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SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
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 (I.R.S. employer
of incorporation or organization) identification no.)
8201 PRESTON ROAD, SUITE 600, DALLAS, TEXAS 75225-6211
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (214) 210-2650
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Common Stock, $0.01 Par Value Pacific Exchange, Inc.
Securities Registered Pursuant to Section 12(g) of the Act:
COMMON STOCK, $0.01 PAR VALUE
(TITLE OF CLASS)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of voting stock held by non-affiliates of the
registrant on March 12, 2001, was $229,283,013. On that date, the number of
outstanding shares, $0.01 par value, was 21,633,006.
Registrant's Registration Statement filed on Form S-2 effective December 1,
1992 for its 8 1/4% Convertible Subordinated Notes is incorporated by reference
in Part IV of this Form 10-K.
Registrant's Registration Statement filed on Form S-4 effective November
27, 1998, is incorporated by reference in Part IV of this Form 10-K.
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FORM 10-K
REMINGTON OIL AND GAS CORPORATION
TABLE OF CONTENTS
PART I...................................................... 1
Item 1. Business......................................... 1
Item 2. Properties....................................... 3
Item 3. Legal Proceedings................................ 5
Item 4. Submission of Matters to a Vote of Security
Holders................................................ 5
PART II..................................................... 6
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.................................... 6
Item 6. Selected Financial Data.......................... 7
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.............. 8
Item 7A. Quantitative and Qualitative Disclosures about
Market Risk............................................ 14
Item 8. Financial Statements and Supplementary Data...... 15
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.............. 37
PART III.................................................... 37
Item 10. Directors and Executive Officers of the
Registrant............................................. 37
Item 11. Executive Compensation........................... 42
Item 12. Security Ownership of Certain Beneficial Owners
and Management......................................... 50
Item 13. Certain Relationships and Related Transactions... 51
PART IV..................................................... 51
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K.................................... 51
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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
- 24 employees on December 31, 2000
We began operations in 1981 as OKC Limited Partnership. In 1992, the
limited partnership was converted into a corporation named Box Energy
Corporation. In 1997, we changed the name of the company to Remington Oil and
Gas Corporation. We restructured our two classes of common stock into a single
class of voting common stock when we merged with S-Sixteen Holding Company in
December 1998.
Our primary business operation is the exploration, development, and
production of oil and gas reserves in the offshore Gulf of Mexico and onshore
Gulf Coast areas.
Long-term Strategy
Our long-term strategy is to increase our oil and gas reserves and
production while keeping our finding and development costs and production costs
competitive with the industry.
Activities and Operations
We identify prospective oil and gas producing properties primarily by using
3-D seismic technology. After acquiring an interest in a prospective property,
we drill an exploratory well. If the exploratory well finds commercial oil
and/or gas, we complete the well 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 or gathering pipelines in order to
produce and deliver the oil and gas to our various markets. Certain properties
require us to drill additional wells to fully develop the oil and gas reserves
on our discoveries. In order to increase our oil and gas reserves and
production, we continually reinvest the net cash flow from our operations into
new or existing exploration, development and acquisition activities.
We share ownership in many of our oil and gas properties with various
industry partners. We currently operate five of our producing offshore
properties, while others operate the remainder of our producing properties.
Operating the property allows us to maintain a greater degree of control over
timing and amount of capital expenditures. The operator, through joint operating
agreements, is generally granted the right to secure payment of non-operators
share of expenses through the form of a lien or other securing instrument.
Risks Involved in Exploration, Development, and Production
Exploration, development, and production operations carry a high degree of
risk. Drilling unsuccessful wells or completing marginal wells that do not
produce enough oil or gas to return a profit on the amount invested is a risk.
We attempt to reduce this risk by using 3-D seismic data or other 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 and technical personnel.
Additional operating risks include mechanical failure, title risk,
blowouts, environmental pollution, and personal injury. We maintain general
liability insurance and insurance against blowouts, redrilling, and certain
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.
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Competition in the Oil and Gas Industry
We compete with:
- Large integrated oil and gas companies
- Independent exploration and production companies
- Private individuals
- Sponsored drilling programs
We compete for:
- Operational, technical, and support staff
- Options and/or leases on properties
- Sales of oil and gas production
- Access to capital
Many of the competitors may have significantly more financial, personnel,
technological, and other resources available. In addition, some of the larger
integrated companies may be better able to respond to industry changes including
price fluctuations, oil and gas demands, and governmental regulations.
Markets for Oil and Gas Production
Oil and gas are generally homogenous commodities, and the prices for these
commodities fluctuate significantly. Purchasers adjust prices for quality,
refined product yield, geographic proximity to refineries or major market
centers, and the availability of transportation pipelines or facilities. Outside
factors beyond our control combine to influence the market prices. Some of the
more critical factors that affect oil and gas commodity prices include the
following:
- Changes in supply and demand
- Levels of economic activity throughout the country
- Seasonal or extraordinary weather patterns
- Political developments throughout the world
We have no real ability to influence the market prices. Therefore, we sell
our oil and gas production based on posted market prices, spot market indices,
or prices derived from the posted price or index. At times we will lock in a
fixed price for a portion of our future gas production to be delivered as it is
produced. An independent marketing company sells almost all of our gas
production and a small quantity of our oil production from the Gulf of Mexico.
The revenue from the sale of oil and gas by this marketing company accounted for
approximately 50% of our total oil and gas revenues in 2000. In addition, we
sold approximately 51% of our total oil production to one company during the
year, which accounted for approximately 21% of our total oil and gas revenues in
2000.
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 at the same time that new
regulations are being considered and implemented. In addition, because we hold
federal leases, the federal government requires us to comply with numerous
additional regulations that focus on government contractors. The regulatory
burden upon the oil and gas industry increases the cost of doing business and
consequently affects our profitability.
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State regulations relate to virtually all aspects of the oil and gas
business including drilling permits, bonds, and operation reports. In addition,
many states have regulations relating to pooling of oil and gas properties,
maximum rates of production, spacing, and plugging and abandonment of wells.
Our oil and gas operations are subject to stringent federal, state, and
local environmental laws and regulations. The most significant environmental
obligations include compliance with federal legislation such as the Oil
Pollution Act of 1990 and the Clean Water Act (and similar state laws) together
with their amendments and accompanying regulations. 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. The legislation and
accompanying regulations impose financial responsibility requirements, liability
features, and operational requirements, which in certain instances could be
onerously burdensome to satisfy.
The laws that require or address environmental remediation apply
retroactively to previous waste disposal practices. In many cases, these laws
apply 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.
Other Business Information
Except for our oil and gas leases with third parties and licenses to
acquire or use seismic data, we have no material patents, licenses, franchises,
or concessions that we consider significant to our oil and gas operations. We do
not have any "backlog" of products, customer orders, or inventory. We have not
been a party to any bankruptcy, reorganization, adjustment or similar proceeding
except in the capacity as a creditor.
ITEM 2. PROPERTIES.
We concentrate our principal operations in the federal waters of the Gulf
of Mexico and its coastal regions. In addition to the information below, we
encourage you to read "Management's Discussion and Analysis of Financial
Condition and Results of Operations" found on pages 8 through 14 and Note 4,
found on pages 21 through 24 in our Notes to Consolidated Financial Statements,
which provides detailed information concerning costs incurred, proved oil and
gas reserves, and discounted future net revenue for proved reserves.
Leasehold Acreage
Our leasehold acreage of proved and unproved properties at December 31,
2000, was as follows:
UNDEVELOPED DEVELOPED
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GROSS NET GROSS NET
------- ------- ------- ------
Offshore........................................ 134,184 85,771 105,614 36,305
Onshore......................................... 110,133 35,242 28,294 8,206
------- ------- ------- ------
Total................................. 244,317 121,013 133,908 44,511
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Proved Oil and Gas Reserves
Net proved oil and gas reserves at December 31, 2000, as evaluated by
Netherland, Sewell, & Associates, Inc. are summarized below on the following
table. The quantities of proved oil and gas reserves discussed in this section
include only the amounts which we reasonably expect to recover in the future
from known oil and gas reservoirs under the current economic and operating
conditions. Proved reserves include only quantities that we expect to recover
commercially using current prices, costs, existing regulatory practices and
technology. Therefore, any changes in future prices, costs, regulations,
technology or other unforeseen factors could materially increase or decrease the
proved reserve estimates.
NET OIL NET GAS PRE-TAX
RESERVES RESERVES PRESENT VALUE
BARRELS MCF DISCOUNTED @10%
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(IN THOUSANDS)
Offshore Gulf of Mexico.................................... 6,342 77,608 $570,694
Onshore Gulf Coast......................................... 4,028 11,042 $ 99,782
------ ------ --------
Total............................................ 10,370 88,650 $670,476
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Producing Properties
The table below summarizes our ownership in producing wells at the end of
the last three years.
AT DECEMBER 31,
---------------------------------------------
2000 1999 1998
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GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
Oil wells
Offshore Gulf of Mexico........................... 14 3.57 18 4.87 22 5.87
Onshore Gulf Coast................................ 29 11.13 45 17.88 52 17.49
--- ----- --- ----- --- -----
Total................................... 43 14.70 63 22.75 74 23.36
=== ===== === ===== === =====
Gas wells
Offshore Gulf of Mexico........................... 29 7.68 26 5.02 41 5.92
Onshore Gulf Coast................................ 85 20.92 85 16.59 80 14.09
--- ----- --- ----- --- -----
Total................................... 114 28.60 111 21.61 121 20.01
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Our offshore Gulf of Mexico properties account for approximately 57% of our
oil production and approximately 80% of our gas production. In addition, total
revenues from offshore Gulf of Mexico oil and gas production during 2000
accounted for approximately 73% of our total oil and gas revenues. We own
varying working interests (5% to 100%) in 44 offshore Gulf of Mexico blocks at
December 31, 2000, and currently produce from 17 of these blocks with 7
additional blocks currently under development. We operate 5 producing
properties, and we are the named operator on 11 undeveloped properties. 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 2000 we successfully drilled and completed 12 exploratory wells on
11 different properties in the offshore Gulf of Mexico. In addition, we, as
operator, installed 2 production platforms, installed 2 subsea production
systems, and drilled and completed 3 development wells on two different
properties.
Our onshore Gulf Coast area properties are principally located in
Mississippi and Texas. In 2000, these properties accounted for approximately 43%
of our oil production and approximately 20% of our gas production. We drilled a
total of 24 wells on our onshore properties and completed 18 wells as producers.
Our working interests in these wells range from 14% to 79%.
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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,
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2000 1999 1998
-------------------------- -------------------------- --------------------------
GROSS NET GROSS NET GROSS NET
----------- ------------ ----------- ------------ ----------- ------------
PROD. DRY PROD. DRY PROD. DRY PROD. DRY PROD. DRY PROD. DRY
----- --- ----- ---- ----- --- ----- ---- ----- --- ----- ----
Exploratory
Offshore Gulf of
Mexico................ 12 -- 5.45 -- 5 1 1.73 0.33 3 -- 0.90 --
Onshore Gulf Coast...... 18 6 4.40 2.27 22 6 5.91 1.63 9 7 2.72 2.13
-- -- ---- ---- -- -- ---- ---- -- -- ---- ----
Total.......... 30 6 9.85 2.27 27 7 7.64 1.96 12 7 3.62 2.13
== == ==== ==== == == ==== ==== == == ==== ====
Development
Offshore Gulf of
Mexico................ 3 -- 1.05 -- 1 -- 0.33 -- -- -- -- --
Onshore Gulf Coast...... 2 -- 0.89 -- 2 -- 0.89 -- 2 1 0.82 0.30
-- -- ---- ---- -- -- ---- ---- -- -- ---- ----
Total.......... 5 -- 1.94 -- 3 -- 1.22 -- 2 1 0.82 0.30
== == ==== ==== == == ==== ==== == == ==== ====
We had an interest in 2 wells (0.65 net) in progress at December 31, 2000,
7 wells (2.73 net) in progress at December 31, 1999, and 5 wells (1.18 net) in
progress at December 31, 1998.
Other Property and Office Lease
We own several non-contiguous tracts of land covering approximately 7,800
surface acres in Southern Louisiana and Southern Mississippi. Outside parties
lease several of the tracts for farming, grazing, timber, sand and gravel,
camping, hunting, and other purposes. Gross revenues from these real estate
properties in 2000 totaled $181,000. We lease approximately 17,000 square feet
of office space in Dallas, Texas. The lease on this office space expires in
April 2008.
ITEM 3. LEGAL PROCEEDINGS.
The information required by this Item is incorporated herein by reference
to Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Phillips Petroleum Litigation and to Item 8. "Financial
Statements and Supplementary Data." -- Notes 9 and 12 of Consolidated Notes to
Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Our common stock trades on the Nasdaq National Market under the symbol ROIL
and on the Pacific Exchange under the symbol REM.P. The following table sets
forth the high and low last sales price per share as reported by Nasdaq for the
periods indicated.
COMMON STOCK
---------------
HIGH LOW
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2001
First Quarter through March 12............................ 16.250 11.625
2000
Fourth Quarter............................................ 13.375 8.000
Third Quarter............................................. 10.438 5.875
Second Quarter............................................ 7.500 3.500
First Quarter............................................. 4.188 2.813
1999
Fourth Quarter............................................ 5.688 3.625
Third Quarter............................................. 6.000 4.375
Second Quarter............................................ 5.063 3.125
First Quarter............................................. 4.000 2.375
On March 12, 2001, the last reported sales price was $14.625 per share. On
that date, there were 982 stockholders of record. We have not declared or paid
any cash dividends during the past nine years. Our credit facility agreements
prohibit our paying dividends. In addition, if we pay dividends in excess of 2%
of the market price per share during a calendar quarter, the conversion price of
the 8 1/4% Convertible Subordinated Notes will be adjusted proportionately. The
determination of future cash dividends, if any, will depend upon, among other
things, our financial condition, cash flow from operating activities, the level
of our capital and exploration expenditure needs, future business prospects, and
renegotiations of our line of credit.
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ITEM 6. SELECTED FINANCIAL DATA.
The selected consolidated financial data should be read in conjunction with
our consolidated financial statements and notes to the consolidated financial
statements. In addition, you should also read our "Management's Discussion and
Analysis of Financial Condition and Results of Operations" included in Item 7.
below.
