CKB & Associates - Treasurer and Assistant Secretary since March 1997
- Director, March 1997-August 1997
- S-Sixteen Holding Company
- Treasurer and Assistant Secretary, March 1997-December 1998
- Director, March 1997-August 1997
Education:
- Bachelor of Science in Economics-The Wharton School of the University of
Pennsylvania
EDWARD V. HOWARD, CPA Age: 39
Positions with us:
- Vice President/Controller since March 1992
- Assistant Secretary since October 1997
Education:
- Bachelor of Business Administration-West Texas State University
Except for Mr. Rollins' consulting practice, no director has a significant
personal interest in the exploration, development or production of oil and gas.
Mr. Rollins is required to abstain on matters in which there may be a conflict
of interest between us and one of his clients.
NEW EXECUTIVE OFFICER
Effective January 1, 2002, Gregory B. Cox, age 48, was appointed Vice
President/Exploration. Mr. Cox joined Remington in 1997 as Exploration Manager.
He received his Bachelor of Science in Geology in 1980 from the University of
Texas at Arlington. Prior to joining us, he was employed as a geologist and
explorationist with several oil and gas exploration and production companies
including Getty Oil Company, Enserch Exploration and Cairn Energy USA. On March
18, 2002, he owned none of our Common Stock, but held 63,666 employee stock
options exercisable within 60 days.
LITIGATION INVOLVING DIRECTORS AND EXECUTIVE OFFICERS
We know of no reportable litigation involving the directors or executive
officers.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Based solely upon the company's review of Forms 3, 4, and 5 received by us
for 2001, all persons required by Section 16(a) of the Securities Exchange Act
of 1934 ("the Act") to file such forms complied with Section 16(a) of the Act
with the following exceptions: James A. Watt filed one late Form 4 reporting one
transaction. J. R. Simplot filed two late Forms 4 reporting two transactions on
each.
42
ITEM 11. EXECUTIVE COMPENSATION.
The following table summarizes the compensation paid by the company during
2001, 2000, and 1999 to the company's Chief Executive Officer and its four most
highly compensated executive officers, other than the Chief Executive Officer,
whose total annual salary and bonus in 2001 exceeded $100,000.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
-------------------------------- ------------------------------------------
RESTRICTED SECURITIES
OTHER ANNUAL STOCK UNDERLYING ALL OTHER
NAME AND FISCAL SALARY BONUS COMPENSATION AWARDS OPTIONS/ SAR'S COMPENSATION
PRINCIPAL POSITION YEAR ($) ($) ($)(1) ($) (#) ($)(3)
------------------ ------ ------- ------- ------------ ---------- -------------- ------------
James A. Watt................ 2001 320,004 405,000 -- (2) 35,000 1,242
Chief Executive Officer 2000 282,501 296,000 -- -- 123,000 1,242
and President 1999 260,004 156,000 -- -- 80,000 695
Robert P. Murphy............. 2001 225,000 200,000 -- -- 25,000 480
Chief Operating Officer and 2000 187,506 140,000 -- -- 66,000 390
Senior Vice President/ 1999 168,108 52,500 -- -- 45,000 257
Exploration and Production
Steven J. Craig.............. 2001 125,808 46,000 -- -- 12,000 364
Senior Vice President/ 2000 121,008 29,000 -- -- 39,000 346
Planning and Administration 1999 114,708 27,500 -- -- 25,000 390
J. Burke Asher............... 2001 119,600 44,000 -- -- 11,500 1,505
Vice President/Finance 2000 115,008 27,600 -- -- 37,000 928
and Secretary 1999 109,200 26,200 -- -- 25,000 1,008
Edward V. Howard............. 2001 100,008 23,000 -- -- 9,000 162
Vice President/Controller 2000 93,504 22,400 -- -- 29,000 148
and Assistant Secretary 1999 88,200 14,600 -- -- 27,500 143
---------------
(1) No amount is included, as it is less than 10% of the total salary and bonus
of the individual for the year.
(2) At December 31, 2001, Mr. Watt held 3,000 restricted shares of common stock
with a value of $51,900. The total number of restricted shares awarded
effective March 17, 1997, was 15,000, which vest 20% per year from the
effective date. If any dividends are paid to holders of common stock, Mr.
