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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K/A
AMENDMENT NO. 1
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-11516
REMINGTON OIL AND GAS CORPORATION
(Exact name of registrant as specified in its charter)
DELAWARE 75-2369148
(State or other jurisdiction of
incorporation or organization) (I.R.S. employer Identification No.)
8201 PRESTON ROAD, SUITE 600, DALLAS, TEXAS 75225-6211
(Address of principal executive offices) (Zip code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE:
(214) 210-2650
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Common Stock, $0.01 Par Value New York Stock Exchange
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/A or any amendment to
this Form 10-K/A. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [X] No [ ]
The aggregate market value of common stock held by non-affiliates of the
registrant as of the last business day of the registrant's most recently
completed second fiscal quarter, was $401,219,317. On March 27, 2003, the number
of outstanding shares of common stock, $0.01 par value, was 26,399,437.
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REMINGTON OIL AND GAS CORPORATION
TABLE OF CONTENTS
PAGE
----
PART I........................................................................ 2
Item 1. Business.................................................... 2
Item 2. Properties.................................................. 5
Item 3. Legal Proceedings........................................... 7
Item 4. Submission of Matters to a Vote of Security Holders......... 7
PART II....................................................................... 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........................................................ 18
Item 8. Financial Statements and Supplementary Data................. 19
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 44
PART III...................................................................... 44
Item 10. Directors and Executive Officers of the Registrant.......... 44
Item 11. Executive Compensation...................................... 51
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 59
Item 13. Certain Relationships and Related Transactions.............. 60
Item 14. Controls and Procedures..................................... 60
PART IV....................................................................... 61
Item 15. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 61
1
PART I
ITEM 1. BUSINESS.
GENERAL
Remington Oil and Gas Corporation
- Incorporated - 1991, Delaware
- Address - 8201 Preston Road, Suite 600, Dallas, Texas 75225-6211
- Telephone number - (214) 210-2650
- Website - www.remoil.net - Our Annual Reports on Form 10-K, Quarterly
Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to
those reports filed or furnished pursuant to Section 13(a) or 15(d) of
the Securities Exchange Act of 1934 are available on our website under
the link "SEC Filings" as soon as reasonably practicable after we
electronically file such material with, or furnish it to, the Securities
and Exchange Commission.
- 29 employees on December 31, 2002
We began operations in 1981 as OKC Limited Partnership. In 1992, the
limited partnership was converted into a corporation named Box Energy
Corporation. In 1997, we changed the name of the company to Remington Oil and
Gas Corporation. We restructured our two classes of common stock into a single
class of voting common stock when we merged with S-Sixteen Holding Company in
December 1998.
Our primary business operation is exploration, development, and production
of oil and gas reserves in the offshore Gulf of Mexico and onshore Gulf Coast
areas. All of our assets are located in these areas and all of our revenues and
expenses are generated in these same regions of the United States.
LONG-TERM STRATEGY
Our long-term strategy is to increase our oil and gas reserves and
production while keeping our finding and development costs and operating costs
competitive with our industry peers. We will implement this strategy through
drilling exploratory and development wells from our inventory of available
prospects that we have evaluated for geologic and mechanical risk and future
reserve or resource potential. Our drilling program will contain some high
risk/high reserve potential opportunities as well as some lower risk/lower
reserve potential opportunities, in order to achieve a balanced program of
reserve and production growth. Success of this strategy is contingent on various
risk factors, as discussed in our filings with the Securities and Exchange
Commission.
ACTIVITIES AND OPERATIONS
We identify prospective oil and gas properties primarily by using 3-D
seismic technology. After acquiring an interest in a prospective property, we
drill one or more exploratory wells. If the exploratory wells find commercial
oil and/or gas, we complete the wells and begin producing the oil or gas.
Because most of our operations are located in the offshore Gulf of Mexico, we
must install facilities such as offshore platforms and gathering pipelines in
order to produce the oil and gas and deliver it to the marketplace. Certain
properties require additional drilling to fully develop the oil and gas reserves
and maximize the production from a particular discovery. In order to increase
our oil and gas reserves and production, we continually reinvest our net
operating cash flow into new or existing exploration, development and
acquisition activities.
We share ownership in our oil and gas properties with various industry
partners. We currently operate 66 of our offshore properties, while others
operate the remainder of our properties. As operator, we are able to maintain a
greater degree of control over the timing and amount of capital expenditures.
2
RISKS INVOLVED IN EXPLORATION, DEVELOPMENT, AND PRODUCTION
Exploration, development, and production operations can be very risky. Each
time we drill a well, there is a risk that the well will not find oil or gas
reserves. If a well does find reserves, it is possible that the well will not
produce enough oil or gas to return a profit on the amount invested in the well.
We mitigate exploration and drilling risks by using 3-D seismic data and other
applied technology to identify and define the parameters prior to drilling,
although this does not guarantee successful results. Our success depends upon
the quality of the information used to determine drilling locations and the
abilities and experience of our management, technical, and service personnel.
Additional operating risks include mechanical failure, title risk,
blowouts, environmental pollution, and personal injury. We maintain both general
liability insurance and activity specific insurance against major production
losses, blowouts, redrilling, and many other operating hazards, including
certain pollution risks. Uninsured losses or losses and liabilities that exceed
the limits of our insurance could adversely affect our financial condition.
COMPETITION IN THE OIL AND GAS INDUSTRY
We compete with: We compete for:
- Large integrated oil and gas companies - Operational, technical, and support staff
- Independent exploration and production - Options and/or leases on properties
companies
- Private individuals - Sales of oil and gas production
- Sponsored drilling programs - Access to capital
Many of our competitors may have significantly more financial, personnel,
technological, and other resources available. In addition, some of the larger
integrated companies may be better able to respond to industry changes including
price fluctuations, oil and gas demands, and governmental regulations.
MARKETS FOR OIL AND GAS PRODUCTION
Oil and gas are generally homogenous commodities, and the market prices for
these commodities fluctuate significantly. Purchasers adjust prices for quality,
refined product yield, geographic proximity to refineries or major market
centers, and the availability of transportation pipelines or facilities. Outside
factors beyond our control combine to influence the market prices. Some of the
more critical factors that affect oil and gas commodity prices include the
following:
- Changes in supply and demand
- Changes in refinery utilization
- Levels of economic activity throughout the country
- Seasonal or extraordinary weather patterns
- Political developments throughout the world
We have no real ability to influence or predict the market prices.
Therefore, we normally sell our oil and gas production based on posted market
prices, spot market indices, or prices derived from the posted price or index.
At times we will lock in a fixed price for a portion of our future production to
be delivered as it is produced. An independent marketing company sells
approximately 91% of our gas production. The revenue from the sale of gas by
this marketing company accounted for approximately 54% of our total oil and gas
revenues in 2002. In addition, we sold approximately 86% of our total oil
production to two companies during the year, which accounted for approximately
36% of our total oil and gas revenues in 2002. Because other customers and
marketers are available, we believe that the loss of any of these companies
would not be detrimental to our operations nor have a material effect on our
revenues.
3
GOVERNMENTAL REGULATION OF OIL AND GAS OPERATIONS AND ENVIRONMENTAL REGULATIONS
Numerous federal and state regulations affect our oil and gas operations.
Current regulations are constantly reviewed by the various agencies at the same
time that new regulations are being considered and implemented. In addition,
because we hold federal leases, the federal government requires us to comply
with numerous additional regulations that focus on government contractors. The
regulatory burden upon the oil and gas industry increases the cost of doing
business and consequently affects our profitability.
State regulations relate to virtually all aspects of the oil and gas
business including drilling permits, bonds, and operation reports. In addition,
many states have regulations relating to pooling of oil and gas properties,
maximum rates of production, and spacing and plugging and abandonment of wells.
Our oil and gas operations are subject to stringent federal, state, and
local environmental laws and regulations. Environmental laws and regulations are
complex, change frequently, and have tended to become more stringent over time.
Many environmental laws require permits from governmental authorities before
construction on a project may be commenced or before wastes or other materials
may be discharged into the environment. The process for obtaining necessary
permits can be lengthy and complex, and can sometimes result in the
establishment of permit conditions that make the project or activity for which
the permit was sought either unprofitable or otherwise unattractive. Even where
permits are not required, compliance with environmental laws and regulations can
require significant capital and operating expenditures, and we may be required
to incur costs to remediate contamination from past releases of wastes into the
environment. Failure to comply with these statutes, rules and regulations may
result in the assessment of administrative, civil and even criminal penalties.
The most significant environmental obligations applicable to our operations
relate to compliance with the federal Oil Pollution Act and the Clean Water Act.
The Oil Pollution Act and its implementing regulations ("OPA") establish
requirements for the prevention of oil spills and impose liability for damages
resulting from spills into waters of the United States. OPA also requires
operators of offshore oil production facilities, such as our facilities in the
Gulf of Mexico, to demonstrate to the U.S. Minerals Management Service that they
possess at least $35.0 million in financial resources that are available to pay
for costs that may be incurred in responding to an oil spill. The Clean Water
Act and its implementing regulations impose restrictions and strict controls on
the discharge of wastes into the waters of the United States, including
discharges of oil, produced water and sand, drilling fluids, drill cuttings, and
other wastes typically generated by the oil and gas industry. Although we
believe that we are in compliance with the requirements of OPA, the Clean Water
Act and other statutes 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.
4
ITEM 2. PROPERTIES.
We concentrate our principal operations in the federal waters of the Gulf
of Mexico and its coastal regions. In addition to the information below, we
encourage you to read "Management's Discussion and Analysis of Financial
Condition and Results of Operations" found on pages 9 through 18 and
"Consolidated Financial Statements and Notes to Consolidated Financial
Statements" found on pages 26 through 41. Note 2 - Oil and Gas Properties and
Note 9 - Oil and Gas Reserves and Present Value Disclosures in our Notes to
Consolidated Financial Statements provide detailed information concerning costs
incurred, proved oil and gas reserves, and discounted future net revenue for
proved reserves.
LEASEHOLD ACREAGE
Our leasehold acreage of oil and gas properties at December 31, 2002, was
as follows:
UNDEVELOPED DEVELOPED
----------------- ----------------
GROSS NET GROSS NET
------- ------- ------- ------
Offshore........................................ 305,155 155,630 165,450 70,084
Onshore......................................... 88,624 28,244 27,250 8,152
------- ------- ------- ------
Total........................................... 393,779 183,874 192,700 78,236
======= ======= ======= ======
The current terms of leases on undeveloped acreage are scheduled to expire
as shown in the table below. The term of a lease may be extended by drilling and
production operations.
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------
2003 2004 2005 2006 - BEYOND TOTAL
-------------- -------------- --------------- ----------------- -----------------
GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET
------ ----- ------ ----- ------ ------ ------- ------- ------- -------
Offshore............. 5,000 4,375 0 0 20,278 11,264 279,877 139,991 305,155 155,630
Onshore.............. 12,670 3,456 29,788 6,963 34,716 8,440 11,450 9,385 88,624 28,244
------ ----- ------ ----- ------ ------ ------- ------- ------- -------
Total................ 17,670 7,831 29,788 6,963 54,994 19,704 291,327 149,376 393,779 183,874
====== ===== ====== ===== ====== ====== ======= ======= ======= =======
PROVED OIL AND GAS RESERVES
Net proved oil and gas reserves at December 31, 2002, as evaluated by
independent reserve engineers, Netherland, Sewell & Associates, Inc., are
summarized below. The quantities of proved oil and gas reserves discussed in
this section include only the amounts which we reasonably expect to recover in
the future from known oil and gas reservoirs under the current economic and
operating conditions. Proved reserves include only quantities that we expect to
recover commercially using current prices, costs, existing regulatory practices
and technology. Therefore, any changes in future prices, costs, regulations,
technology or other unforeseen factors could materially increase or decrease the
proved reserve estimates.
NET OIL NET GAS
RESERVES RESERVES
MBBLS MMCF
-------- --------
Offshore Gulf of Mexico..................................... 8,952 118,651
Onshore Gulf Coast.......................................... 4,162 6,316
------ -------
Total....................................................... 13,114 124,967
====== =======
In 2002 our standardized measure of discounted future net cash flows was
$351.0 million. We used December 31, 2002, West Texas Intermediate posted price
of $28.00 per barrel and a Gulf Coast spot market price of $4.74 per MMBtu
adjusted by property for energy content, quality, transportation fees, and
regional price differentials. We estimated the costs based on the prior year
costs incurred for individual properties or similar properties if a particular
property did not produce during the prior year.
5
PRODUCING PROPERTIES
The table below summarizes our ownership in producing wells at the end of
each of the last three years.
AT DECEMBER 31,
---------------------------------------------
2002 2001 2000
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Oil wells
Offshore Gulf of Mexico......................... 25 8.67 21 6.72 14 3.57
Onshore Gulf Coast.............................. 32 12.89 35 13.61 29 11.13
--- ----- --- ----- --- -----
Total............................................. 57 21.56 56 20.33 43 14.70
=== ===== === ===== === =====
Gas wells
Offshore Gulf of Mexico......................... 35 11.19 38 11.02 29 7.68
Onshore Gulf Coast.............................. 75 18.52 97 23.65 85 20.92
--- ----- --- ----- --- -----
Total............................................. 110 29.71 135 34.67 114 28.60
=== ===== === ===== === =====
The decline in the gross number of wells from 2001 to 2002 is attributable
to the sale of 8 wells and the discontinuance of production from a number of
marginal wells.
Our offshore Gulf of Mexico properties account for approximately 80% of our
oil production and approximately 92% of our gas production. In addition, total
revenues from offshore Gulf of Mexico oil and gas production during 2002
accounted for approximately 89% of our total oil and gas revenues. We owned
varying working interests (5% to 100%) in 94 offshore Gulf of Mexico blocks at
December 31, 2002, and currently produce from 30 of these blocks. Three
additional blocks are currently under development. We operate 17 of these 33
blocks. All of these blocks are located in water depths of less than 600 feet on
the outer continental shelf of the Gulf of Mexico. In addition, we have invested
in long-term 3-D seismic licensing agreements covering approximately 2,700
blocks in this area. Our agreements combined with our computer technology,
provide our technical team immediate in-house access to these seismic data.
During 2002 we successfully drilled and completed 11 exploratory wells on 8
different properties in the offshore Gulf of Mexico. In addition, we, as
operator, constructed and installed or will install 6 production platforms and
drilled and completed 2 development wells on 2 different properties.
Our onshore Gulf Coast area properties are principally located in the State
of Mississippi and along the Texas gulf coast. In 2002, these properties
accounted for approximately 20% of our oil production and approximately 8% of
our gas production. We drilled a total of 9 wells on our onshore properties
during 2002 and completed 6 wells as producers. Our working interests in these
wells range from 15% to 50%.
DRILLING ACTIVITIES
The following is a summary of our exploration and development drilling
activities for the past three years.
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------------------------
2002 2001 2000
--------------------------- --------------------------- ---------------------------
GROSS NET GROSS NET GROSS NET
----------- ------------- ----------- ------------- ----------- -------------
PROD. DRY PROD. DRY PROD. DRY PROD. DRY PROD. DRY PROD. DRY
----- --- ------ ---- ----- --- ----- ---- ----- --- ----- ----
Exploratory
Offshore Gulf of Mexico....... 11 4 5.28 1.66 13 2 4.77 0.91 12 -- 5.45 --
Onshore Gulf Coast............ 5 3 1.66 0.75 9 3 2.81 0.90 18 6 4.40 2.27
--- -- ---- ---- --- -- ---- ---- --- -- ---- ----
Total......................... 16 7 6.94 2.41 22 5 7.58 1.81 30 6 9.85 2.27
=== == ==== ==== === == ==== ==== === == ==== ====
Development
Offshore Gulf of Mexico....... 2 -- 0.66 -- 2 -- 0.58 -- 3 -- 1.05 --
Onshore Gulf Coast............ 1 -- 0.13 -- 5 2 1.11 0.55 2 -- 0.89 --
--- -- ---- ---- --- -- ---- ---- --- -- ---- ----
Total......................... 3 -- 0.79 -- 7 2 1.69 0.55 5 -- 1.94 --
=== == ==== ==== === == ==== ==== === == ==== ====
6
We had an interest in 1 well (0.25 net) in progress at December 31, 2002, 2
wells (0.80 net) in progress at December 31, 2001, and 2 wells (0.65 net) in
progress at December 31, 2000.
