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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997

COMMISSION FILE NUMBER: 000-20849

RUTHERFORD-MORAN OIL CORPORATION
(Exact name of registrant as specified in its charter)

DELAWARE 76-0499690
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)

5 GREENWAY PLAZA
SUITE 220
HOUSTON, TEXAS 77046
(Address of principal executive offices) (Zip Code)

REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 622-5555

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

None

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------

Common Stock, $0.01 par value NASDAQ National Market System

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 the voting stock held by non-affiliates of
the registrant as of March 25, 1998 was $158,316,476 based upon the average bid
and asked price on such date of $24.0625 per share.

Indicate the number of shares outstanding of each of the registrant's
classes of Common Stock, as of the latest practicable date.

NUMBER OF SHARES OUTSTANDING
TITLE OF EACH CLASS AT MARCH 25, 1998
------------------- ----------------------------

Common Stock, $0.01 par value 25,614,000

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant's Proxy Statement pertaining to the Registrant's 1998
Annual Meeting of Stockholders are incorporated by reference into Part III
hereof.
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TABLE OF ADDITIONAL REGISTRANTS

Each of the following subsidiaries of Rutherford-Moran Oil Corporation, and
each other subsidiary that is or becomes a guarantor of the 10 3/4% Senior
Subordinated Notes Due 2004 of the Company, is hereby deemed to be a registrant.

I.R.S.
STATE OR OTHER INDUSTRIAL EMPLOYER
JURISDICTION OF CLASSIFICATION IDENTIFICATION
NAME INCORPORATION NUMBER NUMBER
---- --------------- -------------- --------------

Thai Romo Limited.................................... Kingdom of 1311 76-0435668
Thailand
Thai Romo Holdings, Inc.............................. Delaware 1311 76-0511017
Rutherford-Moran Exploration Company................. Delaware 1311 76-0321674

Rutherford-Moran Oil Corporation (the "Company") is a holding corporation
that owns all of its assets and conducts all of its business through its
subsidiary, Thai Romo Limited ("Thai Romo") and its affiliate, B8/32 Partners,
Ltd. ("B8/32 Partners"), each a company existing under the laws of Thailand. The
Company is the parent company of Rutherford-Moran Exploration Company ("RMEC")
and Thai Romo Holdings, Inc. ("TRH"), which collectively own the outstanding
shares of Thai Romo, except for certain nominal interests. Thai Romo owns 46.34%
of B8/32 Partners. No separate financial information for RMEC, TRH, Thai Romo or
B8/32 Partners has been provided or incorporated by reference in this report
because: (1) the Company does not itself conduct any operations, but rather all
operations of the Company and its subsidiaries are conducted by Thai Romo and
B8/32 Partners; (ii) the Company has no material assets other than its ownership
in RMEC, TRH, Thai Romo and B8/32 Partners; and (iii) substantially all of the
assets and liabilities shown in the consolidated financial statements of the
Company are located in RMEC, TRH, Thai Romo and the Company's proportionate
interest in B8/32 Partners.
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TABLE OF CONTENTS

PAGE
----

Part I. Items 1. and 2. Business and Properties............................... 1
General..................................................... 1
History of Block B8/32...................................... 1
Regional Geology............................................ 2
Current Fields and Prospects................................ 3
Production Facilities....................................... 3
Marketing and Contracts..................................... 4
Thai Concession Terms....................................... 5
Joint Operating Agreement................................... 6
Business Conditions......................................... 6
Primary Customers........................................... 7
Oil and Gas Properties...................................... 7
Reserves.................................................... 7
Acreage and Productive Wells................................ 8
Drilling Activity........................................... 9
Thailand Taxes.............................................. 11
Competition................................................. 11
Employees................................................... 11
Offices..................................................... 12
Item 3. Legal Proceedings........................................... 12
Item 4. Submission of Matters to a Vote of Security Holders......... 12
Part II. Item 5. Market for Registrant's Common Equity and Related
Stockholder
Matters..................................................... 12
Item 6. Selected Financial Data..................................... 12
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 13
Introduction................................................ 13
Overview.................................................... 14
Results of Operations....................................... 16
Liquidity and Capital Resources............................. 17
Year 2000................................................... 18
Foreign Currency Fluctuation and Repatriation............... 19
Effects of Inflation........................................ 19
Changing Oil Prices......................................... 19
SFAS 130, 131 and 132....................................... 20
Item 8. Financial Statements and Supplementary Data................. 20
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 39
Part III. Item 10. Directors and Executive Officers of the Registrant.......... 39
Item 11. Executive Compensation...................................... 39
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 39
Item 13. Certain Relationships and Related Transactions.............. 39
Part IV. Item 14. Exhibits, Financial Schedules and Reports on Form 8-K....... 40