2000(1) 1999 1998(1) 1997(1) 1996
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PRICES, VOLUMES, AND PER SHARE DATA)
Financial
Total revenue......................... $100,100 $ 45,430 $ 87,689 $ 61,053 $ 70,210
Net income (loss)..................... $ 45,044 $ (3,703) $ 13,617 $(26,790) $ (7,662)
Basic income (loss) per share......... $ 2.10 $ (0.17) $ 0.67 $ (1.31) $ (0.37)
Diluted income (loss) per share....... $ 1.99 $ (0.17) $ 0.66 $ (1.31) $ (0.37)
Total assets.......................... $192,474 $119,326 $130,229 $ 98,515 $136,599
8 1/4% convertible subordinated
notes.............................. $ 5,880 $ 5,950 $ 38,371 $ 38,371 $ 55,077
Other bank debt....................... $ 27,428 $ 30,028 $ 3,500 $ 6,000 $ --
Stockholders' equity.................. $102,708 $ 56,054 $ 59,699 $ 44,287 $ 74,356
Total shares outstanding.............. 21,564 21,285 21,247 20,306 20,803
Cash Flow
Net cash flow from operations...... $ 69,963 $ 19,180 $ 54,040 $ 27,546 $ 28,955
Net cash flow from investing....... $(57,511) $(25,911) $(38,149) $(11,820) $(47,602)
Net cash flow from financing....... $ 1,323 $ (7,931) $ (1,425) $(14,171) $ --
Operational
Proved reserves(2)
Oil (MBbls)........................ 10,370 7,177 5,519 4,451 3,299
Gas (MMcf)......................... 88,650 65,508 52,709 36,543 39,332
Future discounted net revenue(2)
Before estimated income taxes...... $670,476 $163,665 $ 70,118 $108,698 $189,155
After estimated income taxes....... $458,649 $126,868 $ 63,467 $ 93,838 $146,013
Average sales price
Oil (per Bbl)...................... $ 27.11 $ 15.48 $ 10.99 $ 17.79 $ 20.21
Gas (per Mcf)...................... $ 3.97 $ 2.42 $ 3.22 $ 5.06 $ 5.69
Average production (net sales volume)
Oil (Bbls per day)................. 3,336 3,242 3,411 3,280 2,555
Gas (Mcf per day).................. 35,340 27,229 17,488 19,496 22,518
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(1) Financial 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. The net loss in 1997 includes
a $14.6 million deferred income tax expense that we recorded when we
increased the valuation allowance against the deferred income tax asset
originally recorded in 1992.
(2) The quantities of proved oil and gas reserves discussed in this table
include only the amounts which we reasonably expect to recover in the future
from known oil and gas reservoirs under the current economic and operating
conditions. Proved reserves include only quantities that we can commercially
recover using current prices, costs, existing regulatory practices and
technology. Therefore, any changes in future prices, costs, regulations,
technology, or other unforeseen factors could significantly increase or
decrease the proved reserve estimates.
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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 of known facts
and trends.
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 production costs
competitive with the industry. The following table reflects our results during
the last three years.
% INCREASE % INCREASE
2000 (DECREASE) 1999 (DECREASE) 1998
-------- ---------- -------- ---------- -------
Production:
Oil MBbls............................... 1,221 3% 1,183 (5)% 1,245
Gas MMcf................................ 12,934 30% 9,939 56% 6,383
-------- -- -------- --- -------
Total MMcfe(1).................. 20,260 19% 17,037 23% 13,853
======== == ======== === =======
Proved reserves:
Oil MBbls............................... 10,370 44% 7,177 30% 5,519
Gas MMcf................................ 88,650 35% 65,508 24% 52,709
-------- -- -------- --- -------
Total MMcfe(1).................. 150,870 39% 108,570 27% 85,823
======== == ======== === =======
Production costs per Mcfe(2).............. $ 0.52 0% $ 0.52 (40)% $ 0.87
Production costs per Mcfe without Net
Profits expense......................... $ 0.43 0% $ 0.43 (30)% $ 0.61
Finding and development costs per
Mcfe(3)................................. $ 0.97 41% $ 0.69 (43)% $ 1.21
- ---------------
(1) Barrels of oil are converted to Mcf equivalents at the ratio of 1 barrel of
oil equals 6 Mcf of gas.
(2) Production costs include operating, transportation and Net Profits expense.
(3) Finding and development costs include acquisition, development and
exploration costs (including exploration costs such as seismic acquisition
costs).
Liquidity and Capital Resources
On December 31, 2000, our current assets exceeded our current liabilities
by $11.7 million. Our current ratio was 1.36 to 1.00.
Cash flow from operations for the year ended December 31, 2000, before
changes in working capital increased by $40.9 million, or 165%, compared to the
prior year primarily because of increased oil and gas revenues. Gas sales
increased by $27.3 million, or 113%, and oil sales increased by $14.8 million,
or 81%. The increase in gas sales relates to a 30% increase in production ($11.9
million) and a 64% increase in gas prices ($15.4 million), and the increase in
oil revenues relates primarily to a 75% increase in oil prices.
The recent increase in oil and gas prices has a positive impact on total
revenues, net income, and cash flow from operations. Based on this increase and
an expected increase in production, our current projections indicate that we can
finance the majority of our planned capital expenditures in 2001 through our
cash flow from operations.
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We incurred capital and exploration expenditures totaling $74.3 million
during 2000. The capital expenditures included drilling 12 successful
exploration wells in the Gulf of Mexico and 18 successful wells in Mississippi
and South Texas. In addition we built and installed two offshore platforms and
drilled 3 successful development wells in the Gulf of Mexico, acquired rights to
an additional 1,000 blocks of seismic data, and drilled 2 successful development
wells in South Texas and Mississippi.
In July 2000, we sold certain non-operated producing properties located in
Nueces, Starr, and Victoria Counties, Texas, for approximately $14.9 million. We
recorded a $12.5 million gain from the sale. We used the cash received from the
sale of these properties to fund a portion of our operated projects in the Gulf
of Mexico and new property acquisitions.
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
$66.0 million for capital expenditures in 2001. Our 2001 capital and exploration
budget includes $39.0 million for exploration, $15.0 million for development,
and $12.0 million for land and seismic costs. We expect that our cash, estimated
future cash flow from operations, and available bank line of credit will be
adequate to fund the capital budget for the remainder of this year.
Our current bank line of credit has a borrowing base of $35.0 million. The
bank reviews the borrowing base semi-annually and may increase or decrease the
borrowing base relative to a redetermined estimate of proved oil and gas
reserves. Our oil and gas properties are pledged as collateral for the line of
credit. Additionally, we have agreed not to pay dividends. In September 2000,
the bank agreed to extend the final maturity date from March 1, 2003, to March
1, 2004, and the availability date from October 1, 2000, to October 1, 2001. We
cannot borrow additional funds after the availability date. In addition, on that
date, the revolving credit loans convert to term loans, which must be amortized
in equal quarterly principal payments through the final maturity date unless the
agreement is amended. On December 31, 2000, we had $7.6 million of unused
borrowing base available on the line of credit.
Remington's stock price increased by 376% during the year from a low
closing price of $2.81 per share on February 9, 2000, to a high closing price of
$13.38 per share on December 28, 2000. The closing price has remained above
$11.50 per share throughout the first quarter of 2001. In 1999, as a long-term
incentive, the Board of Directors approved a contingent stock grant of 679,937
shares of our common stock to the employees and directors of the company. We
made this grant when it was difficult to attract and retain quality employees
and directors due to the ongoing litigation with Phillips Petroleum Company and
our lack of a track record at the time. We have lost no employees or directors
since initiating the program. The number of shares granted each employee and
director is relative to the employee's salary (or base number in the case of
directors) and the closing stock price ($4.19 per share) on June 17, 1999. In
order for the grant to become effective, the price of our stock had to increase
from $4.19 per share to $10.42 per share and close at or above $10.42 per share
for 20 consecutive trading days. The required increase in the stock price
represented the equivalent of a compounded annual rate of return of 20% for five
years. Since 1999 one participant voluntarily surrendered 23,880 shares, and the
Board approved an additional grant of 6,535 shares to a new participant. The
grant became effective on January 24, 2001, when our stock price closed above
the trigger price of $10.42 per share for the twentieth consecutive trading day.
As a result of the stock grant becoming effective, we will recognize non-cash
compensation expense totaling $8.1 million. In the first quarter of 2001 we will
recognize a "catch-up" expense of $2.4 million. The remaining $5.7 million will
be amortized quarterly over the next 5 years as the shares vest to the employees
and directors.
During the last three years we have not recorded a significant amount of
federal income tax expense on our income statement. We had a net deferred income
tax benefit recorded as an asset on our balance sheet against which we also
recorded a valuation allowance equal to the net deferred benefit during those
years. During 1998 and 2000 as we recorded net income, we recorded a deferred
income tax expense but offset the amount to zero by a corresponding reduction in
the valuation allowance. Because of our net income during 2000 we will almost
fully utilize the deferred income tax benefit and the corresponding valuation
allowance. Therefore, beginning in the first quarter of 2001 we expect that we
will begin recording deferred income tax expense equal to approximately 35% of
our income before taxes. We expect our cash income tax expense, primarily
alternative minimum tax, will be between 5% and 10% of our income before taxes.
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Results of Operations
In 2000, we recorded net income totaling $45.0 million or $2.10 basic
income per share, and $1.99 diluted income per share, compared to a net loss of
$3.7 million or $0.17 basic and diluted income per share in 1999. The increase
in net income resulted primarily from higher revenues because of the increased
gas production, increased oil and gas prices, and the sale of certain South
Texas properties in 2000.
The following table discloses the net oil and gas production volumes,
sales, and sales prices for each of the three years ended December 31, 2000,
1999, and 1998. The table is an integral part of the following discussion of
results of operations for the periods 2000 compared to 1999 and 1999 compared to
1998.
% INCREASE % INCREASE
2000 (DECREASE) 1999 (DECREASE) 1998
------- ---------- ------- ---------- -------
Oil production volume (MBbls)............... 1,221 3% 1,183 (5)% 1,245
Oil sales revenue........................... $33,106 81% $18,316 34% $13,677
Price per Bbl............................... $ 27.11 75% $ 15.48 41% $ 10.99
Increase (decrease) in oil sales revenue due
to:
Change in prices.......................... $13,760 $ 5,590
Change in production volume............... 1,030 (951)
------- -------
Total increase (decrease) in oil
sales revenue................... $14,790 $ 4,639
======= =======
Gas production volume (MMcf)................ 12,934 30% 9,939 56% 6,383
Gas sales revenue........................... $51,291 113% $24,028 17% $20,579
Price per Mcf............................... $ 3.97 64% $ 2.42 (25)% $ 3.22
Increase (decrease) in gas sales revenue due
to:
Change in prices.......................... $15,405 $(5,106)
Change in production volume............... 11,858 8,555
------- -------
Total increase (decrease) in gas
sales revenue................... $27,263 $ 3,449
======= =======
2000 compared to 1999
Oil production increased slightly compared to 1999 because of increased
production from Mississippi partially offset by lower oil production from the
Gulf of Mexico. Oil production from Mississippi increased by 179,000 barrels, or
79%, during 2000 because of several new successful wells drilled during the
year. The average oil price increased by 75% during 2000 compared to the prior
year.
Gas production increased by 30% during 2000 compared to 1999 primarily from
gas produced from the Gulf of Mexico and South Texas. Gas production from the
Gulf of Mexico increased by 2.1 Bcf, or 26%, and gas production from South Texas
increased by 714,000 Mcf, or 42% during 2000. The increase resulted from several
successful wells drilled during the year. The average gas price increased by 64%
during 2000 compared to 1999.
Other income increased by $11.9 million because we recorded a $12.4 million
gain on the sale of certain South Texas properties in August 2000, partially
offset by lower oil trading income.
Operating expenses increased during the year 2000 compared to 1999, mainly
due to the increased number of producing properties and an increase in workover
expenses mostly related to West Cameron 170 and Eugene Island 135. Exploration
expense increased by $108,000 during 2000 primarily because of slightly higher
dry hole costs in the current year. Depreciation, depletion, and amortization
expense increased by $196,000 during 2000 compared to the prior year largely as
a result of increased production partially offset by lower finding costs per
unit during the last three years. Impairment expense for the year 2000 primarily
includes the costs for expired unproved properties compared to impairment
expense for the year 1999 that included additional impairments for Main Pass 262
and two small onshore properties.
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Legal expenses decreased $780,000 or 53% mainly because of lower costs
related to the Phillips litigation. We settled all of the Minerals Management
Service issues and the minority stockholders litigation during the year. We
reached two separate accords with the Minerals Management Service concerning the
alleged underpayment of oil and gas royalties. The first agreement, reached in
May 2000, concerned additional royalties asserted to be due on the settlement of
litigation concerning a 1990 gas sales contract. Because of this agreement, we
recorded an expense of $3.2 million in the first quarter of 2000. As to the
second accord, we reached an agreement in October 2000 to settle the issues
concerning oil transportation charges and oil exchange contracts for $2.2
million.
1999 compared to 1998
Oil revenue increased by $4.6 million in 1999 compared to the prior year
primarily because of the 41% increase in the average price. Oil production from
the three Gulf of Mexico platforms in the South Pass area decreased 161.3 MBbls
because of depletion of reserves from existing wells. However, oil production
from other Gulf of Mexico properties increased by 63.6 MBbls and partially
offset the decrease from the South Pass area. In addition, oil production from
Mississippi increased by approximately 37.0 MBbls. The net 5% reduction in oil
production decreased total oil revenues by $951,000.
Gas revenues for 1999 increased by $3.4 million largely because of the
increase in gas production. Gas production from the offshore Gulf of Mexico
increased by approximately 2.7 Bcf. Gas production from the South Texas Gulf
Coast increased by approximately 0.8 Bcf. These volume increases, which resulted
in about $8.6 million in additional revenue, were substantially offset by lower
unit prices, which reduced revenues by approximately $5.1 million. The average
price decreased because during the first half of 1998 we sold gas produced from
South Pass block 89 under a gas sales contract at above market prices. We
terminated the gas contract in July 1998.
Interest income decreased $858,000 because of lower cash and investments
balances throughout 1999 compared to 1998. Other income decreased because in
August 1998 we received $49.8 million from Texas Eastern Transmission
Corporation to terminate the South Pass block 89 gas sales contract.
Operating expenses increased by $1.1 million, or 19%, because of the
increase in the number of producing properties during 1999. Transportation
expenses decreased because we purchased S-Sixteen Holding Company in December
1998. We eliminated the transportation expense in the consolidation of CKB
Petroleum, Inc. Net Profits expense decreased $2.1 million because of lower
production volumes and the termination of the Texas Eastern gas sales contract
in July 1998. The termination of the gas sales contract caused gas revenues from
South Pass block 89 to decrease significantly.
Exploration expenses decreased by $2.8 million, or 29%, because of lower
dry hole costs and lower 3-D seismic costs incurred during 1999 compared to
1998. Depreciation, depletion and amortization expense increased because of an
increase in the number of producing properties and an increase in production.
However, because our per-unit finding and development costs decreased, our
per-unit depreciation, depletion and amortization amounts decreased. In 1999,
impairment of oil and gas properties decreased $2.3 million from the prior year.
In 1998 we recorded a $2.5 million impairment charge on the South Pass block 89
property as a result of the termination of the gas sales contract.
During the third quarter of 1998, we received a judgment against us for
$18.0 million in the Phillips litigation. We recorded the judgment during the
third quarter of 1998 and have continued to record interest on the judgment
amount. In February 2000, we reached an agreement to settle litigation with the
two minority shareholders of CKB & Associates, Inc. and CKB Petroleum, Inc. In
addition, as part of the settlement agreement, we purchased their minority
interest in the two subsidiaries in March 2000. We recorded the estimated
expense portion of the settlement as a charge against income in the fourth
quarter of 1999.
Phillips Petroleum Litigation
In 1977, Phillips Petroleum Company assigned its interest in South Pass 89,
offshore Louisiana, to OKC Limited Partnership, predecessor to Remington Oil and
Gas Corporation. The assignment was accomplished
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through a farmout agreement in which Phillips retained a 33% net profits
interest. Phillips had obtained, through a predecessor corporation, the lease
from the Minerals Management Service, which only granted rights to oil and gas
from production. Paragraph IV of the farmout states that Phillips' net profits
shall be "thirty-three percent (33%) of one-fourth (1/4) of eight-eighths (8/8)"
of production. Paragraph IV (a) states that Phillips "shall look exclusively to
the oil, gas, condensate, and other hydrocarbons, ... produced from the subject
lease for the satisfaction and realization of the net profits interest."