OTHER PROPERTY AND OFFICE LEASE
We own several non-contiguous tracts of land covering approximately 2,500
surface acres in Southern Louisiana and Southern Mississippi. We lease
approximately 17,000 square feet of office space in Dallas, Texas. The lease on
this office space expires in April 2008.
ITEM 3. LEGAL PROCEEDINGS.
We are not a party to any material legal proceedings at this time.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Our common stock trades on the New York Stock Exchange under the symbol
REM. Prior to June 20, 2002, we traded on the Nasdaq National Market under the
symbol ROIL and on the Pacific Exchange under the symbol REM.P. The following
table sets forth the high and low closing price per share for the periods
indicated.
COMMON STOCK
---------------
HIGH LOW
------ ------
2003
First Quarter through March 27, 2003...................... 19.75 16.63
2002
Fourth Quarter............................................ 17.900 14.190
Third Quarter............................................. 19.450 13.460
Second Quarter............................................ 21.670 16.950
First Quarter............................................. 20.570 15.100
2001
Fourth Quarter............................................ 18.350 13.030
Third Quarter............................................. 17.060 11.440
Second Quarter............................................ 19.190 12.125
First Quarter............................................. 16.250 11.625
On March 27, 2003, the last reported sales price for our common stock was
$17.16 per share. On that date, there were 726 stockholders of record, including
92 stockholders of record of class A common stock and 107 stockholders of record
of class B common stock who had not yet surrendered their old stock for the new
common stock to which they are entitled.
In the early part of 2000, one of our subsidiaries, that at that time was
94%-owned by us, paid dividends in the amount of $17,000 to its minority
shareholders. In 2000 the subsidiary acquired and retired the stock of the two
minority holders. As a result, the subsidiary is now wholly-owned by us, and
there is no longer the issue of dividends being paid by a subsidiary to persons
outside the consolidated group. No dividends have ever been paid on our common
stock. Our credit facility agreement prohibits our paying dividends. The
determination of future cash dividends, if any, will depend upon, among other
things, our financial condition,
7
cash flow from operating activities, the level of our capital and exploration
expenditure needs, future business prospects, and renegotiation of our line of
credit.
The remaining information called for by this item relating to "Securities
Authorized for Issuance under Equity Compensation Plans" is reported in Item 12,
Security Ownership of Certain Beneficial Owners and Management, beginning on
page 57 of this report.
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.
2002(1) 2001(1) 2000(1) 1999 1998(1)
--------- ---------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PRICES, VOLUMES, AND PER SHARE DATA)
FINANCIAL
Total revenue.......................... $104,866 $ 116,620 $ 99,661 $ 44,348 $ 84,340
Net income (loss)...................... $ 11,332 $ 8,344 $ 45,044 $ (3,703) $ 13,617
Basic income (loss) per share.......... $ 0.45 $ 0.38 $ 2.10 $ (0.17) $ 0.67
Diluted income (loss) per share........ $ 0.42 $ 0.35 $ 1.99 $ (0.17) $ 0.66
Total assets........................... $288,993 $ 240,432 $192,474 $119,326 $130,229
8 1/4% convertible subordinated
notes................................ $ -- $ -- $ 5,880 $ 5,950 $ 38,371
Other bank debt........................ $ 37,400 $ 71,000 $ 27,428 $ 30,028 $ 3,500
Stockholders' equity................... $193,660 $ 125,338 $102,708 $ 56,054 $ 59,699
Total shares outstanding............... 26,236 22,651 21,564 21,285 21,247
Cash Flow
Net cash flow from operations........ $ 71,420 $ 99,025 $ 69,963 $ 19,180 $ 54,040
Net cash flow from investing......... $(92,126) $(119,242) $(57,511) $(25,911) $(38,149)
Net cash flow from financing......... $ 16,258 $ 21,463 $ 1,323 $ (7,931) $ (1,425)
OPERATIONAL
Proved reserves(2) Oil (MBbls)......... 13,114 13,865 10,370 7,177 5,519
Gas (MMcf)........................... 124,967 111,920 88,650 65,508 52,709
Standardized measure of discounted
future net cash flows - end of
year(2).............................. $351,042 $ 199,983 $458,649 $126,868 $ 63,467
Average sales price(3)
Oil (per Bbl)........................ $ 24.27 $ 23.29 $ 27.69 $ 15.50 $ 10.89
Gas (per Mcf)........................ $ 3.35 $ 4.02 $ 4.02 $ 2.45 $ 3.03
Average production (net sales volume)
Oil (Bbls per day)................... 4,736 3,378 3,234 3,075 3,165
Gas (Mcf per day).................... 47,804 58,265 34,951 26,732 16,544
---------------
(1) Financial results for 2002 include an $8.1 million charge for impairment of
long-lived properties. For 2001 financial results include a $13.5 million
charge for the final settlement of the Phillips Petroleum litigation and a
$10.6 million charge for impairment of long-lived properties. The results
for 2000 include $12.5 million gain on sale of certain South Texas
properties, and for 1998 include $49.8 million in other income from the
termination of our gas sales contract and an $18.0 million charge recorded
for the Phillips Petroleum judgment.
(2) The quantities of proved oil and gas reserves discussed in this table
include only the amounts which we reasonably expect to recover in the future
from known oil and gas reservoirs under the current economic
8
and operating conditions. Proved reserves include only quantities that we
can commercially recover using current prices, costs, and existing
regulatory practices and technology. We base the standardized measure of
discounted future net cash flows on year-end prices. Any changes in future
prices, costs, regulations, technology, or other unforeseen factors could
significantly increase or decrease the proved reserve estimates.
(3) We have not entered into any financial hedges for oil or gas prices during
any of the years presented, therefore the average sales prices represent
actual sales revenue per barrel or Mcf.
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 reserves and
production while keeping our finding and development costs and operating costs
competitive with our industry peers. We will implement this strategy through
drilling exploratory and development wells from our inventory of available
prospects that we have evaluated for geologic and mechanical risk and future
reserve or resource potential. Our drilling program will contain some high
risk/high reserve potential opportunities as well as some lower risk/lower
reserve potential opportunities, in order to achieve a balanced program of
reserve and production growth. Success of this strategy is contingent on various
risk factors, as discussed in our filings with the Securities and Exchange
Commission. Over the last three years, we have invested $297.7 million in oil
and gas properties, found 191.8 Bcfe of proved reserves and replaced 251% of our
production at an average finding and development cost of $1.55 per Mcfe. The
following table reflects our results during the last three years.
% INCREASE % INCREASE
2002 (DECREASE) 2001 (DECREASE) 2000
-------- ---------- -------- ---------- --------
Production:
Oil MBbls.............................. 1,729 40% 1,233 4% 1,181
Gas MMcf............................... 17,448 (18)% 21,267 67% 12,757
-------- --- -------- -- --------
Total MMcfe(1)........................... 27,822 (3)% 28,665 44% 19,843
======== === ======== == ========
Proved reserves:
Oil MBbls.............................. 13,114 (5)% 13,865 34% 10,370
Gas MMcf............................... 124,967 12% 111,920 26% 88,650
-------- --- -------- -- --------
Total MMcfe(1)........................... 203,651 4% 195,110 29% 150,870
======== === ======== == ========
Operating costs per Mcfe................. $ 0.58 4% $ 0.56 10% $ 0.51
Finding costs per Mcfe(2)................ $ 2.40 43% $ 1.68 73% $ 0.97
Percentage of production replaced(3)..... 150% 253% 380%
---------------
(1) Barrels of oil are converted to Mcf equivalents (Mcfe) at the ratio of 1
barrel of oil equals 6 Mcf of gas.
(2) Finding costs include acquisition, development and exploration costs
(including exploration costs such as seismic acquisition costs).
(3) Reserves sold (5.5 Bcfe in 2002 and 14.4 Bcfe in 2000) are excluded from
this calculation.
9
CRITICAL ACCOUNTING POLICIES
We prepare our consolidated financial statements for inclusion in this
report using accounting principles that are generally accepted in the United
States ("GAAP"). Our Notes to Consolidated Financial Statements included on
pages 26 through 41 in this report have a more comprehensive discussion of our
significant accounting policies. GAAP represents a comprehensive set of
accounting and disclosure rules and requirements. We must make judgments,
estimates, and in certain circumstances, choices between acceptable GAAP
alternatives as we apply these rules and requirements.
Successful Efforts Method of Accounting
Oil and gas exploration and production companies choose one of two
acceptable accounting methods, successful-efforts or full cost. The most
significant difference between the two methods relates to the accounting
treatment of drilling costs for unsuccessful exploration wells ("dry holes") and
exploration costs. Under the successful-efforts method, we recognize exploration
costs and dry hole costs as an expense on the income statement when incurred and
capitalize the costs of successful exploration wells as oil and gas properties.
Entities that follow the full cost method capitalize all drilling and
exploration costs including dry hole costs into one pool of total oil and gas
property costs.
We use the successful-efforts method because we believe that it more
conservatively reflects on our balance sheet historical costs that have future
value. However, using successful-efforts often causes our income statement to
fluctuate significantly between reporting periods based on our drilling success
or failure during the periods.
It is typical for companies that drill a significant number of exploration
wells, as we do, to incur dry hole costs. During the last three years we have
drilled 86 exploration wells, of which 18 were considered dry holes. Our dry
hole costs charged to expense during this period totaled $30.0 million out of
total exploratory drilling costs of $124.8 million. It is impossible to predict
future dry holes; however we estimate that between 20% and 30% of our
exploration wells and exploration drilling costs will be dry holes, based on
past experience.
Proved Reserve Estimates
Independent reserve engineers prepare our oil and gas reserve estimates
using guidelines put forth under GAAP and by the Securities and Exchange
Commission. The quality and quantity of data, the interpretation of the data,
and the accuracy of mandated economic assumptions combined with the judgment
exercised by the reserve engineers affect the accuracy of the estimated
reserves. In addition, drilling or production results after the date of the
estimate may cause material revisions to the reserve estimates. You should not
assume that the present value of the future net cash flow disclosed in this
report reflects the current market value of the oil and gas reserves. In
accordance with the Securities and Exchange Commission's guidelines, we use
prices and costs determined on the date of the estimate and a 10% discount rate
to determine the present value of future net cash flow. Actual prices and costs
may vary significantly, and the discount rate may or may not be appropriate
based on outside economic conditions.
In our 2002 year-end reserve report we used December 31, 2002, West Texas
Intermediate posted price of $28.00 per barrel and a Gulf Coast spot market
price of $4.74 per MMBtu adjusted by property for energy content, quality,
transportation fees, and regional price differentials. We estimated the costs
based on the prior year costs incurred for individual properties or similar
properties if a particular property did not have production during the prior
year. While we believe that future costs can be reasonably estimated, future
prices are difficult to estimate since the market prices are influenced by
events beyond our control. Current world political events have caused oil prices
to increase significantly since December 31, 2002. Future global economic and
political events will most likely result in significant fluctuations in future
oil prices. In addition, cold weather during the first quarter of 2003 in the
United States has resulted in significant fluctuations in natural gas prices.
10
Depletion, Depreciation, and Amortization of Oil and Gas Properties
We calculate depletion, depreciation, and amortization expense ("DD&A")
using the estimates of proved oil and gas reserves. We segregate the costs for
individual or contiguous properties or projects and record DD&A of these
property costs separately using the units of production method. Material
downward revisions in reserves increase the DD&A per unit and reduce our net
income; likewise, material upward revisions lower the DD&A per unit and increase
our net income.
Impairment of Oil and Gas Properties
Because we account for our proved oil and gas properties separately, we
assess our assets for impairment property by property rather than in one pool of
total oil and gas property costs. This method of assessment is another feature
of successful-efforts method of accounting. Certain unforeseeable events such as
significantly decreased long-term oil or gas prices, failure of a well or wells
to perform as projected, insufficient data on reservoir performance, and/or
unexpected or increased costs may cause us to record an impairment expense on a
particular property. We base our assessment of possible impairment using our
best estimate of future prices, costs and expected net cash flow generated by a
property. We estimate future prices based on NYMEX 12 month strips, adjusted for
basis differential and escalate both the prices and the costs for inflation if
appropriate. If these estimates indicate an impairment, we measure the
impairment expense as the difference between the net book value of the asset and
its estimated fair value measured by discounting the future net cash flow from
the property at an appropriate rate. Actual prices, costs, discount rates, and
net cash flow may vary from our estimates.
In 2002, we adopted Statement of Financial Accounting ("SFAS") Standards
No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets," which
superseded SFAS No. 121 "Accounting for Impairment of Long-Lived Assets." The
Statement addresses financial accounting and reporting for the impairment or
disposal of long-lived assets. The adoption of this statement did not have a
material effect on our balance sheet or income statement in 2002.
We recognized impairment expenses during the last three years as follows:
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------
2002 2001 2000
-------- --------- ------
(IN THOUSANDS)
Unproved properties................................... $1,640 $ 616 $811
Proved properties..................................... 6,441 10,000 48
------ ------- ----
Total impairment expense.............................. $8,081 $10,616 $859
====== ======= ====
Through December 31, 2001, we assessed the capitalized costs of unproved
properties periodically to estimate whether their value has been impaired below
the capitalized costs, recognizing a loss to the extent such impairment was
indicated. In making these estimations, we considered factors such as
exploratory drilling results, future drilling plans and lease expiration terms.
Effective January 1, 2002, we estimate the amount of individually insignificant
unproved properties which will prove unproductive by amortizing the balance of
our individually immaterial unproved property costs (adjusted by an anticipated
rate of future successful development) over an average lease term. The effect of
this change in estimate was not material to our results of operations.
Individually significant properties will continue to be evaluated periodically
on a separate basis for impairment. We will transfer the original cost of an
unproved property to proved properties when we find commercial oil and gas
reserves sufficient to justify full development of the property. The impairment
of unproved properties for the prior two years primarily resulted from the
actual (due to unsuccessful exploration results) or impending forfeiture of
leaseholds.
We impaired proved properties for 2002 and 2001 because of insufficient
future net cash flows based on the proved developed reserves as determined by
our independent reserve engineers. The properties impaired in 2002, included two
properties in the Gulf of Mexico which totaled $3.5 million and two in the
onshore Gulf Coast which totaled $2.9 million. During 2001, we impaired three
proved properties in the offshore Gulf of
11
Mexico that accounted for $8.7 million and one proved property in South Texas
that accounted for $1.3 million of the total $10.0 million. The impairment
expense on proved properties for 2000 resulted from insufficient oil and gas
reserves on a small property in Alabama. None of the impairments discussed above
were the result of prices causing lower proved reserves. The impairments
resulted primarily from wells depleting sooner than originally estimated or
capital costs in excess of those anticipated.
Under the above critical accounting policies our net income can vary
significantly from period to period because events or circumstances which
trigger recognition as an expense for unsuccessful wells or impaired properties
cannot be accurately forecast. In addition, selling prices for our oil and gas
fluctuate significantly. Therefore we focus more on cash flow from operations
and on controlling our finding and development, operating, administration, and
financing costs.
Accounting for Stock Based Compensation
In June 1999, the Board of Directors approved contingent stock grants to
our employees and directors. In order for the grants to become effective, the
price of our stock had to increase from $4.19 per share to a trigger price of
$10.42 per share and close at or above $10.42 per share for 20 consecutive
trading days. Further, the trigger price had to be achieved within 5 years of
the grant date. This increase from $4.19 per share to $10.42 per share
represented a compound annual rate of return of 20% for 5 years. On the grant
date we did not record any amounts for expense, liability, or equity because the
measurement date for determining the compensation cost depended on the
occurrence of an event after the date of grant. Therefore, we could not be sure
that we would incur any expense as a result of the grants, and we could not
reasonably estimate the amount of possible expense.
January 24, 2001, became the measurement date when the stock price closed
above the trigger price for the twentieth consecutive trading day. On that date,
we measured the total compensation cost at $8.1 million which was the total
number of shares granted multiplied by the market price on that date. We
recorded $8.1 million as restricted common stock, $5.7 million as unearned
compensation reported as a separate reduction in stockholders' equity on the
balance sheet, and $2.4 million as stock based compensation expense. The $2.4
million stock based compensation expense recorded in the first quarter of 2001
included a "catch up" amortization from the date of the grant to the measurement
date of the total compensation cost because the cost should be recognized over
the time period in which the stock grant vested to the employees or directors.