Watt's restricted shares will be entitled to receive dividends.
(3) These amounts are for group term life insurance premiums paid by the
company.
See "Change in Control Arrangements and Employment Contracts" below.
LONG TERM STOCK BASED INCENTIVE PROGRAMS
STOCK OPTIONS
We have stock option plans for our employees and directors because we
believe these options act as both an incentive and a reward for the long-term
growth of our company. The core of our stock option program is the 1997 stock
option plan. Both directors and employees are eligible for options under this
plan. Significant attributes of the 1997 plan include the following:
- Administered by the Compensation Committee of our board of directors.
- Subject to adjustments, up to 3,750,000 shares of our common stock may be
issued under the plan.
- Up to 25% of issuable shares may be issued to any single individual.
- Both qualified incentive and non-qualified options may be issued.
- The plan terminates December 4, 2007.
43
The importance of whether an option is granted as a qualified incentive
option or a non-qualified option is mainly tax driven. If an option is an
incentive option, the exercise price can be no less than the fair market value
on the date of grant. Additional details concerning the 1997 stock option plan
are contained in the plan itself. For a copy of the plan, call Investor
Relations at (214) 210-2650.
OPTION GRANTS IN LAST FISCAL YEAR
--------------------------------------------------------------------------------------------------
INDIVIDUAL GRANTS
---------------------------------------------------
PERCENT OF
NUMBER OF TOTAL
SECURITIES OPTIONS
UNDERLYING GRANTED TO EXERCISE GRANT DATE
OPTIONS EMPLOYEES IN PRICE EXPIRATION PRESENT VALUE
NAME GRANTED FISCAL YEAR $/SHARE DATE $(1)
---- ---------- ------------ -------- ---------- -------------
James A. Watt................ 35,000 11% 15.32 12/11/11 404,600
Robert P. Murphy............. 25,000 8% 15.32 12/11/11 289,000
Steven J. Craig.............. 12,000 4% 15.32 12/11/11 138,720
J. Burke Asher............... 11,500 4% 15.32 12/11/11 132,940
Edward V. Howard............. 9,000 3% 15.32 12/11/11 104,040
---------------
(1) We determined these values using the Black-Scholes option pricing model with
the following assumptions: stock price volatility of 62.68%; interest rate
based on the yield to maturity of a 10-year Treasury security; exercise in
the tenth year; and a dividend rate of zero. We made no adjustments for
nontransferability or risk of forfeiture. Our use of this model does not
constitute an endorsement or an acknowledgment that such model can
accurately determine the value of options. No assurance can be given that
the actual value, if any, realized by an executive upon the exercise of
these options will approximate the estimated values calculated by using the
Black-Scholes model.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION VALUES
----------------------------------------------------------------------------------------------------------
NUMBER OF SECURITIES VALUE OF UNEXERCISED IN-
NUMBER OF UNDERLYING UNEXERCISED THE-MONEY OPTIONS AT
SHARES VALUE OPTIONS AT FISCAL YEAR-END FISCAL YEAR-END($)(1)
ACQUIRED ON REALIZED --------------------------- ---------------------------
NAME EXERCISE ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ----------- -------- ----------- ------------- ----------- -------------
James A. Watt......... 27,749 235,867 296,585 143,666 3,704,338 1,528,391
Robert P. Murphy...... 9,004 121,779 122,996 84,000 1,586,845 841,450
Steven J. Craig....... 35,001 391,448 54,666 46,333 671,141 484,806
J. Burke Asher........ 20,850 236,584 61,151 44,499 754,351 465,740
Edward V. Howard...... 39,600 400,347 26,735 37,499 311,291 392,211
---------------
(1) Computed as the number of securities multiplied by the difference between
the option exercise prices and the closing price of our common stock on
December 31, 2001.
CONDITIONAL STOCK GRANTS
In 1999, the directors approved awards of stock to employees and directors
totaling 679,937 shares of our common stock. The number of shares awarded to
each employee and director is based on the employee's annual base salary as of
June 17,1999, or, in the case of non employee directors, $100,000, divided by
$4.19, which was the closing stock price on June 17, 1999. In order for the
grant to be effective, our stock had to close above a trigger price of $10.42
for 20 consecutive trading days. This trigger was achieved on January 24, 2001.