Subparagraph IV (d) (4) states the net profits account shall be credited with
"an amount equal to the proceeds of all judgments and claims collected on
account of its ownership of the subject lease." Subparagraph IV (d) (5) states
the net profits account shall be credited with "an amount equal to all monies
and things of value received by or inuring to the benefit by virtue of its
ownership interest in the subject lease" of Remington. The interpretation of
Paragraph IV and its subparagraphs has been the primary subject of the recent
litigation between Phillips and us. Our claim, upheld by the trial court and the
appellate court, is that Phillips can look only to actual production for
satisfaction of the net profits interest according to the clear language of
Paragraph IV. It is our position that Subparagraphs IV (d) (4) and (5) merely
define types of production to be credited to the net profits account. Phillips
claims that Subparagraphs IV (d) (4) and (5) should stand alone and not as
subsets of Paragraph IV and entitle Phillips to amounts received by us
regardless of whether they represent revenues from or associated with production
from the lease. We believe that if Phillips, as drafter of the farmout
agreement, intended Subparagraphs IV (d) (4) and (5) to be so controlling, no
reference to production would have been necessary in the farmout.
The current litigation between Phillips and us involves three issues
related to the interpretation of Paragraph IV and its subparagraphs -- the TETCO
issue, the Overriding Royalty issue, and the Pipeline Tariff issue detailed
below.
TETCO -- We entered into a gas purchase agreement with TETCO in 1982
dedicating our gas from South Pass 89 to TETCO for specified prices. In
1989, TETCO sued us claiming the contract was terminated. In November of
1990, we settled with TETCO and received $69.6 million to "settle all
causes of action, claims and controversies between them pertaining to the
Litigation." Furthermore, we agreed to a new contract price for gas sold to
TETCO in exchange for its agreement to drop its legal challenges to the gas
contract. TETCO also paid us an additional $5.4 million (over and above the
$69.6 million) for past production which we credited to the net profits
account. This payment has not been subject to any litigation. In May of
1991, we allocated $5.8 million of the $69.6 million as production to the
net profits account. Phillips claims the remaining $63.8 million should
have been credited to the net profits account. After a three week trial in
1997, the Louisiana trial court ruled that we should have credited $41.2
million to the net profits account as proceeds from production and thus
owed an additional $9.3 million plus interest to Phillips. As part of its
ruling, the trial court supported our claim that Phillips could only look
to actual production for its net profits interest and that the remaining
$28.4 million of the TETCO payment was for settlement of Remington's
counterclaims against TETCO. Phillips appealed this ruling and on December
15, 2000, the Court of Appeal upheld the trial court's opinion.
Overriding Royalty -- Phillips claimed that in months when no net
profits are achieved, its net profits interest should revert to an
overriding royalty. We claimed that once net profits are achieved,
Phillips' net profits interest does not revert to an overriding royalty
until cumulative net profits are depleted. The trial court ruled in
Phillips favor and awarded Phillips $1.6 million plus interest. We appealed
this issue, but the appellate court upheld the trial court's ruling. We
will not appeal the issue further.
Pipeline Tariff -- The farmout agreement allows transportation costs
to be charged to the net profits account. Initially, Marathon constructed
and operated the oil pipeline from the South Pass complex to Venice,
Louisiana, and charged us a tariff of $2.75 per barrel for transportation.
This tariff was charged to the net profits account with no complaint from
Phillips from inception of production in 1982 until 1989. In 1985, CKB
Petroleum, Inc. purchased an interest in the pipeline and entered into a
20-year transportation agreement with us to transport all of our oil for
$2.75 per barrel. Before CKB Petroleum purchased its interest, Phillips was
given the right to purchase the interest under a preferential right
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clause of the pipeline operating agreement, but declined to do so. Phillips
claims that we should charge only a lesser amount which Phillips claims was
our "actual cost" of transportation not what we paid to CKB Petroleum,
Inc.. Phillips has tried to claim that we somehow profited from charging
the net profits account with the tariff amount that we paid to CKB
Petroleum. Such a charge was clearly permitted by the farmout agreement.
The trial court dismissed this claim. On December 15, 2000, the Court of
Appeal upheld the trial court's opinion on this issue. The $2.75 per barrel
tariff has been the market rate for the pipeline for us and our partners
from inception through the trial date.
The total judgment awarded by the trial court in 1998 including interest
was $18.0 million. We recorded an $18.0 million charge to income in the third
quarter of 1998 and continue to accrue interest on this liability each quarter.
The present total liability is $19.7 million. Currently, we have $9.0 million in
restricted cash set aside for this litigation.
Phillips has filed an application for a supervisory writ with the Louisiana
Supreme Court to which we have filed a response. In the application Phillips has
presented no new facts and no new issues of policy, law or equity. The Supreme
Court may refuse to hear the case. If the Supreme Court grants the application
it will, in all probability, be several months before the case is briefed and
heard by the Supreme Court on the merits and possibly several more months before
a decision rendered. After the Supreme Court issues a final ruling on the case,
or refuses to hear the case, it is likely, depending on the ruling, that various
elements will be remanded to the trial court to resolve certain technical issues
in accordance with the court rulings. It may take several months to resolve
these issues in the trial court. When the litigation is concluded and the amount
of our liability is finally determined, we intend to use a combination of cash,
debt financing, and/or property sales to fulfill the amount of any judgment. We
believe that there will be sufficient time from final determination by the
appellate court of last resort and a final determination by the trial court on
remand to allow us to make provision for any required payment. Final resolution
of this matter through the courts may take up to several years.
In August of 1998, we terminated the TETCO gas contract and received $49.8
million. Phillips has claimed that this full $49.8 million payment should be
credited to the net profits account. Litigation on this issue was initiated in
Collin County, Texas, and subsequently stayed pending the resolution of all the
appeals in Phillips' Louisiana suit. Based on the trial court and appellate
court opinions stating that Phillips can look only to production for its net
profits interest, we anticipate that this case will be dismissed or resolved
through summary proceedings. Total liability for this claim would be $16.4
million plus statutory interest until the date of settlement. The trial and any
appeals regarding this issue, if necessary, could take an additional two years
to resolve once the current Louisiana litigation is concluded.
We have settled similar issues with the Minerals Management Service. On a
pro-rata basis, such settlements are for amounts that are significantly lower
than the amounts claimed by Phillips, and also lower than the amounts awarded by
the courts.
New Accounting Standards
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 "Accounting for Derivative Instruments
and Hedging Activities." As amended, the statement is effective for all fiscal
years beginning after June 15, 2000 (January 1, 2001 for us). SFAS No. 133
requires that derivatives be reported on the balance sheet at fair value. If the
derivative is not designated as a hedging instrument, changes in fair value must
be recognized in the income statement in the period of change. If the derivative
is designated as a hedge and to the extent such hedge is determined to be
effective, changes in fair value are either offset by the change in fair value
of the hedged asset or liability (if applicable) or reported as a component of
other comprehensive income in the period of change, and subsequently recognized
in the income statement when the offsetting hedged transaction occurs. The
definition of derivatives has also been expanded to include contracts that
require physical delivery of oil and gas if the contract allows for net cash
settlement. Currently we do not utilize any derivative instruments that fall
under the criteria defined in the accounting standard. Accordingly, we do not
expect the adoption of SFAS No. 133 to have a material effect on our reported
financial statements or disclosures.
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In December 1999, the Securities and Exchange Commission issued Staff
Accounting Bulletin No 101, "Revenue Recognition in Financial Statements." This
bulletin, which provides guidance on applying accounting principles generally
accepted in the United States to revenue recognition, does not have a material
effect on our financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our market risk sensitive instrument at December 31, 2000, is a revolving
line of credit from a bank. At December 31, 2000, the unpaid principal balance
under the line was $27.4 million. The interest rate on this debt is sensitive to
market fluctuations, however we do not believe that significant fluctuations in
the market interest have a material effect on our consolidated financial
position, results of operations, or cash flow from operations.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO FINANCIAL STATEMENTS
Report of Independent Public Accountants.................... 16
Consolidated Balance Sheets as of December 31, 2000 and
1999...................................................... 17
Consolidated Statements of Income for 2000, 1999, and
1998...................................................... 18
Consolidated Statements of Stockholders' Equity for 2000,
1999, and 1998............................................ 19
Consolidated Statements of Cash Flows for 2000, 1999, and
1998...................................................... 20
Notes to Consolidated Financial Statements.................. 21
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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, 2000 and
1999, and the related consolidated statements of income, stockholders' equity
and cash flows for the three years in the period ended December 31, 2000. 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, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas
March 6, 2001
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REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
AT DECEMBER 31,
---------------------
2000 1999
--------- ---------
ASSETS
Current assets
Cash and cash equivalents................................. $ 18,131 $ 4,356
Restricted cash and cash equivalents...................... 2,592 11,042
Accounts receivable -- oil and gas........................ 17,161 6,148
Accounts receivable -- other.............................. 3,981 273
Prepaid expenses and other current assets................. 2,375 2,054
--------- ---------
Total current assets.............................. 44,240 23,873
--------- ---------
Properties
Oil and gas properties (successful-efforts method)........ 336,558 275,690
Other properties.......................................... 2,701 2,862
Accumulated depreciation, depletion and amortization...... (201,506) (183,971)
--------- ---------
Total properties.................................. 137,753 94,581
--------- ---------
Other assets
Cash collateral for Phillips judgment..................... 9,000 --
Other assets.............................................. 1,481 872
--------- ---------
Total other assets................................ 10,481 872
--------- ---------
Total assets...................................... $ 192,474 $ 119,326
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable and accrued expenses..................... $ 25,273 $ 5,181
Phillips judgment......................................... -- 18,894
Short-term notes payable and current portion of long-term
note payable........................................... 7,229 4,067
--------- ---------
Total current liabilities......................... 32,502 28,142
--------- ---------
Long-term liabilities
Phillips judgment......................................... 19,733 --
Notes payable............................................. 24,685 27,526
Convertible subordinated notes payable.................... 5,880 5,950
Other long-term payables.................................. 6,966 1,598
--------- ---------
Total long-term liabilities....................... 57,264 35,074
--------- ---------
Total Liabilities................................. 89,766 63,216
--------- ---------
Commitments and contingencies (Note 9 and Note 12)
Minority interest in subsidiaries........................... -- 56
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, 21,598,605 shares issued and 21,564,246
shares outstanding in 2000, 21,491,170 shares issued
and 21,285,195 shares outstanding in 1999.............. 216 213
Additional paid-in capital................................ 45,897 44,273
Retained earnings......................................... 56,595 11,568
--------- ---------
Total stockholders' equity........................ 102,708 56,054
--------- ---------
Total liabilities and stockholders' equity........ $ 192,474 $ 119,326
========= =========
See accompanying Notes to Consolidated Financial Statements.
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REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEARS ENDED DECEMBER 31,
----------------------------
2000 1999 1998
-------- ------- -------
Revenues
Oil sales................................................. $ 33,106 $18,316 $13,677
Gas sales................................................. 51,291 24,028 20,579
Interest income........................................... 1,442 724 1,582
Other income.............................................. 14,261 2,362 51,851
-------- ------- -------
Total revenues.............................................. 100,100 45,430 87,689
-------- ------- -------
Costs and expenses
Operating costs and expenses.............................. 8,465 6,978 5,861
Transportation expense.................................... 313 329 2,654
Net profits interest expense.............................. 1,753 1,492 3,600
Exploration expenses...................................... 6,833 6,725 9,497
Depreciation, depletion and amortization.................. 20,976 20,780 19,964
Impairment of oil and gas properties...................... 859 1,883 4,154
General and administrative................................ 5,100 4,790 4,782
Legal expense............................................. 685 1,465 552
Royalty settlement........................................ 5,416 -- --
Minority interest settlement.............................. -- 442 --
Phillips judgment......................................... -- -- 17,950
Interest and financing expense............................ 4,561 4,552 4,302
-------- ------- -------
Total costs and expenses.................................... 54,961 49,436 73,316
-------- ------- -------
Income (loss) before taxes.................................. 45,139 (4,006) 14,373
Income taxes.............................................. 100 (273) 756
Minority interest......................................... (5) (30) --
-------- ------- -------
Net income (loss)........................................... $ 45,044 $(3,703) $13,617
======== ======= =======
Basic income (loss) per share............................... $ 2.10 $ (0.17) $ 0.67
======== ======= =======
Diluted income (loss) per share............................. $ 1.99 $ (0.17) $ 0.66
======== ======= =======
See accompanying Notes to Consolidated Financial Statements.
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REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
COMMON STOCK
---------------------------------
CLASS A CLASS B COMMON ADDITIONAL
$1.00 PAR $1.00 PAR $0.01 PAR PAID IN RETAINED TREASURY
VALUE VALUE VALUE CAPITAL EARNINGS STOCK
--------- --------- --------- ---------- -------- --------
Balance December 31, 1997......... $ 3,250 $ 17,553 $ -- $25,197 $ 1,752 $(3,465)
Net income (loss)................. 13,617
Common stock issued............... 27 156
Treasury stock issued............. 305
Merger and exchange of common
stock........................... (3,250) (17,580) 213 18,764 3,160
------- -------- ---- ------- ------- -------
Balance December 31, 1998......... -- -- 213 44,117 15,369 --
------- -------- ---- ------- ------- -------
Net income (loss)................. (3,703)
Common stock issued............... 156
Dividends paid to minority
stockholders.................... (98)
------- -------- ---- ------- ------- -------
Balance December 31, 1999......... -- -- 213 44,273 11,568 --
------- -------- ---- ------- ------- -------
Net income (loss)................. 45,044
Common stock issued............... 3 1,624
Dividends paid to minority
stockholders.................... (17)
------- -------- ---- ------- ------- -------
Balance December 31, 2000......... $ -- $ -- $216 $45,897 $56,595 $ --
======= ======== ==== ======= ======= =======
See accompanying Notes to Consolidated Financial Statements.
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REMINGTON OIL AND GAS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEARS ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------
Cash flow provided by operations
Net income (loss)........................................... $ 45,044 $ (3,703) $ 13,617
Adjustments to reconcile net income
Depreciation, depletion and amortization.................. 20,976 20,780 19,964
Amortization of deferred charges.......................... 334 752 254
Impairment of oil and gas properties...................... 859 1,883 4,154
Dry hole costs............................................ 5,557 5,187 5,222
Minority interest in net income of subsidiaries........... (5) (30) --
Stock issued to directors and employees for
compensation........................................... 174 156 488
Royalty settlement........................................ 5,416 -- --
(Gain) on sale of properties.............................. (12,640) (218) (111)
Deferred income tax expense............................... -- -- 323
Changes in working capital
(Increase) decrease in accounts receivable................ (14,745) (3,230) 3,133
(Increase) decrease in prepaid expenses and other current
assets................................................. 344 (183) 296
Increase in accounts payable and accrued expenses......... 19,199 78 15,554
(Increase) in deferred charges............................ -- -- (104)
(Increase) in restricted cash............................. (550) (2,292) (8,750)
-------- -------- --------
Net cash flow provided by operations........................ 69,963 19,180 54,040
-------- -------- --------
Cash from investing activities
Payments for capital expenditures......................... (72,678) (26,209) (40,155)
Cash acquired in merger with S-Sixteen Holding Company and
Subsidiaries........................................... -- -- 79
Principal repayments -- S-Sixteen Holding Company......... -- -- 1,432
Proceeds from property sales.............................. 15,167 298 495
-------- -------- --------
Net cash (used in) investing activities..................... (57,511) (25,911) (38,149)
-------- -------- --------
Cash from financing activities
Proceeds from notes payable and long-term accounts
payable................................................ 10,630 30,628 7,813
Payments on notes payable and long-term accounts
payable................................................ (9,811) (37,933) (7,400)
Commitment fee on line of credit.......................... -- (528) --
Exercised stock options................................... 521 -- --
Issuance costs for exchange of common stock............... -- -- (1,838)
Dividends paid to minority interest holders............... (17) (98) --
-------- -------- --------
Net cash provided by (used in) financing activities......... 1,323 (7,931) (1,425)
-------- -------- --------
Net increase (decrease) in cash and cash equivalents........ 13,775 (14,662) 14,466
Cash and cash equivalents at beginning of period.......... 4,356 19,018 4,552
-------- -------- --------
Cash and cash equivalents at end of period.................. $ 18,131 $ 4,356 $ 19,018
======== ======== ========
Cash paid for interest...................................... $ 4,338 $ 2,577 $ 3,879
======== ======== ========
Cash paid (received) for taxes.............................. $ 100 $ (327) $ 433
======== ======== ========
See accompanying Notes to Consolidated Financial Statements.