We recorded $3.5 million in 2001 and $1.4 million in 2002 as stock based
compensation expense related to the grants. At December 31, 2002, $3.2 million
of the unearned compensation remained unamortized and will be amortized as the
shares vest during the next three years. The vesting period could accelerate in
the event of a change in control of the company or the death or permanent
disability of an employee. A shorter vesting period would accelerate the
amortization period. Except as noted above, the shares will be issued only to
the extent the employees and directors remain with the company through the
vesting dates.
In accounting for stock options granted to employees and directors, we have
chosen to continue to apply the accounting method promulgated by Accounting
Principles Board Opinion ("APB") No. 25 rather than apply an alternative method
permitted by SFAS No. 123. Under APB No. 25, at the time of grant we do not
record compensation expense on our income statement for stock options granted to
employees or directors. If we applied an alternative method permitted by SFAS
No. 123, our net income would be lower than actually reported. We disclose in
our Notes to Consolidated Financial Statements the pro-forma effect on our
income statement if we were to record the estimated fair value of stock options
on the date granted and amortize the expense over the expected vesting of the
grant. We chose the APB No. 25 method because we believe that the true cost of
options is reflected under this method. If and when the market price of the
stock exceeds the option exercise price, the potential dilution is reflected in
diluted earnings per share. We believe this dilution is the only true cost of
the option. Further, we believe that also including a theoretical or estimated
dollar expense in the income statement amounts to double-counting in calculating
diluted income per share - subtracting an amount from the numerator and adding
an amount to the denominator to reflect the same non-cash item.
12
Defined Benefit Pension Plan
Total assets at fair market value (public market prices for equity and
fixed income mutual funds) for our two defined benefit pension plans were $4.5
million which exceeded the total accumulated benefit obligation as of December
31, 2002. We recorded $396,000 in pension expense and contributed $2.3 million
to the plans during 2002. We have consistently used an 8% estimate for our
long-term rate of return on plan assets and believe that this remains
appropriate based on our plans' historical rates of return and on long-term
historical rates of return for indices similar to our current plan asset
allocation of equities (75%) and fixed income securities (25%). If however, we
reduced the assumed rate of return by 50 basis points, our projected 2003
pension plan expense would increase by approximately $21,000 and our net income
would decrease by approximately $14,000.
The discount rate is another critical assumption in determining pension
liabilities and expenses. We are required to use a rate that approximates the
market rate for high quality, long-term fixed income investments. Accordingly,
we reduced our discount rate assumption from 7.25% in 2001 to 6.5% in 2002. A
lower discount rate increases the calculated present value of benefit
obligations and increases pension expense. If the discount rate decreases by 50
basis points, our projected 2003 pension expense would increase by approximately
$268,000, and our net income would decrease by approximately $174,000.
LIQUIDITY AND CAPITAL RESOURCES
The following table summarizes our contractual obligations and commercial
commitments as of December 31, 2002.
PAYMENTS DUE BY PERIOD
-----------------------------------------------------
LESS THAN AFTER 5
TOTAL 1 YEAR 1-3 YEARS 4-5 YEARS YEARS
------- --------- --------- --------- -------
(IN THOUSANDS)
Contractual obligations Bank debt............ $37,400 $ -- $37,400 $ -- $ --
Other long-term payables................... $ 3,218 $1,715 $ 1,503 $ -- $ --
Office lease............................... $ 2,468 $ 441 $ 920 $984 $123
------- ------ ------- ---- ----
Total........................................ $43,086 $2,156 $39,823 $984 $123
======= ====== ======= ==== ====
On December 31, 2002, our current assets exceeded our current liabilities
by $3.2 million. Our current ratio was 1.07 to 1.00.
Cash flow provided by operations for the year ended December 31, 2002,
decreased by $27.6 million, or 28%, compared to the prior year primarily due to
changes in working capital accounts. We expect our cash flow provided by
operations for 2003 to increase because of higher projected oil and gas prices,
increased production from new properties, and consistent operating, general and
administrative, and interest and financing costs per Mcf equivalent (Mcfe).
Our cash flow from operations fluctuates primarily because of changes in
working capital accounts and variation in oil and gas production and prices,
excluding the effects of significant unforeseen expenses or other income. Our
oil and gas production will vary based on actual well performance or may be
curtailed due to factors beyond our control. Hurricanes in the Gulf of Mexico
will shut down our production for the duration of the storm, or as in the case
of Hurricane Lili in 2002, damage production facilities so that we cannot
produce a particular property for an extended amount of time. In addition,
downstream activities on major pipelines in the Gulf of Mexico can also cause us
to shut-in production for various lengths of time. Oil and gas prices will also
vary significantly due to world political events, supply and demand of products,
or weather patterns in the geographical United States. We sell the vast majority
of our production at spot market prices. Accordingly, product price volatility
can significantly affect our cash flow. To mitigate effects of this volatility,
we sometimes lock in prices for some portion of our production (usually less
than 33%) through the use of forward sale agreements. See additional discussion
under Commodity Price Risk in Item 7A. Quantitative and Qualitative Disclosures
about Market Risk.
13
Significant changes in our working capital accounts from 2001 to 2002
include an increase in our accounts receivable (a decrease in our cash flow
provided by operations) due to higher oil and gas prices, increased production
and increased balances due from our joint interest participants due to an
increase in operating activities (drilling wells and facilities construction) at
year end. Cash flow provided by operations decreased due to an increase in
prepaid expenses and other current assets because of an increase in prepaid
drilling costs on non-operated properties and increased pension plan
contributions. In addition, due to the increase in operating activities our
accounts payable increased by $13.3 million.
We incurred capital and exploration expenditures totaling $100.5 million
during 2002. The capital expenditures included $4.2 million for leasehold
acquisition, $45.4 million for exploration costs, $50.9 million for development
costs including platform and facilities construction. During the year, we built
and installed, or will install in 2003, 6 offshore platforms and facilities. In
addition, in 2002 we drilled 23 exploration wells and 3 development wells.
We expect to continue to make significant capital expenditures over the
next several years as part of our long-term growth strategy. We have budgeted
$96.1 million for capital expenditures in 2003. Our 2003 capital and exploration
budget includes $51.3 million for 30 exploratory wells. We project that we will
spend $45.2 million on 21 wells in the Gulf of Mexico and $6.1 million on 9
onshore wells in South Texas and Mississippi. The budget also includes $25.8
million for platforms and development drilling on operated discoveries at South
Marsh Island block 24, West Cameron blocks 416, 417 and 426, East Cameron block
185, and Eugene Island blocks 299, 302 and 397. The remaining $19.0 million will
be allocated to leasehold acquisitions, seismic acquisitions, and workovers. We
expect that our cash, estimated future cash flow from operations, and available
bank line of credit will be adequate to fund these expenditures for the
remainder of 2003.
If our exploratory drilling results in significant new discoveries, we will
have to acquire additional capital in order to finance the completion,
development, and potential additional opportunities generated by our success. We
believe that, because of the additional reserves resulting from the exploratory
success and our record of reserve growth in recent years, we will be able to
acquire sufficient additional capital through additional bank financing and/or
offerings of debt or equity securities.
In March 2002 we issued 3.0 million shares of common stock at $18.50 per
share. Net proceeds from the offering totaled approximately $52.8 million. We
used $44.0 million of the net proceeds to reduce outstanding bank debt from
$71.0 million to $27.0 million, and we used the remainder for working capital.
As of December 31, 2002, our amended credit facility has a borrowing base
of $75.0 million. As of March 21, 2003, we had $37.4 million borrowed under the
facility. The banks review the borrowing base semi-annually and may increase or
decrease the borrowing base at their discretion relative to the new estimate of
proved oil and gas reserves. The banks will reevaluate the borrowing base in
April 2003. Our oil and gas properties are pledged as collateral for the line of
credit. Additionally, we have agreed not to pay dividends. Unless renewed or
extended, the line of credit expires on May 3, 2004, when all principal becomes
due.
The most significant financial covenants in the line of credit include
maintaining a minimum current ratio (as defined in the agreement) of 1.0 to 1.0,
a minimum tangible net worth of $85.0 million plus 50% of net income
(accumulated from the inception of the agreement) and 100% of any non-redeemable
preferred or common stock offerings, and interest coverage of 3.0 to 1.0. We are
currently in compliance with these financial covenants in all material respects.
If we don't comply with these covenants, the lenders have the right to refuse to
advance additional funds under the facility and/or declare all principal and
interest immediately due and payable.
RESULTS OF OPERATIONS
In 2002, we recorded net income totaling $11.3 million or $0.45 basic
income per share, and $0.42 diluted income per share, compared to a net income
of $8.4 million or $0.38 basic income per share and $0.35 diluted income per
share in 2001. The increase in net income resulted primarily from lower total
costs and expenses,
14
primarily the $13.5 million settlement expense for Phillips Petroleum recorded
in 2001. In addition, total revenues decreased by 10% primarily because of lower
gas prices.
The following table discloses the net oil and gas production volumes,
sales, and sales prices for each of the three years ended December 31, 2002,
2001, and 2000. The table is an integral part of the following discussion of
results of operations for the periods 2002 compared to 2001 and 2001 compared to
2000.
% INCREASE % INCREASE
2002 (DECREASE) 2001 (DECREASE) 2000
--------- ---------- ------- ---------- -------
Oil production volume (MBbls)............... 1,729 40% 1,233 4% 1,181
Oil sales revenue........................... $ 41,969 46% $28,717 (12)% $32,684
Price per Bbl............................... $ 24.27 4% $ 23.29 (16)% $ 27.69
Increase (decrease) in oil sales revenue due
to:
Change in prices............................ $ 1,208 $(5,196)
Change in production volume................. 12,044 1,229
--------- -------
Total increase (decrease) in oil sales
revenue................................... $ 13,252 $(3,967)
========= =======
Gas production volume (MMcf)................ 17,448 (18)% 21,267 67% 12,757
Gas sales revenue........................... $ 58,412 (32)% $85,504 67% $51,274
Price per Mcf............................... $ 3.35 (17)% $ 4.02 0% $ 4.02
Increase (decrease) in gas sales revenue due
to:
Change in prices............................ $ (14,249) $ 0
Change in production volume................. $ (12,843) 34,230
--------- -------
Total increase (decrease) in gas sales
revenue................................... $ (27,092) $34,230
========= =======
2002 compared to 2001
Oil sales revenue increased by $13.3 million, or 46%, because oil
production increased by 496,000 barrels, or 40%, and average oil prices
increased by $0.98 or 4%. Oil production from offshore Gulf of Mexico increased
by 591,000 barrels, or 73%, because of production from new properties. Oil
production from onshore gulf coast properties decreased by 95,000 barrels, or
21%, because of natural depletion of the existing producing properties and the
sale of certain properties in South Texas in April 2002. Average prices
increased from $23.29 in 2001 to $24.27 in 2002, which increased oil revenues by
$1.2 million.
Gas sales revenue decreased by $27.1 million, or 32% because of lower
average gas prices and lower production. Average gas prices decreased from $4.02
per Mcf in 2001 to $3.35 per Mcf, or 17%, in 2002, causing gas sales revenues to
decrease by $14.2 million. Production decreased by 3.8 Bcf, or 18%, primarily
because of lower gas production from the offshore Gulf of Mexico. During the
fourth quarter of 2001 we lost production from a well on East Cameron block 364.
The production from this property during 2001 was 3.1 Bcf compared to 0.3 Bcf
during 2002. The decrease from this property was partially offset by increased
gas production from new offshore properties.
Other income increased primarily because of a $4.1 million gain on the sale
of certain immaterial South Texas properties in April 2002.
Total operating costs increased by $203,000 and operating costs per Mcfe
increased by $0.02 to $0.58 during 2003.
Impairment expense for 2002 included a $6.4 million charge for impaired
proved property costs and $1.6 million for amortization of unproved property
costs. During 2001, we recorded $10.0 million for impairment charges of proved
property costs and $616,000 for impairment of unproved property costs.
Exploration expenses increased by $2.5 million, or 19%, because of
increased dry hole costs during 2002 partially offset by a $2.7 million decrease
in seismic expenses in 2002 compared to 2001. Depreciation,
15
depletion and amortization expense increased by $265,000, or less than 1% for
the year ended December 31, 2002, compared to the prior year. During 2002,
depreciation, depletion and amortization increased to $1.38 per Mcfe from $1.33
per Mcfe in 2001.
General and administrative expenses decreased by $410,000, or 7%, due
primarily to lower legal fees. Stock based compensation expense decreased by
$2.1 million or 56% because in 2001 we included a "catch up" provision related
to the contingent stock grants. The catch up included the period June 1999 (the
date of the grant) to January 2001 (the date of measurement). The grant became
effective in January 2001 when the requirements for the triggering of the stock
grants were achieved. During the second quarter of 2001, we settled the Phillips
litigation and charged $13.5 million to settlement expense. Interest and
financing expense decreased because of lower interest rates and lower
outstanding debt. Income taxes increased by $2.5 million as a result of
increased income before taxes.
2001 compared to 2000
Oil production increased by 4% 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 16% during 2001 which in turn caused oil sales
revenues to be $5.2 million lower.
Gas sales revenue increased by $34.2 million or 67% because of a 67%
increase in production compared to 2000. Production from the offshore Gulf of
Mexico increased by 8.7 Bcf, or 101%, 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. Average
prices were unchanged.
Interest income decreased by $467,000, or 32% because of lower rates earned
on our short-term investments and because we used the $9.0 million of restricted
cash previously set aside for the Phillips Petroleum judgment in the settlement
of that litigation in May 2001. Other income decreased because we had a
non-recurring $12.5 million gain from the sale of South Texas properties in
2000.
Operating costs and expenses increased by $5.9 million, or 58%, because of
new producing properties. Exploration expenses increased by $6.3 million, or
92%, 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 settlement agreements with the Minerals Management Service concerning
claims for underpaid 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.
16
During 2001, we recorded income tax expense totaling $3.6 million, all of
which is deferred. We fully utilized our net deferred income tax benefit during
2000 and the first quarter of 2001.
NEW ACCOUNTING PRONOUNCEMENTS
SFAS No. 143 "Accounting for Asset Retirement Obligations" will be
effective for years beginning after June 15, 2002. The statement requires that
we estimate the fair value for our asset retirement obligations (dismantlement
and abandonment of oil and gas wells and offshore platforms) in the periods the
assets are first placed in service. Currently we accrue the estimated liability
for dismantlement and abandonment over the life of the property using a unit of
production method. Because of this new standard, effective January 1, 2003, we
must increase both our recorded assets and liabilities by the estimated cost of
the ultimate asset retirement obligation. We will then increase the estimated
obligation amount by contingency and inflation factors, and then discount the
total amount to present value. Further, on a periodic basis we will record the
accretion of the discount. For properties owned at December 31, 2002, we
estimate the undiscounted asset retirement obligation to be approximately $15.0
million. We will also amortize the cost into depletion, depreciation, and
amortization expense. The charges to the income statement will not be materially
different under this standard as compared to our present method.
In December 2002, the Financial Accounting Standards Board issued SFAS No.
148, "Accounting for Stock-Based Compensation -- Transition and Disclosure."
SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation," to
provide alternative methods of transition to SFAS No. 123's fair value method of
accounting for stock-based employee compensation. SFAS No. 148 also amends the
disclosure provisions of SFAS No. 123 and APB No. 28, "Interim Financial
Reporting," to require disclosure in the summary of significant accounting
policies of the effects of an entity's accounting policy with respect to stock-
based employee compensation on reported net income and earnings per share in
annual and interim financial statements. While SFAS No. 148 does not amend SFAS
No. 123 to require companies to account for employee stock options using the
fair value method, the disclosure provisions of SFAS No. 148 are applicable to
all companies with stock-based employee compensation, regardless of whether they
account for that compensation using the fair value method of SFAS No. 123 or the
intrinsic value method of APB No. 25. We disclose in our Notes to Consolidated
Financial Statements the pro-forma effect on our income statement if we were to
record the estimated fair value of stock options on the date granted and
amortize the expense over the expected vesting of the grant.
SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and
Intangible Assets" became effective for us on July 1, 2001 and January 1, 2002,
respectively. SFAS No. 141 requires all business combinations initiated after
June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS
No. 141 requires companies to disaggregate and report separately from goodwill
certain intangible assets. SFAS No. 142 establishes new guidelines for
accounting for goodwill and other intangible assets. Under SFAS No. 142,
goodwill and certain other intangible assets are not amortized, but rather are
reviewed annually for impairment. The appropriate application of SFAS Nos. 141
and 142 to oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves is unclear.