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PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

GENERAL

Rutherford-Moran Oil Corporation, a Delaware corporation ("RMOC" or the
"Company"), is an independent energy company engaged in the acquisition,
exploration, development and production of oil and gas properties in Southeast
Asia. Currently, the Company's exploration and development activities are
entirely in the Gulf of Thailand and are conducted through its subsidiary, Thai
Romo Limited ("Thai Romo") and its affiliate B8/32 Partners, Ltd. ("B8/32
Partners"), each a company existing under the laws of Thailand.

The Company was a private concern until June 1996 when it completed an
initial public offering (the "Offering"). Since April 1996, Rutherford-Moran Oil
Corporation has been the parent company of Rutherford-Moran Exploration Company
("RMEC") and Thai Romo Holdings, Inc. ("TRH"). RMEC and TRH collectively own the
outstanding shares of Thai Romo except for certain nominal interests. During
June 1996, RMOC sold 16% of its common stock in the Offering, in conjunction
with the consummation of the exchange of RMEC common stock and Thai Romo
interests for common stock of RMOC, (the "Exchange").

Thai Romo is one of four original concessionaires in Block B8/32 (sometimes
referred to as the "Block" or the "Concession"), currently covering
approximately 734,300 acres in the central portion of the Gulf of Thailand.
Currently, subsidiaries or affiliates of Pogo Producing Company ("Pogo"), The
Sophonpanich Co. Limited ("Sophonpanich") and B8/32 Partners are the other
concessionaires (together, the "Concessionaires") in the Block.

As of December 31, 1997, the Company had net proved reserves of
approximately 358 BCFE in the Tantawan and Benchamas Fields and the Maliwan
Area. Oil and gas production from the Tantawan Field commenced in February 1997,
and development is underway at the Benchamas Field. Appraisal wells drilled by
the Concessionaires in three areas within the Block (Tantawan, Benchamas and
Pakakrong) have tested at commercial flow rates of hydrocarbons and established
the potential for significant additional reserves in those areas. While testing
did not occur at any of the four wells drilled in the Maliwan Area, the results
of those wells indicated geological and reservoir properties substantially
similar to these other established areas. The Concessionaires have entered into
a 30 year Gas Sales Agreement (the "GSA") with the Petroleum Authority of
Thailand ("PTT") to sell natural gas from the Tantawan and Benchamas Fields. The
Company sells its oil into the spot market to a variety of potential purchasers
in Thailand and other Asian countries.

On January 22, 1998, the Company announced that it intends to explore
various strategic alternatives regarding the ongoing development of its interest
in the Block. Such alternatives include the possible merger or sale of the
Company.

The Company's principal executive offices are located at 5 Greenway Plaza,
Suite 220, Houston, Texas 77046 and the Company's telephone number is (713)
622-5555. Unless the context otherwise requires, reference to the business
conducted by the Company or RMOC shall mean the business conducted by the
Company or RMOC through its subsidiaries.

HISTORY OF BLOCK B8/32

In August 1991, Thai Romo, Thaipo Limited ("Thaipo") and Maersk Oil
(Thailand) Ltd. ("MOTL" or "Maersk") were awarded Petroleum Concession No.
1/2534/36 for Block B8/32 in the central portion of the Gulf of Thailand.
Subsequent to the award, Sophonpanich became one of the Concessionaires by
acquiring an interest in the Concession as a co-venturer. MOTL was designated as
Operator of the Block pursuant to a Joint Operating Agreement among the
Concessionaires.