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REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- DESCRIPTION OF THE COMPANY AND BASIS OF PRESENTATION
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.
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.
NOTE 2 -- CONSOLIDATION OF SUBSIDIARIES
We own the following subsidiaries: CKB Petroleum, Inc., CKB & Associates,
Inc., Box Brothers Realty Investments Company, CB Farms, Inc., and Box
Resources, Inc. We eliminated all inter-company transactions and account
balances for the periods of consolidation. The primary operating subsidiary, CKB
Petroleum, Inc., acquired in December 1998, owns an undivided interest in a
pipeline that transports oil from our South Pass blocks, offshore Gulf of
Mexico, to Venice, Louisiana.
NOTE 3 -- CASH, CASH EQUIVALENTS AND RESTRICTED CASH
Cash equivalents consist of 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.
Our restricted cash is collateral for various bonds in favor of the
Minerals Management Service relating to audit issues and qualifications as
lessees and/or operators on various properties. In January 2001, $3.6 million of
the bonds were cancelled after we paid the Minerals Management Service for the
settlement of MMS audit issues, resulting in a release back to us of $1.8
million of related cash collateral. In addition, we have set aside $9.0 million
with a surety company as collateral for the suspensive appeal bond for the
Phillips litigation. This amount is classified as a non-current asset.
NOTE 4 -- OIL AND GAS PROPERTIES, ACCOUNTING METHODS, COSTS, PROVED RESERVES AND
VALUE BASED INFORMATION
We use the successful-efforts method to account for oil and gas exploration
and development expenditures. Under this method, we record the expenditures for
leasehold acquisitions, tangible equipment, and intangible drilling costs for an
individual oil and gas property as an asset. In addition, if the construction
cost of an offshore platform is significant, we record an allocated portion of
the interest expense incurred during the construction period as part of the oil
and gas property cost. No interest expense has been capitalized in 2000.
21
24
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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,
-------------------------------------------------------------------
2000 1999
-------------------------------- --------------------------------
PROVED UNPROVED TOTAL PROVED UNPROVED TOTAL
--------- -------- --------- --------- -------- ---------
(IN THOUSANDS)
Onshore..................... $ 46,618 $ 2,125 $ 48,743 $ 38,373 $ 4,991 $ 43,364
Offshore.................... 272,680 15,135 287,815 222,803 9,523 232,326
--------- ------- --------- --------- ------- ---------
Total....................... 319,298 17,260 336,558 261,176 14,514 275,690
Accumulated depreciation,
Depletion and
amortization.............. (199,451) -- (199,451) (182,139) -- (182,139)
--------- ------- --------- --------- ------- ---------
Net oil and gas
properties................ $ 119,847 $17,260 $ 137,107 $ 79,037 $14,514 $ 93,551
========= ======= ========= ========= ======= =========
We accumulate the expenditures incurred in drilling exploratory wells as
work in process until we determine whether the well has encountered commercial
oil and gas reserves. If the well has encountered commercial reserves, we
transfer the accumulated cost to oil and gas properties; otherwise, we charge
the accumulated cost, net of salvage value, to dry hole expense. If the well has
encountered commercial reserves but cannot be classified as proved within one
year after discovery, then we consider the well to be impaired, and we charge to
expense the capitalized costs (net of any salvage value) of drilling the well.
We record expenditures for geological, geophysical or other prospecting costs as
exploration expenses on the income statement when incurred. The following table
presents a summary of our oil and gas expenditures during the last three years.
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------
2000 1999 1998
--------- --------- ---------
(UNAUDITED, IN THOUSANDS)
Unproved acquisition costs.................................. $13,057 $ 2,732 $11,160
Proved acquisition costs.................................... $ 1,779 $ 379 $ 5,353
Exploration costs........................................... $38,224 $17,535 $23,279
Development costs........................................... $21,249 $ 7,007 $ 4,318
We amortize the capitalized cost of each oil and gas property using the
units-of-production method. To calculate the cost per unit we divide the
leasehold costs by total proved reserves and the costs for wells, platforms, and
other equipment by proved developed reserves. We classify as proved developed
oil and gas reserves that do not require significant additional cost, such as a
new well or major sidetrack. We then multiply the cost per unit by the actual
production and charge the result to depreciation, depletion and amortization
expense. Gas reserves are converted at a ratio of 6 Mcf to 1 barrel of oil.
Future dismantlement, restoration and abandonment costs include the
estimated costs to dismantle, restore, and abandon our offshore platforms,
wells, and related facilities. As of December 31, 2000, the total estimated
liability of our future dismantlement and restoration costs is $6.9 million. We
record 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. The accrued liability at December 31, 2000 and 1999, was
$4.6 million and $4.0 million, respectively.
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 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. The impairment expense is equal to the difference
between the net book value
22
25
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. We recognized impairment expenses as
follows in the table below:
FOR THE YEARS ENDED
DECEMBER 31,
----------------------
2000 1999 1998
---- ------ ------
(IN THOUSANDS)
Unproved properties......................................... $811 $ 794 $1,176
Proved properties........................................... 48 1,089 2,978
---- ------ ------
Total impairment expense.................................... $859 $1,883 $4,154
==== ====== ======
The impairment expense on proved properties for all three years primarily
resulted from inadequate oil and gas reserves or a significant decrease in oil
and gas production from the specific property. The expense in 1999 included an
impairment of $852,000 for the platform located on Main Pass block 262 and the
expense in 1998 included $2.5 million from South Pass block 89 because of the
reduction in estimated undiscounted future net cash flow caused by the
termination of the long-term gas sales contract for that property.
The estimates of oil and gas reserves were prepared by the independent
engineering and consulting firms of Netherland, Sewell & Associates, Inc. for
the year 2000 and by Netherland, Sewell & Associates, Inc. and Miller and Lents,
Ltd. for the previous two years. The determination of these reserves is a
complex and interpretative process that is subject to continued revision as
additional information becomes available. In many cases, a relatively accurate
determination of reserves may not be possible for several years due to the time
necessary for development drilling, testing and studies of the reservoirs.
The quantities of proved oil and gas reserves presented below include only
the amounts which we reasonably expect to recover in the future from known oil
and gas reservoirs under the current economic and operating conditions. Proved
reserves include only quantities that we can commercially recover using current
prices, costs, existing regulatory practices and technology. Therefore, any
changes in future prices, costs, regulations, technology or other unforeseen
factors could significantly increase or decrease proved reserve estimates. The
following table presents our net ownership interest in proved oil and gas
reserves.
AT DECEMBER 31,
----------------------------------------------------
2000 1999 1998
---------------- --------------- ---------------
OIL GAS OIL GAS OIL GAS
BBLS MCF BBLS MCF BBLS MCF
------ ------- ------ ------ ------ ------
(UNAUDITED, IN THOUSANDS)
Beginning of period...................... 7,177 65,508 5,519 52,709 4,451 36,543
Revisions of previous estimates........ 111 1,070 1,173 3,340 850 6,533
Extensions, discoveries and other...... 5,028 44,528 1,668 19,580 1,311 10,958
Reserves purchased..................... 35 294 -- -- 152 5,058
Reserves sold.......................... (760) (9,816) -- (182) -- --
Production............................. (1,221) (12,934) (1,183) (9,939) (1,245) (6,383)
------ ------- ------ ------ ------ ------
End of period............................ 10,370 88,650 7,177 65,508 5,519 52,709
====== ======= ====== ====== ====== ======
Proved developed reserves................ 5,345 71,995 5,593 56,742 3,605 33,680
The proved developed and undeveloped reserves and standardized measure of
discounted future net cash flows associated with South Pass block 89 are
burdened by a 33% net profits interest. The reserves included in the above table
include our full net ownership interest without any reduction for the net
profits interest. We
23
26
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
treat the net profits interest as an operating expense rather than a reduction
in proved reserves. Please see Note 12 -- Net Profits Expense and Phillips
Litigation for a more detailed discussion about the net profit interest.
The following tables represent value-based information about our proved oil
and gas reserves. The standardized measure of discounted future net cash flows
results 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
by the proved oil and gas reserves. Future production and development costs
include the estimated costs to produce or develop the proved reserves based
primarily on historical costs. We calculated the future net profits expense by
multiplying the net profit percentage by the future revenue less production and
development costs on South Pass block 89. We estimated future income tax expense
on a year-by-year basis by applying the current tax rate to the future net cash
flow from all properties. Finally, we discounted the future net cash flow, after
tax, by 10% per year to arrive at the standardized measure of discounted future
net cash flows presented below.
AT DECEMBER 31,
--------------------------------
2000 1999 1998
---------- -------- --------
(UNAUDITED, IN THOUSANDS)
Oil and natural gas revenues................................ $1,111,238 $308,063 $160,416
Production costs............................................ (96,847) (47,243) (31,474)
Development costs........................................... (75,995) (25,603) (30,665)
Net Profits expense......................................... (15,059) (7,267) (3,453)
Income tax expense.......................................... (287,959) (49,843) (7,888)
---------- -------- --------
Net cash flow............................................... 635,378 178,107 86,936
10% annual discount......................................... (176,729) (51,239) (23,469)
---------- -------- --------
Standardized measure of discounted future net cash flow..... $ 458,649 $126,868 $ 63,467
========== ======== ========
The following table summarizes the principal sources of change in the
standardized measure of discounted future net cash flows from year to year.
AT DECEMBER 31
-------------------------------
2000 1999 1998
--------- -------- --------
(UNAUDITED, IN THOUSANDS)
Standardized measure of discounted cash flows at beginning
of year................................................... $ 126,868 $ 63,467 $ 93,838
Sales and transfers of oil and natural gas produced, net of
production costs and net profits expense.................. (73,866) (33,393) (24,796)
Net changes in prices and production costs.................. 268,139 50,133 (77,769)
Net changes in estimated development costs.................. (7,973) 1,746 1,274
Net changes in estimated net profits expense................ (7,139) (5,306) 17,624
Net changes in income tax expense........................... (175,031) (28,504) 8,208
Extensions, discoveries and improved recovery less related
costs..................................................... 314,747 44,823 11,625
Proved oil and gas reserves purchased....................... 2,888 -- 5,050
Proved oil and gas reserves sold............................ (26,016) (111) --
Development costs incurred during the year.................. 21,249 7,007 4,318
Revisions of previous quantity estimates.................... 8,274 25,122 18,673
Other changes............................................... (6,178) (4,463) (3,962)
Accretion of discount....................................... 12,687 6,347 9,384
--------- -------- --------
Standardized measure of discounted future net cash flows end
of year................................................... $ 458,649 $126,868 $ 63,467
========= ======== ========
24
27
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 5 -- OTHER PROPERTIES
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.
NOTE 6 -- OTHER ASSETS
Other assets include the net unamortized origination fees and a long-term
account receivable. The origination fees include fees paid for the 8 1/4%
Convertible Subordinated Notes and the bank line of credit. Both are amortized
on a straight-line basis over the term of the debt. We charge the amortized
amount to interest and financing costs. The long-term account receivable 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.
NOTE 7 -- MINORITY INTEREST IN SUBSIDIARIES
Two individuals owned a combined 5.8824% interest in two of our
subsidiaries, CKB Petroleum, Inc. and CKB & Associates, Inc. The two
subsidiaries were acquired when we merged with S-Sixteen Holding Company in
December 1998. The minority interest liability reflects their percentage of the
total combined equity in the two subsidiaries. In February 2000, we reached an
agreement to settle certain litigation claims by the minority interest owners
and purchased their minority interests in the two subsidiaries. In connection
with the settlement of the litigation, we recorded $442,000 as a settlement
expense in December 1999.
NOTE 8 -- NOTES PAYABLE AND OTHER LONG-TERM PAYABLES
In February 1999 we obtained a $50.0 million line of credit with a bank.
The following schedule reflects certain information about the line of credit for
the last two years.
AT DECEMBER 31,
-----------------
2000 1999
------- -------
(IN THOUSANDS)
Borrowing base.............................................. $35,000 $32,000
Outstanding balance (including current maturities).......... 27,428 30,028
Letters of credit issued.................................... -- 1,788
------- -------
Available amount............................................ $ 7,572 $ 184
======= =======
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 1.625 to 2.375 percentage points over the London Interbank Offered Rates.
Interest only is payable quarterly through September 30, 2001. If the line is
not extended or renegotiated, the loans under the line of credit convert to term
loans on October 1, 2001, and principal payments will be scheduled as follows:
2001 -- $2.7 million; 2002 -- $11.0 million; 2003 -- $11.0 million; 2004 -- $2.7
million. Unless renegotiated or extended, the line expires March 1, 2004.
The most significant financial covenants in the line of credit include,
among others, maintaining a minimum current ratio of 1.0 to 1.0 excluding any
liabilities associated with the Phillips Petroleum Company litigation, a minimum
tangible net worth of $55.0 million plus 50% of future net income and 100% of
any non-redeemable preferred or common stock offerings, maximum debt to EBITDA
of 3.0 to 1.0, and interest coverage of 3.0 to 1.0. Additionally, certain
adverse outcomes of the Phillips litigation could constitute an event of
default. See Note 12.
25
28
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In December 1992, we issued $55.1 million of 8 1/4% Convertible
Subordinated Notes. The notes mature December 1, 2002, and may convert into
shares of common stock at the election of the note-holder any time before
maturity, unless previously redeemed. Interest is payable semiannually on June 1
and December 1. We may redeem all or a portion of the notes any time after
December 1, 2000, at 101.65% of the face amount. The redemption price decreases
.825% on December 1, 2001. The notes are unsecured and subordinate to existing
and future senior indebtedness.
The indenture for the notes requires us to make an offer to purchase the
notes if a "change in control" occurs. The purchase price is the total of the
par value plus accrued interest through the date of purchase. As a result of
this "change in control" provision we repurchased $16.7 million of the notes
outstanding in October 1997 and $32.4 million of the notes outstanding in
February 1999.
Other long-term payables include amounts payable under the MMS settlement
agreement concerning the TETCO issue.