Depending on how the accounting and disclosure literature is clarified, these
oil and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves for both undeveloped and
developed leaseholds may be classified separately from oil and gas properties,
as intangible assets on our balance sheets. Additional disclosures required by
SFAS Nos. 141 and 142 would be included in the notes to financial statements.
Historically, we, like many other oil and gas companies, have included these oil
and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves as part of the oil and gas
properties, even after SFAS Nos. 141 and 142 and became effective.
This interpretation of SFAS Nos. 141 and 142 would affect only our balance
sheet classification of oil and gas leaseholds. Our results of operations and
cash flows would not be affected, since these oil and gas mineral rights held
under lease and other contractual arrangements representing the right to extract
such reserves would continue to be amortized in accordance with accounting rules
for oil and gas companies provided in SFAS No. 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies."
17
At December 31, 2002, we had net leaseholds cost of approximately $35.8
million. If we applied the interpretation currently being deliberated, this
classification would require us to make the disclosures set forth under SFAS No.
142 related to these interests. We will continue to classify our oil and gas
leaseholds as oil and gas properties until further guidance is provided.
In June 2002, the Financial Accounting Standards Board issued SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities." SFAS No. 146
addresses accounting and financial reporting for costs associated with certain
exit or disposal activities. We do not anticipate initiating any activities that
are subject to this standard.
Financial Accounting Standards Board Interpretation No. 45 elaborates on
the disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued. We
have no guarantees affected by this interpretation.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
INTEREST RATE RISK
Our revolving bank line of credit is sensitive to changes in interest
rates. At December 31, 2002, the unpaid principal balance under the line was
$37.4 million which approximates its fair value. The interest rate on this debt
is based on a premium of 150 to 225 basis points over the London Interbank
Offered Rate ("Libor"). The rate is reset periodically, usually every three
months. If on December 31, 2002, Libor changed by one full percentage point (100
basis points) the fair value of our revolving debt would change by approximately
$93,000. We have not entered into any interest rate hedging contracts.
COMMODITY PRICE RISK
A vast majority of our production is sold on the spot markets. Accordingly,
we are at risk for the volatility in the commodity prices inherent in the oil
and gas industry.
Occasionally we sell forward portions of our production under physical
delivery contracts that by their terms cannot be settled in cash or other
financial instruments. Such contracts are not subject to the provisions of
Statement of Financial Accounting Standards No. 133 "Accounting for Derivative
Instruments and Hedging Activities." Accordingly we do not provide sensitivity
analysis for such contracts. For the period January 1, 2003, through March 31,
2003, we did not have any forward sales contracts in place. For the period April
1, 2003, through December 31, 2003, we have physical delivery contracts in place
to sell 21,500 MMBtu of gas per day and 1,200 barrels of oil per day at the
following prices:
PRICE PER
--------------
PERIOD BARREL MMBTU
------ ------ -----
April 1, 2003 through June 30, 2003........................ $30.92 $5.16
July 1, 2003 through September 30, 2003.................... $28.70 $4.89
October 1, 2003 through December 31, 2003.................. $27.41 $4.95
18
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO FINANCIAL STATEMENTS
Report of Independent Public Accountants.................... 20
Report of Independent Public Accountants (Prior Years)...... 21
Consolidated Balance Sheets as of December 31, 2002 and
2001...................................................... 22
Consolidated Statements of Income for 2002, 2001, and
2000...................................................... 23
Consolidated Statements of Stockholders' Equity for 2002,
2001, and 2000............................................ 24
Consolidated Statements of Cash Flows for 2002, 2001, and
2000...................................................... 25
Notes to Consolidated Financial Statements.................. 26
19
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Stockholders and Board of Directors of
Remington Oil and Gas Corporation
We have audited the accompanying consolidated balance sheet of Remington
Oil and Gas Corporation ("the Company"), a Delaware corporation, as of December
31, 2002, and the related consolidated statements of income, stockholders'
equity and cash flows for the year ended December 31, 2002. These consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits. The financial statements of Remington Oil and Gas Corporation as of
December 31, 2001, and for the two years in the period ended December 31, 2001
were audited by other auditors who have ceased operations. Those auditors
expressed an unqualified opinion on those financial statements in their report
dated March 15, 2002.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Remington
Oil and Gas Corporation as of December 31, 2002, and the results of their
operations and their cash flows for the year ended December 31, 2002, in
conformity with accounting principles generally accepted in the United States.
As discussed above, the consolidated financial statements of Remington Oil
and Gas Corporation as of December 31, 2001, and for the two years in the period
ended December 31, 2001, were audited by other auditors who have ceased
operations. As described in Note 1, these consolidated financial statements have
been revised to include the transitional disclosures required by Statement of
Financial Accounting Standards (Statement) No. 148, Accounting for Stock Based
Compensation -- Transition and Disclosure, which was adopted by the Company as
of December 31, 2002. Our audit procedures with respect to the disclosures in
Note 1 for 2001 and 2000 included (a) agreeing the as reported and proforma net
income, as reported and proforma basic earnings per share, and as reported and
proforma diluted earnings per share to the previously issued financial
statements, (b) agreeing the stock based employee compensation expense
(including any related tax effects) determined under a fair value method for all
awards to the Company's underlying records obtained from management, and (c)
testing the mathematical accuracy of the reconciliation of proforma net income
to reported net income. In our opinion, the disclosures for 2001 and 2000 in
Note 1 are appropriate. However, we were not engaged to audit, review, or apply
any procedures to the 2001 and 2000 consolidated financial statements of the
Company other than with respect to such disclosures and, accordingly, we do not
express an opinion or any other form of assurance on the 2001 and 2000 financial
statements taken as a whole.
/s/ ERNST & YOUNG LLP
Dallas, Texas
March 24, 2003
20
THIS REPORT HAS NOT BEEN REISSUED BY ARTHUR ANDERSEN LLP.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Stockholders and Board of Directors of Remington Oil and Gas
Corporation
We have audited the accompanying balance sheets of Remington Oil and Gas
Corporation ("the Company"), a Delaware corporation, as of December 31, 2001 and
2000, and the related consolidated statements of income, stockholders' equity
and cash flows for the three years in the period ended December 31, 2001. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Remington Oil and Gas
Corporation as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas
March 15, 2002
The above is a copy of the Report of Independent Public Accountants issued
by Arthur Andersen LLP in connection with Remington Oil and Gas Corporation's
filing of an annual report on Form 10-K for the year ended December 31, 2001.
Arthur Andersen LLP has not reissued its Report in connection with the filing of
the Company's annual report on Form 10-K for the year ended December 31, 2002,
nor has Arthur Andersen LLP consented to the inclusion of their Report in this
annual report on Form 10-K. Arthur Andersen LLP has ceased practicing before the
Securities and Exchange Commission. See Exhibit 23.2 for further discussion. The
consolidated balance sheet as of December 31, 2000, and the consolidated
statements of income, stockholders' equity, and cash flows for the year ended
December 31, 1999, have not been included in the accompanying financial
statements.
21
REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED BALANCE SHEETS
AT DECEMBER 31,
---------------------
2002 2001
--------- ---------
(IN THOUSANDS,
EXCEPT SHARE DATA)
ASSETS
CURRENT ASSETS
Cash and cash equivalents................................. $ 14,929 $ 19,377
Accounts receivable....................................... 32,555 19,445
Prepaid drilling costs.................................... 3,115 400
Prepaid expenses and other current assets................. 1,863 1,087
--------- ---------
TOTAL CURRENT ASSETS........................................ 52,462 40,309
--------- ---------
PROPERTIES
Oil and gas properties (successful-efforts method)........ 510,921 433,988
Other properties.......................................... 3,182 3,023
Accumulated depreciation, depletion and amortization...... (279,722) (237,661)
--------- ---------
TOTAL PROPERTIES............................................ 234,381 199,350
--------- ---------
OTHER ASSETS
Other assets.............................................. 2,150 773
--------- ---------
TOTAL OTHER ASSETS.......................................... 2,150 773
--------- ---------
TOTAL ASSETS................................................ $ 288,993 $ 240,432
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable and accrued expenses..................... $ 47,523 $ 34,232
Short-term notes payable and current portion of other
long-term payables...................................... 1,715 3,253
--------- ---------
TOTAL CURRENT LIABILITIES................................... 49,238 37,485
--------- ---------
LONG-TERM LIABILITIES
Notes payable............................................. 37,400 71,000
Other long-term payables.................................. 1,503 3,758
Deferred income taxes..................................... 7,192 2,851
--------- ---------
TOTAL LONG-TERM LIABILITIES................................. 46,095 77,609
--------- ---------
TOTAL LIABILITIES........................................... 95,333 115,094
--------- ---------
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, 26,327,195 shares issued and 26,236,459
shares outstanding in 2002, 22,685,240 shares issued and
22,650,881 shares outstanding in 2001................... 263 227
Additional paid-in capital................................ 115,827 56,698
Restricted common stock................................... 5,468 8,055
Unearned compensation..................................... (3,192) (4,581)
Treasury stock (56,377 shares common stock in 2002, at
cost)................................................... (977) --
Retained earnings......................................... 76,271 64,939
--------- ---------
TOTAL STOCKHOLDERS' EQUITY.................................. 193,660 125,338
--------- ---------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $ 288,993 $ 240,432
========= =========
See accompanying Notes to Consolidated Financial Statements.
22
REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31,
------------------------------
2002 2001 2000
-------- -------- --------
(IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
REVENUES
Oil sales................................................. $ 41,969 $ 28,717 $ 32,684
Gas sales................................................. 58,412 85,504 51,274
Interest income........................................... 198 975 1,442
Gain on sale of assets and other income................... 4,287 1,424 14,261
-------- -------- --------
Total revenues.............................................. 104,866 116,620 99,661
-------- -------- --------
COSTS AND EXPENSES
Operating costs and expenses.............................. 16,150 15,947 10,092
Exploration expenses...................................... 15,623 13,100 6,833
Depreciation, depletion, and amortization................. 38,528 38,263 20,976
Impairment of oil and gas properties...................... 8,081 10,616 859
General and administrative................................ 6,912 9,409 5,785
Settlements expense....................................... -- 13,524 5,416
Interest and financing expense............................ 2,145 3,829 4,561
-------- -------- --------
TOTAL COSTS AND EXPENSES.................................... 87,439 104,688 54,522
-------- -------- --------
INCOME BEFORE TAXES......................................... 17,427 11,932 45,139
Income taxes.............................................. 6,095 3,588 100
Minority interest......................................... -- -- (5)
-------- -------- --------
NET INCOME.................................................. $ 11,332 $ 8,344 $ 45,044
======== ======== ========
BASIC INCOME PER SHARE...................................... $ 0.45 $ 0.38 $ 2.10
======== ======== ========
DILUTED INCOME PER SHARE.................................... $ 0.42 $ 0.35 $ 1.99
======== ======== ========
See accompanying Notes to Consolidated Financial Statements.
23
REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
COMMON
STOCK ADDITIONAL RESTRICTED
$0.01 PAR PAID IN COMMON UNEARNED TREASURY RETAINED
VALUE CAPITAL STOCK COMPENSATION STOCK EARNINGS
--------- ---------- ---------- ------------ -------- --------
(IN THOUSANDS)
Balance December 31, 1999...... $213 $ 44,273 $ -- $ -- $ -- $11,568
Net income..................... -- -- -- -- -- 45,044
Common stock issued............ 3 1,624 -- -- -- --
Dividends paid to minority
stockholders of a
consolidated subsidiary...... -- -- -- -- -- (17)
---- -------- ------- ------- ----- -------
Balance December 31, 2000...... 216 45,897 -- -- -- 56,595
---- -------- ------- ------- ----- -------
Net income..................... -- -- -- -- -- 8,344
Contingent stock grant......... -- -- 8,055 (8,055) -- --
Amortization of unearned
compensation................. -- -- -- 3,474 -- --
Common stock issued............ 22 30,640 -- -- -- --
Tax benefit from exercise of
stock options................ -- 794 -- -- -- --
Common stock repurchased and
retired...................... (11) (20,633) -- -- -- --
---- -------- ------- ------- ----- -------
Balance December 31, 2001...... 227 56,698 8,055 (4,581) -- 64,939
---- -------- ------- ------- ----- -------
Net income..................... -- -- -- -- -- 11,332
Amortization of unearned
compensation................. -- -- -- 1,389 -- --
Common stock issued............ 36 57,375 (2,587) -- -- --
Tax benefit from exercise of
stock options................ -- 1,754 -- -- -- --
Common stock repurchased....... -- -- -- -- (977) --
---- -------- ------- ------- ----- -------
Balance December 31, 2002...... $263 $115,827 $ 5,468 $(3,192) $(977) $76,271
==== ======== ======= ======= ===== =======
See accompanying Notes to Consolidated Financial Statements.
24
REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31,
-------------------------------
2002 2001 2000
-------- --------- --------
(IN THOUSANDS)
CASH FLOW PROVIDED BY OPERATIONS
NET INCOME.................................................. $ 11,332 $ 8,344 $ 45,044
Adjustments to reconcile net income
Depreciation, depletion, and amortization................. 38,528 38,263 20,976
Deferred income tax expense............................... 6,095 3,600 --
Amortization of deferred finance charges.................. 228 172 334
Deferred net profits expense.............................. -- 1,270 --
Impairment of oil and gas properties...................... 8,081 10,616 859
Dry hole costs............................................ 14,828 9,589 5,557
Cash paid for dismantlement and restoration liability..... (247) (622) --
Minority interest in net income of subsidiaries........... -- -- (5)
Stock based compensation.................................. 1,609 3,696 174
Royalty settlement........................................ -- -- 5,416
Gain on sale of properties................................ (4,095) (201) (12,640)
CHANGES IN WORKING CAPITAL
Decrease (increase) in accounts receivable................ (13,099) 1,580 (14,745)
Decrease (increase) in prepaid expenses and other current
assets.................................................. (5,131) 526 344
Increase in accounts payable and accrued expenses......... 13,291 10,600 19,199
Decrease (increase) in restricted cash.................... -- 11,592 (550)
-------- --------- --------
NET CASH FLOW PROVIDED BY OPERATIONS........................ 71,420 99,025 69,963
-------- --------- --------
CASH FROM INVESTING ACTIVITIES
Payments for capital expenditures......................... (99,865) (119,673) (72,678)
Proceeds from property sales.............................. 7,739 431 15,167
-------- --------- --------
NET CASH (USED IN) INVESTING ACTIVITIES..................... (92,126) (119,242) (57,511)
-------- --------- --------
CASH FROM FINANCING ACTIVITIES
Proceeds from notes payable and long-term accounts
payable................................................. 17,000 51,500 10,630
Payments on notes payable and long-term accounts
payable................................................. (54,393) (12,464) (9,811)
Purchase common stock..................................... (977) (20,644) --
Commitment fee on line of credit.......................... -- (307) --
Common stock issued....................................... 54,628 3,378 521
Dividends paid to minority stockholders of a consolidated
subsidiary.............................................. -- -- (17)
-------- --------- --------
NET CASH PROVIDED BY FINANCING ACTIVITIES................... 16,258 21,463 1,323
-------- --------- --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ (4,448) 1,246 13,775
Cash and cash equivalents at beginning of period.......... 19,377 18,131 4,356
-------- --------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD.................. $ 14,929 $ 19,377 $ 18,131
======== ========= ========
Cash paid for interest...................................... $ 2,552 $ 2,925 $ 4,338
======== ========= ========
Cash paid (received) for taxes.............................. $ -- $ (12) $ 100
======== ========= ========
Non-cash issuance of common stock (Note 6).................. $ -- $ 21,250 $ --
======== ========= ========
See accompanying Notes to Consolidated Financial Statements.
25
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
Remington Oil and Gas Corporation, formerly Box Energy Corporation, is an
independent oil and gas exploration and production company incorporated in
Delaware. We have working interest ownership rights in properties in the
offshore Gulf of Mexico and onshore Gulf Coast. We acquired the following
subsidiaries in 1998: CKB Petroleum, Inc., CKB & Associates, Inc., Box Brothers
Realty Investments Company, CB Farms, Inc., and Box Resources, Inc. We
consolidate 100% of the assets, liabilities, equity, income and expense of the
subsidiaries and eliminate all inter-company transactions and account balances
for the periods of consolidation. We own 100% of the outstanding capital stock
of all of the subsidiaries. The primary operating subsidiary, CKB Petroleum,
Inc., owns an undivided interest in a pipeline that transports our oil from our
South Pass blocks, offshore Gulf of Mexico, to Venice Louisiana. We account for
our undivided interests in properties using the proportionate consolidation
method, whereby our share of assets, liabilities, revenues and expenses are
included in our financial statements.
USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS
Management prepares the financial statements in conformity with accounting
principles generally accepted in the United States. This requires estimates and
assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reported periods. Some of the more significant estimates
include oil and gas reserves, useful lives of assets, impairment of oil and gas
properties, and future dismantlement and restoration liabilities. Actual results
could differ from those estimates. We make certain reclassifications to prior
year financial statements in order to conform to the current year presentation.
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH
Cash equivalents consist of highly liquid investments that mature within
three months or less when purchased. Our cash equivalents include investment
grade commercial paper and institutional money market funds. We record cash
equivalents at cost, which approximates their market value at the balance sheet
date.
CONCENTRATION OF CREDIT RISK
Our financial instruments that are potentially subject to a concentration
of credit risk are principally cash and trade receivables. We have cash deposits
at two institutions that exceed the $100,000 federally insured limit by $14.8
million and $19.3 million at December 31, 2002 and 2001, respectively. At
December 31, 2002, 3 companies accounted for approximately 58% of the total
accounts receivable, and at December 31, 2001, 4 companies accounted for
approximately 81% of the total accounts receivable. In 2002, gas sales by a gas
marketing company accounted for approximately 54% of our total oil and gas
revenue. In addition, oil sales to one company accounted for approximately 23%
of our total oil and gas revenues in 2002 and oil sales to a second company
accounted for approximately 11% of our total oil and gas revenues in 2002. The
revenue from the sale of oil and gas by the gas marketing company accounted for
approximately 65% of our total oil and gas revenues in 2001. In addition, we
sold approximately 56% of our total oil production to one company during the
year, which accounted for approximately 14% of our total oil and gas revenues in
2001. We do not believe that the loss of services or sales from any of these
companies would have a material adverse effect on us due to the fungible nature
of the oil and gas production for which there is high and growing demand and
numerous customers that can easily be replaced.
26
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 2002, the
total estimated liability of our future dismantlement and restoration costs is
approximately $15.0 million. The accrued liability at December 31, 2002 and
2001, was $5.7 million and $4.3 million, respectively. We record expenditures
for geological, geophysical or other prospecting costs as exploration expenses
on the income statement when incurred.
Periodically, if there is a large decrease in oil and gas reserves or
production on a property, or if a dry hole is drilled on or near one of our
properties we will review the properties for impairment. In addition,
significant decreases in long-term oil and gas prices may also indicate that a
property has become impaired. If the net book value of a property is greater
than the estimated undiscounted future net cash flow from the same property, the
property is considered impaired. We base our assessment of possible impairment
using our best estimate of future prices, costs and expected net cash flow
generated by a property. The impairment expense is equal to the difference
between the net book value and the fair value of the asset. We estimate fair
value by discounting, at an appropriate rate, the future net cash flows from the
property. In addition, we assess the capitalized costs of unproved properties
periodically to determine whether their value has been impaired below the
capitalized costs. We recognize a loss to the extent that such impairment is
indicated. In making these assessments, we consider factors such as exploratory
drilling results, future drilling plans, and lease expiration terms.
Other properties include improvements on the leased office space and office
computers and equipment. The company depreciates these assets using the
straight-line method over their estimated useful lives that range from 3 to 12
years.
OTHER ASSETS
Other assets include the long-term portion of prepaid pension expenses (see
Note 7. Employee and Director Benefit Plans -- Pension Plan), and net
unamortized credit facility origination fees. The origination fees are amortized
on a straight-line basis over the term of the debt. We charge the amortized
amount to interest and financing costs. In addition, other assets also include a
long-term account receivable totaling $366,000, which is CKB Petroleum's claim
under Collateral Assignment Split Dollar Insurance Agreements among CKB
Petroleum and Don D. Box (an officer and director) and two of his brothers.
The amount due CKB Petroleum from Don D. Box under the Collateral
Assignment Split Dollar Insurance Agreement was $140,000 on December 31, 2002,
and $135,000 on December 31, 2001.
27
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses were as follows:
AT DECEMBER 31,
-----------------
2002 2001
------- -------
(IN THOUSANDS)
Accounts payable - trade.................................... $32,908 $25,907
Advance billings............................................ 8,353 5,374
Royalties and other revenue payable......................... 5,850 2,428
Other current payables...................................... 412 523
------- -------
Total accounts payable and accrued expenses................. $47,523 $34,232
======= =======
OIL AND GAS REVENUES
When oil and gas is produced, we sell it immediately. Consequently, we
recognize oil and gas revenue in the month of actual production based on our
share of the revenues. Our actual sales have not been materially different from
our entitled share of production, and we do not have any significant gas
imbalances.
TRANSPORTATION COSTS
We include transportation costs in operating costs and expenses. During the
years ended December 31, 2002, 2001, and 2000, we incurred transportation costs
totaling $2.1 million, $1.6 million and $313,000, respectively.
STOCK OPTIONS
In December 2002, the Financial Accounting Standards Board issued SFAS No.
148, "Accounting for Stock-Based Compensation -- Transition and Disclosure."
SFAS No. 148 amends SFAS No. 123, "Accounting for Stock-Based Compensation," to
provide alternative methods of transition to SFAS No. 123's fair value method of
accounting for stock-based employee compensation.
SFAS No. 148 also amends the disclosure provisions of SFAS No. 123 and APB
No. 28, "Interim Financial Reporting," to require disclosure in the summary of
significant accounting policies of the effects of an entity's accounting policy
with respect to stock-based employee compensation on reported net income and
earnings per share in annual and interim financial statements. While SFAS No.
148 does not amend SFAS No. 123 to require companies to account for employee
stock options using the fair value method, the disclosure provisions of SFAS No.
148 are applicable to all companies with stock-based employee compensation,
regardless of whether they account for that compensation using the fair value
method of SFAS No. 123 or the intrinsic value method of APB No. 25.
We continue to apply the accounting provisions of Accounting Principles
Board Opinion 25, entitled "Accounting for Stock Issued to Employees," and
related interpretations to account for stock-based compensation and have adopted
the disclosure requirements of SFAS 123 and SFAS 148 as of December 31, 2002.
Accordingly, we measure compensation cost for stock options as the excess, if
any, of the quoted market price of our stock at the date of the grant over the
amount an employee must pay to acquire the stock. All of our options are granted
with exercise prices at or above the quoted market price on the date of grant.
28
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes relevant information as to the reported
results under our intrinsic value method of accounting for stock awards, with
supplemental information as if the fair value recognition provision of SFAS No.
123 had been applied:
FOR YEARS ENDED DECEMBER 31,
-----------------------------
2002 2001 2000
-------- ------- --------
(IN THOUSANDS)
As reported:
Net income............................................. $11,332 $8,344 $45,044
Basic income per share................................. $ 0.45 $ 0.38 $ 2.10
Diluted income per share............................... $ 0.42 $ 0.35 $ 1.99
Stock based compensation (net of tax) included in net
income as reported..................................... $ 1,046 $2,402 $ 113
Stock based compensation (net of tax) if using the fair
value method as applied to all awards.................. $ 2,531 $4,248 $ 1,271
Proforma (if using the fair value method applied to all
awards):
Net income............................................. $ 9,847 $6,498 $43,886
Basic income per share................................. $ 0.39 $ 0.30 $ 2.05
Diluted income per share............................... $ 0.36 $ 0.27 $ 1.94
Weighted average shares used in computation
Basic.................................................. 25,294 21,979 21,435
Diluted................................................ 27,122 24,414 22,759
The fair value of each option grant for the years ended December 31, 2002,
2001, and 2000 is estimated on the date of grant using the Black-Scholes
option-pricing model with the following weighted average assumptions:
FOR YEARS ENDED
DECEMBER 31,
---------------------
2002 2001 2000
----- ----- -----
Expected life (years)....................................... 10 10 10
Interest rate............................................... 4.17% 5.13% 6.18%
Volatility.................................................. 61.62% 62.56% 59.01%
Dividend yield.............................................. 0% 0% 0%
As required, the pro-forma disclosures above include options granted since
January 1, 1995. Consequently, the effects of applying SFAS No. 123 for
providing pro-forma disclosures may not be representative of the effects on
reported net income for future years until all options outstanding are included
in the pro-forma disclosures. For purposes of pro-forma disclosures, the
estimated fair value of stock-based compensation plans and other options are
amortized to expense primarily over the vesting period.
SEGMENT REPORTING
We operate in only one business segment.
ADOPTED AND NEW ACCOUNTING POLICIES
In 2002, we adopted Statement of Financial Accounting Standards No. 144
"Accounting for the Impairment or Disposal of Long-Lived Assets," which
superceded Statement of Financial Accounting Standards No. 121 "Accounting for
Impairment of Long-Lived Assets." The Statement addressed financial accounting
and reporting for the impairment or disposal of long-lived assets. The adoption
of this statement did not have a material effect on our balance sheet or income
statement in 2002.
29
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. We will then increase the estimated obligation amount by contingency
and inflation factors and then discount the total amount to present value.
Further, on a periodic basis we will record the accretion of the discount. For
properties owned at December 31, 2002, we estimate that amount to be
approximately $15.0 million. We will also amortize the cost into depletion,
depreciation, and amortization expense. The charges to the income statement will
not be materially different under this standard as compared to our present
method.
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
expected to be 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
30
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,
--------------------------
2002 2001 2000
------- ------ -------
(IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
Net income available for basic income per share............. $11,332 $8,344 $45,044
Interest expense on Convertible Notes (net of tax)........ -- 188 318
------- ------ -------
Net income available for diluted income per share........... $11,332 $8,532 $45,362
======= ====== =======
Basic income per share...................................... $ 0.45 $ 0.38 $ 2.10
======= ====== =======
Diluted income per share.................................... $ 0.42 $ 0.35 $ 1.99
======= ====== =======
Weighted average common shares for basic income per share... 25,294 21,979 21,435
Dilutive stock options outstanding (treasury stock
method)................................................ 1,378 1,453 784
Common stock grant........................................ 450 663 --
Shares assumed issued by conversion of the Notes.......... -- 319 540
------- ------ -------
Total common shares for diluted income per share............ 27,122 24,414 22,759
======= ====== =======
Potential issues of common stock for diluted income per
share Weighted average shares from warrant issued in
merger.................................................... -- -- 200
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,
-------------------------------------------------------------------
2002 2001
-------------------------------- --------------------------------
PROVED UNPROVED TOTAL PROVED UNPROVED TOTAL
--------- -------- --------- --------- -------- ---------
(IN THOUSANDS)
Onshore................... $ 58,227 $ 3,511 $ 61,738 $ 55,190 $ 3,189 $ 58,379
Offshore.................. 432,103 17,080 449,183 357,137 18,472 375,609
--------- ------- --------- --------- ------- ---------
Total..................... 490,330 20,591 510,921 412,327 21,661 433,988
Accumulated depreciation,
depletion and
amortization............ (277,330) -- (277,330) (235,428) -- (235,428)
--------- ------- --------- --------- ------- ---------
Net oil and gas
properties.............. $ 213,000 $20,591 $ 233,591 $ 176,899 $21,661 $ 198,560
========= ======= ========= ========= ======= =========
SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and
Intangible Assets" became effective for us on July 1, 2001 and January 1, 2002,
respectively. SFAS No. 141 requires all business combinations initiated after
June 30, 2001 to be accounted for using the purchase method. Additionally, SFAS
No. 141 requires companies to disaggregate and report separately from goodwill
certain intangible assets. SFAS No. 142 establishes new guidelines for
accounting for goodwill and other intangible assets. Under SFAS No. 142,
goodwill and certain other intangible assets are not amortized, but rather are
reviewed annually for impairment. The appropriate application of SFAS Nos. 141
and 142 to oil and gas mineral rights held under lease and other contractual
arrangements representing the right to extract such reserves is unclear.
Depending on how the accounting and disclosure literature is clarified, these
oil and gas mineral rights held under lease and other contractual arrangements
representing the right to extract such reserves for both undeveloped and
developed leaseholds may be classified separately from oil and gas properties,
as intangible
31
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
assets on our balance sheets. Additional disclosures required by SFAS Nos. 141
and 142 would be included in the notes to financial statements. Historically,
we, like many other oil and gas companies, have included these oil and gas
mineral rights held under lease and other contractual arrangements representing
the right to extract such reserves as part of the oil and gas properties, even
after SFAS Nos. 141 and 142 and became effective.
This interpretation of SFAS Nos. 141 and 142 would affect only our balance
sheet classification of oil and gas leaseholds. Our results of operations and
cash flows would not be affected, since these oil and gas mineral rights held
under lease and other contractual arrangements representing the right to extract
such reserves would continue to be amortized in accordance with accounting rules
for oil and gas companies provided in SFAS No. 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies."
At December 31, 2002, we had net leaseholds cost of approximately $35.8
million. If we applied the interpretation currently being deliberated, this
classification would require us to make the disclosures set forth under SFAS No.
142 related to these interests. We will continue to classify our oil and gas
leaseholds as oil and gas properties until further guidance is provided.
The following table presents a summary of our oil and gas expenditures
during the last three years.
FOR YEARS ENDED DECEMBER 31,
-----------------------------
2002 2001 2000
-------- -------- -------
(UNAUDITED, IN THOUSANDS)
Unproved acquisition costs............................ $ 4,215 $ 9,885 $13,057
Proved acquisition costs.............................. -- 5,000 1,779
Exploration costs..................................... 45,381 46,825 38,224
Development costs..................................... 50,904 61,145 21,249
-------- -------- -------
Total................................................. $100,500 $122,855 $74,309
======== ======== =======
We recognized impairment expenses as follows in the table below:
FOR YEARS ENDED DECEMBER 31,
-----------------------------
2002 2001 2000
-------- -------- -------
(IN THOUSANDS)
Unproved properties................................... $ 1,640 $ 616 $ 811
Proved properties..................................... 6,441 10,000 48
-------- -------- -------
Total impairment expense.............................. $ 8,081 $ 10,616 $ 859
======== ======== =======
Through December 31, 2001, we assessed the capitalized costs of unproved
properties periodically to estimate whether their value has been impaired below
the capitalized costs, recognizing a loss to the extent such impairment was
indicated. In making these estimations, we considered factors such as
exploratory drilling results, future drilling plans and lease expiration terms.
Effective January 1, 2002, we estimate the amount of individually insignificant
unproved properties which will prove unproductive by amortizing the balance of
our individually immaterial unproved property costs (adjusted by an anticipated
rate of future successful development) over an average lease term. The effect of
this change in estimate was not material to our results of operations.
Individually significant properties will continue to be evaluated periodically
on a separate basis for impairment. We will transfer the original cost of an
unproved property to proved properties when we find commercial oil and gas
reserves sufficient to justify full development of the property. The impairment
of unproved properties for the prior two years primarily resulted from the
actual (due to unsuccessful exploration results) or impending forfeiture of
leaseholds.
We impaired proved properties for 2002 and 2001 because of insufficient
future net cash flows based on the proved developed reserves as determined by
our independent reserve engineers. In order to determine the amount of
impairment on properties, we estimate future prices based on NYMEX 12 month
strips adjusted
32
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
for basis differences and escalate both the prices and the costs for inflation
if appropriate. The properties impaired in 2002, included two properties in the
Gulf of Mexico which totaled $3.5 million and two on the onshore Gulf Coast
which totaled $2.9 million. During 2001, we impaired three proved properties in
the offshore Gulf of Mexico that accounted for $8.7 million and one proved
property in South Texas that accounted for $1.3 million of the total $10.0
million. The impairment expense on proved properties for 2000 resulted form
insufficient oil and gas reserves on one small property in Alabama.
NOTE 3 -- NOTES PAYABLE AND OTHER LONG-TERM PAYABLES
BANK CREDIT FACILITY
As of December 31, 2002, 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,
-----------------
2002 2001
------- -------
(IN THOUSANDS)
Borrowing base.............................................. $75,000 $75,000
Outstanding balance......................................... 37,400 71,000
------- -------
Available amount............................................ $37,600 $ 4,000
======= =======
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 (as defined in the agreement)
of 1.0 to 1.0, a minimum tangible net worth of $85.0 million plus 50% of net
income (accumulated from the inception of the agreement) and 100% of any
non-redeemable preferred or common stock offerings, and interest coverage of 3.0
to 1.0. We are currently in compliance with these financial covenants in all
material respects. If we don't comply with these covenants, the lenders have the
right to refuse to advance additional funds under the facility and/or declare
all principal and interest immediately due and payable.