Recipients of the grant must remain an employee or a director during the vesting
schedules in order to receive the shares. Employees and directors individually
elected one of two vesting periods. The first vesting schedule has 50% percent
of the grant vesting on June 17, 2002, with an additional 25% vesting on June
17, 2003, and the final 25% vesting on June 17, 2004. 267,502 shares are subject
to the this vesting schedule. The second vesting option has 20% of the grant
vesting on January 17, 2002, with an additional 20% vesting on each successive
January 17 through 2006. 395,080 shares are subject to the second vesting
schedule. While 679,937 shares of restricted stock were granted in 1999, as of
March 12, 2001, 662,592 shares are subject to the grant because a director
voluntarily surrendered 23,880 shares, and a new employee was granted
44
6,535 shares. The number of shares subject to the grant may decrease to the
degree that participants fail to remain with us during the vesting period. In
the event of a participant's death while employed or serving as a director with
us, or reaching the retirement age of 65 or receiving long term disability
benefits while employed with us, the grant becomes 100% vested. In addition, the
grants can become 100% vested upon a change of control.
PENSION PLANS
Our defined benefit pension plans provide retirement and other benefits to
eligible employees upon reaching the "normal retirement age," which is age 65 or
after 3 years of service (5 years if employment terminated prior to January 1,
2001), if later. Directors who are not also employees of the company are not
eligible to participate in the plans. Employees are eligible to participate on
January 1 following the completion of six months of service or the attainment of
age 20 1/2, if later. Additional provisions are made for early or late
retirement, disability retirement and benefits to surviving spouses. At normal
retirement age, an eligible employee will receive a monthly retirement income
equal to 35% of his or her average monthly compensation during the three
consecutive calendar years in the prior 10 years which provide the highest
average compensation, plus 0.65% of such average compensation in excess of the
amount shown in the Social Security Covered Compensation Table (as published
annually by the Internal Revenue Service) multiplied by his or her years of
service, limited to 35 years. If an employee terminates employment (other than
by death or disability) before completion of three years of service (five years
if employment terminated prior to January 1, 2001), no benefits are payable. If
an employee terminates employment after three years of service (five years if
employment terminated prior to January 1, 2001), the employee is entitled to all
accrued benefits. The following table illustrates the annual pension for plan
participants that retire at "normal retirement age" in 2001:
PENSION PLAN TABLE
-------------------------------------------------------------------------------------------
YEARS OF SERVICE(1)(3)(4)
AVERAGE ------------------------------------------
COMPENSATION(1)(2) 15 20 25 30 35
------------------ ------ ------ ------ ------ ------
($) ($) ($) ($) ($) ($)
125,000................................... 52,311 55,164 58,018 61,871 63,725
150,000................................... 63,498 67,164 70,830 74,496 78,162
170,000................................... 72,448 76,764 81,080 85,396 89,712
175,000................................... 72,448 76,764 81,080 85,396 89,712
200,000................................... 72,448 76,764 81,080 85,396 89,712
225,000................................... 72,448 76,764 81,080 85,396 89,712
250,000................................... 72,448 76,764 81,080 85,396 89,712
300,000................................... 72,448 76,764 81,080 85,396 89,712
400,000................................... 72,448 76,764 81,080 85,396 89,712
450,000................................... 72,448 76,764 81,080 85,396 89,712
500,000................................... 72,448 76,764 81,080 85,396 89,712
---------------
(1) As of December 31, 2001, the Internal Revenue Code does not allow qualified
plan compensation to exceed $170,000 or the benefit payable annually to
exceed $140,000. The Internal Revenue Service will adjust these limitations
for inflation in future years. When the limitations are raised, the
compensation considered and the benefits payable under the pension plans
will increase to the level of the new limitations or the amount otherwise
payable under the pension plans, whichever amount is lower.
(2) Subject to the above limitations, compensation in this table is generally
equal to all of a participant's cash compensation paid in a fiscal year (the
total of Salary, Bonus, and Other Annual Compensation in the Summary
Compensation Table). Average compensation in this table is the average of a
plan participant's compensation during the highest three consecutive years
out of the prior 10 years.