The Company originally owned a 31.67% interest in the Block. On December
19, 1996, RMOC, through its subsidiary, Thai Romo, exercised its preferential
right to purchase 46.34% of the outstanding shares of MOTL and a
Co-Concessionnaire in the Block owning 31.67% interest in the Block outside of
the Tantawan

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Field (Thai Romo had increased its interest in the Tantawan Field from 31.67% to
46.34% in 1995 through a previous purchase of MOTL's interest in that Field). On
March 3, 1997, TRH, as Thai Romo's nominee under the Share Sales Agreement with
Maersk, purchased its proportionate share of the outstanding shares of MOTL for
approximately $28.6 million, which included approximately $1.6 million in
satisfaction of outstanding debt. Following the purchase, MOTL changed its name
to B8/32 Partners, Ltd. The remaining 53.66% of MOTL stock was purchased by
Thaipo, a subsidiary of Pogo and by Palang Sophon Limited ("Palang") of Bangkok,
Thailand, as successor to Sophonpanich. This acquisition increased RMOC's
interest in the Concession outside of the Tantawan Field from the original
31.67% to 46.34%, and effectively resulted in a uniform 46.34% interest
throughout the Block. At the same time, Thaipo was designated as operator for
the remainder of the Block. Current interests in the Tantawan Field and the
remainder of Block B8/32 are as follows:

TANTAWAN FIELD
--------------

Thaipo Limited.............................................. 46.34%
Thai Romo Limited........................................... 46.34%
Palang Sophon Limited....................................... 7.32%

REMAINDER OF BLOCK B8/32
------
Thaipo Limited.............................................. 31.67%
Thai Romo Limited........................................... 31.67%
B8/32 Partners Limited(1)................................... 31.66%
Palang Sophon Limited....................................... 5.00%

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

(1) B8/32 Partners Limited is owned by Thaipo, Thai Romo and Palang.

On August 23, 1995, the Thai Petroleum Committee and the Ministry of
Industry designated approximately 68,000 acres as a production license area to
Thaipo, on behalf of the Tantawan Concessionaires. Similar production licenses
have since been granted for 101,000 acres in the Benchamas Field/Pakakrong Area
and for 91,000 acres in the Maliwan Area.

In accordance with the Thai Petroleum Act, the Concessionaires relinquished
50% of the exploration acreage of the Block on August 1, 1995 and approximately
50% of the remaining acreage on August 1, 1997. Relinquishment excluded
production licenses in the aforementioned Tantawan, Benchamas/Pakakrong, and
Maliwan areas for which production approvals had been granted. In May 1997, Thai
Romo and its partners received an extension of the exploration period in the
Block until July 31, 2000 from the Department of Mineral Resources. Most of this
remaining acreage can be retained after July 2000 through payment of annual
lease rentals.

REGIONAL GEOLOGY

Block B8/32 is located on the western side of the Pattani Basin, which is
believed to have developed as a result of the Permo-Triassic collision of the
continents of India and Asia. The collision developed a tectonic regime in
Thailand which formed a conjugate set of major strike-slip faults trending
northwest to southeast and northeast to southwest together with a set of north
to south trending normal faults. The regional strain field accompanying the
shearing had a major component of east-west extension which created the Pattani
Basin and its gas rich structures to the south (e.g., Erawan, Pailin and Satun).
Management believes the Tantawan, Benchamas, and Maliwan Fields are a northern
continuation of the same trend. The eastern boundary of Block B8/32 is located
near the axis of the Pattani Basin. The Basin extends north-northeast through
the eastern one-third of Block B8/32 and extends southward through Unocal's
extensive holdings. The basin is bounded to the west by the Ko Kra Ridge, a
dominant paleo high.