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
2003.
OTHER
Other long-term payables include certain vender 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 $40.6 million at
December 31, 2002 and $78.0 million at December 31, 2001. We based the fair
value on current rates available for our bank debt. The book value of our other
long-term indebtedness approximates fair value.
33
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4 -- COMMITMENTS AND CONTINGENT LIABILITIES
We lease approximately 17,000 square feet of office space in Dallas, Texas.
The non-cancelable operating lease expires in April 2008. The following table
reflects our rent payments for the past three years and the commitment for the
future minimum rental payments.
YEAR RENT($)
---- -------
2000........................................................ 407,000
2001........................................................ 433,000
2002........................................................ 441,000
2003........................................................ 441,000
2004........................................................ 441,000
2005........................................................ 479,000
2006........................................................ 492,000
2007........................................................ 492,000
Remaining commitment........................................ 123,000
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.
In the early part of 2000, one of our subsidiaries, that at that time was
94%-owned by us, paid dividends in the amount of $17,000 to its minority
shareholders. In 2000 the subsidiary acquired and retired the stock of the two
minority holders. As a result, the subsidiary is now wholly-owned by us, and
there is no longer the issue of dividends being paid by a subsidiary to persons
outside the consolidated group. No dividends have ever been paid on our common
stock.
NOTE 6 -- SETTLEMENTS EXPENSE
On May 22, 2001, we settled litigation with Phillips Petroleum Company and
acquired Phillips' Net Profits Interest in South Pass block 89, offshore
Louisiana. We paid $21.25 million cash and issued 1,189,344 shares of our common
stock as consideration for the settlement and assignment of the net profits
interest.
Of the total $42.5 million settlement, we had previously recorded $20.2
million as an accrued liability. We recorded $12.3 million of the remaining
$22.3 million as additional settlement expense and capitalized $10.0 million as
the cost for our purchase of the net profits interest. In addition, we charged
the remaining $1.2 million deferred net profits expense related to a 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.
34
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Minerals Management Service is the grantor of all leases in the federal
waters offshore Louisiana. When production is established, they collect a
royalty from 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.
NOTE 7 -- EMPLOYEE AND DIRECTOR BENEFIT PLANS
STOCK OPTION PLAN
The compensation committee of the Board of Directors, comprising three
independent directors, administers the 1997 Stock Option Plan. This committee
has the discretion to determine the participants, the number of shares granted
to each person, the purchase price of the common stock covered by each option,
and most other terms of the option. Options granted under the plan may be either
incentive stock options or non-qualified stock options. The committee may issue
options for up to 3.75 million shares of common stock, but no more than 937,500
shares to any individual. Forfeited options are available for future issuance.
In accounting for stock options granted to employees and directors, we have
chosen to continue to apply the accounting method promulgated by Accounting
Principles Board Opinion No. 25 ("APB 25") rather than apply an alternative
method permitted by Statement of Financial Accounting Standards No. 123 ("SFAS
123"). Under APB 25, at the time of grant we do not record compensation expense
on our income statement for stock options granted to employees or directors.
A summary of our stock option plans as of December 31, 2002, 2001, and
2000, and changes during the years ending on those dates is presented below:
AT DECEMBER 31,
------------------------------------------------------------------
2002 2001 2000
-------------------- -------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- -------- --------- -------- --------- --------
Outstanding at beginning of year.... 2,598,700 $ 6.72 2,581,503 $ 5.28 1,761,000 $6.12
Granted............................. 400,000 $17.20 345,000 $15.33 979,000 $3.89
Exercised........................... (440,978) $ 4.87 (327,803) $ 4.39 (33,497) $3.66
Forfeited........................... (5,503) $ 9.04 -- $ -- (125,000) $6.87
--------- ------ --------- ------ --------- -----
Outstanding at end of year.......... 2,552,219 $ 8.68 2,598,700 $ 6.72 2,581,503 $5.28
========= ====== ========= ====== ========= =====
Options exercisable at year-end..... 1,613,554 $ 6.54 1,441,384 $ 6.13 1,097,860 $6.72
Weighted-average fair value of
options Granted during the year... $12.64 $11.55 $2.92
35
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The options outstanding at December 31, 2002, have a weighted-average
remaining contractual life of 7.18 years and an exercise price ranging from
$3.125 to $20.34 per share. A breakdown of the options outstanding at December
31, 2002 by price range is presented below:
WEIGHTED WEIGHTED
AVERAGE AVERAGE
WEIGHTED REMAINING PRICE
AVERAGE LIFE NUMBER ON OPTIONS
OPTION PRICE RANGE NUMBER EXERCISE PRICE (YEARS) EXERCISABLE EXERCISABLE
------------------- --------- --------------- --------- ----------- -----------
$3.125 -- $4.25 1,016,901 $ 3.86 7.00 716,569 $ 3.90
$5.0625 -- $6.9375 499,818 $ 6.34 4.92 499,818 $ 6.34
$8.625 -- $9.00 145,000 $ 8.95 5.73 135,000 $ 8.97
$11.00 -- $15.32 460,500 $13.84 8.05 252,167 $12.72
$16.55 -- $20.34 430,000 $17.16 9.80 10,000 $16.67
The table below reflects the effect on our net income if we recorded the
estimated compensation costs for the stock options using the estimated fair
value as determined by applying the Black-Scholes option pricing model.
FOR YEARS ENDED DECEMBER 31,
-----------------------------
2002 2001 2000
-------- ------- --------
(IN THOUSANDS)
As reported:
Net income................................................ $11,332 $8,344 $45,044
Basic income per share.................................... $ 0.45 $ 0.38 $ 2.10
Diluted income per share.................................. $ 0.42 $ 0.35 $ 1.99
Stock based compensation (net of tax at statutory rate of
35%) included in net income as reported................... $ 1,046 $2,402 $ 113
Stock based compensation (net of tax at statutory rate of
35%) if using the fair value method as applied to all
awards.................................................... $ 2,531 $4,248 $ 1,178
Proforma (if using the fair value method applied to all
awards):
Net income................................................ $ 9,847 $6,498 $43,866
Basic income per share.................................... $ 0.39 $ 0.30 $ 2.05
Diluted income per share.................................. $ 0.36 $ 0.27 $ 1.94
Weighted average shares used in computation Basic........... 25,294 21,979 21,435
Diluted................................................... 27,122 24,414 22,759
The fair value of each option grant for the years ended December 31, 2002,
2001, and 2000 is estimated on the date of grant using the Black-Scholes
option-pricing model with the following weighted average assumptions:
FOR YEARS ENDED
DECEMBER 31,
-----------------------
2002 2001 2000
----- ----- -----
Expected life (years)....................................... 10 10 10
Interest rate............................................... 4.17% 5.13% 6.18%
Volatility.................................................. 61.62% 62.56% 59.01%
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
36
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 usually no more than the maximum tax
deductible contribution 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,
---------------
2002 2001
------ ------
RECONCILIATION OF THE CHANGE IN BENEFIT OBLIGATION
Beginning benefit obligation.............................. $3,305 $3,103
Service cost........................................... 291 151
Interest cost.......................................... 263 221
Actuarial loss......................................... 1,179 59
Benefits paid.......................................... (205) (229)
------ ------
Ending benefit obligation................................. $4,833 $3,305
====== ======
RECONCILIATION OF THE CHANGE IN PLAN ASSETS
Beginning market value.................................... $2,766 $3,090
Actual return on plan assets........................... (324) (282)
Employer contributions................................. 2,269 187
Benefit payments....................................... (205) (229)
------ ------
Ending market value....................................... $4,506 $2,766
====== ======
FUNDED STATUS AND AMOUNTS RECOGNIZED IN THE BALANCE SHEET
Funded status............................................. $ (327) $ (539)
Unrecognized net actuarial loss........................... 2,473 813
------ ------
Adjusted prepaid benefit cost............................. $2,146 $ 274
====== ======
The net periodic pension cost recognized in our income statements include
the following components:
FOR YEARS ENDED
DECEMBER 31,
------------------
2002 2001 2000
---- ---- ----
(IN THOUSANDS)
COMPONENTS OF NET PERIODIC PENSION COST
Service cost.............................................. $291 $151 $119
Interest cost on projected benefit obligation............. 263 221 226
Expected return on plan assets............................ (219) (239) (273)
Recognized net actuarial loss............................. 62 -- --
Net amortization and deferrals............................ -- -- (2)
---- ---- ----
Net periodic pension cost................................. $397 $133 $ 70
==== ==== ====
37
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR YEARS ENDED
DECEMBER 31,
------------------
2002 2001 2000
---- ---- ----
(IN THOUSANDS)
WEIGHTED AVERAGE ASSUMPTIONS
Discount rate............................................. 6.50% 7.25% 7.50%
Expected return on plan assets............................ 8.00% 8.00% 8.00%
Rate of compensation increase............................. 3.00% 3.00% 3.00%
Remington's aggregate projected benefit obligation at December 31, 2002 was
$4.2 million and the aggregate fair value of plan assets was $3.8 million. On
December 31, 2002, Remington had a prepaid benefit cost of $1.8 million. CKB
Petroleum's aggregate projected benefit obligation at December 31, 2002 was
$613,000 and the aggregate fair value of plan assets was $673,000. On December
31, 2002, CKB Petroleum had a prepaid benefit cost of $344,000.
CONTINGENT STOCK GRANT
In June 1999, the Board of Directors approved a contingent stock grant to
our employees and directors. In order for the grant to become effective, the
price of our stock had to increase from $4.19 per share to a trigger price of
$10.42 per share and close at or above $10.42 per share for 20 consecutive
trading days within 5 years of the grant date.
On January 24, 2001, the stock price closed above the trigger price for the
twentieth consecutive trading day. On that date, we measured the total
compensation cost at $8.1 million which was the total number of shares granted
multiplied by the market price on that date. We recorded $8.1 million as
restricted common stock, $5.7 million as unearned compensation reported as a
separate reduction in stockholders' equity on the balance sheet, and $2.4
million as stock based compensation expense. The $2.4 million stock based
compensation expense recorded in the first quarter of 2001 included a "catch up"
amortization from the date of the grant to the measurement date of the total
compensation cost. During the last three quarters of 2001 we amortized an
additional $1.0 million. During 2002 we amortized $1.4 million to stock based
compensation expense. The remaining unearned compensation expense will be
amortized over the next three 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.
38
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 8 -- INCOME TAXES
The following table provides a summary of our income tax expense:
FOR YEARS ENDED
DECEMBER 31,
----------------------------
2002 2001 2000
------ ------------ ----
(IN THOUSANDS)
Current income tax expense (benefit)..................... $ -- $ (12) $100
Deferred income tax expense.............................. 6,095 3,600 --
------ ------ ----
Total income tax expense................................. $6,095 $3,588 $100
====== ====== ====
Total income tax expense differs from the amount computed by applying the
federal income tax rate to net income before income taxes as follows:
FOR YEARS ENDED
DECEMBER 31,
-------------------------
2002 2001 2000
------ ------ -------
(IN THOUSANDS)
Federal income tax expense at statutory rate.............. $6,095 $4,175 $15,799
Net adjustment to valuation allowance..................... -- (575) (15,799)
Other..................................................... -- (12) 100
------ ------ -------
Total income tax expense.................................. $6,095 $3,588 $ 100
====== ====== =======
The following table reflects the significant components of our deferred tax
asset.
AT DECEMBER 31,
-------------------
2002 2001
-------- --------
(IN THOUSANDS)
(Liability) from difference in book and tax basis of oil and
gas properties............................................ $(15,671) $(14,777)
Asset from difference in book and tax basis of other
assets.................................................... 43 826
Asset from difference in book and tax basis of accrued
liabilities............................................... 2,745 2,923
Federal income tax operating loss carry-forward............. 5,275 7,761
Federal capital loss carry-forwards......................... -- --
Alternative minimum tax credit carry-forward................ 416 416
-------- --------
Total deferred tax (liability).............................. $ (7,192) (2,851)
Valuation allowance......................................... -- --
-------- --------
Net deferred tax (liability)................................ $ (7,192) $ (2,851)
======== ========
The unused federal income tax operating loss carry-forward of $15.1 million
will expire during the years 2007 through 2020 if not utilized sooner.
NOTE 9 -- OIL AND GAS RESERVES AND PRESENT VALUE DISCLOSURES (UNAUDITED)
The estimates of oil and gas reserves were prepared by the independent
reserve engineering firm of Netherland, Sewell & Associates, Inc. The
determination of these reserves is a complex and interpretative process that is
subject to continued revision as additional information becomes available. In
many cases, a relatively accurate determination of reserves may not be possible
for several years due to the time necessary for development drilling, testing
and studies of the reservoirs. We do not file reserve estimates with any other
Federal authority or agency.
39
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The quantities of proved oil and gas reserves presented below include only
the amounts which we reasonably expect to recover in the future from known oil
and gas reservoirs under the current economic and operating conditions. Proved
reserves include only quantities that we can commercially recover using current
prices, costs, existing regulatory practices and technology. Therefore, any
changes in future prices, costs, regulations, technology or other unforeseen
factors could significantly increase or decrease proved reserve estimates. Our
proved undeveloped reserves are generally brought on line within 12 months.
Alternatively, they are associated with long life fields where economics dictate
waiting for an existing wellbore available for sidetrack, or waiting to mobilize
a platform rig for operations. Accordingly, proved undeveloped reserves in major
fields may be carried for many years. The following table presents our net
ownership interest in proved oil and gas reserves.
AT DECEMBER 31,
------------------------------------------------------------
2002 2001 2000
------------------ ------------------ ------------------
OIL BBLS GAS MCF OIL BBLS GAS MCF OIL BBLS GAS MCF
-------- ------- -------- ------- -------- -------
(IN THOUSANDS)
Beginning of period........... 13,865 111,920 10,370 88,650 7,177 65,508
Revisions of previous
estimates................... (596) (4,271) 1,221 (1,414) 71 893
Extensions, discoveries and
other....................... 1,678 39,603 3,507 45,951 5,028 44,528
Reserves purchased............ -- -- -- -- 35 294
Reserves sold................. (104) (4,837) -- -- (760) (9,816)
Production.................... (1,729) (17,448) (1,233) (21,267) (1,181) (12,757)
------ ------- ------ ------- ------ -------
End of period................. 13,114 124,967 13,865 111,920 10,370 88,650
====== ======= ====== ======= ====== =======
Proved developed reserves..... 7,977 71,481 6,690 60,756 5,345 71,995
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 year ended December 31, 2000. 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,
because the agreement creating the net profits allowed only an interest in the
net profit and not an ownership interest in the oil and gas reserves.
The following tables represent value-based information about our proved oil
and gas reserves. The standardized measure of discounted future net cash flows
result from the application of specific criteria applicable to the value-based
disclosures of all oil and gas reserves in the industry. Due to the imprecise
nature of estimating oil and gas reserve quantities and the uncertainty of
future economic conditions, we cannot make any representation about
interpretations that may be made or what degree of reliance that may be placed
on this method of evaluating proved oil and gas reserves.
We compute future cash revenue by multiplying the year-end commodity prices
or contractual pricing if applicable, by estimated future production from proved
oil and gas reserves. We use year end West Texas Intermediate posted prices per
barrel and Gulf Coast spot market prices or NYMEX Henry Hub futures price per
MMBtu adjusted by property for energy content, quality, transportation fees, and
regional price differentials.
YEARS ENDED DECEMBER 31,
------------------------
2002 2001 2000
------ ------ ------
West Texas Intermediate (per barrel)....................... $28.00 $16.75 $26.80
Gulf Coast Spot Market (per MMbtu)......................... $ 4.74 $ 2.65 --
NYMEX Henry Hub futures price (per MMbtu).................. -- -- $ 9.78
40
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
We estimated the costs based on the prior year costs incurred for
individual properties, or, similar properties if a particular property did not
have production during the prior year. 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.
