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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, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from to
Commission file number 1-11516
REMINGTON OIL AND GAS CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 75-2369148
(State or other jurisdiction of
incorporation or organization) (I.R.S. employer identification no.)
8201 Preston Road, Suite 600, Dallas, Texas 75225-6211
(Address of principal executive offices) (Zip code)
Registrant's telephone number, including area code: (214) 890-8000
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange on which
registered
Class A (Voting) Common Stock,
$1 Par Value Pacific Stock Exchange
Class B (Non-Voting) Common Stock,
$1 Par Value Pacific Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Class A (Voting) Common Stock, $1 Par Value
(Title of Class)
Class B (Non-Voting) Common Stock, $1 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 26, 1998 was $8,243,910. On that date, the number
of outstanding shares of Class A (Voting) Common Stock, $1 par value, was
3,221,510, and the number of outstanding shares of Class B (Non-Voting)
Common Stock, $1 par value, was 17,128,738.
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.
FORM 10-K
REMINGTON OIL AND GAS CORPORATION
Table of Contents
PART I
ITEM 1. BUSINESS. 3
ITEM 2. PROPERTIES. 6
ITEM 3. LEGAL PROCEEDINGS. 11
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. 11
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS. 12
ITEM 6. SELECTED FINANCIAL DATA. 13
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS. 13
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. 20
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE. 41
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. 41
ITEM 11. EXECUTIVE COMPENSATION.. 45
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT. 55
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. 57
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K. 59
PART I
ITEM 1. BUSINESS.
THE COMPANY
Remington Oil and Gas Corporation, formerly known as Box Energy
Corporation, (the "Company" or "Remington") is an independent oil and gas
exploration and production company with activity and properties in the Gulf
of Mexico, Mississippi, Alabama, Texas and New Mexico. Remington is
incorporated in Delaware with its executive offices located at 8201 Preston
Road, Suite 600, Dallas, Texas 75225-6211 (telephone number 214/890-8000).
The Company employed 15 people on December 31, 1997. Originally organized
in 1981 as OKC Limited Partnership (the "Partnership"), the Company
converted to a corporation on April 15, 1992 (the "Corporate Conversion").
The Corporate Conversion involved the exchange of the Company's common
stock for the assets and liabilities of the Partnership. The Partnership
distributed the common stock to its partners and other unitholders on a
one-for-one basis and then dissolved.
The Company has two classes of stock, Class A (Voting) Common Stock
("Class A Stock") and Class B (Non-Voting) Common Stock ("Class B Stock").
Class A Stock carries voting rights while no voting rights are carried by
the Class B Stock, unless otherwise required by Delaware law. However, both
classes are entitled to equal participation in earnings, dividends and
liquidation proceeds. Unless otherwise required by the context, the term
"Company" or "Remington" includes Remington Oil and Gas Corporation, Box
Energy Corporation and the Partnership.
S-Sixteen Holding Company ("SSHC"), formerly known as Box Brothers
Holding Company ("BBHC"), owns 1.8 million shares or approximately 57% of
the Company's outstanding Class A Stock. In August 1997, entities
controlled by Mr. J. R. Simplot purchased BBHC (the "Simplot Transaction").
LONG-TERM BUSINESS STRATEGY
The Company is primarily engaged in one industry segment and one line
of business, which is finding, developing, and producing oil and natural
gas reserves. The Company's strategy for 1997 was to focus on stopping a
decline in oil and natural gas reserves. The Company accomplished this
objective by increasing oil and natural gas reserves at December 31, 1997
by approximately seven percent on a barrel of oil equivalent ("BOE") basis
over oil and natural gas reserves at December 31, 1996. The long-term
strategy for the future will now focus on increasing reserves by sustaining
an acceptable annual growth rate for reserves with finding and development
costs in line with industry peers. Capital expenditures, financed primarily
by operating cash flow, will entail a balanced exploration, development and
acquisition program.
Natural gas production from one of the Company's producing properties,
South Pass Block 89, is subject to a gas sales contract containing prices
substantially higher than current spot market prices. Part of the strategy
also includes developing the full potential of this block.
The Company employs operational, technical and support staff that
conduct independent evaluations of the acquisition, exploration and
development activities in three core areas, Gulf of Mexico,
Mississippi/Alabama and onshore Gulf Coast area. Remington owns three 3-D
workstations and utilizes current technology to generate oil and gas
prospects in its core areas and review outside generated oil and gas
prospects which are available for acquisition, farm-in or working interest
participation.
COMPETITION
The Company faces competition from large integrated oil and gas
companies, independent exploration and production companies, private
individuals and sponsored drilling programs. The Company competes for
operational, technical and support staff, options and/or leases on
prospective oil and natural gas properties and sales of products from
developed properties. Many of the Company's competitors 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
The Company sells its oil production based upon a market price for
crude oil as posted from day to day by major purchasers. The applicable
posted price is modified for crude oil quality, refined product yields,
geographical proximity to refineries and availability of transportation
facilities. In certain areas, because of the volume produced, the Company
negotiates a premium over the posted prices. Oil prices fluctuate
significantly over time because of changes in supply and demand, changes in
refinery utilization, levels of economic activity throughout the country
and political developments throughout the world.
The Company sells its natural gas production from South Pass Block 89
under a sales contract with Texas Eastern Transmission Company ("Texas
Eastern") which expires on July 15, 2002. In November 1990, the Company
settled litigation with Texas Eastern. Part of the settlement modified the
original gas sales contract by lowering the price paid, limiting the
production sold from the northern portion of South Pass Block 89 to 15.0
Bcf and exempting production from sands beneath the U-sand horizon. In
January 1998, the Company received $12.35 and $6.84 per Mcf for natural gas
sold under the contract from wells in the southern and northern portion of
South Pass Block 89, respectively. Prices for gas sold under the gas
contract increase 10% on January 1 of each year. Texas Eastern is obligated
to take or pay for 80% of the Company's delivery capacity (i.e., the
maximum efficient flow rate based on periodic field deliverability tests)
of gas well gas. Texas Eastern is required to take and pay for 100% of the
casinghead gas. Casinghead gas is gas produced from "oil wells," as
distinguished from gas produced from "gas wells." The gas sales contract
expressly provides that Texas Eastern assumes any and all regulatory risks
associated with the performance of the contract and waives any right to
assert that it is not obligated to perform under the contract by reason of
economic, governmental or regulatory conditions or changes, including
action by a regulatory agency such as the Federal Energy Regulatory
Commission ("FERC"). PanEnergy Corporation, the parent company of Texas
Eastern, guarantees all of the obligations of Texas Eastern under the
contract.
The Company sells its non-contract natural gas production at spot
market prices or a derivation thereof. Late in 1997, the Company began to
use a third party to market a significant portion of its non-contract
natural gas production. Natural gas spot market prices fluctuate
significantly because of changes in supply and demand, seasonal or
extraordinary weather patterns and levels of economic activity throughout
the country.
MAJOR CUSTOMERS
Purchases by BayOil (USA), Inc. during 1997 and 1996 represented 31%
and 18%, respectively, of the Company's total oil and natural gas revenues.
Marathon Oil Company's purchases during 1995 accounted for 25% of the total
oil and natural gas revenues for that year. Purchases by Texas Eastern
during 1997, 1996 and 1995 represented 42%, 51%, and 70%, respectively, of
the total oil and natural gas revenues.
RISK OF COMPANY OPERATIONS
Exploration, development and production operations involve a high
degree of risk. Unprofitable efforts may result not only from dry holes but
also from marginally productive wells that do not produce oil or gas in
sufficient quantities to return a profit on the amounts expended. The
Company is dependent upon production from wells in the South Pass area and
upon the continued performance by the natural gas purchaser under the
Company's long-term gas sales contract covering South Pass Block 89. The
loss of one well or such contract could cause a material decline in
revenues, cash flow and profitability. The utilization of 3-D seismic data
or other technology to identify and define the parameters of drilling
prospects may be unprofitable in situations where the interpretation of the
data determines that a prospect should not be drilled or indicates that a
prospect should be drilled which later proves to be unproductive. The
success of the Company's operations depends, in part, upon the ability and
continued employment of its management and technical personnel.
Accordingly, there is no assurance that the Company's oil and gas drilling
or acquisition activities will be successful, that significant additional
production will be obtained, that any such production, if obtained, will be
profitable or that the Company's management and technical personnel will
make correct decisions or continue to be employed.
The Company's operations are subject to all of the operating hazards
and risks normally incident to drilling for and producing oil and gas, such
as title risks, exploration risks, geophysical interpretation risks and
risks of encountering unusual or unexpected formations and pressures,
blowouts, environmental pollution and personal injury. The Company
maintains general liability insurance and insurance against blowouts,
redrilling expenses and certain other operating hazards, including certain
pollution risks. If the Company sustains an uninsured loss or liability, or
if the amount of loss exceeds the limits of its insurance, its financial
condition may be materially adversely affected.
GOVERNMENTAL REGULATION
Oil and Gas Operations
As an oil and gas company, Remington is subject to numerous federal
and state regulations as it pursues its domestic exploration, production
and oil and natural gas sales activities. Current regulations are
constantly reviewed at the same time that new regulations are being
considered and implemented. This regulatory burden upon the oil and gas
industry increases its cost of doing business and consequently affects its
profitability. These burdens are increased because the Company holds
federal leases which, as government contracts, require the Company to
comply with numerous regulations not focused simply on the oil and gas
industry but on government contractors as a whole. These regulations
increase the Company's general and administrative costs.
State regulatory agencies further exert a regulatory burden on the
Company. 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 or pooling of oil and
gas properties, maximum rates of production and spacing and plugging and
abandonment of wells.
Environmental
Remington's oil and gas operations are subject to stringent federal,
state and local laws and regulations relating to improving or maintaining
the quality of the environment. The Company's costs associated with
environmental compliance, while not yet of a material amount, have
increased over time and the Company expects such costs to rise in the
future. Moreover, the cost of compliance with federal legislation and its
state counterparts, such as the Oil Pollution Act of 1990 and the Clean
Water Act together with their Amendments could have a significant impact on
the financial ability of the Company to carry out its oil and gas
operations. The legislation and accompanying regulations could impose
financial responsibility requirements, liability features and operational
requirements which the Company cannot profitably satisfy.
The laws, which 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. Liability under these laws can result in
severe fines and cleanup costs being levied against the liable party. The
Company has never been a liable party under these laws nor has it been
named a potentially responsible party for waste disposal at any site. The
potential for sudden and unpredictable liability under these environmental
laws is an issue of increasing importance to the Company and, indeed, the
oil and gas industry as a whole.