We estimate that the combined fair value of our bank debt and 8 1/4%
Convertible Subordinated Notes, including the current maturities of such
obligations, is approximately $34.0 million at December 31, 2000 and $35.5
million at December 31, 1999. We based the fair value on broker estimates for
our convertible notes and on current rates available for our bank debt. The book
value of our other long-term indebtedness approximates fair value.
NOTE 9 -- 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
- ---- ----------
1998..................................................... $ 474,000
1999..................................................... $ 407,000
2000..................................................... $ 407,000
2001..................................................... $ 433,000
2002..................................................... $ 441,000
2003..................................................... $ 441,000
2004..................................................... $ 441,000
2005..................................................... $ 479,000
Remaining commitment..................................... $1,107,000
We are defendants in litigation with Phillips Petroleum Company concerning
their net profits interest ownership in South Pass block 89. We discuss this
litigation in more detail in Note 12 -- Net Profits Expense and Phillips
Litigation.
Minerals Management Service Issues
MMS is the grantor of all leases in the federal waters offshore Louisiana.
When production is established, MMS collects a 16.67% royalty from all
hydrocarbons produced from the lease. After a routine audit of Remington's
royalty payments, MMS issued orders to pay additional royalty on three separate
claims regarding our South Pass 89 lease complex. The orders to pay involved the
TETCO issue, the Pipeline Tariff issue and the Exchange Agreement issue as
detailed below:
TETCO -- MMS initially claimed that the full 1990 TETCO payment of
$69.6 million should be subject to royalty of 16.67%. This is identical to
Phillips' demand that this $69.6 million payment should
26
29
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
all have been allocated to their net profits account as detailed in Note
12. After a review of the facts, MMS concluded, as did the trial court and
the appellate court in the Phillips litigation, that $41.2 million of the
$69.6 million should have been allocated to production and thus royalty was
due on that amount. This claim was settled for $4.8 million in additional
royalties to be paid over three years. Because of this settlement, we
recorded a $3.2 million expense in the first quarter of 2000 net of
Phillips' net profits interest.
In the settlement agreement, MMS agreed that, based on federal law, no
royalty would be due on the $49.8 million termination payment received from
TETCO by us in July of 1998, as it was not from production. Phillips, in
the Collin County, Texas, action on the same matter, claims that this
payment should be allocated to the net profits agreement as detailed in
Note 12.
Pipeline Tariff -- MMS has claimed that since CKB Petroleum, Inc. was
an affiliated entity of the company, we could not charge MMS our actual
cost of $2.75 per barrel for transportation of their oil, but could only
charge the operator's actual operating charges to CKB Petroleum. We
documented to the MMS that $2.75 per barrel was the actual cost to us and
our public shareholders, that costs to CKB Petroleum were significantly
more than the operating charges from the pipeline operator, and that the
$2.75 per barrel was approved by FERC. Phillips has made a similar claim
which was dismissed by the trial court. This dismissal was affirmed by the
Court of Appeal.
Exchange Agreement -- MMS claimed underpayment of royalty since 1998
on certain oil sold from South Pass 89 complex through exchange agreements.
This underpayment claim arises from a rule change by MMS in 1998. We began
crediting MMS with the value of the exchanges in May of 1999 as set
pursuant to their new rule. Phillips was paid net profits on these exchange
agreements.
We agreed with the MMS to settle these last two issues concurrently
for a total payment by Remington of $2.2 million. This $2.2 million is
reflected as an expense in the third quarter of 2000. A related reduction
of approximately $421,000 in the net profits expense partially offsets this
charge. Of the $2.2 million, we have allocated approximately $1.4 million
as applicable to the exchange agreement issue and the remainder as
applicable to the pipeline tariff issue.
We have no other material pending legal proceedings other than the
litigation mentioned above. Other than certain possible outcomes of the Phillips
litigation, it is our opinion that any adverse judgments or results would not
have a material adverse effect on our financial position or results of
operation.
NOTE 10 -- 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 3.0 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 13 -- Employee and Director Compensation
Plans. Additionally, we reserved 200,000 shares for a warrant issued in
connection with our acquisition of S-Sixteen Holding Company in December 1998.
Dividend payments are currently prohibited by our line of credit agreement.
In addition, if we pay dividends in excess of 2% of the market price per share
during a calendar quarter, the conversion price of the 8 1/4% Convertible
Subordinated Notes will be adjusted proportionately.
27
30
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 11 -- OIL AND GAS REVENUES
We recognize oil and gas revenue in the month of actual production. Our
actual sales have not been materially different from our entitled share of
production and we do not have any significant gas imbalances. In 2000, sales by
a gas marketing company accounted for approximately 50% of our total oil and gas
revenue. In addition, we sold approximately 51% of our total oil production to
one company during the year, which accounted for approximately 21% of our total
oil and gas revenues in 2000. We do not believe that losing services or sales
from either of these companies would have a material adverse effect on us.
NOTE 12 -- NET PROFITS EXPENSE AND PHILLIPS LITIGATION
We pay Phillips Petroleum Company 33% of the "net profits," as defined in
the farm-out agreement, from South Pass block 89. The following table summarizes
the net profits expense calculation:
FOR YEARS ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------
(IN THOUSANDS)
Oil and natural gas revenue (net of transportation)..... $ 7,846 $ 6,611 $13,434
Operating, overhead, and capital expenditures........... (2,534) (2,090) (2,525)
------- ------- -------
"Net profit" from South Pass block 89................... $ 5,312 $ 4,521 $10,909
======= ======= =======
Net profit expense (at 33%)................... $ 1,753 $ 1,492 $ 3,600
======= ======= =======
In 1977, Phillips Petroleum Company assigned its interest in South Pass 89,
offshore Louisiana, to OKC Limited Partnership, predecessor to Remington Oil and
Gas Corporation. The assignment was accomplished through a farmout agreement in
which Phillips retained a 33% net profits interest. Phillips had obtained,
through a predecessor corporation, the lease from the Minerals Management
Service, which only granted rights to oil and gas from production. Paragraph IV
of the farmout states that Phillips' net profits shall be "thirty-three percent
(33%) of one-fourth (1/4) of eight-eighths (8/8)" of production. Paragraph IV
(a) states that Phillips "shall look exclusively to the oil, gas, condensate,
and other hydrocarbons, ... produced from the subject lease for the satisfaction
and realization of the net profits interest." Subparagraph IV (d) (4) states the
net profits account shall be credited with "an amount equal to the proceeds of
all judgments and claims collected on account of its ownership of the subject
lease." Subparagraph IV (d) (5) states the net profits account shall be credited
with "an amount equal to all monies and things of value received by or inuring
to the benefit by virtue of its ownership interest in the subject lease" of
Remington. The interpretation of Paragraph IV and its subparagraphs has been the
primary subject of the recent litigation between Phillips and us. Our claim,
upheld by the trial court and the appellate court, is that Phillips can look
only to actual production for satisfaction of the net profits interest according
to the clear language of Paragraph IV. It is our position that Subparagraphs IV
(d) (4) and (5) merely define types of production to be credited to the net
profits account. Phillips claims that Subparagraphs IV (d) (4) and (5) should
stand alone and not as subsets of Paragraph IV and entitle Phillips to amounts
received by us regardless of whether they represent revenues from or associated
with production from the lease. We believe that if Phillips, as drafter of the
farmout agreement, intended Subparagraphs IV (d) (4) and (5) to be so
controlling, no reference to production would have been necessary in the
farmout.
The current litigation between Phillips and us involves three issues
related to the interpretation of Paragraph IV and its subparagraphs -- the TETCO
issue, the Overriding Royalty issue, and the Pipeline Tariff issue detailed
below.
TETCO -- We entered into a gas purchase agreement with TETCO in 1982
dedicating our gas from South Pass 89 to TETCO for specified prices. In
1989, TETCO sued us claiming the contract was terminated. In November of
1990, we settled with TETCO and received $69.6 million to "settle all
28
31
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
causes of action, claims and controversies between them pertaining to the
Litigation." Furthermore, we agreed to a new contract price for gas sold to
TETCO in exchange for its agreement to drop its legal challenges to the gas
contract. TETCO also paid us an additional $5.4 million (over and above the
$69.6 million) for past production which we credited to the net profits
account. This payment has not been subject to any litigation. In May of
1991, we allocated $5.8 million of the $69.6 million as production to the
net profits account. Phillips claims the remaining $63.8 million should
have been credited to the net profits account. After a three week trial in
1997, the Louisiana trial court ruled that we should have credited $41.2
million to the net profits account as proceeds from production and thus
owed an additional $9.3 million plus interest to Phillips. As part of its
ruling, the trial court supported our claim that Phillips could only look
to actual production for its net profits interest and that the remaining
$28.4 million of the TETCO payment was for settlement of Remington's
counterclaims against TETCO. Phillips appealed this ruling and on December
15, 2000, the Court of Appeal upheld the trial court's opinion.
Overriding Royalty -- Phillips claimed that in months when no net
profits are achieved, its net profits interest should revert to an
overriding royalty. We claimed that once net profits are achieved,
Phillips' net profits interest does not revert to an overriding royalty
until cumulative net profits are depleted. The trial court ruled in
Phillips favor and awarded Phillips $1.6 million plus interest. We appealed
this issue, but the appellate court upheld the trial court's ruling. We
will not appeal the issue further.
Pipeline Tariff -- The farmout agreement allows transportation costs
to be charged to the net profits account. Initially, Marathon constructed
and operated the oil pipeline from the South Pass complex to Venice,
Louisiana, and charged us a tariff of $2.75 per barrel for transportation.
This tariff was charged to the net profits account with no complaint from
Phillips from inception of production in 1982 until 1989. In 1985, CKB
Petroleum, Inc. purchased an interest in the pipeline and entered into a
20-year transportation agreement with us to transport all of our oil for
$2.75 per barrel. Before CKB Petroleum purchased its interest, Phillips was
given the right to purchase the interest under a preferential right clause
of the pipeline operating agreement, but declined to do so. Phillips claims
that we should charge only a lesser amount which Phillips claims was our
"actual cost" of transportation not what we paid to CKB Petroleum, Inc..
Phillips has tried to claim that we somehow profited from charging the net
profits account with the tariff amount that we paid to CKB Petroleum. Such
a charge was clearly permitted by the farmout agreement. The trial court
dismissed this claim. On December 15, 2000, the Court of Appeal upheld the
trial court's opinion on this issue. The $2.75 per barrel tariff has been
the market rate for the pipeline for us and our partners from inception
through the trial date.
The total judgment awarded by the trial court in 1998 including interest
was $18.0 million. We recorded an $18.0 million charge to income in the third
quarter of 1998 and continue to accrue interest on this liability each quarter.
The present total liability is $19.7 million. Currently, we have $9.0 million in
restricted cash set aside for this litigation.
Phillips has filed an application for a supervisory writ with the Louisiana
Supreme Court to which we have filed a response. In the application Phillips has
presented no new facts and no new issues of policy, law or equity. The Supreme
Court may refuse to hear the case. If the Supreme Court grants the application
it will, in all probability, be several months before the case is briefed and
heard by the Supreme Court on the merits and possibly several more months before
a decision rendered. After the Supreme Court issues a final ruling on the case,
or refuses to hear the case, it is likely, depending on the ruling, that various
elements will be remanded to the trial court to resolve certain technical issues
in accordance with the court rulings. It may take several months to resolve
these issues in the trial court. When the litigation is concluded and the amount
of our liability is finally determined, we intend to use a combination of cash,
debt financing, and/or property sales to fulfill the amount of any judgment. We
believe that there will be sufficient time from final determination by
29
32
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the appellate court of last resort and a final determination by the trial court
on remand to allow us to make provision for any required payment. Final
resolution of this matter through the courts may take up to several years.
In August of 1998, we terminated the TETCO gas contract and received $49.8
million. Phillips has claimed that this full $49.8 million payment should be
credited to the net profits account. Litigation on this issue was initiated in
Collin County, Texas, and subsequently stayed pending the resolution of all the
appeals in Phillips' Louisiana suit. Based on the trial court and appellate
court opinions stating that Phillips can look only to production for its net
profits interest, we anticipate that this case will be dismissed or resolved
through summary proceedings. Total liability for this claim would be $16.4
million plus statutory interest until the date of settlement. The trial and any
appeals regarding this issue, if necessary, could take an additional two years
to resolve once the current Louisiana litigation is concluded.
NOTE 13 -- EMPLOYEE AND DIRECTOR BENEFIT PLANS
Stock option plans
A committee that includes at least two or more outside non-employee
directors administers the 1997 Stock Option Plan. The committee has the
discretion to determine the participants, the number of shares granted to each
person, the purchase price of the common stock covered by each option, and most
other terms of the option. Options granted under the plan may be either
incentive stock options or non-qualified stock options. The committee may issue
options for up to 2.8 million shares of common stock, but no more than 687,500
shares to any individual. Forfeited options are available for future issuance.
We continue to apply the accounting provisions of Accounting Principles
Board Opinion 25, entitled "Accounting for Stock Issued to Employees," and
related interpretations to account for stock-based compensation. Accordingly,
compensation cost for stock options is measured 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. A summary of our stock option plans as
of December 31, 2000, 1999, and 1998, and changes during the years ending on
those dates is presented below:
AT DECEMBER 31,
------------------------------------------------------------------
2000 1999 1998
-------------------- -------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
--------- -------- --------- -------- --------- --------
Outstanding at beginning of
year......................... 1,761,000 $6.12 1,175,500 $6.15 455,000 $6.92
Granted........................ 979,000 $3.89 614,000 $6.22 751,000 $5.72
Exercised...................... (33,497) $3.66 -- --
Forfeited...................... (125,000) $6.87 (28,500) $9.63 (30,500) $6.80
--------- ----- --------- ----- --------- -----
Outstanding at end of year..... 2,581,503 $5.28 1,761,000 $6.12 1,175,500 $6.15
========= ===== ========= ===== ========= =====
Options exercisable at
year-end..................... 1,097,860 $6.72 653,682 $6.78 257,921 $7.07
Weighted-average fair value of
options granted during the
year......................... $2.92 $2.88 $3.32
The options outstanding at December 31, 2000 have a weighted-average
remaining contractual life of 9 years and an exercise price ranging from $2.75
to $11.00 per share.
30
33
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The table below reflects the effect on our net income or loss if we
recorded the estimated compensation costs for the stock options using the
estimated fair value as determined by applying the Black-Scholes option pricing
model.
FOR YEARS ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------
(IN THOUSANDS)
Net income (loss).................................. As reported $45,044 $(3,703) $13,617
Pro forma $43,866 $(4,719) $12,591
Basic income (loss) per share...................... As reported $ 2.10 $ (0.17) $ 0.67
Pro forma $ 2.05 $ (0.22) $ 0.62
Diluted income (loss) per share.................... As reported $ 1.99 $ (0.17) $ 0.66
Pro forma $ 1.94 $ (0.22) $ 0.61
The fair value of each option grant for the years ended December 31, 2000,
1999, and 1998 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,
---------------------
2000 1999 1998
----- ----- -----
Expected life (years)....................................... 10 10 10
Interest rate............................................... 6.18% 5.88% 5.50%
Volatility.................................................. 59.01% 56.74% 51.17%
Dividend yield.............................................. 0 0 0
Non-Employee Director Stock Purchase Plan
The stockholders approved the non-employee director stock purchase plan in
December 1997. The plan allows the non-employee directors to receive their
directors' fees in shares of restricted common stock instead of cash. The number
of shares received will be equal to 150% of the cash fees divided by the closing
market price of the common stock on the day that the cash fees would otherwise
be paid. The director cannot transfer the common stock until one year after
issuance or the termination of a director resulting from death, disability,
removal, or failure to be nominated for an additional term. The director can
vote the shares of restricted stock and receive any dividend paid in cash or
other property.