45
(3) The estimated credited service at December 31, 2001, for the executive
officers shown in the Summary Compensation Table on page 43 is as follows:
James A. Watt (5 years), Robert P. Murphy (4 years), Steven J. Craig (7
years), J. Burke Asher (5 years), and Edward V. Howard (11 years).
(4) The normal form of payment is a life annuity for a single participant or a
50% joint and survivor annuity for a married participant. Such benefits are
not subject to a deduction for Social Security or other offset amounts.
COMPENSATION OF DIRECTORS
- Only non-employee directors are compensated for board service
- Compensation includes:
- Annual retainer of $20,000
- $1,000 per board meeting attended (Chairman of the Board receives extra
$250 per board meeting attended)
- Unless surrendered, eligible for stock grant (see discussion of grant on
page 44)
- Committee meeting fee of $750 per meeting attended by committee members
or $1,000 for the committee chairman per meeting attended, if on a
different day than a full board meeting
- Directors are entitled to reimbursement of company related out-of-pocket
expenses
- We provide directors and officers insurance and indemnification to the
full extent allowed by law
- All or part of a director's board compensation may be received in
company stock in accordance with the Non-Employee Director Stock
Purchase Plan
- There were six board meetings in 2001
- All directors attended at least 75% of the meetings
- During 2001, we paid an entity controlled by director David E. Preng
$2,000 for consulting fees.
NON-EMPLOYEE DIRECTOR STOCK PURCHASE PLAN
- This plan was adopted December 4, 1997
- Each non-employee director may, once a year, elect to receive all or part
of his board compensation in our common stock
- The number of shares received equals 150% of the cash amount of
compensation divided by the closing market price of our common stock on
the day the cash fees would be payable
- Shares received under this plan may not be transferred for one year after
issuance
- Shares may be transferred earlier than one year based on a director's
death, disability or departure from the board
- During the restricted transfer period the director may vote the stock and
receive any dividends
- The board may terminate this plan at any time
46
- Shares received under plan for 2001:
- John E. Goble, Jr. 1,164 shares in lieu of $12,000 cash
- William E. Greenwood 2,815 shares in lieu of $29,500 cash
- James Arthur Lyle 2,684 shares in lieu of $28,250 cash
- David E. Preng 2,684 shares in lieu of $28,250 cash
- Thomas W. Rollins 776 shares in lieu of $8,000 cash
- Alan C. Shapiro 2,808 shares in lieu of $29,750 cash
CHANGE IN CONTROL ARRANGEMENTS AND EMPLOYMENT CONTRACTS
All of our full-time regular employees are covered by a severance plan that
we adopted in 1997. Under this plan, if an employee is involuntarily terminated,
as that term is defined in the plan, the employee will be entitled to a payment
of between two months base pay and eighteen months base pay depending on the
employee's job and years of experience. If an employee voluntarily quits, is
terminated for cause as defined in the plan, dies, leaves due to a disability
for which benefits are payable, or the termination is expected to be of short
duration, the employee is not eligible for payment under the plan. In addition,
under certain circumstances, a change in control could cause immediate vesting
and triggering of stock options and contingent stock grants. If the contingent
stock grants were vested by a change in control, it would result in the issuance
of a maximum aggregate of 662,592 shares to directors and employees.