OTHER BUSINESS CONDITIONS
Except for its oil and gas leases with third parties, the Company has
no material patents, licenses, franchises or concessions which it considers
significant to its oil and gas operations. The nature of the Company's
business is such that it does not maintain or require a "backlog" of
products, customer orders or inventory. The Company has not been a party to
any bankruptcy, reorganization, adjustment or similar proceeding.
Generally, the Company's business activities are not seasonal in nature.
However, weather conditions affect the demand for natural gas and can
hinder drilling activities. Demand for natural gas is typically higher
during winter months.
ITEM 2. PROPERTIES.
OIL AND GAS PROPERTIES
Certain information required by this Item is incorporated herein by
reference from Item 7. "Management's Discussion and Analysis of Financial
Condition and Results of Operations", Item 8. "Financial Statements and
Supplementary Data" and Note 12. Notes to Financial Statements. The
following table presents the Company's gross and net acreage at December
31, 1997.
Undeveloped Developed
Gross Net Gross Net
Offshore Gulf of Mexico 75,646 36,672 23,534 6,094
Onshore Gulf Coast 39,339 6,200 16,500 3,316
Mississippi/Alabama 31,096 13,644 860 607
Other 4,951 2,746 754 189
Total 151,032 59,262 41,648 10,206
The following table presents the Company's net proved oil and natural
gas reserves by area at December 31, 1997 as evaluated by Netherland,
Sewell and Associates, Inc. and Miller and Lents, Ltd.
Oil (MBbls) Gas (MMcf)
Gross Net Gross Net
Offshore Gulf of Mexico 10,043 2,211 141,457 30,234
Onshore Gulf Coast 4,971 944 41,173 6,273
Mississippi Alabama 2,136 1,271 0 0
Other 110 25 164 36
Total 17,260 4,451 182,794 36,543
OFFSHORE GULF OF MEXICO
Oil and natural gas reserves totaling 2.2 million barrels of oil
(MMBbls) and 30.2 billion cubic feet of gas (Bcf) in the Gulf of Mexico,
represent approximately 50% and 83% of Remington's total net oil and
natural gas reserves, respectively. The Company has and continues to
diversify its offshore portfolio away from the South Pass area through new
lease purchases, evaluation of submittals of others and evaluation of
acquisition opportunities. The Company owns three 3-D workstations for
evaluating offshore prospects and has purchased an extensive database of
both 2-D and 3-D seismic for reviewing exploration and development
opportunities. The Company owns several undeveloped offshore blocks that,
depending on rig availability and partner approvals, will be drilled in
1998 or beyond. The following table presents the proved oil and natural gas
reserves for major properties in the Gulf of Mexico at December 31, 1997.
Oil (MBbls) Gas (MMcf)
Gross Net Gross Net
South Pass 89 4,516 943 48,660 10,140
South Pass 87 2,920 709 42,314 10,993
South Pass 86 953 199 16,804 3,501
Eugene Island 135 942 118 27,165 3,396
West Cameron 170 712 242 6,400 2,172
Main Pass 262 0 0 114 32
Total 10,043 2,211 141,457 30,234
South Pass Block 89
The Company acquired South Pass Block 89 through a farmout from
Aminoil USA, now Phillips Petroleum Company ("Phillips") in 1977. The
Company has a 25% working interest burdened with a 33% Net Profits Interest
("NPI") to Phillips pursuant to the original farmout. Remington and
Phillips are currently involved in litigation concerning the calculation of
the NPI. See Item 3. "Legal Proceedings." Marathon Oil Company
("Marathon") is operator of the block. The Company's natural gas production
is subject to a gas sales contract through July 15, 2002 with Texas Eastern
Transmission Company. See Item 1. "Business-Markets."
Platform B was installed in South Pass Block 89 in 1991 and has
produced 48.7 MMBO (10.2 MMBO net) and 174.6 BCFG (36.4 BCFG net). The U-
sand is the primary reservoir on the block with the beds orientated almost
vertically adjacent to a sub-surface salt dome. At December 31, 1997, one
well was producing from this reservoir and 11 wells were producing from
shallower reservoirs. The Company's reserve report requires an additional
well to produce all the reserves defined.
The Company is producing two wells from Platform C, into the northern
portion of South Pass Block 89. The platform is physically located on South
Pass Block 86, immediately to the north of South Pass Block 89. The two
wells in South Pass Block 89 are completed in the U-sand reservoir, but in
an isolated fault block separated from the U-sand production from Platform
B. The U-sand reservoir in this location is not as structurally complex as
at Platform B. Cumulative production from the C Platform wells completed
in South Pass Block 89 as of December 31, 1997 was 5.2 MMBbls (1.08 MMBbls
net) and 28.5 Bcf (5.9 Bcf net). The platform was installed in 1992 and
Marathon is the operator.
South Pass Block 87, West Delta Block 128
Platform D, located on South Pass Block 87 to the northwest of South
Pass Block 89 was installed in 1995 with Marathon as operator. There are
five wells producing from South Pass Block 87 and West Delta Block 128. The
Company has a 33% working interest in the four wells in South Pass Block 87
and a 20% working interest in one well in West Delta Block 128. Cumulative
production from Platform D, all of which has been from the U-sand through
December 1997 was 5.0 MMBbls (1.0 MMBbls net) and 24.9 Bcf (5.2 Bcf net).
Additional drilling is anticipated on this block in 1998.
South Pass Block 86
The Company completed five wells from Platform C in the southern
portion of South Pass Block 86. The Company has a 25% working interest in
the block and Marathon is the operator. The primary reservoir is the U-
sand. Cumulative production from 1992 to December 31, 1997 was 3.6 MMBbls
(748 MBbls net) and 16.6 Bcf (3.5 Bcf net).
Eugene Island Block 135
The Company acquired a 15% working interest in the block in 1995,
drilled, and successfully tested the #1 well in 1996. In 1997, a platform
was installed, the A-1 well completed, the A-2 well drilled and completed
and the A-3 well partially drilled. Enron Oil and Gas Company is operator
of the block. The A-3 well will be completed in 1998 and additional
drilling may be proposed. Production from Eugene Island Block 135 commenced
in the last quarter of 1997 with cumulative production of 83 MBO (10 MBO
net) and 600 MMCFG (76MMCFG net). The Company acquired a 20% working
interest in Eugene Island Blocks 153 and 154 immediately to the south of
Eugene Island Block 135 in 1997.
West Cameron Block 170
The Company acquired a 42% working interest in this block in 1997. CXY
Energy Offshore, Inc. ("CXY") is the operator and the block has a
production platform in place. Drilling commenced on the #2 well in 1997 and
the well logged sufficient pay to book proved oil and natural gas reserves
in the shallow portion of the hole before year-end. Deeper pays have been
drilled in the well and it is anticipated to be completed in 1998. The
deeper pays are not included in the December 31, 1997 proved oil and
natural gas reserves. The Company anticipates additional drilling on this
block before the end of 1998.
Main Pass Block 262
The Company completed three wells from the platform on this block in
1996 and 1997. The Company has a 33% working interest in the block and CXY
is the operator. These wells did not perform as anticipated and the
undepreciated cost of the wells was impaired in the fourth quarter of 1997.
The Company anticipates drilling a deeper exploratory test well from the
platform in 1998.
MISSISSIPPI/ALABAMA
In the onshore Mississippi/Alabama area, the Company's proved oil
reserves are 1.3 MMBbls representing approximately 29% of Remington's net
proved oil reserves at December 31, 1997. Currently, the Company has an
interest in two developed fields and one developing field. Using outside
consultants, the Company has developed several prospects for drilling in
1998 and beyond. This program is anticipated to continue using a database
of 2-D data coupled with specific 3-D data on field discoveries. The
following table presents the proved oil reserves attributable to
Mississippi/Alabama at December 31, 1997.
Oil (MBbls)
Gross Net
East Melvin 103 43
Indian Wells 355 261
Parker Creek 1,678 967
Total 2,136 1,271
East Melvin Field
The East Melvin field, located in Choctaw County, Alabama, is a two-
well field that produces from the Smackover formation. The Company has a
52% working interest in the field. The second well in the field was drilled
in 1997 and is anticipated to be completed in 1998. The Company does not
expect any further development of this field.
Indian Wells Field
The Indian Wells field is located in Jasper County, Mississippi and
produces from the Rodessa formation. The Company has a 92% working interest
in the field. Two wells are completed in the field and no additional
development is anticipated.
Parker Creek Field (formerly Moselle Dome Prospect)
The Parker Creek field is on the flank of a salt dome located in Jones
County, Mississippi. The first well drilled in 1996 and completed in 1997
encountered pays from the shallow Eutaw and Tuscaloosa interval above 8000
feet and the Hosston interval below 14,000 feet. The Company completed this
first deep well in the Hosston interval in the first quarter of 1997. The
Company completed a second well, the first shallow well completion, in the
Tuscaloosa interval during the third quarter of 1997. The shallow Eutaw and
Tuscaloosa are heavy oils. In the fourth quarter of 1997, the Company began
drilling both a second deep well and a second shallow well. Both wells will
be completed and producing in 1998. A newly acquired 3-D seismic survey is
scheduled to be completed in the summer of 1998. Additional drilling is
anticipated in the field after interpretation of the 3-D seismic survey is
completed. During the partial year of 1997, the field produced 162 MBbls
(98 MBbls net).
ONSHORE GULF COAST
The Company's net proved oil and natural gas reserves in the onshore
Gulf Coast area are 944 MBbls and 6.2 Bcf, representing approximately 21%
and 17% of the net proved oil and natural gas respectively. The Company
initiated an active acquisition program in this area in 1997 along with
participating in an active exploration program conducted by Suemaur
Exploration, Inc. This exploration program has resulted in 3-D surveys
defining several prospects that are anticipated to be drilled in 1998 and
beyond. The acquisition program resulted in one acquisition of an interest
in six separate fields in 1997. The Company anticipates using the knowledge
gained from participating in the various 3-D surveys not only to develop
new prospects but to better define the upside opportunities within the
fields acquired. The following table presents the proved oil and natural
gas reserves from the major properties in the Onshore Gulf Coast area at
December 31, 1997.
Oil (MBbls) Gas (MMcf)
Gross Net Gross Net
W. Buna 4,324 874 19,919 3,628
Other 647 70 21,254 2,645
Total 4,971 944 41,173 6,273
West Buna Field
This field, located in Jasper and Hardin counties, Texas is the
largest field of the six-well group of fields acquired in 1997. The field
currently has 23 wells producing from the Wilcox formation. Additional
drilling and workover operations are anticipated in 1998. The Company has
approximately a 30% working interest in the field.
PRODUCING WELLS
The following table presents a summary of the gross and net producing
wells by core area for the years ended December 31, 1997, 1996 and 1995.