31
34
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pension Plan
Remington and CKB Petroleum each have a noncontributory defined benefit
pension plan. The retirement benefits available are generally based on years of
service and average earnings. We fund the plans with annual contributions at
least equal to the minimum funding provisions of the Employee Retirement Income
Security Act of 1974, as amended, but no more than the maximum tax deductible
contribution 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,
---------------
2000 1999
------ ------
Reconciliation of the change in benefit obligation
Beginning benefit obligation.............................. $2,850 $3,331
Service cost........................................... 119 101
Interest cost.......................................... 226 217
Effect of settlement................................... -- (335)
Actuarial loss (gain).................................. 156 (286)
Benefits paid.......................................... (248) (178)
------ ------
Ending benefit obligation................................. $3,103 $2,850
====== ======
Reconciliation of the change in plan assets
Beginning market value.................................... $3,501 $3,389
Actual return on plan assets........................... (163) 625
Employer contributions................................. -- --
Benefit payments....................................... (248) (513)
------ ------
Ending market value....................................... $3,090 $3,501
====== ======
Funded Status and amounts recognized in the balance sheet
Funded status............................................. $ (13) $ 651
Unrecognized net actuarial loss (gain).................... 233 (394)
Effect of the settlement.................................. -- 32
------ ------
Adjusted prepaid (accrued) benefit cost................... $ 220 $ 289
====== ======
32
35
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The net periodic pension cost recognized in our income statements include
the following components:
FOR YEARS ENDED
DECEMBER 31,
---------------------
2000 1999 1998
----- ----- -----
(IN THOUSANDS)
Components of net periodic pension cost
Service cost.............................................. $ 119 $ 101 $ 79
Interest cost on projected benefit obligation............. 226 217 201
Expected return on plan assets............................ (273) (264) (259)
Net amortization and deferrals............................ (2) -- --
----- ----- -----
Net periodic pension cost................................. 70 54 21
Special recognition due to curtailment and lump sum
settlements............................................ -- (32) --
----- ----- -----
Net periodic pension cost................................... $ 70 $ 22 $ 21
===== ===== =====
Weighted average assumptions
Discount rate............................................. 7.50% 7.75% 7.00%
Expected return on plan assets............................ 8.00% 8.00% 8.00%
Rate of compensation increase............................. 3.00% 3.00% 3.00%
Contingent Stock Grant
In June 1999, the Board of Directors approved a contingent stock grant to
our employees and directors. If our common stock's closing price closed at or
above $10.42 per share for twenty consecutive trading days prior to the
expiration of the five-year period beginning June 17, 1999, each grant of stock
would become effective. The number of shares granted each employee and director
is relative to the employee's salary (or base number in the case of directors)
and the closing stock price on June 17, 1999.
The grant became effective on January 24, 2001, when our stock price closed
above the trigger price of $10.42 per share for the twentieth consecutive
trading day. As a result of the stock grant becoming effective, we will
recognize non-cash compensation expense totaling $8.1 million. In the first
quarter of 2001, we will recognize a "catch-up" expense of $2.4 million. The
remaining $5.7 million will be amortized quarterly over the next five years as
the shares vest to the employees and directors.
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.
33
36
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 14 -- INCOME TAXES
Income tax expense or benefit includes both the current income taxes and
deferred income taxes. Current income tax expense or benefit equals the amount
calculated on our income tax return for that year. Deferred income tax expense
or benefit equals the change in the net deferred income tax asset or liability
from the beginning of the year to the end of the year. The following table
provides a summary of our income tax expense or (benefit):
FOR YEARS ENDED
DECEMBER 31,
-------------------
2000 1999 1998
---- ----- ----
(IN THOUSANDS)
Current income tax expense (benefit)........................ $100 $(256) $433
Deferred income tax expense (benefit)....................... -- (17) 323
---- ----- ----
Total income tax expense (benefit)................ $100 $(273) $756
==== ===== ====
Total income tax expense (benefit) differs from the amount computed by
applying the federal income tax rate to net income (loss) before income taxes as
follows:
FOR YEARS ENDED DECEMBER 31,
----------------------------
2000 1999 1998
-------- ------- -------
(IN THOUSANDS)
Federal income tax expense (benefit) at statutory
rate................................................. $ 15,799 $(1,402) $ 5,031
Net adjustment to valuation allowance.................. (15,799) 1,402 (4,708)
Other.................................................. 100 (17) --
-------- ------- -------
Total income tax expense (benefit)........... $ 100 $ (273) $ 756
======== ======= =======
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. The following table reflects the significant components of our deferred
tax asset.
AT DECEMBER 31,
-------------------
2000 1999
-------- --------
(IN THOUSANDS)
Asset (liability) from difference in book and tax basis of
oil and gas properties.................................... $(12,181) $ (1,873)
Asset (liability) from difference in book and tax basis of
other assets.............................................. (939) (337)
Asset from difference in book and tax basis of accrued
liabilities............................................... 5,723 6,334
Federal income tax operating loss carry-forward............. 7,483 11,654
Federal capital loss carry-forwards......................... -- 327
Alternative minimum tax credit carry-forward................ 489 389
-------- --------
Total deferred tax asset.......................... 575 16,494
Valuation allowance......................................... (575) (16,494)
-------- --------
Net deferred tax asset............................ $ -- $ --
======== ========
The unused federal income tax operating loss carry-forward of $21 million
will expire during the years 2007 through 2020 if not utilized sooner.
34
37
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 15 -- 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 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,
------------------------------
2000 1999 1998
-------- -------- --------
(IN THOUSANDS, EXCEPT
PER SHARE AMOUNTS)
Net income (loss) available for basic income per share... $45,044 $(3,703) $13,617
Interest expense on the 8 1/4% Convertible Subordinated
Notes (net of tax)(2)............................... 318 -- 2,058
------- ------- -------
Net income (loss) available for diluted income per
share.................................................. $45,362 $(3,703) $15,675
======= ======= =======
Basic income (loss) per share............................ $ 2.10 $ (0.17) $ 0.67
======= ======= =======
Diluted income (loss) per share.......................... $ 1.99 $ (0.17) $ 0.66
======= ======= =======
Weighted average common shares for basic income (loss)
per share.............................................. 21,435 21,326 20,370
Dilutive stock options outstanding (treasury stock
method)(1).......................................... 784 -- --
Shares assumed issued by conversion of the 8 1/4%
Convertible Subordinated Notes(2)................... 540 -- 3,488
------- ------- -------
Total common shares for diluted income (loss) per
share.................................................. 22,759 21,326 23,858
======= ======= =======
Potential increase to net income for diluted income per
share
Interest expense on 8 1/4% Convertible Subordinated
Notes (net of tax).................................. $ -- $ 581 $ --
Potential issues of common stock for diluted income per
share
Weighted average stock options granted................. -- 1,677 875
Weighted average shares from warrant issued in
merger.............................................. 200 200 2
Weighted average shares issued assuming conversion of
8 1/4% Convertible Subordinated Notes............... -- 985 --
- ---------------
(1) Non dilutive in 1999 and 1998.
(2) Non dilutive in 1999
NOTE 16 -- OTHER RELATED PARTY 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 arm's length transaction.
Prior to our acquisition of S-Sixteen Holding Company in December 1998, we
paid CKB Petroleum, Inc., a subsidiary of S-Sixteen Holding Company,
transportation costs totaling $3.0 million in 1998. In addition, we received
$527,000 in interest income in 1998 from S-Sixteen Holding Company on a note
receivable. The note receivable was effectively canceled when we acquired
S-Sixteen Holding Company. The
35
38
REMINGTON OIL AND GAS CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
December 31, 1999 accounts receivable -- other includes $210,000 on a claim
against the Estate of Cloyce K. Box. Don D. Box, an officer and director of the
company, is co-executor of the Estate. In early 2000, we collected $240,000 in
full settlement of this claim.
NOTE 17 -- QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
FOR YEARS ENDING
DECEMBER 31,
---------------------
2000 1999
--------- ---------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
First Quarter
Net sales................................................. $15,868 $ 6,389
Gross profit.............................................. $ 8,785 $(4,797)
Net income................................................ $ 3,784 $(6,676)
Basic net income per share................................ $ 0.18 $ (0.31)
Diluted net income per share.............................. $ 0.18 $ (0.31)
Second Quarter
Net sales................................................. $18,823 $ 9,232
Gross profit.............................................. $ 9,462 $ 761
Net income................................................ $ 7,758 $(1,073)
Basic net income per share................................ $ 0.36 $ (0.05)
Diluted net income per share.............................. $ 0.35 $ (0.05)
Third Quarter
Net sales................................................. $22,012 $12,221
Gross profit.............................................. $13,847 $ 2,891
Net income................................................ $22,704 $ 1,373
Basic net income per share................................ $ 1.06 $ 0.06
Diluted net income per share.............................. $ 0.98 $ 0.06
Fourth Quarter
Net sales................................................. $27,693 $14,502
Gross profit.............................................. $13,099 $ 5,301
Net income................................................ $10,798 $ 2,673
Basic net income per share................................ $ 0.50 $ 0.13
Diluted net income per share.............................. $ 0.47 $ 0.13
- ---------------
(1) Net sales include only oil and gas sales revenue.
(2) Gross profit is net sales less operating costs, transportation expense, net
profits expense, exploration expense, depreciation, depletion and
amortization, and impairment of oil and gas properties.
(3) Net income during the third quarter of 2000 includes a $12.5 million gain on
sale of certain South Texas properties.
36
39
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The following information relates to the members of our board of directors
or executive officers during 2000. 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: 50
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
- - Director, Corporate Development March 1994-January 1995
Positions with our affiliates:
- - CKB Petroleum, Inc.
-- Vice President since September 1997
-- Director August 1982-September 1997
-- President August 1982-September 1997
- - CKB & Associates, Inc.
-- Vice President since May 1981
-- Director May 1981-September 1997
- - S-Sixteen Holding Company
-- Director December 1981-September 1997
-- President December 1981-February 1996, April 1997-September 1997
-- Vice President February 1996-April 1997, September 1997-December 1998
Outside directorships
- - Authoriszer, Inc.
Education
- - Bachelor of Arts-University of Pennsylvania
- - Bachelor of Science in Economics-The Wharton School of the University of
Pennsylvania
- - Masters of Business Administration-Southern Methodist University
JOHN E. GOBLE, JR., CPA Age:
54
Positions with us:
- - Director since April 1997
- - Member-Audit Committee
Employment:
- - Byrd Investments-Investment and financial advisor since 1986
Outside Directorships:
- - Miracle of Pentecost Foundation
Education:
- - Bachelor of Business Administration-Southern Methodist University
37
40
WILLIAM E. GREENWOOD Age: 62
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:
- - AmeriTruck Distribution Corporation
- - Mark VII, Inc.
- - Transport Dynamics, Inc.
- - President-Mendota Museum and Historical Society
Education:
- - Bachelor of Science-Marquette University
DAVID H. HAWK Age: 56
Positions with us:
- - Director since September 1997
- - Chairman of the Board since October 1997
- - Member-Executive Committee
Employment:
- - J.R. Simplot Company-Director, Energy Natural Resources since 1984
- - Previously employed with Atlantic Richfield Company and Tenneco Inc. as an
Exploration Geologist
- - Prior executive positions with IGC Production Company, Sundance Oil Company
and Horn Resources Corporation
Education:
- - Bachelor of Science in Geology and Distinguished Graduate Medalist-University
of Idaho
- - Master of Science in Geology-University of Oklahoma
JAMES ARTHUR LYLE, CCIM Age:
55
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
38
41
DAVID E. PRENG Age: 54
Position with us:
- - Director since April 1997
- - Chairman-Compensation Committee
Employment:
- - Chief Executive Officer and President since 1980-Preng and Associates, Inc.,
an international executive search firm specializing in the energy industry
Outside directorships:
- - Director-British American Business Council
- - Fellow-Institute of Directors
Education:
- - Bachelor of Science in Business Administration-Marquette University
- - Master of Business Administration-DePaul University
THOMAS W. ROLLINS Age: 70
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 President and Chief Executive Officer-Park Avenue Exploration
Corporation, an oil and gas exploration firm and a subsidiary of USF&G
Corporation
- - 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-Enron Cash Company #2
- - 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: 55
Positions with us:
- - Director since May 1994
- - Chairman-Audit Committee
Employment:
- - The Ivadelle and Theodore Johnson Professor of Banking and Finance in the
Department of Finance and Business Economics, Marshall School of Business,
University of Southern California, since 1992
- - Previously Chairman of the Department of Finance and Business Economics,
University of Southern California, 1993-1998
- - Frequent consultant and expert witness to business and government
Publications:
- - Multinational Financial Management, a best selling textbook used in MBA
programs worldwide
- - Numerous other books and articles
39
42
Education:
- - Bachelor of Arts in Mathematics-Rice University
- - Ph.D. in Economics-Carnegie Mellon University
JAMES A. WATT Age: 51
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
Education:
- - Bachelor of Science in Physics-Rensselaer Polytechnic Institute
ROBERT P. MURPHY Age: 42
Positions with us:
- - Chief Operating Officer since October 2000
- - Senior Vice President/Exploration & Production since July 1999
- - Vice President/Exploration, January 1998-June 1999
Previous employment:
- - Director-Cairn Energy USA, Inc., May 1996-November 1997
- - Vice President-Exploration-Cairn Energy USA, March 1993-January 1998
- - Exploration Geologist-Cairn Energy USA, 1990-March 1993
- - Exploration Geologist-Enserch Exploration, 1984-1990
Education:
- - Bachelor of Science in Geology-The University of Texas at Austin
- - Master of Science in Geosciences-The University of Texas at Dallas
STEVEN J. CRAIG Age: 49
Positions with us:
- - Senior Vice President/Planning and Administration since April 1997
- - Administrative Assistant to the Chairman, August 1996 to April 1997
- - Vice President, February 1994-March 1995
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
-- Assistant Treasurer and Controller, March 1996-March 1997
40
43
- - CKB & Associates, Inc.
-- Director and Vice President since January 1999
-- Vice President and Assistant Treasurer, March 1997-October 1997
-- Director, March 1997-August 1997
-- Assistant Treasurer and Controller, March 1996-March 1997
- - S-Sixteen Holding Company
-- Vice President and Assistant Treasurer, March 1997-October 1997
-- Director, March 1997-August 1997
-- Chief Financial Officer and Assistant Treasurer, May 1996-March 1997
Previous Employment:
- - Self Employed-Real Estate and Consulting, 1992-1994, March 1995-March 1996
Education:
- - Bachelor of Arts in Economics-Southern Methodist University
- - Master of Business Administration-Southern Methodist University
J. BURKE ASHER Age: 60
Positions with us:
- - Vice President/Finance since December 1997
- - Secretary since October 1996
- - Chief Accounting Officer, September 1996-December 1997
Positions with our affiliates:
- - CKB Petroleum
-- Treasurer and Assistant Secretary since March 1997
-- Director, March 1997-April 1997
- - CKB & Associates
-- Treasurer and Assistant Secretary since March 1997
-- Director, March 1997-August 1997
- - S-Sixteen Holding Company
-- Treasurer and Assistant Secretary, March 1997-December 1998
-- Director, March 1997-August 1997
Previous employment:
- - Self employed financial consultant and advisor, 1987-1996
- - Controller-Doty-Moore Tower Services, Inc., a contractor to the communications
industry, 1993-1995
Education:
- - Bachelor of Science in Economics-The Wharton School of the University of
Pennsylvania
EDWARD V. HOWARD, CPA Age: 38
Positions with us:
- - Vice President/Controller since March 1992
- - Senior Accountant, October 1989-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 present litigation involving the directors or executive
officers.