EMPLOYMENT AGREEMENTS
We have employment agreements with James A. Watt, Robert P. Murphy, Steven
J. Craig, and J. Burke Asher. The most significant terms of such agreements are
summarized below:
James A. Watt
- Term of three years from January 31, 2000, subject to single year
extensions by mutual agreement
- Base salary of $270,000 a year, subject to discretionary increases
- Eligible to receive discretionary performance bonus (targeted at 70% of
base salary)
- If terminated prior to a change in control, without cause, he receives
his salary plus a pro rata bonus
- He receives 2.99 times the sum of his base salary plus his target bonus
if he is terminated within 24 months of a change in control, other than
for death, disability or cause, or he leaves for good reason within the
24 month period
Robert P. Murphy
- Term of three years from September 30, 1999, subject to single year
extensions by mutual agreement
- Base salary of $175,000 a year, subject to discretionary increases
- Eligible to receive discretionary performance bonus (targeted at 50% of
base salary)
- If terminated prior to a change in control, without cause, he receives
his salary plus a pro rata bonus
- He receives 2.99 times the sum of his base salary plus his target bonus
if he is terminated within twelve months of a change in control, other
than for death, disability or cause, or he leaves for good reason within
the twelve month period
Steven J. Craig and J. Burke Asher
- Term of two years from September 30, 1999, subject to single year
extensions by mutual agreement
- Base salary of $114,200 (Mr. Craig) and $109,200 (Mr. Asher), subject to
discretionary increases
- Eligible to receive discretionary performance bonus (targeted at 20% of
base salary)
47
- Severance payments similar to Robert Murphy's, except that Mr. Craig and
Mr. Asher each receive 2 times the sum of his annual salary plus target
bonus in connection with leaving employment within twelve months of a
change in control
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION IN COMPENSATION
DECISIONS
David E. Preng, William E. Greenwood, and James Arthur Lyle served on the
compensation committee in 2001. No executive officer or employee serves on the
compensation committee of the board. None of our executive officers serves on
the board of directors of any other entity that has an executive officer serving
on our board.
BOARD COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
We believe that employing and retaining highly qualified and high
performing executive officers is vital to our achievement of long-term business
goals. To this end, the Compensation Committee of the board of directors (the
"Committee") developed an executive compensation program which is designed to
attract and retain such officers.
The philosophy is to develop a systematic, competitive executive
compensation program which recognizes an executive officer's position and
responsibilities, takes into account competitive compensation levels payable
within the industry by similarly sized companies, and reflects both individual
and company performance.
The executive compensation program developed by the Committee is composed
of the following three elements: (i) a base salary, (ii) a performance-based
annual cash incentive (short-term), and (iii) a stock-based incentive
(long-term). Under this program, short-term and long-term incentives are "at
risk" and are based on performance of the company versus defined goals.
The Committee compiles data reflecting the compensation practices of a
broad range of organizations in the oil and gas industry that are similar to us
in size and performance. For both the base salary and annual cash incentives
portions of executive compensation discussed below, the Committee adopted a
philosophy of paying the executive officers at a level that is competitive and
within the ranges reflected by the data compiled.
BASE SALARIES
Base salary is the portion of an executive officer's total compensation
package which is payable for performing the specific duties and assuming the
specific responsibilities defining the executive's position with the company.
The Committee's objective is to provide each executive officer a base salary
that is competitive at the desired level.
ANNUAL CASH INCENTIVES
The Committee developed a performance-based annual cash incentive plan
covering the executive officers and top managers. The objectives in designing
the plan are to reward participants for accomplishing objectives which are
generally measurable and increase shareholder value. Under the annual cash
incentive plan, the Committee has established a "target" cash incentive award
for each executive officer (including the Chief Executive Officer) that is
payable based mostly upon the company's achieving certain performance targets
and, to a lesser extent, for achieving highly challenging individual performance
objectives. The performance targets are increasing reserves and production;
controlling finding, development, and production costs; and achieving an overall
return on capital; all of which are competitive with a peer group of oil and gas
companies. The committee also determined that award levels under the plan should
be fiscally prudent.
48
LONG-TERM STOCK-BASED INCENTIVES
We maintain a stock option plan for officers and other employees. The
philosophy is to award stock options to selected plan participants based on
their levels within the company and upon individual merit. The plan is to grant
stock options which are competitive within the industry for other individuals at
the employee's level and which provide the employee a meaningful incentive to
remain with the company, to increase performance, and to focus on achieving
long-term increases in shareholder value. Other factors the Committee considers
in granting stock options include the employee's contributions toward achieving
the company's long-term objectives, such as reserve replacements and
acquisitions, as well as the employee's contributions in achieving the company's
short-term and long-term profitability targets.
COMPENSATION COMMITTEE
David E. Preng
William E. Greenwood
James Arthur Lyle
49
PERFORMANCE GRAPH
The following performance graph compares the performance of all classes of
our common stock to the Nasdaq indices of United States companies and to a peer
group comprising Nasdaq companies listed under the Standard Industrial
Classification Codes 1310-1319 for the company's last five fiscal years. Such
industrial codes include companies engaged in the oil and gas business. The
graph assumes that the value of an investment in our common stock and in each
index was $100 at December 31, 1996, and that all dividends were reinvested.