YEARS ENDED DECEMBER 31,
--------------------------------
2002 2001 2000
-------- -------- ----------
(IN THOUSANDS)
Oil and gas revenues................................ $946,813 $542,193 $1,111,238
Production costs.................................... (150,084) (107,586) (96,847)
Development costs (1)............................... (116,944) (84,561) (75,995)
Net Profits expense................................. -- -- (15,059)
Income tax expense.................................. (166,864) (53,020) (287,959)
-------- -------- ----------
Net cash flow....................................... 512,921 297,026 635,378
10% annual discount................................. (161,879) (97,043) (176,729)
-------- -------- ----------
Standardized measure of discounted future net cash
flows............................................. $351,042 $199,983 $ 458,649
======== ======== ==========
---------------
(1) Based on Netherland, Sewell & Associates' reserve report for January 1,
2003, we estimate that the amount of capital required to convert proved
undeveloped reserves to proved developed reserves will be $88.2 million of
the $116.9 million of future development costs, including $25.9 million in
2003, $14.5 million in 2004 and $10.4 million in 2005. Our actual
expenditures may differ from these estimates. Capital expenditures incurred
to develop proved undeveloped reserves were $28.5 million in 2002, $19.3
million in 2001 and $2.3 million in 2000.
41
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.
YEARS ENDED DECEMBER 31,
------------------------------
2002 2001 2000
-------- -------- --------
(IN THOUSANDS)
Standardized measure of discounted cash flows at
beginning of year.................................. $199,983 $458,649 $126,868
Sales and transfers of oil and gas produced, net of
production costs and net profits expense........... (84,231) (98,274) (73,866)
Net changes in prices and production costs........... 198,760 (486,774) 268,139
Net changes in estimated development costs........... (4,229) 70 4,500
Net changes in estimated net profits expense......... -- 10,510 (7,139)
Net changes in income tax expense.................... (79,090) 172,708 (175,031)
Extensions, discoveries and improved recovery less
related costs...................................... 123,755 89,048 314,747
Proved oil and gas reserves purchased................ -- -- 2,888
Proved oil and gas reserves sold..................... (6,997) -- (26,016)
Previously estimated development costs incurred
during the year.................................... 22,893 32,687 8,776
Revisions of previous quantity estimates............. (24,244) 13,356 8,274
Other changes........................................ (15,556) (37,861) (6,178)
Accretion of discount................................ 19,998 45,864 12,687
-------- -------- --------
Standardized measure of discounted future net cash
flows at end of year............................... $351,042 $199,983 $458,649
======== ======== ========
42
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 10 -- QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
FOR YEARS ENDING
DECEMBER 31,
---------------------
2002 2001
--------- ---------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
FIRST QUARTER
Net revenues(1)............................................. $19,375 $39,290
Net income.................................................. $ 258 $14,657
Basic net income per share.................................. $ 0.01 $ 0.68
Diluted net income per share................................ $ 0.01 $ 0.60
SECOND QUARTER
Net revenues(1)............................................. $27,406 $33,380
Net income (2).............................................. $ 6,252 $ 1,241
Basic net income per share.................................. $ 0.24 $ 0.06
Diluted net income per share................................ $ 0.22 $ 0.05
THIRD QUARTER
Net revenues(1)............................................. $25,937 $22,664
Net income.................................................. $ 3,967 $ 383
Basic net income per share.................................. $ 0.15 $ 0.02
Diluted net income per share................................ $ 0.14 $ 0.02
FOURTH QUARTER
Net revenues(1)............................................. $27,663 $18,887
Net income (loss)........................................... $ 855 $(7,937)
Basic net income per share.................................. $ 0.03 $ (0.35)
Diluted net income per share................................ $ 0.03 $ (0.35)
---------------
(1) Net revenues include only oil and gas sales revenue.
(2) Net income during the second quarter of 2002 includes a $4.1 million gain on
sale of certain South Texas properties.
43
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
As recommended by Remington's Audit Committee, Remington's Board of
Directors on April 17, 2002, dismissed Arthur Andersen LLP ("Andersen") as
Remington's independent public accountants and engaged Ernst & Young LLP to
serve as Remington's independent public accountants for 2002.
Andersen's reports on Remington's consolidated financial statements for the
past two years did not contain an adverse opinion or disclaimer of opinion, nor
were they qualified or modified as to uncertainty, audit scope or accounting
principles.
During Remington's two most recent fiscal years and through April 17, 2002,
there were no disagreements with Andersen on any matter of accounting principles
or practices, financial statement disclosure, or auditing scope or procedure
which, if not resolved to Andersen's satisfaction, would have caused them to
make reference to the subject matter in connection with their report on
Remington's consolidated financial statements for such years; and there were no
reportable events, as listed in Item 304(a)(1)(v) of Regulation S-K.
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 2002. 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 52
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
44
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: 56
POSITIONS WITH US:
- Director since April 1997
- Member -- Audit Committee (Chairman)
EMPLOYMENT:
- Byrd Investments -- Investment and financial advisor since 1986
OUTSIDE DIRECTORSHIPS:
- Miracle of Pentecost Foundation
EDUCATION:
- Bachelor of Business Administration -- Southern Methodist University
WILLIAM E. GREENWOOD Age: 64
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:
- Transport Dynamics Inc. (Chairman)
- President -- Mendota Museum and Historical Society
45
EDUCATION:
- Bachelor of Science -- Marquette University
DAVID H. HAWK Age: 58
POSITIONS WITH US:
- Director since September 1997
- Chairman of the Board since October 1997
- Member -- Executive Committee
EMPLOYMENT:
- J.R. Simplot Company (a large producer of frozen potatoes, vegetables,
fertilizer and cattle) -- 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: 58
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: 56
POSITION WITH US:
- Director since April 1997
- Chairman -- Compensation Committee
46
EMPLOYMENT:
- Chief Executive Officer and President since 1980 -- Preng and Associates,
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: 72
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: 57
POSITIONS WITH US:
- Director since May 1994
- 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
- Chairman of the Department of Finance and Business Economics, University
of Southern California, 1993-1998
- Frequent consultant and expert witness to business and government
47
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: 53
POSITIONS WITH US:
- Chief Executive Officer since February 1998
- President since March 1997
- Director since September 1997
- Member -- Executive Committee
POSITIONS WITH OUR AFFILIATES:
- CKB Petroleum, Inc.
- Director and President since January 1999
- CKB & Associates, Inc.
- Director and President since January 1999
PREVIOUS EMPLOYMENT HIGHLIGHTS:
- Vice President/Exploration -- Seagull E&P, Inc., 1993-1997
- Vice President/Exploration and Exploitation -- Nerco Oil & Gas, Inc.,
1991-1993
OUTSIDE DIRECTORSHIPS:
- Director -- Suzuki Institute of Dallas
EDUCATION:
- Bachelor of Science in Physics -- Rensselaer Polytechnic Institute
ROBERT P. MURPHY Age: 44
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
48
- 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: 51
POSITIONS WITH US:
- Senior Vice President/Planning and Administration since April 1997
POSITIONS WITH OUR AFFILIATES:
- CKB Petroleum, Inc.
- Director and Vice President since January 1999
- Vice President and Assistant Treasurer, March 1997-October 1997
- Director, March 1997-August 1997
- CKB & Associates, Inc.
- Director and Vice President since January 1999
- Vice President and Assistant Treasurer, March 1997-October 1997
- Director, March 1997-August 1997
- S-Sixteen Holding Company
- Vice President and Assistant Treasurer, March 1997-October 1997
- Director, March 1997-August 1997
EDUCATION:
- Bachelor of Arts in Economics -- Southern Methodist University
- Master of Business Administration in Finance and Quantitative
Analysis -- Southern Methodist University
J. BURKE ASHER Age: 62
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, Inc.
- Treasurer and Assistant Secretary since March 1997
- Director, March 1997-April 1997
- CKB & Associates, Inc.
- Treasurer and Assistant Secretary since March 1997
- Director, March 1997-August 1997
49
- 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
GREGORY B. COX Age: 49
POSITIONS WITH US:
- Vice President/Exploration since January 2002
- Exploration Manager since October 1997
EDUCATION:
- Bachelor of Science in Geology -- University of Texas at Arlington
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.
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 our review of Forms 3, 4, and 5 received by us for 2002,
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.
50
ITEM 11. EXECUTIVE COMPENSATION.
The following table summarizes the compensation paid by the company during
2002, 2001, and 2000 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 2002 exceeded $100,000.
SUMMARY COMPENSATION TABLE
LONG-TERM COMPENSATION
--------------------------------------
ANNUAL COMPENSATION SECURITIES
-------------------------------- RESTRICTED UNDERLYING
OTHER ANNUAL STOCK OPTIONS/ ALL OTHER
NAME AND FISCAL SALARY BONUS COMPENSATION AWARDS SAR'S COMPENSATION
PRINCIPAL POSITION YEAR ($) ($) ($)(1) (#) (#) ($)(4)
------------------ ------ ------- ------- ------------ ---------- ---------- ------------
James A. Watt................... 2002 360,000 252,000 -- (2) 35,000 1,242
Chief Executive 2001 320,004 405,000 -- 62,089(3) 35,000 1,242
Officer and President 2000 282,501 296,000 -- --....... 123,000 1,242
Robert P. Murphy................ 2002 275,004 159,000 -- --....... 32,000 540
Chief Operating Officer and 2001 225,000 200,000 -- 41,791(3) 25,000 480
Senior Vice President/ 2000 187,506 140,000 -- --....... 66,000 390
Exploration and Production
Gregory B. Cox.................. 2002 167,004 57,000 -- --....... 20,000 511
Vice President/ 2001 147,000 45,000 -- 30,089(3) 15,000 439
Exploration 2000 132,300 43,000 -- --....... 45,000 387
Steven J. Craig................. 2002 165,000 41,000 -- --....... 18,000 773
Senior Vice President/ 2001 125,808 46,000 -- 27,391(3) 12,000 364
Planning and Administration 2000 121,008 29,000 -- --....... 39,000 346
J. Burke Asher.................. 2002 150,000 37,000 -- --....... 17,500 1,980
Vice President/Finance 2001 119,600 44,000 -- 26,077(3) 11,500 1,505
and Secretary 2000 115,008 27,600 -- --....... 37,000 928
---------------
(1) No amount is included, as it is less than 10% of the total salary and bonus
of the individual for the year.
(2) Effective March 17, 1997, in connection with his initial employment
agreement, Mr. Watt was awarded 15,000 restricted shares of common stock,
which vested and became unrestricted 20% per year from the effective date.
(3) On January 24, 2001, contingent grants of the number of shares of common
stock shown became effective. For Mr. Cox, the shares vest 50% on June 17,
2002, and 25% each on June 17, 2003 and 2004. For the other officers, the
shares vest 20% annually beginning January 17, 2002. Except in the event of
death, long-term disability, or change of control, the officers will forfeit
unvested shares if their employment with us terminates prior to the vesting
dates.
(4) 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
51
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:
- Approved by the stockholders.
- Administered by the Compensation Committee of our board of directors.
- Subject to adjustments, up to 3,750,000 shares of our common stock may be
issued under the plan.
- Up to 25% of issuable shares may be issued to any single individual.
- Both qualified incentive and non-qualified options may be issued.
- The plan terminates December 4, 2007.
The importance of whether an option is granted as a qualified incentive
option or a non-qualified option is mainly tax driven. If an option is an
incentive option, the exercise price can be no less than the fair market value
on the date of grant. Additional details concerning the 1997 stock option plan
are contained in the plan itself. For a copy of the plan, call Investor
Relations at (214) 210-2650.
OPTION GRANTS IN LAST FISCAL YEAR
INDIVIDUAL GRANTS
---------------------------------------------------------------
NUMBER OF PERCENT OF
SECURITIES TOTAL OPTIONS
UNDERLYING GRANTED TO EXERCISE GRANT DATE
OPTIONS EMPLOYEES IN PRICE EXPIRATION PRESENT
NAME GRANTED FISCAL YEAR $/SHARE DATE VALUE $(1)
---- ---------- ------------- -------- ---------- ----------
James A. Watt.................. 35,000 11% 17.15 12/17/12 440,640
Robert P. Murphy............... 32,000 10% 17.15 12/17/12 402,870
Gregory B. Cox................. 20,000 6% 17.15 12/17/12 251,794
Steven J. Craig................ 18,000 6% 17.15 12/17/12 226,615
J. Burke Asher................. 17,500 5% 17.15 12/17/12 220,320
---------------
(1) We determined these values using the Black-Scholes option pricing model with
the following assumptions: stock price volatility of 61.61%; interest rate
based on the yield to maturity of a 10-year Treasury security; exercise in
the tenth year; and a dividend rate of zero. We made no adjustments for
nontransferability or risk of forfeiture. Our use of this model does not
constitute an endorsement or an acknowledgment that such model can
accurately determine the value of options. No assurance can be given that
the actual value, if any, realized by an executive upon the exercise of
these options will approximate the estimated values calculated by using the
Black-Scholes model.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION
VALUES
NUMBER OF SECURITIES VALUE OF UNEXERCISED
NUMBER OF UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS AT
SHARES VALUE OPTIONS AT FISCAL YEAR-END FISCAL YEAR-END ($)(2)
ACQUIRED ON REALIZED --------------------------- ---------------------------
NAME EXERCISE ($)(1) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ----------- -------- ----------- ------------- ----------- -------------
James A. Watt........... 49,099 603,580 308,197 99,333 3,633,763 544,493
Robert P. Murphy........ 33,588 495,251 137,742 70,666 1,514,724 296,686
Gregory B. Cox.......... -- -- 73,666 45,000 809,762 200,800
Steven J. Craig......... 56,402 563,653 23,597 21,000 248,450 173,300
J. Burke Asher.......... 32,151 494,442 54,499 37,500 550,277 164,493
---------------
(1) Computed as the number of securities multiplied by the difference between
the option exercise price and the mean of the high and low price of our
common stock on the date of exercise.
(2) 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, 2002.
52
CONTINGENT STOCK GRANTS
In 1999, the directors approved contingent 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 was 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 within 5 years of the grant date. 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. 264,863 shares are subject to 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. 395,090
shares are subject to the second vesting schedule. While 679,937 shares of
restricted stock were granted in 1999, as of March 27, 2003, 659,953 shares are
subject to the grant because a director voluntarily surrendered 23,880 shares, a
new employee was granted 6,535 shares, and an employee terminated, forfeiting
2,639 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, a 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 2002:
53
PENSION PLAN TABLE
YEARS OF SERVICE (1)(3)(4)
--------------------------------------------
AVERAGE COMPENSATION(1)(2) 15 20 25 30 35
-------------------------- ------ ------ ------ ------- -------
($) ($) ($) ($) ($) ($)
125,000......................................... 52,135 54,930 57,725 60,520 63,315
150,000......................................... 63,323 66,930 70,538 74,145 77,753
175,000......................................... 74,510 78,930 83,350 87,770 92,190
200,000......................................... 85,698 90,930 96,163 101,395 106,628
225,000......................................... 85,698 90,930 96,163 101,395 106,628
250,000......................................... 85,698 90,930 96,163 101,395 106,628
300,000......................................... 85,698 90,930 96,163 101,395 106,628
400,000......................................... 85,698 90,930 96,163 101,395 106,628
450,000......................................... 85,698 90,930 96,163 101,395 106,628
500,000......................................... 85,698 90,930 96,163 101,395 106,628
---------------
(1) As of December 31, 2002, the Internal Revenue Code does not allow qualified
plan compensation to exceed $200,000 or the benefit payable annually to
exceed $160,000. The Internal Revenue Service will adjust these limitations
for inflation in future years. When the limitations are raised, the
compensation considered and the benefits payable under the pension plans
will increase to the level of the new limitations or the amount otherwise
payable under the pension plans, whichever amount is lower.
(2) Subject to the above limitations, compensation in this table is generally
equal to all of a participant's cash compensation paid in a fiscal year (the
total of Salary, Bonus, and Other Annual Compensation in the Summary
Compensation Table). Average compensation in this table is the average of a
plan participant's compensation during the highest three consecutive years
out of the prior 10 years.
(3) The estimated credited service at December 31, 2002, for the executive
officers shown in the Summary Compensation Table on page 49 is as follows:
James A. Watt (6 years), Robert P. Murphy (5 years), Steven J. Craig (8
years), J. Burke Asher (6 years), and Gregory B. Cox (5 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 beginning on page 53)
- 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 5 board meetings in 2002
54
- 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.