41
44
Section 16(a) Beneficial Ownership Reporting Compliance
Based solely upon the company's review of Forms 3, 4, and 5 received by the
company, all persons required by Section 16(a) of the Securities Exchange Act of
1934 ("the Act") to file such forms complied with Section 16(a) of the Act with
the following exception: In March 2001 David H. Hawk filed one late Form 4
reporting one transaction.
ITEM 11. EXECUTIVE COMPENSATION.
The following table summarizes the compensation paid by the company during
2000, 1999, and 1998 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 2000 exceeded $100,000.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION
-------------------------------- --------------------------------------
SECURITIES
OTHER RESTRICTED UNDERLYING
ANNUAL STOCK OPTIONS/ ALL OTHER
NAME AND FISCAL SALARY BONUS COMPENSATION AWARDS SAR'S COMPENSATION
PRINCIPAL POSITION YEAR ($) ($) ($)(1) ($) (#) ($)
- ------------------ ------ ------- ------- ------------ ---------- ---------- ------------
James A. Watt............... 2000 282,501 296,000 -- (2) 123,000 1,242(3)
Chief Executive 1999 260,004 156,000 -- -- 80,000 695(3)
Officer and President 1998 250,006 70,000 -- -- 130,000 174(3)
Robert P. Murphy............ 2000 187,506 140,000 -- -- 66,000 390(3)
Chief Operating Officer 1999 168,108 52,500 -- -- 45,000 257(3)
and Senior Vice President/ 1998 146,260 30,000 -- -- 80,000 62(3)
Exploration and Production
Steven J. Craig............. 2000 121,008 29,000 -- -- 39,000 346(3)
Senior Vice President/ 1999 114,708 27,500 -- -- 25,000 390(3)
Planning and
Administration 1998 110,259 20,000 -- -- 40,000 174(3)
J. Burke Asher.............. 2000 115,008 27,600 -- -- 37,000 928(3)
Vice President/Finance 1999 109,200 26,200 -- -- 25,000 1,008(3)
and Secretary 1998 105,000 19,000 -- -- 35,000 450(3)
Edward V. Howard............ 2000 93,504 22,400 -- -- 29,000 148(3)
Vice President/Controller 1999 88,200 14,600 -- -- 27,500 143(3)
and Assistant Secretary 1998 84,000 12,500 -- -- 27,500 64(3)
- ---------------
(1) No amount is included, as it is less than 10% of the total salary and bonus
of the individual for the year.
(2) At December 31, 2000, Mr. Watt held 6,000 restricted shares of common stock
with a value of $78,000. The total number of restricted shares awarded
effective March 17, 1997, was 15,000, which vest 20% per year from the
effective date. If any dividends are paid to holders of common stock, Mr.
Watt's restricted shares will be entitled to receive dividends.
(3) These amounts are for group term life insurance premiums paid by the
company.
See "Change in Control Arrangements and Employment Contracts" below.
42
45
LONG TERM STOCK BASED INCENTIVE PROGRAMS
STOCK OPTIONS
We have stock option plans for our employees and directors because we
believe these options act as both an incentive and a reward for the long-term
growth of our company. The core of our stock option program is the 1997 stock
option plan. Both directors and employees are eligible for options under this
plan. Significant attributes of the 1997 plan include the following:
- Administered by the Compensation Committee of our board of directors.
- Up to 2,750,000 shares of our common stock may be issued under the plan.
- Up to 687,500 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 VALUE
NAME GRANTED FISCAL YEAR $/SHARE DATE $(1)
- ---- ---------- ------------- -------- ---------- -------------
James A. Watt............................. 123,000 12.69% 3.75 3/27/10 345,630
Robert P. Murphy.......................... 66,000 6.81% 3.75 3/27/10 185,460
Steven J. Craig........................... 39,000 4.02% 3.75 3/27/10 109,590
J. Burke Asher............................ 37,000 3.82% 3.75 3/27/10 103,970
Edward V. Howard.......................... 29,000 2.99% 3.75 3/27/10 81,490
- ---------------
(1) We determined these values using the Black-Scholes option pricing model with
the following assumptions: stock price volatility of 59.12%; interest rate
based on the yield to maturity of a 10-year Treasury security; exercise in
the tenth year; and a dividend rate of zero. We made no adjustments for
nontransferability or risk of forfeiture. Our use of this model does not
constitute an endorsement or an acknowledgment that such model can
accurately determine the value of options. No assurance can be given that
the actual value, if any, realized by an executive upon the exercise of
these options will approximate the estimated values calculated by using the
Black-Scholes model.
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46
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION
VALUES
NUMBER OF SECURITIES VALUE OF UNEXERCISED
UNDERLYING UNEXERCISED IN-THE-MONEY OPTIONS AT
NUMBER OF VALUE OPTIONS AT FISCAL YEAR-END FISCAL YEAR-END($)(1)
SHARES ACQUIRED REALIZED --------------------------- ---------------------------
NAME ON EXERCISE ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---- --------------- -------- ----------- ------------- ----------- -------------
James A. Watt............... -- -- 173,335 259,665 1,364,180 2,233,563
Robert P. Murphy............ -- -- 68,335 122,665 582,930 1,098,818
Steven J. Craig............. -- -- 55,001 68,999 431,259 621,991
J. Burke Asher.............. 1,000 5,063 50,668 65,332 390,096 621,404
Edward V. Howard............ 4,166 30,985 37,334 57,500 273,485 497,375
- ---------------
(1) Computed as the number of securities multiplied by the difference between
the option exercise prices and the closing price of our common stock on
December 31, 2000.
CONTINGENT STOCK GRANTS
In addition to the stock option program, our employees and directors have
received contingent grants of restricted stock. In 1999, the directors approved
awards of restricted stock to employees and directors totaling 679,937 shares of
our common stock. The number of shares awarded to each employee and director is
based on the employee's annual base salary as of June 17, 1999, or, in the case
of non-employee directors, $100,000, divided by $4.19, which was the closing
stock price on June 17, 1999. In order for the grant to be effective, 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. The required increase in the stock price represented the equivalent of a
compounded annual rate of return of 20% for five years. 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. 274,037 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. 388,555
shares are subject to the second vesting schedule. While 679,937 shares of
restricted stock were granted in 1999, as of March 12, 2001, 662,592 shares are
subject to the grant because a director voluntarily surrendered 23,880 shares,
and a new employee was granted 6,535 shares. The number of shares subject to the
grant may decrease to the degree that participants fail to remain with us during
the vesting period. In the event of a participant's death while employed or
serving as a director with us, or reaching the retirement age of 65 or receiving
long term disability benefits while employed with us, the grant becomes 100%
vested. In addition, the grants can become 100% vested upon a change of control.
PENSION PLANS
Our defined benefit pension plans provide retirement and other benefits to
eligible employees upon reaching the "normal retirement age," which is age 65 or
after five years of service, 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 five years of service, no benefits
are payable. If an employee terminates employment after five years of service,
the employee is entitled
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to all accrued benefits. The following table illustrates the annual pension for
plan participants that retire at "normal retirement age" in 2000:
PENSION PLAN TABLE
YEARS OF SERVICE(1)(3)(4)
AVERAGE ------------------------------------------
COMPENSATION(1)(2) 15 20 25 30 35
------------------ ------ ------ ------ ------ ------
($) ($) ($) ($) ($) ($)
125,000..... 52,486 55,398 58,310 61,222 64,134
150,000..... 63,674 67,398 71,123 74,847 78,572
170,000..... 72,624 76,998 81,373 85,747 90,122
175,000..... 72,624 76,998 81,373 85,747 90,122
200,000..... 72,624 76,998 81,373 85,747 90,122
225,000..... 72,624 76,998 81,373 85,747 90,122
250,000..... 72,624 76,998 81,373 85,747 90,122
300,000..... 72,624 76,998 81,373 85,747 90,122
400,000..... 72,624 76,998 81,373 85,747 90,122
450,000..... 72,624 76,998 81,373 85,747 90,122
500,000..... 72,624 76,998 81,373 85,747 90,122
- ---------------
(1) As of December 31, 2000, the Internal Revenue Code does not allow qualified
plan compensation to exceed $170,000 or the benefit payable annually to
exceed $135,000. 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 compensation paid in a fiscal year (the
total of Salary, Bonus and Other Annual Compensation in the Summary
Compensation Table) except amounts attributable to group term life insurance
premiums paid by the Company. 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, 2000, for the executive
officers shown in the Summary Compensation Table on page 42 is as follows:
James A. Watt (4 years), Robert P. Murphy (3 years), Steven J. Craig (6
years), J. Burke Asher (4 years), and Edward V. Howard (11 years).
(4) The normal form of payment is a life annuity for a single participant or a
50% joint and survivor annuity for a married participant. Such benefits are
not subject to a deduction for Social Security or other offset amounts.
COMPENSATION OF DIRECTORS
- Only non-employee directors are compensated for board service
- Compensation includes:
-- Annual retainer of $20,000
-- $1,000 per board meeting attended
-- Unless surrendered, eligible for contingent stock grant (see discussion
of grants on page 44.)
-- Committee meeting fee of $750 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
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48
- Five board meetings in 2000
- All directors attended at least 75% of the meetings
- During 2000, we paid Rollins Resources, a proprietorship owner by
director Thomas W. Rollins, $1,500 for consulting fees.
NON-EMPLOYEE DIRECTOR STOCK PURCHASE PLAN
- Adopted December 4, 1997
- Each non-employee director may, once a year, elect to receive all or part
of his board compensation in our common stock
- The number of shares received equals 150% of the cash amount of
compensation divided by the closing market price of our common stock on
the day the cash fees would be payable
- Shares received under this plan may not be transferred for one year after
issuance
- Shares may be transferred earlier than one year based on a director's
death, disability or departure from the board
- During the restricted transfer period, the director may vote the stock
and receive any dividends
- The board may terminate this plan at any time
- Shares received under plan for 2000:
- John E. Goble, Jr. ................... 2,451 shares in lieu of $12,000 cash
- William E. Greenwood.................. 5,692 shares in lieu of $27,750 cash
- James Arthur Lyle..................... 5,229 shares in lieu of $25,500 cash
- David E. Preng........................ 5,229 shares in lieu of $25,500 cash
- Alan C. Shapiro....................... 5,337 shares in lieu of $26,250 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 restricted stock grants. If the
vesting of the contingent restricted stock grants were accelerated by a change
in control, it would result in the issuance of a maximum aggregate of 662,592
shares to directors and employees.
Employment Agreements
We have employment agreements with James A. Watt, Robert P. Murphy, Steven
J. Craig, and J. Burke Asher. The most significant terms of such agreements are
summarized below:
James A. Watt
- Term of three years from January 31, 2000, subject to single year
extensions by mutual agreement
- Base salary of $270,000 a year subject to discretionary increases
- Eligible to receive discretionary performance bonus (targeted at 70%
of base salary, as amended)
- If terminated prior to a change in control, without cause, he receives
his salary plus a pro rata bonus
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49
- 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, as amended)
- If terminated prior to a change in control, without cause, he receives
his salary plus a pro rata bonus
- He receives 2.99 times the sum of his base salary plus his target
bonus if he is terminated within twelve months of a change in control,
other than for death, disability or cause, or he leaves for good
reason within the twelve month period
Steven J. Craig and J. Burke Asher
- Term of two years from September 30, 1999, subject to single year
extensions by mutual agreement
- Base salary of $114,200 (Mr. Craig) and $109,200 (Mr. Asher) subject
to discretionary increases
- Eligible to receive discretionary performance bonus (targeted at 20%
of base salary)
- Severance payments similar to Robert Murphy's, except that Mr. Craig
and Mr. Asher receive 2 times the sum of their 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
No executive officer serves on the compensation committee of the board. The
company paid $234,000 to Preng & Associates, Inc., which is majority-owned by
David E. Preng, chairman of compensation committee, for executive search
services provided to the company from July 1996 through the end of 1998,
including $40,000 in 1998. The level of fees received by Preng & Associates
usually depends, at least in part, on the initial level of compensation we offer
to the candidate successfully recruited by us through Preng & Associates.
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50
BOARD COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
We believe that employing and retaining highly qualified and high
performing executive officers is vital to our achievement of long-term business
goals. To this end, the Compensation Committee of the board of directors (the
"Committee") developed an executive compensation program which is designed to
attract and retain such officers.
The philosophy is to develop a systematic, competitive executive
compensation program which recognizes an executive officer's position and
responsibilities, takes into account competitive compensation levels payable
within the industry by similarly sized companies, and reflects both individual
and company performance.
The executive compensation program developed by the Committee is composed
of the following three elements: (i) a base salary, (ii) a performance-based
annual cash incentive (short-term), and (iii) a stock-based incentive
(long-term). Under this program, short-term and long-term incentives are "at
risk" and are based on performance of the company versus defined goals.
The Committee compiles data reflecting the compensation practices of a
broad range of organizations in the oil and gas industry that are similar to us
in size and performance. For both the base salary and annual cash incentives
portions of executive compensation discussed below, the Committee adopted a
philosophy of paying the executive officers at a level that is competitive and
within the ranges reflected by the data compiled.
BASE SALARIES
Base salary is the portion of an executive officer's total compensation
package which is payable for performing the specific duties and assuming the
specific responsibilities defining the executive's position with the company.
The Committee's objective is to provide each executive officer a base salary
that is competitive at the desired level.
ANNUAL CASH INCENTIVES
The Committee developed a performance-based annual cash incentive plan
covering the executive officers and top managers. The objectives in designing
the plan are to reward participants for accomplishing objectives which are
generally measurable and increase shareholder value. Under the annual cash
incentive plan, the Committee has established a "target" cash incentive award
for each executive officer (including the Chief Executive Officer) that is
payable based mostly upon the company's achieving certain performance targets
and, to a lesser extent, for achieving highly challenging individual performance
objectives. The performance targets are increasing reserves and production;
controlling finding, development, and production costs; and achieving an overall
return on capital; all of which are competitive with a peer group of oil and gas
companies. The committee also determined that award levels under the plan should
be fiscally prudent.
LONG-TERM STOCK-BASED INCENTIVES
We maintain a stock option plan for officers and other employees. The
philosophy is to award stock options to selected plan participants based on
their levels within the company and upon individual merit. The plan is to grant
stock options which are competitive within the industry for other individuals at
the employee's level and which provide the employee a meaningful incentive to
remain with the company, to increase performance, and to focus on achieving
long-term increases in shareholder value. Other factors the Committee considers
in granting stock options include the employee's contributions toward achieving
the company's long-term objectives, such as reserve replacements and
acquisitions, as well as the employee's contributions in achieving the company's
short-term and long-term profitability targets.
COMPENSATION COMMITTEE
David E. Preng
William E. Greenwood
James Arthur Lyle
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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 comprised of 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, 1995, and that all dividends were reinvested.