(PERFORMANCE GRAPH)
--------------------------------------------------------------------------------------------------
12/31/1996 12/31/1997 12/31/1998 12/31/1999 12/31/2000 12/31/2001
--------------------------------------------------------------------------------------------------
ROILA(1) 100.00 56.76 39.63 48.18 161.62 215.08
ROILB(1) 100.00 56.85 34.93 42.47 142.47 189.59
NASDAQ U.S. 100.00 122.50 172.70 320.80 193.00 153.10
NASDAQ O&G 100.00 95.30 46.30 47.80 99.40 74.50
---------------
(1) The last day of trading for ROILA and ROILB was December 24, 1998. Effective
at the opening of trading on December 28, 1998, both former classes of stock
were replaced by a new single class of voting common stock (ROIL). The
values shown above as of December 31, 1998,1999, and 2000 for ROILA give
effect to the 1.15:1 exchange ratio that the former holders of ROILA
received in the exchange for the new class of common stock, and the 1:1
exchange ratio that the former holders of ROILB received in the exchange for
the new class of common stock.
50
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
As of March 18, 2001, the following persons held shares of the company's
common stock in amounts totaling more than 5% of the total shares of common
stock outstanding. This information was furnished to us by such persons or
statements filed with the Commission.
SHARES OF
COMMON STOCK
BENEFICIALLY PERCENT OF
NAME AND ADDRESS OF BENEFICIAL OWNER OWNED COMMON STOCK
------------------------------------ ------------ ------------
J.R. Simplot............................................. 5,631,028(1) 25%
999 Main Street
Boise, Idaho 83702(1)
---------------
(1) Mr. J.R. Simplot is the trustee and beneficiary of the J.R. Simplot Self
Declaration of Revocable Trust, an inter vivos revocable trust. The Trust is
the manager of JRS Investments, L.L.C. which is the sole holder of the 1%
general partnership interest of JRS Properties III, LP ("JRS III"). In
addition, the trust holds the 99% limited partnership interest in JRS III.
Included in shares of common stock beneficially owned by Mr. Simplot are all
of the following, of which Mr. Simplot may be deemed a beneficial owner:
2,785,028 shares owned by JRS III; 2,845,000 shares owned by the Trust; and
1,000 shares owned jointly by Mr. Simplot and his spouse.
OWNERSHIP OF MANAGEMENT
The number of shares of the company's common stock beneficially owned as of
March 18, 2001, by directors of the company, each officer listed in the
compensation table on page 43, and as a group comprising all directors and
executive officers, are set forth in the following table. This information was
furnished to the company by such persons.
OPTIONS
SHARES OF EXERCISABLE
COMMON STOCK WITHIN 60 DAYS PERCENT OF
BENEFICIALLY OF MARCH 12, COMMON
NAME OWNED 2001 TOTAL STOCK
---- ------------ -------------- --------- ----------
J. Burke Asher.............................. 11,447 74,484 85,931 *
Don D. Box.................................. 73,244 153,334 226,578 *
Steven J. Craig............................. 28,867 67,666 96,533 *
John E. Goble, Jr. ......................... 17,849 101,667 119,516 *
William E. Greenwood........................ 15,283 101,667 116,950 *
David H. Hawk............................... 2,430 -- 2,430 *
Edward V. Howard............................ 26,583 36,402 62,985 *
James Arthur Lyle........................... 29,768 101,667 131,435 *
Robert P. Murphy............................ 18,729 141,008 159,737 *
David E. Preng.............................. 49,724 111,667 161,391 *
Thomas W. Rollins........................... 15,481 76,667 92,148 *
Alan C. Shapiro............................. 40,285 101,667 141,952 *
James A. Watt............................... 67,082 337,585 404,667 1.8%
All directors and executive officers as a
group (14 persons)........................ 396,772 1,469,147 1,865,919 7.7%
---------------
* Less than one percent of the outstanding shares.