Productive wells are producing wells and wells capable of production but do
not include wells awaiting completion or the installation of a platform.
Gross wells refer to the total producing wells in which the Company owns an
interest. Net wells represent the gross wells multiplied by the Company's
working interest percentage.
1997 1996 1995
Gross Net Gross Net Gross Net
Oil Wells
Gulf of Mexico 17 4.37 18 4.61 25 6.28
Mississippi and Alabama 6 4.38 5 3.53 2 1.00
Onshore Gulf Coast 3 .28 2 0.21 - -
Other 3 .81 3 0.81 1 0.31
Total 29 9.84 28 9.16 28 7.59
Gas Wells
Gulf of Mexico 10 2.46 9 2.57 4 1.16
Mississippi and Alabama - - - - - -
Onshore Gulf Coast 78 18.24 3 0.53 - -
Other - - - - - -
Total 88 20.70 12 3.10 4 1.16
DRILLING ACTIVITIES
The following is a summary of the Company's exploration and
development drilling activities for the past three years by core area:
1997 1996 1995
Gross Net Gross Net Gross Net
Prod. Dry Prod. Dry Prod. Dry Prod. Dry Prod .Dry Prod. Dry
Exploratory
Gulf of
Mexico 2 2 .30 .42 4 4 1.15 1.15 1 1 .25 .33
Mississippi
and Alabama 1 2 .80 1.84 2 8 1.65 5.81 1 1 .52 .25
Onshore Gulf
Coast - 2 - .32 4 5 .60 1.87 1 4 .47 1.56
Other - 1 - .40 2 4 .50 1.72 1 1 .30 .35
Total 3 7 1.10 2.98 12 21 3.90 10.55 4 7 1.54 2.49
Development
Gulf of
Mexico 1 - .25 - - - - - 1 - .33 -
Mississippi
and Alabama 1 3 .76 2.42 1 2 .94 1.87 2 - .89 -
Onshore Gulf
Coast 3 - .82 - - - - - - - - -
Other - 1 - .35 - - - - - - - -
Total 5 4 1.83 2.77 1 2 .94 1.87 3 - 1.22 -
At December 31, 1997, the Company had an interest in six (1.77 net to
Remington) wells in progress.
OPERATING AGREEMENTS
The Company typically owns its interests in oil and gas properties
subject to joint operating agreements naming another company as operator of
the property. Many of the agreements grant the operator a lien on the
Company's interests to secure payment of the Company's share of expenses.
Being a non-operator is advantageous to the Company by not requiring the
Company to employ an operational staff, but is disadvantageous in that the
Company foregoes certain control over the property as a non-operator. The
Company may become an operator of certain properties in 1998.
TITLE TO PROPERTIES
The Company's oil and gas properties are subject to customary royalty
interests, liens incident to operating agreements and liens for other
burdens, including other mineral encumbrances and restrictions. Such
burdens, encumbrances or other restrictions do not materially interfere
with the normal operations of such properties. After a thorough examination
of title to its properties, the Company believes that it is vested with
satisfactory title to such properties. The Company does a preliminary
investigation of titles on all undeveloped properties and obtains a full
title opinion before commencement of drilling operations.
NON-OIL AND GAS PROPERTIES
The Company owns approximately 7,800 surface acres in several non-
contiguous tracts of land 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 operating
revenues from these real estate properties in 1997 totaled $224,000. The
Company intends to divest these properties, although the timing and the
amount of sales proceeds from the disposition of these properties is
unknown.
OFFICE LEASE
The Company leases office space in Dallas, Texas covering
approximately 33,000 square feet. In January 1998, the Company amended the
current lease effective April 1998. The amended lease extends the term an
additional 10 years and reduces the leased office space to approximately
17,000 square feet.
ITEM 3. LEGAL PROCEEDINGS.
The information required by this Item is incorporated herein by
reference to Item 8. "Financial Statements and Supplementary Data." - Note
11. Notes to Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
On December 4, 1997, the Company held its annual stockholders' meeting
to elect members to the Company's Board of Directors, adopt the 1997 Stock
Option Plan, adopt the Non-Employee Director Stock Purchase Plan and change
the name of the Company to "Remington Oil and Gas Corporation." Set forth
below are the results of the stockholder voting:
Director For Withheld
Don D. Box 2,342,240 39,135
John E. Goble, Jr. 2,373,625 7,750
William E. Greenwood 2,373,625 7,750
David H. Hawk 2,373,625 7,750
James Arthur Lyle 2,372,475 8,900
David E. Preng 2,372,475 8,900
Thomas W. Rollins 2,373,625 7,750
Alan C. Shapiro 2,373,210 8,165
James A. Watt 2,373,625 7,750
For Against Abstain
Adoption of 1997 Stock Option Plan 2,001,723 57,300 4,480
Adoption of Non-Employee Director
Stock Purchase Plan 2,003,343 51,115 9,045
Name change to Remington Oil and
Gas Corporation 2,361,970 16,785 2,620
The members of the Company's Board of Directors do not serve staggered
terms of office. All directors elected at the meeting were already members
of the Board at the time of election. No Director serving at the time of
the election failed to retain his seat on the Board, other than Bernay C.
Box, who did not stand for reelection.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
The Company has two classes of stock: Class A Stock and Class B Stock.
Both classes trade on the NASDAQ National Market System, under the trading
symbols ROILA and ROILB, respectively. Previously, as Box Energy
Corporation the shares traded under the symbols BOXXA and BOXXB,
respectively. The stock also trades on the Pacific Stock Exchange under the
symbols REMA.P and REMB.P, respectively, and previously traded under the
symbols BXCA.P and BXCB.P, respectively, as Box Energy Corporation before
the change of name. The following table sets forth, for the periods
indicated, the high and low last sales price per share for the Class A
Stock and the Class B Stock as reported by NASDAQ.
Class A Stock Class B Stock
High Low High Low
1998
First Quarter (through
March 26, 1998) 6.250 5.125 6.375 5.000
1997
Fourth Quarter 8.875 5.125 8.125 5.063
Third Quarter 9.250 6.500 8.750 6.250
Second Quarter 8.750 6.375 7.500 5.813
First Quarter 10.500 7.000 9.313 6.625
1996
Fourth Quarter 11.000 8.000 10.375 8.000
Third Quarter 10.750 8.000 9.750 8.000
Second Quarter 11.625 9.000 11.125 8.750
First Quarter 13.000 8.625 11.375 7.750
On March 26, 1998, the last reported sales prices of Class A Stock and
Class B Stock were $6.00 and $6.125 per share, respectively. On such date,
there were 427 shareholders of record of Class A Stock and 1,074
shareholders of record of Class B Stock. The Company has not declared or
paid any cash dividends since its commencement of operations in 1992. There
are no contractual restrictions on the amount of dividends that may be
paid. However, if dividends in excess of 2% of the then market price per
share of Class B Stock are paid in 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, the Company's financial condition, cash
flow from operating activities, the level of its capital and exploration
expenditure needs and its future business prospects.
ITEM 6. SELECTED FINANCIAL DATA.
1997 1996 1995 1994 1993
(In thousands, except per share data, unless otherwise indicated)
Financial
Total revenue $ 61,053 $ 70,210 $ 59,493 $ 59,244 $ 37,102
Net income (loss) $ (26,790) $ (7,662) $ 5,392 $ 9,157 $ 2,161
Basic and diluted
income (loss) per
share $ (1.31) $ (0.37) $ 0.26 $ 0.44 $ 0.10
Total assets $ 98,515 $ 136,599 $ 145,491 $ 135,041 $ 128,882
8 1/4% convertible
subordinated notes $ 38,371 $ 55,077 $ 55,077 $ 55,077 $ 55,077
Other indebtedness $ 6,000 $ 0 0 $ 0 $ 1,970
Stockholders' equity $ 44,287 $ 74,356 $ 82,047 $ 75,513 $ 67,655
Shares outstanding
Class A Common Stock 3,219 3,250 3,250 3,250 3,245
Class B Common Stock 17,087 17,553 17,553 17,553 17,558
Net cash flow from
operations $ 27,546 $ 28,955 $ 24,047 $ 27,644 $ 11,006
Net cash flow from
investments (38,442) $ (39,538) $ (19,899) $ (13,769) $ (10,082)
Net cash flow from
financing $ 12,451 $ (8,064) $ 0 $ (1,970) $ (514)
Operational
Average sales prices
Oil (per Bbl) $ 17.79 $ 20.21 $ 16.64 $ 15.51 $ 17.02
Natural Gas (per Mcf) $ 5.06 $ 5.69 $ 6.89 $ 7.46 $ 5.07
Future net revenue
from proved reserves
(before tax)
Undiscounted $ 141,672 $ 227,817 $ 223,896 $ 206,701 $ 222,300
Discounted $ 108,698 $ 189,155 $ 173,388 $ 157,721 $ 163,793
Future net revenue
from proved reserves
(after tax)
Undiscounted $ 124,828 $ 177,178 $ 173,869 $ 163,633 $ 167,626
Discounted $ 93,838 $ 146,013 $ 133,982 $ 124,490 $ 124,002
Proved reserves
Oil (MBbls) 4,451 3,299 2,938 3,298 3,389
Natural gas (Bcf) 36.5 39.3 51.4 50.3 53.2
Average production
(net sales volume)
Oil (BOPD) 3,280 2,555 2,300 1,796 2,204
Natural gas (MMcfgd) 19.5 22.5 16.1 17.2 10.7
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
The following discussion will assist in the understanding of the
Company's financial position and results of operations. The information
below should be read in conjunction with the financial statements and the
related notes to financial statements. This discussion contains historical
information and certain forward-looking statements that involve risks and
uncertainties about the business, long-term strategy, financial condition
and future of the Company. Statements concerning results of future
exploration, exploitation, development and acquisition expenditures and
expense and reserve levels are forward-looking statements. These statements
are based on assumptions concerning commodity prices, drilling results and
production and administrative and interest costs that management believes
are reasonable based on currently available information of known facts and
trends. However, management's assumptions and the Company's future
performance are both subject to a wide range of business risks and there is
no assurance that these goals and projections can or will be met. Factors
that may affect future results are included in the discussion below and in
Part I, Item 1. "Business" and Item 2. "Properties."