[PERFORMANCE CHART]
- --------------------------------------------------------------------------------------------------
12/31/1995 12/31/1996 12/31/1997 12/31/1998 12/31/1999 12/31/2000
- --------------------------------------------------------------------------------------------------
ROILA(1) 100.00 85.06 48.28 33.71 40.98 137.47
ROILB(1) 100.00 105.80 60.14 36.96 44.93 150.72
NASDAQ U.S. 100.00 123.00 150.70 212.50 394.90 237.70
NASDAQ O&G 100.00 144.50 137.70 66.90 69.20 143.30
The last day of trading for ROILA and ROILB was December 24, 1998.
Effective at the opening of trading on December 28, 1998, both former classes of
stock were replaced by a new single class of voting common stock (ROIL). The
values shown above as of December 31, 1998, 1999, and 2000 for ROILA give effect
to the 1.15:1 exchange ratio that the former holders of ROILA received in the
exchange for the new class of common stock, and the 1:1 exchange ratio that the
former holders of ROILB received in the exchange for the new class of common
stock.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
Ownership of Certain Beneficial Owners
As of March 12, 2001, the following person 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
NAME AND ADDRESS OF COMMON STOCK PERCENT OF
BENEFICIAL OWNER BENEFICIALLY OWNED COMMON STOCK
- ------------------- ------------------ ------------
J.R. Simplot.......................................... 5,831,028(1) 27%
999 Main Street
Boise, Idaho 83702(1)
- ---------------
(1) Mr. J.R. Simplot is the trustee and beneficiary of the J.R. Simplot Self
Declaration of Revocable Trust dated December 21, 1989, an inter vivos
revocable trust. The Trust is the sole general partner of S-Sixteen Limited
Partnership, an Idaho limited partnership. Included in shares of common
stock beneficially owned by Mr. Simplot are all of the following, of which
Mr. Simplot may be deemed a beneficial owner: 2,785,028 shares and 200,000
warrants owned by S-Sixteen Limited Partnership; 2,845,000 shares owned by
the Trust; and 1,000 shares owned jointly by Mr. Simplot and his spouse.
200,000 shares of common stock are issuable to S-Sixteen Limited
Partnership upon the exercise of the warrants within 60 days of March 12, 2001.
100,000 warrants are exercisable at $9.00 per share for a period of 36 months
from December 28, 1998; and 100,000 warrants are exercisable at $11.00 per share
for a period of 60 months from December 28, 1998.
Ownership of Management
The number of shares of the company's common stock beneficially owned as of
March 12, 2001, by directors of the company, each officer listed in the
compensation table on page 42, 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.
SHARES OF OPTIONS
COMMON STOCK EXERCISABLE PERCENT OF
BENEFICIALLY WITHIN 60 DAYS OF COMMON
NAME OWNED MARCH 12, 2001 TOTAL STOCK
- ---- ------------ ----------------- --------- ----------
J. Burke Asher............................. 5,201 66,802 72,003 *
Don D. Box................................. 66,083 110,001 176,084 *
Steven J. Craig............................ 15,825 63,400 79,225 *
John E. Goble, Jr. ........................ 11,909 88,334 100,243 *
William E. Greenwood....................... 7,692 88,334 96,026 *
David H. Hawk.............................. 2,430 -- 2,430 *
Edward V. Howard........................... 8,436 48,834 57,270 *
James Arthur Lyle.......................... 22,308 88,334 110,642 *
Robert P. Murphy........................... 7,650 103,667 111,317 *
David E. Preng............................. 42,264 95,001 137,265 *
Thomas W. Rollins.......................... 22,304 88,334 110,638 *
Alan C. Shapiro............................ 32,701 88,334 121,035 *
James A. Watt.............................. 45,345 251,001 296,346 1.4%
All directors and executive officers as a
group (13 persons)....................... 290,148 1,180,376 1,470,524 6.5%
- ---------------
* Less than one percent of the outstanding shares.
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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.
In the merger with S-Sixteen Holding Company we acquired a receivable in
the estimated fair value amount of $210,000 from the Estate of Cloyce K. Box. In
early 2000, we collected $240,000 in full settlement of this claim. Don D. Box
is co-executor of the Estate.
A long-term receivable in the aggregate amount of $344,000 acquired in the
merger reflects CKB Petroleum's claims under Collateral Assignment Split Dollar
Insurance Agreements among CKB Petroleum and Don D. Box and two of his brothers.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a) Documents filed as part of this report:
1. Financial Statements included in Item 8:
(i) Report of Independent Public Accountants
(ii) Consolidated Balance Sheets as of December 31, 2000 and 1999
(iii) Consolidated Statements of Income for years ended December
31, 2000, 1999 and 1998
(iv) Consolidated Statement of Stockholders' Equity for years ended
December 31, 2000, 1999 and 1998
(v) Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 1999 and 1998
(vi) Notes to Consolidated Financial Statements
(vii) Supplemental Oil and Natural Gas Information (Unaudited)
(Included in 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:
On December 21, 2000, we filed a Form 8-K to attach a press release
dated December 19, 2000 announcing that the Louisiana Appellate Court had
vacated its prior opinion.
(c) Exhibits:
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.0++ -- Agreement and Plan of Merger dated as of June 22, 1998,
by and between Remington Oil and Gas Corporation and
S-Sixteen Holding Company.
3.1* -- Certificate of Incorporation, as amended.
3.2### -- Certificate of Amendment of Certificate of Incorporation
of Box Energy Corporation.
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EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.2.1++ -- Certificate of Amendment of Certificate of Incorporation
of Remington Oil and Gas Corporation.
3.3+++ -- By-Laws as amended.
4.1* -- Form of Indenture Box Energy Corporation to United States
Trust Company of New York, Trustee, dated December 1,
1992, 8 1/4% Convertible Subordinated Notes due December
1, 2002.
10.1* -- Farmout Agreement with Aminoil USA, Inc., effective May
1, 1977, dated May 9, 1977.
10.2* -- Transportation Agreement with CKB Petroleum, Inc. dated
March 1, 1985, as amended on April 19, 1989.
10.3* -- Agreement of Compromise and Amendment to Farmout
Agreement, dated July 3, 1989.
10.4** -- Pension Plan of Box Energy Corporation, effective April
16, 1992.
10.5# -- First Amendment to the Pension Plan of Box Energy
Corporation dated December 16, 1993.
10.6## -- Second Amendment to the Pension Plan of Box Energy
Corporation dated December 31, 1994.
10.7*** -- Amended and Restated Promissory Note between Box Energy
Corporation and Box Brothers Holding Company.
10.8*** -- Amended and Restated Pledge Agreement between Box Energy
Corporation and Box Brothers Holding Company.
10.9*** -- Agreement by and between Box Energy Corporation and James
A. Watt.
10.10### -- Box Energy Corporation Severance Plan.
10.11+ -- Box Energy Corporation 1997 Stock Option Plan. (as
amended June 17, 1999)
10.12### -- Box Energy Corporation Non-Employee Director Stock
Purchase Plan.
10.13(-) -- Form of Employment Agreement effective September 30,
1999, by and between Remington Oil and Gas Corporation
and two executive officers.
10.14(-) -- Form of Employment Agreement effective September 30,
1999, by and between Remington Oil and Gas Corporation
and an executive officer.
10.15(-)(-) -- Employment Agreement effective January 31, 2000, by and
between Remington Oil and Gas Corporation and James A.
Watt.
10.16 -- Form of Contingent Stock Grant Agreement -- Directors.
10.17 -- Form of Contingent Stock Grant Agreement -- Employees.
10.18 -- Form of Amendment to Contingent Stock Grant
Agreement -- Directors.
10.19 -- Form of Amendment to Contingent Stock Grant
Agreement -- Employees.
21 -- Subsidiaries of the registrant.
23.1 -- Consent of Arthur Andersen LLP.
- ---------------
* Incorporated by reference to the Company's Registration Statement on Form
S-2 (file number 33-52156) filed with the Commission and effective on
December 1, 1992.
** Incorporated by reference to the Company's Form 10-K (file number 0-19967)
for the fiscal year ended December 31, 1992 filed with the Commission and
effective on or about March 30, 1993.
# Incorporated by reference to the Company's Form 10-K (file number 0-19967)
for the fiscal year ended December 31, 1993 filed with the Commission and
effective on or about March 30, 1994.
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55
## Incorporated by reference to the Company's Form 10-K (file number 0-19967)
for the fiscal year ended December 31, 1994 filed with the Commission and
effective on or about March 30, 1995.
+ Incorporated by reference to the Company's Form 10-Q (file number 1-11516)
for the fiscal quarter ended June 30, 1999 filed with the Commission and
effective on or about August 13, 1999.
*** Incorporated by reference to the Company's Form 10-Q (file number 1-11516)
for the fiscal quarter ended June 30, 1997 filed with the Commission and
effective on or about August 12, 1997.
### Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the fiscal year ended December 31, 1997 filed with the Commission and
effective on or about March 30, 1998.
++ Incorporated by reference to the Company's Registration Statement on Form
S-4 (file number 333-61513) filed with the Commission and effective on
November 27, 1998.
+++ Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the fiscal year ended December 31, 1998 filed with the Commission and
effective on or about March 30, 1999.
(-) Incorporated by reference to the Company's Form 10-Q (file number 1-11516)
for the fiscal quarter ended September 30, 1999 filed with the Commission
and effective on or about November 12, 1999.
(-)(-)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 and
effective on or about March 30, 2000.
53
56
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
REMINGTON OIL AND GAS CORPORATION
By: /s/ JAMES A. WATT
----------------------------------
James A. Watt
President and Chief Executive
Officer
Date: March 16, 2001
Pursuant to the requirements of the Securities Act of 1934, this report has
been signed below by the following persons on behalf of the Registrant and in
the capacities and on the date indicated.
DIRECTORS:
SIGNATURE TITLE
--------- -----
/s/ DON D. BOX Director
- -----------------------------------------------------
Don D. Box
/s/ JOHN E. GOBLE, JR. Director
- -----------------------------------------------------
John E. Goble, Jr.
/s/ WILLIAM E. GREENWOOD Director
- -----------------------------------------------------
William E. Greenwood
/s/ DAVID H. HAWK Director
- -----------------------------------------------------
David H. Hawk
/s/ JAMES ARTHUR LYLE Director
- -----------------------------------------------------
James Arthur Lyle
/s/ DAVID E. PRENG Director
- -----------------------------------------------------
David E. Preng
/s/ THOMAS W. ROLLINS Director
- -----------------------------------------------------
Thomas W. Rollins
/s/ ALAN C. SHAPIRO Director
- -----------------------------------------------------
Alan C. Shapiro
/s/ JAMES A. WATT Director
- -----------------------------------------------------
James A. Watt
54
57
OFFICERS:
SIGNATURE TITLE
--------- -----
/s/ JAMES A. WATT President and Chief Executive Officer
- -----------------------------------------------------
James A. Watt
/s/ J. BURKE ASHER Vice President/Finance and Secretary
- -----------------------------------------------------
J. Burke Asher
/s/ EDWARD V. HOWARD Vice President/Controller and Assistant
- ----------------------------------------------------- Secretary
Edward V. Howard
Date: March 16, 2001
55
58
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.0++ -- Agreement and Plan of Merger dated as of June 22, 1998,
by and between Remington Oil and Gas Corporation and
S-Sixteen Holding Company.
3.1* -- Certificate of Incorporation, as amended.
3.2### -- Certificate of Amendment of Certificate of Incorporation
of Box Energy Corporation.
3.2.1++ -- Certificate of Amendment of Certificate of Incorporation
of Remington Oil and Gas Corporation.
3.3+++ -- By-Laws as amended.
4.1* -- Form of Indenture Box Energy Corporation to United States
Trust Company of New York, Trustee, dated December 1,
1992, 8 1/4% Convertible Subordinated Notes due December
1, 2002.
10.1* -- Farmout Agreement with Aminoil USA, Inc., effective May
1, 1977, dated May 9, 1977.
10.2* -- Transportation Agreement with CKB Petroleum, Inc. dated
March 1, 1985, as amended on April 19, 1989.
10.3* -- Agreement of Compromise and Amendment to Farmout
Agreement, dated July 3, 1989.
10.4** -- Pension Plan of Box Energy Corporation, effective April
16, 1992.
10.5# -- First Amendment to the Pension Plan of Box Energy
Corporation dated December 16, 1993.
10.6## -- Second Amendment to the Pension Plan of Box Energy
Corporation dated December 31, 1994.
10.7*** -- Amended and Restated Promissory Note between Box Energy
Corporation and Box Brothers Holding Company.
10.8*** -- Amended and Restated Pledge Agreement between Box Energy
Corporation and Box Brothers Holding Company.
10.9*** -- Agreement by and between Box Energy Corporation and James
A. Watt.
10.10### -- Box Energy Corporation Severance Plan.
10.11+ -- Box Energy Corporation 1997 Stock Option Plan. (as
amended June 17, 1999)
10.12### -- Box Energy Corporation Non-Employee Director Stock
Purchase Plan.
10.13(-) -- Form of Employment Agreement effective September 30,
1999, by and between Remington Oil and Gas Corporation
and two executive officers.
10.14(-) -- Form of Employment Agreement effective September 30,
1999, by and between Remington Oil and Gas Corporation
and an executive officer.
10.15(-)(-) -- Employment Agreement effective January 31, 2000, by and
between Remington Oil and Gas Corporation and James A.
Watt.
10.16 -- Form of Contingent Stock Grant Agreement -- Directors.
10.17 -- Form of Contingent Stock Grant Agreement -- Employees.
10.18 -- Form of Amendment to Contingent Stock Grant
Agreement -- Directors.
10.19 -- Form of Amendment to Contingent Stock Grant
Agreement -- Employees.
21 -- Subsidiaries of the registrant.
23.1 -- Consent of Arthur Andersen LLP.
59
- ---------------
* Incorporated by reference to the Company's Registration Statement on Form
S-2 (file number 33-52156) filed with the Commission and effective on
December 1, 1992.
** Incorporated by reference to the Company's Form 10-K (file number 0-19967)
for the fiscal year ended December 31, 1992 filed with the Commission and
effective on or about March 30, 1993.
# Incorporated by reference to the Company's Form 10-K (file number 0-19967)
for the fiscal year ended December 31, 1993 filed with the Commission and
effective on or about March 30, 1994.
## Incorporated by reference to the Company's Form 10-K (file number 0-19967)
for the fiscal year ended December 31, 1994 filed with the Commission and
effective on or about March 30, 1995.
+ Incorporated by reference to the Company's Form 10-Q (file number 1-11516)
for the fiscal quarter ended June 30, 1999 filed with the Commission and
effective on or about August 13, 1999.
*** Incorporated by reference to the Company's Form 10-Q (file number 1-11516)
for the fiscal quarter ended June 30, 1997 filed with the Commission and
effective on or about August 12, 1997.
### Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the fiscal year ended December 31, 1997 filed with the Commission and
effective on or about March 30, 1998.
++ Incorporated by reference to the Company's Registration Statement on Form
S-4 (file number 333-61513) filed with the Commission and effective on
November 27, 1998.
+++ Incorporated by reference to the Company's Form 10-K (file number 1-11516)
for the fiscal year ended December 31, 1998 filed with the Commission and
effective on or about March 30, 1999.
(-) Incorporated by reference to the Company's Form 10-Q (file number 1-11516)
for the fiscal quarter ended September 30, 1999 filed with the Commission
and effective on or about November 12, 1999.
(-) (-)
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 and
effective on or about March 30, 2000.