51
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
A resolution adopted in 1992 by our board of directors authorizes us to
enter into a transaction with an affiliate of ours so long as the board of
directors determines that such a transaction is fair and reasonable to us and is
on terms no less favorable to us than can be obtained from an unaffiliated party
in an arms' length transaction.
A long-term receivable in the aggregate amount of $354,000 acquired in the
merger reflects CKB Petroleum's claims under Collateral Assignment Split Dollar
Insurance Agreements among CKB Petroleum and Don D. Box and two of his brothers.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) Documents filed as part of this report:
1. Financial Statements included in Item 8:
(i) Independent Auditors' Report
(ii) Consolidated Balance Sheets as of December 31, 2001 and 2000
(iii) Consolidated Statements of Income for years ended December
31, 2001, 2000 and 1999
(iv) Consolidated Statement of Stockholders' Equity for years ended
December 31, 2001, 2000 and 1999
(v) Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999
(vi) Notes to Consolidated Financial Statements
(vii) Supplemental Oil and Natural Gas Information (Unaudited)
(Included in the Notes to Consolidated Financial Statements)
2. Financial Statement Schedules
Financial statement schedules are omitted as they are not
applicable, or the required information is included in the financial
statements or notes thereto.
(b) Reports on Form 8-K:
We filed no reports on Form 8-K during the three months ended December
31, 2001.
(c) Exhibits:
2.0++ Agreement and Plan of Merger dated as of June 22, 1998, by
and between Remington Oil and Gas Corporation and S-Sixteen
Holding Company.
3.1* Certificate of Incorporation, as amended.
3.2### Certificate of Amendment of Certificate of Incorporation of
Box Energy Corporation.
3.2.1++ Certificate of Amendment of Certificate of Incorporation of
Remington Oil and Gas Corporation.
3.3+++ By-Laws as amended.
4.1* Form of Indenture Box Energy Corporation to United States
Trust Company of New York, Trustee, dated December 1, 1992,
8 1/4% Convertible Subordinated Notes due December 1, 2002.
10.1* Farmout Agreement with Aminoil USA, Inc., effective May 1,
1977, dated May 9, 1977.
52
10.2* Transportation Agreement with CKB Petroleum, Inc. dated
March 1, 1985, as amended on April 19, 1989.
10.3* Agreement of Compromise and Amendment to Farmout Agreement,
dated July 3, 1989.
10.4 Pension Plan of Remington Oil and Gas Corporation, as
Amended and Restated effective January 1, 2000.
10.5 Amendment Number One to the Pension Plan of Remington Oil
and Gas Corporation.
10.6*** Agreement by and between Box Energy Corporation and James A.
Watt.
10.7### Box Energy Corporation Severance Plan.
10.8+ Box Energy Corporation 1997 Stock Option Plan. (as amended
June 17, 1999 and May 23, 2001)
10.9### Box Energy Corporation Non-Employee Director Stock Purchase
Plan
10.10Y Form of Employment Agreement effective September 30, 1999,
by and between Remington Oil and Gas Corporation and two
executive officers.
10.11Y Form of Employment Agreement effective September 30, 1999,
by and between Remington Oil and Gas Corporation and an
executive officer.
10.12# Employment Agreement effective January 31, 2000, by and
between Remington Oil and Gas Corporation and James A. Watt.
21 Subsidiaries of the registrant.
23.1 Consent of Arthur Andersen LLP
23.2 Consent of Netherland, Sewell & Associates
23.3 Consent of Miller and Lents, Ltd.
99.1 Letter from Remington Oil and Gas Corporation to Securities
and Exchange Commission regarding Arthur Andersen LLP
representation.
---------------
* Incorporated by reference to the Company's Registration
Statement on Form S-2 (file number 33-52156) filed with the
Commission and effective on December 1, 1992.
# 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 and effective on or about 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 or about
November 9, 2001.
*** Incorporated by reference to the Company's Form 10-Q (file
number 1-11516) for the fiscal quarter ended June 30, 1997
filed with the Commission and effective on or about August
12, 1997.
### 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 and effective on or about 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-K (file
number 1-11516) for the fiscal year ended December 31, 1998
filed with the Commission and effective on or about March
30, 1999.
Y 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 and effective on or about
November 12, 1999.