Remington Oil and Gas Corporation (the "Company") is an independent
oil and gas exploration and production company with activity and properties
located in offshore Gulf of Mexico, Mississippi/Alabama and onshore Gulf
Coast. The Company acquired all of the assets and liabilities of OKC
Limited Partnership (the "Partnership") on April 15, 1992, in exchange for
the common stock of the Company (the "Corporate Conversion"). The
Partnership then distributed, as part of its liquidation and dissolution,
3,245,110 shares of Class A Common (Voting) Stock (the "Class A Stock") and
17,558,110 shares of Class B (Non-Voting) Common Stock (the "Class B
Stock") to the former general partners, limited partners and unitholders of
the Predecessor Partnership. After the Corporate Conversion, Cloyce K. Box,
one of the former general partners, owned approximately 57% of the
outstanding Class A Stock.
At the time of the Corporate Conversion, Mr. J.R. Simplot, Mr. James
Arthur Lyle and others had pending litigation against the Partnership
concerning voting issues and the purchase of an oil pipeline by a privately
controlled affiliate of Cloyce K. Box (the "Griffin Case"). See Notes to
the Financial Statements - Note 11. Contingencies - Griffin Case. After
Cloyce Box's death in October 1993, the Class A Stock was foreclosed upon
by Box Brothers Holding Company ("BBHC"). At the time of the foreclosure,
BBHC was primarily owned and controlled by the four sons of Cloyce K. Box.
A number of disputes and lawsuits concerning the control of BBHC arose
among the four brothers.
In March 1997, the Company appointed James A. Watt as President and
Chief Operating Officer. Subsequently, in February 1998, the Board of
Directors named Mr. Watt Chief Executive Officer. Mr. Watt, who has
significant oil and gas experience, is the first executive from outside the
controlling interest of the Company to head the Company. In August 1997, an
entity controlled by Mr. Simplot purchased the controlling interest in BBHC
(the "Simplot Transaction"). Shortly thereafter, BBHC changed its name to
S-Sixteen Holding Company ("SSHC"). In connection with this purchase, Mr.
Simplot and the four Box brothers agreed to settle all lawsuits among them
and the Company.
The primary objective set by the new management for 1997 was to stop
the decline in oil and natural gas reserves and bring average finding costs
down to industry averages. The Company accomplished the first objective by
increasing oil and natural gas reserves by approximately 7% at December 31,
1997 compared to December 31, 1996. Management also made great progress in
the second objective by decreasing average finding costs from $65.02 per
BOE in 1996 to $13.71 per BOE in 1997. The long-term strategy now focuses
on increasing reserves by sustaining an acceptable annual growth rate for
reserves with finding and development costs that are in line with industry
peers. Capital expenditures, financed primarily by operating cash flow,
will entail a balanced exploration, development and acquisition program.
LIQUIDITY AND CAPITAL RESOURCES
The Company's balance sheet liquidity decreased significantly during
1997. At December 31, 1996, current assets exceeded current liabilities by
$39.0 million, and the current ratio was approximately 6.4 to 1. At
December 31, 1997, current assets exceeded current liabilities by $3.0
million and the current ratio was approximately 1.2 to 1. The decline in
liquidity resulted primarily from the sale of marketable securities in
October 1997, and the use of the proceeds to repurchase $16.7 million of
the 8 1/4 % Convertible Subordinated Notes (the "Notes"). The Simplot
Transaction caused a "change in control" as defined in the Indenture for
the Notes (the "Indenture") that required the Company to make an offer to
purchase the Notes at 100% of the face amount. In addition, during 1997,
the Company used some of the liquid assets and borrowed $6.0 million to
purchase $3.5 million of treasury stock and fund the excess of capital
expenditures over net cash flow from operations.
Cash flow from operations for the year ended December 31, 1997 was
$27.5 million compared to $29.0 million for the prior year. In addition to
lower natural gas revenues of $10.7 million, cash payments totaling $7.1
million for reorganization costs had a detrimental effect on the cash flow
from operations during the year. The lower natural gas revenues resulted
primarily from a decrease in natural gas production from South Pass Block
89. Natural gas production from this offshore Gulf of Mexico Block is sold
under a gas sales contract that includes prices substantially above spot
market prices. Therefore, a reduction in production from this block has a
significant effect on natural gas revenues, total revenues, net income and
cash flow from operations. The concern over the concentration of revenues
has prompted management to diversify the revenue stream through
acquisitions and exploration drilling in other areas. Natural gas revenues
from South Pass Block 89 accounted for 40%, 51%, and 79% of total revenues
for 1997, 1996, and 1995, respectively. Reorganization costs paid during
1997 included employee severance expense, litigation settlement amounts and
other costs related to the Simplot Transaction. See Notes to Financial
Statements - Note 5. Reorganization Costs.
The Company will continue to make significant capital expenditures
over the next several years as part of the long-term growth strategy and
the primary source of funding the capital expenditures will be net cash
flow from operations. As stated above, natural gas sales from South Pass
Block 89 provided approximately 40% of the Company's total revenue in 1997.
Further, a significant portion of the natural gas revenues from South Pass
Block 89 is dependent on Well B-20S. Early in 1997 and throughout the year,
the Company identified and followed a trend of increasing oil production
and decreasing natural gas production in the Well B-20S, the only well
currently producing from the U-sand reservoir. The trend may indicate,
among other things, that natural gas production will continue to decline as
the oil column moves into the perforations of this well. The Company's net
working interest deliverability ("Seller's Delivery Capacity") from
Platform B has declined from 7.2 MMcfgd in January 1997 to 2.9 MMcfgd in
December 1997. Current estimates have Well B-20S producing at decreasing
rates until March 1999. A large quantity of proved undeveloped natural gas
reserves still remains in the U-1/1 reservoir above the existing
perforations in Well B-20S. Management is currently evaluating several
possible courses of action concerning the maximization of profit from South
Pass Block 89 and specifically the U-1/1 reservoir. Such plans include, but
are not limited to, a new well or sidetrack of an existing wellbore in the
U-1/1 reservoir. Recent discoveries, development wells and acquisitions
lessen the Company's dependence on natural gas revenue from this block, but
may not be adequate to replace the immediate decline in gas revenue from
unforeseen mechanical or other problems with Well B-20S.
The recent decline in oil prices has a negative impact on total
revenues and therefore net income and cash flow from operations. The
Company's average oil price for 1997 was $17.79 per barrel but has averaged
under $14.00 per barrel for the first two months of 1998. While the
Company's gas sales contract insulates the Company to some degree from the
lower oil prices, continued low prices for oil production will reduce the
projected cash flow from operations and may cause the Company to defer or
eliminate certain capital expenditures. The following table sets forth the
Company's actual capital expenditures, including exploration expenses, for
the last three years and the current 1998 capital and exploration budget.
1998 1997 1996 1995
Budget Actual Actual Actual
(In thousands)
Acquisition $ 6,000 $ 12,545 $ - $ -
Land and leasehold 4,000 5,793 5,548 3,215
Development 13,300 9,975 9,359 11,597
Exploration 15,900 13,767 27,811 8,902
Total $ 39,200 $ 42,080 $ 42,718 $ 23,714
Net proved oil and natural gas
reserve additions (in barrels
of oil equivalents) 3,070 657 1,630
Finding costs (per barrel of
oil equivalent) $ 13.71 $ 65.02 $ 14.55
Capital and exploration expenditures for oil and natural gas
properties during 1997 totaled $42.1 million compared to $42.7 million in
1996. The primary capital expenditures for 1997 included drilling,
completion and platform construction costs for Eugene Island Block 135,
drilling costs for a well on West Cameron 170, drilling and completion
costs on the Parker Creek field and a purchase of several South Texas
properties. Expected development costs for 1998 include one or two new
wells in South Pass Block 87, a new well or a side-track well in South Pass
Block 89, additional development of West Cameron Block 170 and Eugene
Island Block 135 and four to six onshore wells including three to four
wells in the Parker Creek field. The Company budgeted $10.0 million for
acquisition, land and leasehold costs. The Company will use these budgeted
amounts to purchase oil and natural gas reserves at attractive prices and
to maintain and develop an inventory of exploration development projects.
In March 1998, the Company completed an acquisition for $1.6 million and
submitted the high bid on one offshore block in the MMS lease sales. The
Company does not yet know whether the bid will be accepted. Budgeted
exploration costs include three planned wells in the Gulf of Mexico, at
least two wells in Mississippi, and several wells in the onshore gulf coast
region. In addition, the Company plans for approximately $4.0 million of
exploration expenses, which is primarily to purchase 2-D and 3-D seismic
data. The capital and exploration budget for 1998 is flexible and the
Company can delay many of the planned expenditures if better opportunities
arise or if capital is not available from operations.
Additional sources of capital include the repayment of the note
receivable from SSHC and additional cash available on the Company's line of
credit. The note receivable from SSHC is due May 29, 1998. The balance at
December 31, 1997 was $6.2 million, and payments from SSHC have been
greater than the required $100,000 per month. During the second quarter of
1994, the Company established a $25.0 million line of credit with a bank.
The line of credit, with a current borrowing base of $10.0 million, expires
in June 1998. The Company anticipates renewing this line again in 1998 or
obtaining a similar line of credit when the line of credit comes due. The
line of credit is collateralized by the Company's South Pass oil and
natural gas properties. The Company has borrowed $6.0 million and has
issued letters of credit totaling $250,000 against this line.
The Company and Phillips Petroleum Company ("Phillips") are engaged in
a dispute concerning the Net Profits Interest in South Pass Block 89. A
non-jury trial was held in April 1997. Phillips alleges damages in excess
of $21.5 million on one claim and several million dollars on two additional
claims. Phillips further contended that it was entitled to double damages
and cancellation of the farmout agreement that created the Net Profits
Interest. Oral arguments were presented to the court September 3, 1997.
Certain outcomes of this litigation could have a material adverse impact on
the liquidity of the Company.
The Company adopted Statement of Financial Accounting Standards
("SFAS") No. 128, entitled "Earnings per Share" in 1997. SFAS simplifies
the standards for computing earnings per share previously found in
Accounting Principles Board ("APB") Opinion No. 15. Basic income per share
and diluted income per share have replaced primary income per share and
fully diluted income per share, respectively. Basic income per share
excludes dilution and is computed by dividing net income by the weighted
average number of common shares outstanding for the period. Diluted income
per share reflects the potential dilution from the exercise or conversion
of securities or other contracts to issue common stock and other events
that result in the issuance of common stock that shares in the net income
of the Company. Diluted income per share is computed similarly to fully
diluted income per share pursuant to APB Opinion 15. The Company's
presentation of basic income per share and diluted income per share are the
same as the previously presented primary income per share and fully diluted
income per share. Basic income per share and diluted income per share are
the same because the effects of the potential dilutive securities are anti
dilutive. See Notes to Financial Statements - Note 1. Significant
Accounting Policies.