- In 2002, non-employee directors were awarded non-qualified stock options
with exercise prices of $17.15, exercisable 1/3 per year beginning one
year after the date of grant, as follows:
- David H. Hawk - 10,000 shares
- John E. Goble, David E. Preng, and Alan C. Shapiro - 7,500 shares
each
- William E. Greenwood, Thomas W. Rollins, and James Arthur Lyle -
5,000
shares
each
Non-Employee Director Stock Purchase Plan
- This plan was approved by the stockholders December 4, 1997
- Each non-employee director may, once a year, elect to receive all or
part of his board compensation in our common stock
- The number of shares received equals 150% of the cash amount of
compensation divided by the closing market price of our common stock
on the day the cash fees would be payable
- Shares received under this plan may not be transferred for one year
after issuance
- Shares may be transferred earlier than one year based on a
director's death, disability or departure from the board
- During the restricted transfer period the director may vote the
stock and receive any dividends
- The board may terminate this plan at any time
- Shares received under plan for 2002:
- John E. Goble, Jr...................... 1,041 shares in lieu of $12,000
cash
- William E. Greenwood................... 2,560 shares in lieu of $29,500
cash
- James Arthur Lyle...................... 2,243 shares in lieu of $25,750
cash
- David E. Preng......................... 2,266 shares in lieu of $26,000
cash
- Thomas W. Rollins...................... 692 shares in lieu of $8,000
cash
- Alan C. Shapiro........................ 2,560 shares in lieu of $29,500
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. As of December 31,
2002, if the contingent stock grants were vested by a change in control, it
would result in the issuance of a maximum aggregate of 447,192 shares to
directors and employees.
Employment Agreements
We have employment agreements with James A. Watt, Robert P. Murphy, Gregory
B. Cox, 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
55
- 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
Gregory B. Cox
- Term of two years from April 30, 2002, subject to one year
extensions by mutual agreement
- Base salary of $167,000, subject to discretionary increases
- Eligible to receive discretionary performance bonus (targeted at 35%
of base salary)
- If terminated prior to a change in control, without cause, he
receives all accrued compensation and a pro rata bonus plus a
severance payment in lieu of further compensation equal to 1 times
his current base salary
- He receives accrued compensation and a pro rata bonus and 2 times
the sum of his base salary plus target bonus if he is terminated
within twelve months of a change in control, other than for death,
disability or cause, or he leaves for good reason within the twelve
month period
Steven J. Craig and J. Burke Asher
- Term of two years from September 30, 1999, subject to single year
extensions by mutual agreement
- Base salary of $114,200 (Mr. Craig) and $109,200 (Mr. Asher),
subject to discretionary increases
- Eligible to receive discretionary performance bonus (targeted at 20%
of base salary)
- Severance payments similar to Robert Murphy's, except that Mr. Craig
and Mr. Asher each receive 2 times the sum of his annual salary plus
target bonus in connection with leaving employment within twelve
months of a change in control
Compensation Committee Interlocks and Insider Participation in Compensation
Decisions
David E. Preng, William E. Greenwood, and James Arthur Lyle served on the
compensation committee in 2002. 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.
56
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, production, and general and administrative
costs; and achieving an acceptable overall return on capital; all of which are
competitive with a peer group of oil and gas companies. The Committee also
determined that award levels under the plan should be fiscally prudent.
Long-term stock-based incentives
We maintain a stock option plan for officers and other employees. The
philosophy is to award stock options to selected plan participants based on
their levels within the company and upon individual merit. The plan is to grant
stock options which are competitive within the industry for other individuals at
the employee's level and which provide the employee a meaningful incentive to
remain with the company, to increase performance, and to focus on achieving
long-term increases in shareholder value. Other factors the Committee considers
in granting stock options include the employee's contributions toward achieving
the company's long-term objectives, such as reserve and production growth, 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
57
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, 1997, and that all dividends were reinvested.
PEFORMANCE GRAPH
----------------------------------------------------------------------------------------------------------------------
12/31/1997 12/31/1998 12/31/1999 12/31/2000 12/31/2001 12/31/2002
----------------------------------------------------------------------------------------------------------------------
REMA(1)......................... 100.00 69.88 84.99 284.76 378.95 359.46
REMB(1)......................... 100.00 61.46 74.76 250.48 333.33 316.18
NASDAQ U.S. .................... 100.00 141.00 261.50 157.40 124.90 86.30
NASDAQ O&G...................... 100.00 48.60 50.20 104.30 78.10 77.50
---------------
(1) The last day of trading for REMA and REMB 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 (REM). The values
shown above as of December 31, 1998, 1999, 2000, 2001 and 2002 for REMA give
effect to the 1.15:1 exchange ratio that the former holders of REMA received
in the exchange for the new class of common stock, and the 1:1 exchange
ratio that the former holders of REMB received in the exchange for the new
class of common stock.
Until December 24, 1998, our 2 classes of common stock were traded on the
Nasdaq Stock Exchange under the symbols ROILA and ROILB. From December 28,
1998, through June 19, 2002, our single class of common stock traded on the
Nasdaq Stock Exchange under the symbol ROIL. Since June 20, 2002, our common
stock has traded on the New York Stock Exchange under the symbol REM. The
designation REMA and REMB are used in the table above only to distinguish
between the two classes of common stock that were outstanding on December
31, 1997.
58
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Ownership of Certain Beneficial Owners
As of March 27, 2003, 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
NAME AND ADDRESS OF BENEFICIALLY PERCENT OF
BENEFICIAL OWNER OWNED COMMON STOCK
------------------- ------------ ------------
J.R. Simplot................................................ 5,477,928(1) 20.8%
999 Main Street
Boise, Idaho 83702(1)
---------------
(1) 2,785,028 shares are directly owned by JRS Properties III L.P. ("JRS
Properties III"). The J.R. Simplot Self Declaration of Revocable Trust (the
"Trust"), of which Mr. Simplot is the beneficiary and trustee, controls JRS
Properties III. The Trust and a trust for the benefit of Mr. Simplot's
spouse ("Mrs. Simplot's Trust"), which exercises no investment control,
holds approximately 79.6% of the beneficial interest in the shares owned by
JRS Properties III. 2,692,900 shares are directly owned by JRS Properties
L.P. ("JRS Properties"). The Trust controls JRS Properties. The Trust and
Mrs. Simplot's Trust hold approximately 98.7% of the beneficial interest in
the shares owned by JRS Properties.
Ownership of Management
The number of shares of the company's common stock beneficially owned as of
March 27, 2003, by directors of the company, each officer listed in the
compensation table on page 49, 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
EXERCISABLE
SHARES OF WITHIN 60 PERCENT
COMMON STOCK DAYS OF OF
BENEFICIALLY MARCH 27, COMMON
NAME OWNED 2003 TOTAL STOCK
---- ------------ ------------ --------- -------
J. Burke Asher........................ 18,397 66,833 85,230 *
Don D. Box............................ 73,947 191,667 265,614 1.0%
Gregory B. Cox........................ 48,546 40,120 88,666 *
Steven J. Craig....................... 92,282 28,264 120,546 *
John E. Goble, Jr..................... 23,666 90,001 113,667 *
William E. Greenwood.................. 22,619 116,667 139,286 *
David H. Hawk......................... 2,430 -- 2,430 *
James Arthur Lyle..................... 36,787 116,667 153,454 *
Robert P. Murphy...................... 34,719 156,742 191,461 *
David E. Preng........................ 56,766 126,667 183,433 *
Thomas W. Rollins..................... 20,979 91,667 112,646 *
Alan C. Shapiro....................... 47,621 116,667 164,288 *
James A. Watt......................... 108,988 349,197 458,185 1.7%
All directors and executive officers
as a group (14 persons)............. 615,493 1,512,991 2,128,484 7.6%
---------------
* Less than one percent of the outstanding shares.
59
The following table presents information about our equity compensation
plans at December 31, 2002:
NUMBER OF
SECURITIES TO BE NUMBER OF
ISSUED UPON SECURITIES
EXERCISE OF WEIGHTED AVERAGE REMAINING
OUTSTANDING EXERCISE PRICE OF AVAILABLE
OPTIONS, WARRANTS OUTSTANDING OPTIONS, FOR FUTURE
PLAN CATEGORY AND RIGHTS WARRANTS AND RIGHTS ISSUANCE
------------- ------------------- -------------------- ----------
(A) (B) (C)
Equity compensation plans approved by
stockholders................................. 2,552,219 $8.68 544,235
Equity compensation plans not approved by
stockholders................................. 447,192 $0.00 0
--------- ----- --------
Total.......................................... 2,999,411 $7.39 544,235
========= ===== ========
The information above regarding equity compensation plans not approved by
the stockholders includes contingent one-time stock grants made in 1999 to all
employees and directors, which include the following significant attributes:
- Shares awarded based on annual base salary as of June 17, 1999, or in the
case of non-employee directors $100,000, divided by $4.19 (the closing
price on June 17, 1999).
- In order for the grants to become effective, our common stock had to
close at or above $10.42 per share for 20 consecutive trading days within
5 years of the grant date (the "trigger event").
- The trigger event was achieved on January 24, 2001.
- 686,472 shares were awarded. As of December 31, 2002, 212,761 shares have
vested, and 26,519 shares have been forfeited. Of the remaining 447,192
shares, 131,117 shares vest 50% on June 17, 2003, and 50% on June 17,
2004; and 316,075 shares vest 25% on each successive January 17 beginning
January 17, 2003.
- Each employee and director must remain an employee or director during
his/her respective vesting schedule in order to receive the shares.
- In the event of death, long-term disability, change of control, or
reaching the retirement age of 65, the shares will fully vest.
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.
We acquired a long-term receivable under a Collateral Assignment Split
Dollar Insurance Agreement between CKB Petroleum, Inc. and Don D. Box in a
merger in 1998. The amount due CKB Petroleum from Don D. Box under the
Collateral Assignment Split Dollar Insurance Agreement was $140,000 on December
31, 2002, and $135,000 on December 31, 2001.
ITEM 14. CONTROLS AND PROCEDURES.
As of the end of the period covered by this report, our management,
including our Chief Executive Officer and our Principal Financial Officer,
evaluated the effectiveness of our disclosure controls and procedures as defined
in Exchange Act Rule 13a-15(e). Based on that evaluation, our management,
including the Chief Executive Officer and the Principal Financial Officer,
concluded that our disclosure controls and procedures were effective as of the
end of the period covered by this report. Further, during the period covered by
this report, there was no significant change in internal controls over financial
reporting that has materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.
60
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) Documents filed as part of this report:
1. Financial Statements included in Item 8:
(i) Independent Auditors' Report
(ii) Consolidated Balance Sheets as of December 31, 2002 and 2001
(iii) Consolidated Statements of Income for years ended December 31,
2002, 2001 and 2000
(iv) Consolidated Statement of Stockholders' Equity for years ended
December 31, 2002, 2001 and 2000
(v) Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000
(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,
2002.
(c) Exhibits:
3.1# Certificate of Amendment of Certificate of Incorporation of
Remington Oil and Gas Corporation.
3.3### By-Laws as amended.
10.1*** Pension Plan of Remington Oil and Gas as Amended and
Restated Effective January 1, 2000.
10.2*** Amendment Number One to the Pension Plan of Remington Oil
and Gas Corporation.
10.3### Amendment Number Two to the Pension Plan of Remington Oil
and Gas Corporation.
10.4### Amendment Number Three to the Pension Plan of Remington Oil
and Gas Corporation.
10.6* Box Energy Corporation Severance Plan.
10.7++ Box Energy Corporation 1997 Stock Option Plan. (as amended
June 17, 1999 and May 23, 2001)
10.8* Box Energy Corporation Non-Employee Director Stock Purchase
Plan
10.9+ Form of Employment Agreement effective September 30, 1999,
by and between Remington Oil and Gas Corporation and two
executive officers.
61
10.10+ Form of Employment Agreement effective September 30, 1999,
by and between Remington Oil and Gas Corporation and an
executive officer.
10.11** Employment Agreement effective January 31, 2000, by and
between Remington Oil and Gas Corporation and James A. Watt.
10.12### Form of Employment Agreement effective April 30, 2002, by
and between Remington Oil and Gas Corporation and an
executive officer.
21### Subsidiaries of the registrant.
23.1+++ Consent of Ernst & Young LLP.
23.2+++ Notice Regarding Consent of Arthur Andersen LLP.
23.3+++ Consent of Netherland, Sewell & Associates.
31.1+++ Certification of James A. Watt, Chief Executive Officer, as
required pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
31.2+++ Certification of J. Burke Asher, Principal Financial
Officer, as required pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1+++ Certification of James A. Watt, Chief Executive Officer,
pursuant to 18 U.S.C. Section 1350, as required pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
32.2+++ Certification of J. Burke Asher, Principal Financial
Officer, pursuant to 18 U.S.C. Section 1350, as required
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99*** Letter from Remington Oil and Gas Corporation to Securities
and Exchange Commission regarding Arthur Andersen LLP
representations.
---------------
* Incorporated by reference to the Company's Form 10-K (file number
1-11516) for the fiscal year ended December 31, 1997 filed with the
Commission on March 30, 1998.
# Incorporated by reference to the Company's Registration Statement on Form
S-4 (file number 333-61513) filed with the Commission and effective on
November 27, 1998.
+ Incorporated by reference to the Company's Form 10-Q (file number 1-11516)
for the fiscal quarter ended September 30, 1999 filed with the Commission
on November 12, 1999.
** Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the fiscal year ended December 31, 1999 filed with the Commission on
March 29, 2000.
++ 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
on November 9, 2001.
*** Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the fiscal year ended December 31, 2001 filed with the Commission on
March 21, 2002.
### Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the year ended December 31, 2002, filed with the Commission on March
31, 2003.
+++ Filed herewith.
62
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this Amendment No. 1 to
this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
REMINGTON OIL AND GAS CORPORATION
By: /s/ JAMES A. WATT
------------------------------------
James A. Watt
President and Chief Executive
Officer
Date: December 16, 2003
63
EXHIBIT INDEX
EXHIBIT
NUMBER EXHIBIT
------- -------
3.1# Certificate of Amendment of Certificate of Incorporation of
Remington Oil and Gas Corporation.
3.3### By-Laws as amended.
10.1*** Pension Plan of Remington Oil and Gas as Amended and
Restated Effective January 1, 2000.
10.2*** Amendment Number One to the Pension Plan of Remington Oil
and Gas Corporation.
10.3### Amendment Number Two to the Pension Plan of Remington Oil
and Gas Corporation.
10.4### Amendment Number Three to the Pension Plan of Remington Oil
and Gas Corporation.
10.6* Box Energy Corporation Severance Plan.
10.7++ Box Energy Corporation 1997 Stock Option Plan. (as amended
June 17, 1999 and May 23, 2001)
10.8* Box Energy Corporation Non-Employee Director Stock Purchase
Plan
10.9+ Form of Employment Agreement effective September 30, 1999,
by and between Remington Oil and Gas Corporation and two
executive officers.
10.10+ Form of Employment Agreement effective September 30, 1999,
by and between Remington Oil and Gas Corporation and an
executive officer.
10.11** Employment Agreement effective January 31, 2000, by and
between Remington Oil and Gas Corporation and James A. Watt.
10.12### Form of Employment Agreement effective April 30, 2002, by
and between Remington Oil and Gas Corporation and an
executive officer.
21### Subsidiaries of the registrant.
23.1+++ Consent of Ernst & Young LLP.
23.2+++ Notice Regarding Consent of Arthur Andersen LLP.
23.3+++ Consent of Netherland, Sewell & Associates.
31.1+++ Certification of James A. Watt, Chief Executive Officer, as
required pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
31.2+++ Certification of J. Burke Asher, Principal Financial
Officer, as required pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1+++ Certification of James A. Watt, Chief Executive Officer,
pursuant to 18 U.S.C. Section 1350, as required pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
32.2+++ Certification of J. Burke Asher, Principal Financial
Officer, pursuant to 18 U.S.C. Section 1350, as required
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99*** Letter from Remington Oil and Gas Corporation to Securities
and Exchange Commission regarding Arthur Andersen LLP
representations.
---------------
* Incorporated by reference to the Company's Form 10-K (file number
1-11516) for the fiscal year ended December 31, 1997 filed with the
Commission on March 30, 1998.
# Incorporated by reference to the Company's Registration Statement on Form
S-4 (file number 333-61513) filed with the Commission and effective on
November 27, 1998.
+ Incorporated by reference to the Company's Form 10-Q (file number 1-11516)
for the fiscal quarter ended September 30, 1999 filed with the Commission
on November 12, 1999.
** Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the fiscal year ended December 31, 1999 filed with the Commission on
March 29, 2000.
++ 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
on November 9, 2001.
*** Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the fiscal year ended December 31, 2001 filed with the Commission on
March 21, 2002.
### Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the year ended December 31, 2002, filed with the Commission on March
31, 2003.
+++ Filed herewith.