53
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Date: March 21, 2002 REMINGTON OIL AND GAS CORPORATION
By: /s/ JAMES A. WATT
------------------------------------
James A. Watt
President and Chief Executive
Officer
Pursuant to the requirements of the Securities Act of 1934, this report has
been signed below by the following persons on behalf of the Registrant and in
the capacities and on the date indicated.
DIRECTORS:
/s/ DON D. BOX /s/ JOHN E. GOBLE, JR. /s/ WILLIAM E. GREENWOOD
----------------------------- ----------------------------- -----------------------------
Don D. Box John E. Goble, Jr. William E. Greenwood
Director Director Director
/s/ DAVID H. HAWK /s/ JAMES ARTHUR LYLE /s/ DAVID E. PRENG
----------------------------- ----------------------------- -----------------------------
David H. Hawk James Arthur Lyle David E. Preng
Director Director Director
/s/ THOMAS W. ROLLINS /s/ ALAN C. SHAPIRO /s/ JAMES A. WATT
----------------------------- ----------------------------- -----------------------------
Thomas W. Rollins Alan C. Shapiro James A. Watt
Director Director 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 Chief Executive Vice President/Finance Vice President/Controller
Officer (Principal Financial Officer) (Principal Accounting
Officer)
Date: March 21, 2002
54
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
------- -----------------------
2.0++ Agreement and Plan of Merger dated as of June 22, 1998, by
and between Remington Oil and Gas Corporation and S-Sixteen
Holding Company.
3.1* Certificate of Incorporation, as amended.
3.2### Certificate of Amendment of Certificate of Incorporation of
Box Energy Corporation.
3.2.1++ Certificate of Amendment of Certificate of Incorporation of
Remington Oil and Gas Corporation.
3.3+++ By-Laws as amended.
4.1* Form of Indenture Box Energy Corporation to United States
Trust Company of New York, Trustee, dated December 1, 1992,
8 1/4% Convertible Subordinated Notes due December 1, 2002.
10.1* Farmout Agreement with Aminoil USA, Inc., effective May 1,
1977, dated May 9, 1977.
10.2* Transportation Agreement with CKB Petroleum, Inc. dated
March 1, 1985, as amended on April 19, 1989.
10.3* Agreement of Compromise and Amendment to Farmout Agreement,
dated July 3, 1989.
10.4 Pension Plan of Remington Oil and Gas Corporation, as
Amended and Restated effective January 1, 2000.
10.5 Amendment Number One to the Pension Plan of Remington Oil
and Gas Corporation.
10.6*** Agreement by and between Box Energy Corporation and James A.
Watt.
10.7### Box Energy Corporation Severance Plan.
10.8+ Box Energy Corporation 1997 Stock Option Plan. (as amended
June 17, 1999 and May 23, 2001)
10.9### Box Energy Corporation Non-Employee Director Stock Purchase
Plan
10.10Y Form of Employment Agreement effective September 30, 1999,
by and between Remington Oil and Gas Corporation and two
executive officers.
10.11Y Form of Employment Agreement effective September 30, 1999,
by and between Remington Oil and Gas Corporation and an
executive officer.
10.12# Employment Agreement effective January 31, 2000, by and
between Remington Oil and Gas Corporation and James A. Watt.
21 Subsidiaries of the registrant.
23.1 Consent of Arthur Andersen LLP
23.2 Consent of Netherland, Sewell & Associates
23.3 Consent of Miller and Lents, Ltd.
99.1 Letter from Remington Oil and Gas Corporation to Securities
and Exchange Commission regarding Arthur Andersen LLP
representation.
---------------
* Incorporated by reference to the Company's Registration
Statement on Form S-2 (file number 33-52156) filed with the
Commission and effective on December 1, 1992.
# 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 and effective on or about 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 or about
November 9, 2001.
*** Incorporated by reference to the Company's Form 10-Q (file
number 1-11516) for the fiscal quarter ended June 30, 1997
filed with the Commission and effective on or about August
12, 1997.
### 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 and effective on or about 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-K (file
number 1-11516) for the fiscal year ended December 31, 1998
filed with the Commission and effective on or about March
30, 1999.
Y 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 and effective on or about
November 12, 1999.