The Company has assessed and continues to assess the impact of the
"year 2000" issue on its reporting systems and operations. The "year 2000"
issue exists because many computer systems and applications currently use
two-digit date fields to designate a year. As the century date occurs, date
sensitive systems will recognize the year 2000 as 1900 or not at all. This
inability to recognize or properly treat the year 2000 may cause systems to
process critical financial and operational information incorrectly. The
Company's system is a PC based network and all application software is
purchased from outside third parties that have a significant presence in
the oil and natural gas industry or in general application software. The
Company projects all computer systems and software will be year 2000
compliant during 1998. Management does not estimate future expenditures
related to the year 2000 exposure to be significant.
RESULTS OF OPERATIONS
The following table discloses the net oil and natural gas sales
volumes, average sales prices and average lifting costs for each of the
three years ended December 31, 1997, 1996, and 1995. The table is an
integral part of the following discussion of results of operations for the
periods 1997 compared to 1996 and 1996 compared to 1995.
% Increase % Increase
1997 (Decrease) 1996 (Decrease) 1995
Net sales volumes:
Oil (MBbls) 1,197 28 % 933 11 % 839
Natural gas (MMcf) 7,116 (13)% 8,219 40 % 5,867
Average sales price:
Oil (per Bbl) $ 17.79 (12)% $ 20.21 21 % $ 16.64
Natural gas (per Mcf) $ 5.06 (11)% $ 5.69 (17)% $ 6.89
Average lifting costs
(per BOE) $ 1.68 1 % $ 1.66 (4)% $ 1.73
1997 Compared to 1996
The Company incurred a net loss for 1997 of $26.8 million or $1.31
per share compared to the prior year loss of $7.6 million or $0.37 per
share. The net loss for 1997 included non-cash charges totaling $18.9
million or $0.94 per share. The charges included deferred income tax
expense of $14.6 million or $0.73 per share, impairment charges from
marginal oil and gas properties of $3.9 million or $0.19 per share, and
accelerated amortization of debt-issue costs of $416,000 or $0.02 per
share, caused by the early retirement of some of the Company's Notes. In
addition, during 1997, the Company incurred reorganization costs totaling
$7.1 million, or $0.34 per share, and legal costs and expenses totaling
$2.5 million, or $0.12 per share.
Total revenues were $ 61.1 million for the year ended December 31,
1997 compared to $70.2 million for the year ended December 31, 1996.
Natural gas sales revenue decreased $10.7 million, or 23%, for 1997
compared to 1996. Lower natural gas production caused the decrease but was
partially offset by higher average prices of 6% for spot gas sales and 10%
for natural gas sales under the South Pass gas sales contract. The increase
in average prices added $1.3 million to natural gas sales revenue. Natural
gas production from South Pass Block 89 Platform B decreased 1.4 Bcf during
1997 as production from Well B-20 experienced anticipated declines. The
decrease in natural gas production from Platform B caused natural gas
revenues to decrease by $14.2 million. Natural gas production from the
Company's South Texas properties increased 379,000 Mcf during 1997 but was
more than offset by lower net natural gas production from other offshore
properties.
An increase in oil production partially offset by lower oil prices
resulted in a net increase in oil sales revenue of $2.4 million, or 13%,
for the year ended December 31, 1997 as compared to the prior year. Oil
production increased by 264,000 barrels which increased oil sales revenue
by $4.8 million. However, a decrease of $2.44 in average oil prices caused
oil sales revenue to be $2.4 million lower. A net increase in oil
production came from all areas of operation primarily the Parker Creek
field in Mississippi and South Pass 86 and 87 in the Gulf of Mexico.
Interest income was lower in 1997 because of the sale of the
marketable securities in October. Most of the proceeds of the sale were
used to purchase $16.7 million of the Company's outstanding Notes. Other
income was lower because of lower oil trading income and losses on the sale
of assets, primarily artwork.
Operating and transportation expenses increased as a result of new
operating properties and an increase in oil production from the South Pass
area. Net Profits expense decreased as a result of the lower natural gas
sales revenues from South Pass Block 89. In addition, Exploration expenses
decreased significantly as a result of lower dry hole costs. In 1996 the
Company drilled three high cost dry exploration wells totaling $10.6
million in the Gulf of Mexico.
Depreciation, depletion and amortization expenses increased because of
new properties becoming productive. Marginal production as well as lower
oil prices caused the Company to record impairment charges against some of
the oil and natural gas properties. A large decrease in production during
the last quarter of 1997 from Main Pass Block 262, located in the Gulf of
Mexico, caused the Company to record a $1.9 million impairment charge to
write down 100% of the remaining well costs. The Company will use the
platform on Main Pass Block 262 to drill a new unrelated prospect in 1998.
Another $1.2 million charge was recorded on the Hub property located in
Mississippi. This property was drilled in 1996 but never performed up to
expectations. The remaining impairment charge related primarily to lower
oil prices which reduced the amount of commercially recoverable oil
reserves.
General and administrative expenses decreased by 18% during 1997 when
compared to 1996. Salaries and other employment related expenses during
1997 decreased $706,000 as the number of employees decreased from 41 at
December 31, 1996 to 15 at December 31, 1997. Other areas of significant
savings were professional fees and investor relations' expenses. Legal
fees decreased by $1.1 million as the Company settled the Griffin
litigation including all of the surrounding litigation, ended the family
litigation, and concluded the trial proceedings in the Phillips
litigation.
Reorganization expense for the year includes payments to employees
under the employee severance agreements and legal fees or other charges
that relate to or were paid because of the Simplot Transaction.
Reorganization costs accrued or paid are as follows: employee severance
payments $3.6 million, Thomas D. Box severance, legal claims and fees $1.2
million, Mr. Simplot and Mr. Lyle $2.0 million, and other associated
expenses $300,000. See Notes to the Financial Statements - Note 5.
Reorganization Costs.
Interest and financing expenses increased during 1997 when compared to
1996 as a result of interest costs from a $6.0 million balance on the line
of credit and a non-cash charge for deferred offering costs in October
1997, partially offset by lower interest costs from a reduced outstanding
balance on the Notes. The Company used the line of credit to provide a
portion of the funds to purchase some onshore Gulf Coast properties. In
addition, under the terms of the Indenture, the Company purchased $16.7
million of the Notes. The Simplot transaction triggered the offer to
purchase requirement in the Indenture.
Although the Company expects to realize the benefits of the deferred
income tax asset, it adopted a more conservative view of the accounting and
reporting policies and increased the valuation allowance in 1997 to reserve
the full amount of the deferred income tax asset. The Company believes that
this approach is consistent with other small-cap exploration and production
companies particularly those companies that are attempting to grow their
oil and natural gas reserves. The Company is required to analyze its
ability to realize the deferred income tax asset based on proved reserves
and a "more likely than not" scenario for future projections. The analysis
excludes probable and possible oil and natural gas reserves and does not
include results from future drilling activities. The Company concluded that
based on the future growth plans of the Company, prior actual results, and
the "more likely than not" criteria, it was more desirable to reserve the
entire deferred income tax asset. The Company will realize a benefit from
these tax attributes if income is generated in the future.
1996 Compared to 1995
The Company incurred a net loss for 1996 totaling $7.7 million, or
$0.37 per share. This loss resulted primarily from a $15.9 million, or
323%, increase in exploration expenses; a $7.8 million, or 52%, increase in
depreciation, depletion and amortization expense on the oil and natural gas
properties, and a $4.0 million, or 43%, increase in general and
administrative and reorganization expenses. Exploration expenses increased
because of higher dry hole costs which resulted from the increased drilling
activity. The most significant dry holes drilled during the year included
the following offshore Gulf of Mexico blocks: Ship Shoal Block 352 at $7.9
million, High Island Block 576 at $1.8 million and West Cameron Block 365
at $923,000. Depreciation, depletion and amortization expense increased as
a result of new properties being depleted, an increase in the depreciable
basis of offshore platforms and a decrease in net oil and natural gas
reserves.
General and administrative expenses and reorganization costs were
higher because of an increase in legal fees primarily related to the
reimbursement of legal fees to the Estate of Cloyce K. Box for the Simplot
litigation and the "change in control" which occurred when BBHC replaced
the existing Board of Directors by a written consent effective July 30,
1996. The "change in control" triggered the applicability of severance
agreements which then resulted in the payment of severance benefits in
certain situations. Resignations and terminations decreased the total
number of employees from 55 prior to July 30, 1996, to 41 at December 31,
1996.
Natural gas revenue increased $6.3 million primarily as a result of
higher average natural gas prices. Although the average sales price shown
on the table above reflects a decrease, such decrease in prices is a result
of the lower percentage of total volume from South Pass Block 89 sold at
above market prices compared to a higher percentage of total volume from
other areas which were sold at spot market prices during 1996 as compared
to the prior years. The 10% per annum increase in the gas price for South
Pass Block 89 production, in accordance with the gas sales contract,
resulted in an additional $3.3 million in natural gas sales revenue.
Average spot market prices for natural gas increased from $1.88 in 1995 to
$2.45 for 1996, which added another $2.4 million to natural gas sales
revenue. In addition, production from Platform D located in South Pass
Block 87, Main Pass Block 262, and other properties increased by 3.0 Bcf,
or 222%, when compared to 1995, resulting in an additional $6.7 million in
natural gas sales revenue. However, the above increases were partially
offset by a 624,000 Mcf decrease in natural gas production from South Pass
Block 89 which, when combined with the high contract price received for
production from this block, lowered natural gas sales revenue by $5.5
million. Natural gas production from South Pass Block 89 decreased because
the B-11 Well experienced mechanical difficulties in March 1996, and
attempts to drill a replacement well in 1996 were not successful. Net
natural gas production from South Pass Block 86 decreased 296,000 Mcf,
resulting in a decrease in natural gas sales revenue totaling $550,000.
Oil sales increased $4.9 million, or 35%, because of an increase of
$3.57 in the average oil price from $16.64 to $20.21 and an increase in
total oil production of 94,000 Bbls. The increase in price caused oil sales
revenue to increase $3.3 million, and the increase in production caused oil
sales revenue to increase $1.6 million. Oil production increased as a
result of a full year of production from Platform D producing from South
Pass Block 87 and West Delta Block 128, and new production from the Indian
Wells field in Mississippi and other onshore oil properties. Platform D
production increased 233,000 Bbls and new production from the Indian Wells
Field totaled 39,000 Bbls in 1996. Oil production from South Pass Blocks 86
and 89 decreased primarily as a result of natural depletion of the
reservoirs.
In 1995, the Company sold real estate properties in Mississippi and
Louisiana for a total gain of $1.0 million as part of a reorganization plan
adopted in early 1995. In 1996, the gain from the sales of real estate in
Mississippi and Louisiana was $93,000. The decrease was partially offset by
a $661,000 increase in net oil trading income.
Operating expenses were $889,000, or 16%, higher in 1996 because of
the increase in the number of operating properties, a full year of
operating cost from Platform D in South Pass Block 87, and a partial year
of operating costs from Main Pass Block 262. Net Profits expense decreased
approximately 8%, or $1.0 million primarily, because of a net decrease in
natural gas revenues from South Pass Block 89 as described above.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO FINANCIAL STATEMENTS
Reports of Independent Accountants 21
Balance Sheets as of December 31, 1997 and 1996 22
Statements of Income for 1997, 1996 and 1995 23
Statements of Stockholders' Equity for 1997, 1996 and 1995 24
Statements of Cash Flow for 1997, 1996 and 1995 25
Notes to Financial Statements 26
REPORT OF INDEPENDENT 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") as of December 31, 1997 and 1996 and the
related statements of income, stockholders' equity and cash flows for each
of the two years in the period ending December 31, 1997. These 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 generally accepted auditing
standards. 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, 1997 and 1996 and the results of its
operations and its cash flows for each of the two years in the period ended
December 31, 1997 in conformity with generally accepted accounting
principles.
Dallas, Texas
March 20, 1998 /S/ ARTHUR ANDERSEN LLP
To The Stockholders and Board of Directors of
Remington Oil and Gas Corporation
We have audited the accompanying statements of income, stockholders'
equity and cash flows of Remington Oil and Gas Corporation (formerly Box
Energy Corporation) for the year ended December 31, 1995. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based
on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. 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 audit
provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the results of operations and cash flows
of Remington Oil and Gas Corporation for the year ended December 31, 1995
in conformity with generally accepted accounting principles.
Dallas, Texas
March 5, 1996, except for the thirteenth
paragraph of Note 1 as to which the
date is March 27, 1998
/S/ COOPERS & LYBRAND L.L.P.
Remington Oil and Gas Corporation
Balance Sheets
(In thousands, except share data)
For Years Ended
December 31,
Assets 1997 1996
Current assets
Cash and cash equivalents $ 4,552 $ 2,997
Marketable securities - available for sale - 32,678
Accounts receivable - oil and natural gas 5,725 7,093
Accounts receivable - other 268 1,456
Note receivable - S-Sixteen Holding Company 6,192 -
Prepaid expenses and other current assets 2,118 1,961
Total current assets 18,855 46,185
Properties
Unproved oil and gas properties 8,755 6,504
Oil and natural gas properties
(successful-efforts method) 211,726 180,747
Other properties 2,800 3,226
Accumulated depreciation, depletion and
amortization (144,548) (116,371)
Total properties 78,733 74,106
Other assets
Deferred income taxes (net of valuation
allowance) - 14,723
Deferred charges (net of accumulated
amortization) 927 1,585
Total other assets 927 16,308
Total assets $ 98,515 $ 136,599
Liabilities and stockholders' equity
Current liabilities
Accounts payable $ 8,694 $ 5,043
Accrued interest payable 264 379
Accrued transportation payable - related party 305 263
Net Profits expense payable 594 1,481
Short-term notes payable 6,000 -
Total current liabilities 15,857 7,166
Convertible subordinated notes payable 38,371 55,077
Total Liabilities 54,228 62,243
Commitments and Contingencies (Note 11)
Stockholders' equity
Common Stock, $1.00 par value
Class A (Voting) - 15,000,000 shares
authorized; 3,250,110 shares issued 3,250 3,250
Class B (Non-Voting) - 30,000,000 shares
authorized; 17,553,010 shares issued 17,553 17,553
Additional paid-in capital 25,197 25,197
Treasury stock, at cost, 31,100 shares
Class A, and 465,600 shares Class B (3,465) -
Retained earnings 1,752 28,542
Valuation allowance for marketable securities - (186)
Total stockholders' equity 44,287 74,356
Total liabilities and stockholders' equity $ 98,515 $ 136,599
See accompanying Notes to Financial Statements.
Remington Oil and Gas Corporation
Statements of Income
(In thousands, except per share amounts)
Years Ended December 31,
1997 1996 1995
Revenues
Oil sales $ 21,292 $ 18,849 $ 13,966
Gas sales 36,012 46,757 40,440
Interest income 1,998 2,273 2,123
Gain (loss) investment (125) (73) -
Other income 1,876 2,404 2,964
Total revenues 61,053 70,210 59,493
Costs and expenses
Operating costs and expenses 4,015 3,825 3,142
Transportation expense 2,851 2,491 2,285
Net Profits Interest expense 8,341 11,479 12,500
Exploration expenses 8,554 20,805 4,924
Depreciation, depletion and amortization 24,298 22,349 14,401
Impairment of oil and natural gas properties 3,953 451 566
General and administrative 6,344 7,731 7,073
Legal expense 2,509 3,657 1,452
Reorganization expense 7,072 1,959 800
Interest and financing expense 5,283 4,895 4,836
Total costs and expense 73,220 79,642 51,979
Income (loss) before taxes (12,167) (9,432) 7,514
Income tax expense (benefit) 14,623 (1,770) 2,122
Net income (loss) $ (26,790) $ (7,662) $ 5,392
Basic and diluted income (loss) per share $ (1.31) $ (0.37) $ 0.26
See accompanying Notes to Financial Statements.
Remington Oil and Gas Corporation
Statements of Stockholders' Equity
(In thousands)
Common Stock Valuation
Class A Stock Class B Stock Additional Allowance
Par Par Paid in Retained Treasury Marketable
Shares Value Shares Value Capital Earnings Stock Securities
Balance
December 31,
1994 3,250 $3,250 17,553 $17,553 $25,197 $30,812 $ - $(1,299)
Net income 5,392
Unrealized gain
(net of income
taxes) 1,142
Balance
December 31,
1995 3,250 3,250 17,553 17,553 25,197 36,204 - (157)
Net income
(loss) (7,662)
Unrealized loss
(net of income
taxes) (29)
Balance
December 31,
1996 3,250 3,250 17,553 17,553 25,197 28,542 - (186)
Net income
(loss) (26,790)
Purchase of
Treasury Stock (3,465)
Unrealized gain
(net of income
taxes) 186
Balance
December 31,
1997 3,250 $3,250 17,553 $17,553 $25,197 $ 1,752 $(3,465) $ -
See accompanying Notes to Financial Statements.
Remington Oil and Gas Corporation
Statements of Cash Flows
(In thousands)
Years Ended December 31,
1997 1996 1995
Cash flow provided by operations
Net income (loss) $ (26,790) $ (7,662) $ 5,392
Depreciation, depletion and amortization 24,298 22,349 14,401
Impairment of oil and natural gas properties 3,953 451 566
Amortization of deferred charges 658 262 254
Amortization of premium on marketable securities 27 27 15
Deferred income tax (benefit) expense 14,623 (1,696) 1,995
Dry hole costs 5,319 17,638 2,223
Decrease in accounts receivable 2,556 105 (3,492)
(Increase) in prepaid expenses and other current
assets (157) (1,298) (127)
Increase (decrease) in accounts payable and
accrued expenses 2,692 (1,201) 3,900
Loss (gain) on sale of properties 367 (20) (1,080)
Net cash flow provided by operations 27,546 28,955 24,047
Cash from investing activities
Payments for capital expenditures (39,144) (39,798) (21,274)
Proceeds from property sales 702 260 1,375
Net cash used in investing activities (38,442) (39,538) (19,899)
Cash from financing activities
Proceeds from notes payable 7,000 - -
Payments on notes payable (1,000) - -
Sales and maturities of marketable securities 33,411 19,127 -
Investment in marketable securities (597) (27,191) -
Notes receivable - S-Sixteen Holding Company (7,250) - -
Principal repayments - S-Sixteen Holding Company 1,058 - -
Repurchase common stock (3,465) - -
Principal payments on Convertible Subordinated
Notes (16,706) - -
Net cash provided by (used in) financing activities 12,451 (8,064) -
Net increase (decrease) in cash and cash equivalents 1,555 (18,647) 4,148
Cash and cash equivalents at beginning of period 2,997 21,644 17,496
Cash and cash equivalents at end of period $ 4,552 $ 2,997 $ 21,644
See accompanying Notes to Financial Statements.
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
Remington Oil and Gas Corporation, formerly Box Energy Corporation,
(the "Company" or "Remington") is an independent oil and gas exploration
and production company with activity and properties in three core areas:
offshore Gulf of Mexico, Mississippi/Alabama and onshore Gulf Coast.
Originally organized in 1981 as OKC Limited Partnership (the
"Partnership"), the Company converted to a corporation on April 15, 1992
(the "Corporate Conversion"). The Corporate Conversion involved the
exchange of common stock for the assets and liabilities of the Partnership.
Management prepares the financial statements in conformity with generally
accepted accounting principles. 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. Actual results could differ from those
estimates. The Company makes certain reclassifications to prior year
financial statements in order to conform to the current year presentation.
S-Sixteen Holding Company ("SSHC") (formerly known as Box Brothers
Holding Company ("BBHC")) owns 1.8 million shares or approximately 57% of
the Company's outstanding Class A (Voting) Common Stock ("Class A Stock").
On August 29, 1997, entities controlled by Mr. J. R. Simplot purchased BBHC
(the "Simplot Transaction").
Cash and Cash Equivalents
Cash equivalents consist of liquid investments with maturities of
three months or less when purchased, including investment grade commercial
paper and money market funds invested in United States government
securities. Cash and cash equivalents are stated at cost that approximates
market value.
Marketable Securities
Marketable securities, classified as available-for-sale, are recorded
on the balance sheet at their market value on the balance sheet date.
Unrealized holding gains and losses for securities classified as available-
for-sale are excluded from earnings and recorded, net of tax, as a separate
component of stockholders' equity.
Oil and Natural Gas Properties
The Company uses the successful-efforts accounting method for oil and
gas exploration and development expenditures. Capitalized costs include
leasehold acquisition costs, development costs, including costs of tangible
equipment, intangible drilling costs and certain interest costs. Costs
classified and charged to exploration expense include geological,
geophysical and other prospecting costs. The Company capitalizes drilling
costs for exploratory wells pending a determination of commercial oil and
natural gas reserves. The costs of exploratory wells that do not ultimately
find commercial oil and natural gas reserves are charged to exploration
expense as a dry hole cost. The Company amortizes capitalized costs using
the units-of-production method based on total proved reserves for leasehold
acquisition costs and total proved developed oil and natural gas reserves
for all other capitalized costs. The Company capitalizes interest costs
incurred for construction of major facilities such as offshore platforms.
No interest was capitalized in 1997 or 1996, and $69,000 was capitalized in
1995.
Periodically the Company records an impairment expense for oil and
natural gas properties when the net book value of a particular property is
greater than the undiscounted future net cash flows before income taxes
from that same property. Certain events such as drilling a dry hole, a
large decrease in oil and natural gas reserves or production and
significantly lower oil and natural gas prices cause the Company review the
property to determine if an impairment charge is proper. The impairment
loss is equal to the difference between the net book value and the fair
value of the asset. Undiscounted future net cash flow includes estimated
proved and risk adjusted probable and possible oil and natural gas
reserves. The Company uses the present value of the future net cash flows
from proved oil and natural gas reserves discounted at an appropriate rate
to estimate the fair value of the asset.
Impairment losses totaling $3.9 million, $451,000, and $566,000 were
recognized during 1997, 1996, and 1995, respectively. In 1997, the
Company's impairment losses included interests in Main Pass Block 262,
located in the Gulf of Mexico, the Hub Prospect and East Melvin properties
located in Mississippi and the Bronco S. W. and Whopper II properties
located in Texas and New Mexico, respectively. In 1996, the impairment
losses included the Company's interests in East Melvin and Raleigh
properties located in Mississippi. In 1995, the Company recorded an
impairment of the Traxler property located in Mississippi.
Future dismantlement, restoration and abandonment ("DR&A") costs
include the estimated costs to dismantle, restore and abandon the Company's
offshore platforms, flowlines, wells and related structures. The total
estimated future DR&A liability is $4.2 million. The liability is accrued
over the life of the property using the units-of production method and
recorded as a component of depreciation, depletion and amortization
expense. The accrued liability at December 31, 1997 and 1996 was $3.1
million and $2.5 million, respectively. See Note 12. Supplemental
Disclosures - Oil and Natural Gas Properties.
Other Properties
Other properties include leasehold improvements, furnishings and
equipment for office space leased by the Company and are depreciated on a
straight-line method over their estimated useful lives ranging from 3 to 12
years.
Deferred Charges
Deferred charges are the costs incurred in 1992 with respect to the
Company's offering of the Notes, as defined in Note 5 below. The deferred
charges are amortized to interest and financing costs on a straight-line
basis over the 10-year term of the Notes. In October 1997, the Company
purchased $16.7 million of the outstanding Notes. The retirement of these
Notes resulted in the accelerated amortization of the deferred offering
costs totaling $416,000. See Note 7. Notes Payable.
Oil and Gas Revenues
The Company recognizes oil and natural gas sales as revenue in the
month of production. The Company's actual sales are not materially
different from its entitled share of production. There are no significant
natural gas imbalances for the years ended December 31, 1997, 1996, and
1995.
Income Taxes
Income tax expense or benefit includes the current income taxes and
deferred income taxes. Current income tax expense or benefit is the amount
calculated on the current year income tax return. Deferred income tax
expense or benefit is calculated as the change in the net deferred income
tax asset or liability at the beginning of the year compared to the end of
the year. The amount of the deferred income tax asset or liability is
determined 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 the temporary differences or carry-forwards expect to
be reversed or utilized. A valuation allowance offsets deferred income tax
assets, which are not expected to reverse in future years using a "more
likely than not" scenario that excludes probable and possible oil and
natural gas reserves. See Note 6. Deferred Income Tax Asset and Income
Taxes.
Income per Common Share
The Company adopted Statement of Financial Accounting Standards
("SFAS") No. 128, entitled "Earnings per Share" in 1997. SFAS simplifies
the standards for computing earnings per share previously found in
Accounting Principles Board ("APB") Opinion No. 15. Primary income per
share has been replaced by basic income per share. Basic income per share
excludes dilution and is computed 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. Diluted income per share is computed
similarly to fully diluted income per share pursuant to APB Opinion 15. As
a result of the adoption of SFAS No. 128 income per share has been restated
to conform with the provisions of the statement. The amounts restated equal
the amounts as reported in the prior years. The following table presents
the Company's calculation of basic and diluted income per share.
For Years Ended December 31,
1997 1996 1995
(In thousands, except per share data)
Net income (loss) available for basic
income per share $ (26,790) $ (7,662) $ 5,392
Interest expense on the Notes
(net of tax) (1) - - -
Net income (loss) available for diluted
income per share $ (26,790) $ (7,662) $ 5,392
Basic income (loss) per share $ (1.31) $ (0.37) $ 0.26
Diluted income (loss) per share $ (1.31) $ (0.37) $ 0.26
Weighted average
Class A Stock 3,233 3,250 3,250
Class B Stock 17,291 17,553 17,553
Total Common shares for basic income
(loss) per share 20,524 20,803 20,803
Dilutive stock options outstanding
(treasury stock method) (1) - - -
Shares assumed issued by conversion
of the Notes (1) - - -
Total common share for diluted income
(loss) per share 20,524 20,803 20,803
(1) Non dilutive.
Potential increase to net income for
diluted income per share
Interest expense on Notes (net of tax) $ 2,835 $ 2,954 $ 2,954
Potential issues of common stock for
diluted income per share
Weighted average stock options granted 99 302 312
Weighted average shares issued assuming
conversion of Notes 4,741 5,007 5,007
NOTE 2. MARKETABLE SECURITIES
The following table presents the amortized costs of all marketable
securities, the range of maturities and the gross unrealized holding gains
and losses.
At December 31,
1997 1996
(In thousands)
Amortized cost of marketable securities:
Maturities within one year
United States government and agency debt securities - $ 1,240
Corporate debt securities - 1,491
Maturities between one and five years
United States government and agency debt securities - 21,001
Corporate debt securities - 7,679
Foreign government debt securities - 1,553
Total amortized cost of marketable securities - 32,964
Gross unrealized holding gains - 47
Gross unrealized holding losses - (333)
Net carrying value at year end - $ 32,678
Realized gains and losses are computed based on specific
identification of the securities sold. The proceeds from the sale of
available-for-sale securities and the gross realized gains and losses and
change in net unrealized holding gains and losses included as a separate
component of shareholders' equity were as follows:
For Years ended December 31,
1997 1996 1995
(In thousands)
Sales Proceeds $ 33,411 $ 8,127 $ -
Gross realized gains $ 46 $ 7 -
Gross realized (losses) $ (169) $ (80) -
Change in net unrealized holding
gains and losses $ 186 $ (29) $ 1,142
NOTE 3. NOTE RECEIVABLE S-SIXTEEN HOLDING COMPANY
On April 29, 1997, the Company lent SSHC $7.25 million. The original
May 29, 1997 due date was extended to June 3, 1997, at which time the note
receivable was replaced by a new $6.95 million note receivable dated June
3, 1997. The new note receivable matures May 29, 1998, and requires monthly
installment payments of principal and interest totaling $100,000 commencing
June 29, 1997. The interest rate is equal to the prime rate of Texas
Commerce Bank National Association plus 1% until the sixth month when the
rate escalates monthly by 0.1% over the previous month's rate. Pledged as
collateral under a related Amended and Restated Pledge Agreement (the
"Pledge Agreement") are the 1.8 million shares of the Company's Class A
Stock, 800,000 shares of CKB Petroleum, Inc. ("CKBP") common stock and
800,000 shares of CKB & Associates, Inc. ("Associates") common stock owned
by SSHC. The pledged stock represents approximately 57%, 94% and 94% of the
outstanding shares of the classes stock, respectively. The fair market
value of the collateral is required to be $2.00 for each $1.00 of unpaid
principal debt. Failure to pay the monthly installment within 10 days and
failure to maintain fair market value of collateral are two, among several,
actions which constitute events of default under the Pledge Agreement. In
the event of default, as defined in the Pledge Agreement, the Company, upon
five days' notice to SSHC, has the right to foreclose upon and sell the
collateral stock. The Pledge Agreement also provides that upon the
occurrence and during the continuance of an event of default, if the
collateral has not been foreclosed upon, the Company may direct the vote of
the collateral stock.
NOTE 4. NET PROFITS EXPENSE
The Company pays a Net Profits expense to Phillips Petroleum
Company("Phillips") party pursuant to a farmout agreement regarding the
Company's working interest in the oil and gas lease covering South Pass
Block 89. Net Profits expense is calculated as 33% of the Company's "net
profits" from the subject lease, as defined in the farmout agreement.
Phillips and the Company are involved in litigation concerning the
calculation and inclusion of certain revenues or expenses in the "net
profits account." See Note 11. Commitments and Contingencies - Phillips
Petroleum Case. The following table summarizes the Net Profits expense
calculation:
For years ending December 31,
1997 1996 1995
(In thousands)
South Pass Block 89
Oil and natural gas revenue
(net of transportation) $ 30,567 $ 42,063 $ 45,354
Operating, overhead and capital expenditures (5,292) (7,279) (7,475)
"Net Profits" from South Pass Block 89 $ 25,275 $ 34,784 $ 37,879
Net Profits expense (at 33%) $ 8,341 $ 11,479 $ 12,500
NOTE 5. REORGANIZATION COSTS
Reorganization expense includes employee severance expense, litigation
settlement amounts and other costs. The litigation settlement amounts and
certain other costs were connected with the Simplot Transaction. The
expense accrued and recorded through December 31, 1997, 1996, and 1995 was
$7.1 million, $2.0 million, and $800,000, respectively, of which $9.6
million has been paid as of December 31, 1997. The remaining accrued
reorganization liability on December 31, 1997 is $361,000.
Employee Severance
The Company's prior management entered into severance agreements with
its employees in December 1995. The severance agreements provided between 6
and 18 months' pay plus certain benefits to employees terminated by the
Company without cause (as defined in the severance agreements) or who
resign for good reason. Good reason (as defined in the severance
agreements) includes, among other things, any change in benefits or job
status that an employee believes is adverse to that employee. On July 30,
1996, certain of the Company's Directors were replaced by written consent
of the holders of more than a majority of the Company's Class A stock. The
replacement of the directors caused a change in control as defined in the
severance agreements and the agreements became exercisable.
During 1997, 31 employees were dismissed, resigned or notified the
Company of their resignation. The 31 employees included three executive
officers (Senior Vice President/Operations, Vice President/Marketing and
Supply, and Treasurer), ten employees from the operations technical staff
(eight geologists and geophysicists, one engineer and one landman), and 18
other professional or clerical personnel. The total employee severance
expense during 1997 was $3.6 million. In 1996, under the same severance
agreements, 15 employees were dismissed, resigned or notified the Company
of their resignation. The employees included the Chief Executive Officer,
Executive Vice President, Chief Financial Officer, General Counsel, and
Chief Accounting Officer. The reorganization expense for 1996 was $2.0
million which included severance pay, related legal fees and other related
costs. During 1995, the Company adopted a reorganization plan which
eliminated eight positions within the Company, including personnel involved
with corporate development and the management of the Company's real estate
properties in Mississippi and Louisiana. Total reorganization costs
included primarily severance pay and benefits to terminated employees, but
also included rent expense on closed offices.
Thomas D. Box Settlement
In the third quarter of 1997, in connection with the Simplot
Transaction, the Company agreed to pay Thomas D. Box $1.2 million to settle
his severance claims and lawsuits against the Company. See Note 11.
Contingencies - Thomas D. Box Cases. Mr. Box was the Chief Executive
Officer and President of the Company before his termination by the
Company's Board of Directors in August 1996. Additionally, Mr. Box was
granted options to purchase 50,000 shares of Class B Stock at $9.00 per
share, office furniture, computer equipment and a 3-D seismic workstation.
Simplot Settlement
Further, in connection with the Simplot Transaction, the Company and
the plaintiffs in the Griffin Case executed a letter of intent to settle
all the litigation brought by the plaintiffs. See Note 11. Contingencies -
Griffin Case. Under the terms of the subsequently-executed settlement
agreement, the Company paid Mr. Simplot $1.9 million for attorneys' fees
and Mr. James Arthur Lyle (one of the plaintiffs in the Griffin Case)
$100,000 for attorneys' fees. The amounts were accrued in the third quarter
of 1997 and paid during the fourth quarter of 1997.
NOTE 6. DEFERRED INCOME TAX ASSET AND INCOME TAXES
The significant components of the Company's deferred tax asset are as
follows:
At December 31,
1997 1996
(In thousands)
Excess of tax basis over book basis for oil
and natural gas properties $ 11,012 $ 7,461
Excess of tax basis over book basis for other
properties 192 133
Excess of tax basis over book basis for
marketable securities - 100
Excess of accrued book liabilities over tax
liabilities 1,204 862
Federal income tax operating loss carry-forward 9,549 9,072
Federal long-term capital loss carry-forward 197 197
Alternative minimum tax credit carry-forward 262 262
Total deferred tax asset 22,416 18,087
Valuation allowance (22,416) (3,364)
Net deferred tax asset $ - $14,723
The Company carried over the tax basis in the oil and gas properties
from the Partnership. The tax basis for the Partnership consisted primarily
of the sum of each partner's tax basis in the oil and gas properties, which
exceeded the Company's book basis as accounted for under generally accepted
accounting principles. The unused federal income tax operating loss carry-
forward of $27.3 million will expire during the years 2007 through 2012 if
not previously utilized, and the long-term capital loss carry-forward of
$563,000 will expire in 1999. Although the Company expects to realize the
benefits of the deferred income tax asset, it adopted a more conservative
view of the accounting and reporting policies and increased the valuation
allowance in 1997, to reserve the full amount of the deferred income tax
asset. The Company believes that this approach is consistent with other
small-cap exploration and production companies particularly those companies
that are attempting to grow their oil and natural gas reserves. The Company
is required to analyze its ability to realize the deferred income tax asset
based on proved reserves and a "more likely than not" scenario for future
projections. The analysis excludes probable and possible oil and natural
gas reserves and does not include results from future drilling activities.
The Company concluded that based on the future growth plans of the Company,
prior actual results, and the "more likely than not" criteria it was more
desirable to reserve the entire deferred income tax asset. The following
table provides a reconciliation of the Company's income tax expense or
(benefit):
For the Years Ended December 31,
1997 1996 1995
(In thousands)
"Expected" tax expense (benefit) (computed at 35%
of income before taxes) $ (4,258) $ (3,301) $ 2,630
Expense (benefit) from change in book and tax
basis differences 230 932 (2,397)
(Benefit) from alternative minimum tax credit - - (127)
(Benefit) from long-term capital loss carry-forward - - (197)
Utilization (benefit) of net operating loss (401) (363) 2,608
Total deferred income tax expense (benefit) (4,429) (2,732) 2,517
Valuation allowance 19,052 1,036 (522)
Net deferred income tax expense (benefit) 14,623 (1,696) 1,995
Current income tax expense (benefit) - (74) 127
Total income tax expense (benefit) $ 14,623 $ (1,770) $ 2,122
NOTE 7. NOTES PAYABLE
In December 1992, the Company issued $55.1 million of 8 1/4%
Convertible Subordinated Notes ("Notes"). The Notes mature December 1, 2002
and are convertible into shares of Class B (Non-Voting) Common Stock
("Class B Stock") at the election of the holder any time before maturity,
unless previously redeemed. Interest accrued at 8 1/4% per annum is payable
semiannually on each June 1 and December 1. The Company may redeem all or a
portion of the Notes any time after December 1, 1995, at 105.775% of the
face amount. This percentage decreases .825% each subsequent December 1.
The Notes are unsecured and subordinate in right of payment to all existing
and future senior indebtedness.
The Simplot Transaction caused a "change in control" as defined in the
Indenture for the Notes (the "Indenture"). On September 22, 1997, in
accordance with the Indenture, the Company made an offer to purchase the
Notes at 100% of the face amount, plus accrued interest. In October 1997,
the Company repurchased $16.7 million of the Notes outstanding, as a result
of the offer to purchase required by the Indenture.
During the second quarter of 1994, the Company established a one-year
line of credit with a bank. The line of credit with a borrowing base of
$10.0 million expires in June 1998. The Company renewed the line in 1995,
1996 and 1997. The line of credit is collateralized by the Company's South
Pass oil and natural gas properties. The interest rate for the line of
credit is the lender's floating base rate plus 0.5%. The Company has
borrowed $6.0 million and has issued letters of credit totaling $250,000
against this line of credit. The Company is currently negotiating an
increase in the borrowing base. The credit facility will expire in June
1998, unless renewed.
The estimated fair value of the Company's long-term indebtedness,
including the current maturities of such obligations, was approximately
$43.0 million and $55.8 million at December 31, 1997 and 1996,
respectively. The fair value was based on the quoted market bid price for
the Company's Notes and on current rates available to the Company for its
other indebtedness with the same remaining maturities.
NOTE 8. COMMON STOCK AND DIVIDENDS ON COMMON STOCK
The holders of Class A Stock and Class B Stock of the Company
participate equally in earnings, dividends and other characteristics. The
only difference between the two classes of stock is that Class A Stock has
voting rights while the Class B Stock has no voting rights, unless
otherwise required by Delaware law. Twenty eight thousand five hundred
shares of authorized but unissued Class B Stock have been reserved for the
two 1992 stock option plans, and 2.8 million shares have been reserved for
the 1997 Stock Option Plan. See Note 9. Employee and Director Benefit
Plans.
The Company has not paid a dividend since 1992. Currently, dividends
are not contractually restricted. However, in the event that the Company
pays dividends in excess of 2% of the market price of Class B Stock in a
calendar quarter, the conversion price for Class B Stock under the Notes
will be adjusted proportionally.
NOTE 9. EMPLOYEE AND DIRECTOR BENEFIT PLANS
Stock option plans
SFAS No. 123, entitled "Accounting for Stock-Based Compensation,"
encourages but does not require companies to record compensation cost for
stock-based employee compensation plans at fair value. During 1996, the
Company adopted the disclosure provisions of SFAS No. 123. The Company
continues 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 the Company's stock at the date of
the grant over the amount an employee must pay to acquire the stock.
The Company has two stock option plans: the 1992 Incentive Stock
Option Plan and the 1997 Stock Option Plan. A third plan, the 1992 Non-
Qualified Stock Option Plan was discontinued in1997. The Company no longer
uses the 1992 Non Qualified Stock Option Plan however, 28,500 options
remain outstanding. Under the 1992 Incentive Stock Option Plan 50% of the
options are exercisable no sooner than three years from the date of the
grant, and the remaining 50% may be exercised only after five years from
the date of the grant and the options expire ten years from the date of
grant.
The 1997 Stock Option Plan is intended to benefit the Company by
providing Directors and key employees of the Company with additional
incentives and giving them a greater interest as stockholders in the
success of the Company. The 1997 Stock Option Plan provides for the
issuance of options to purchase Class B Stock. A committee that includes at
least two or more outside Non-Employee Directors administers the plan. The
committee has the discretion to determine the participants to be granted
options, the number of shares granted to each person, the purchase price of
the Class B Stock covered by each option and other terms of the option.
Options granted under the plan may be either incentive stock options or
non-qualified stock options. The Company may issue up to 2.8 million shares
of Class B Stock upon the exercise of the options but no individual may be
issued more than 275,000 shares.
A summary of the Company's stock option plans as of December 31, 1997,
1996, and 1995 and changes during the years ending on those dates is
presented below:
For Years Ended December 31,
1997 1996 1995
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
Outstanding at beginning
of year 312,500 $ 9.52 622,000 $10.08 334,000 $11.71
Granted 426,500 $ 6.73 41,000 $ 8.85 353,800 $ 8.87
Exercised - - -
Forfeited (284,000) $ 9.51 (350,500) $10.43 (65,800) $11.88
Outstanding at end of year 455,000 $ 6.92 312,500 $ 9.52 622,000 $10.08
Options exercisable at
year-end 8,000 $11.88 38,600 $11.88 116,600 $11.98
Weighted-average fair value
of options granted during
the year $ 4.65 $ 6.15 $ 6.00
The options outstanding at December 31, 1997 have a weighted-average
remaining contractual life of 9 years and an exercise price ranging from $6
5/8 to $11 7/8 per share.
The following is a pro forma disclosure of the effect on net income or
loss if compensation cost for the Company's stock option compensation plans
had been determined consistent with SFAS No. 123.
For Years Ended December 31,
1997 1996 1995
(In thousands)
Net income (loss) As reported $(26,790) $(7,662) $ 5,392
Pro forma $(27,062) $(7,774) $ 4,987
Basic and diluted income (loss) per share As reported $ (1.31) $ (0.37) $ 0.26
Pro forma $ (1.32) $ (0.37) $ 0.24
The fair value of each option grant for the years ended December 31,
1997, 1996, and 1995 is estimated on the date of grant using the Black-
Scholes option-pricing model with the following weighted average
assumptions:
For the Years Ended December 31,
1997 1996 1995
Expected life (years) 10 10 10
Interest rate 6.19% 6.85% 5.97%
Volatility 49.50% 48.21% 47.96%
Dividend yield 0 0 0
Non-Employee Director Stock Purchase Plan
The Company approved the Non-Employee Director Stock Purchase Plan in
December 1997. The plan provides a means for the Non-Employee Directors to
receive their directors' fees in shares of Class B Stock. Each non-employee
Director of the Company may elect once each year to receive all or a
portion of the fees he receives as a director in restricted shares of Class
B Stock in lieu of cash. The number of shares received