Regional structural dip towards the Pattani Basin center is interrupted by
north-south trending normal faults. These fault zones are related to basement
relief features. Oil and natural gas traps in Block B8/32 are typically related
to highly faulted graben systems, structural closure on tilted fault blocks and
anticlinal

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structures between east-west dipping faults and stratigraphic traps. The main
reservoir sands in Block B8/32 are fluvial channel sands, point bar sands,
alluvial fans and deltas associated with lacustrine depositional environments.

CURRENT FIELDS AND PROSPECTS

From 1992 until December 31, 1997, the Company along with its
co-concessionaires, have drilled 40 gross development wells and 35 exploratory
wells in Block B8/32. Thirty-seven of the development wells and 20 exploratory
wells have been successful. All of the development wells and 31 of the
exploratory wells are successful or are being evaluated.

The Company estimates it will invest a total of approximately $120 million
during 1998 in connection with its capital expenditure programs, of which
approximately 80% is budgeted for the development of the Benchamas Field. The
actual expenditures on each project in the drilling and development program may
vary from the Company's estimates as a result of the actual costs incurred and
changes in the drilling and development program, including the acceleration of
the development of certain projects and prospects based on actual drilling
results, as well as the availability of additional capital to the Company.

PRODUCTION FACILITIES

Under the development plan for the Tantawan Field, two platforms and
production facilities were installed prior to first production in February 1997.
A third production platform was installed during the third quarter of 1997, and
a fourth platform was installed during the fourth quarter of 1997. The oil and
natural gas are separated on each platform and processed on a Floating
Production, Storage and Offloading vessel ("FPSO") which was delivered in
December 1996. Oil is exported via tankers, and gas is discharged into a 33-mile
spur pipeline owned by PTT. Production of oil and gas is currently from all four
platforms.

Platforms. The first two production platforms are four-pile, twelve slot
units designed for drilling with either a jack-up or tender assisted rig.
Wellhead fluids are separated at each production platform into three streams:
high pressure gas, intermediate pressure gas and low pressure oil and water. As
required, natural gas is drawn off the intermediate pressure system, compressed,
and fed back down the wells to provide gas lift to optimize oil recovery.
Hydrocarbons are fed into flowlines which run between each platform and a
pipeline end manifold located at the FPSO. The third and fourth platforms are
similar in design, but are both nine slot units.

FPSO. The FPSO was used to facilitate an accelerated development of the
Tantawan Field and provide present value benefits given the lack of an offshore
oil pipeline infrastructure. The FPSO used for the Tantawan development is under
the management of an affiliate of Single Buoy Moorings Inc. ("SBM"), one of the
largest builders and operators of FPSO's. Another affiliate of SBM owns the
vessel and leases it under a bareboat charter to another affiliate, Tantawan
Production B.V., who in turn leases it under a Bareboat Charter Agreement (the
"Charter") to Tantawan Services L.L.C. ("TS"), a company currently owned by
Thaipo. All FPSO costs (including the vessel, detailed design engineering and
all equipment purchased for the FPSO) were borne directly by SBM. The final cost
of the installed and commissioned FPSO is being recovered by SBM in the bareboat
charter day rate over the term of the Charter. The initial term of the Charter
is for 10 years, subject to extension, with a commencement date of February,
1997. In addition, TS has a purchase option on the FPSO throughout the term of
the Charter. TS has also contracted with another company, SBM Marine Services
Thailand Ltd. ("FPSO Operator"), to operate the FPSO on a reimbursable basis
throughout the initial term of the Charter. Performance of both the Charter and
the agreement to operate the FPSO are non-recourse to TS and the Company.
However, TS's performance is secured by a lien on any hydrocarbons stored on the
FPSO and is guaranteed severally by each of the Tantawan Concessionaires. The
Company's guarantee is limited to its percentage interest in the Tantawan Field.

The FPSO production facilities include process facilities for separation
and treatment of the produced fluids and compressors for gas. This equipment is
very similar to that utilized on conventional fixed platforms, except for
features that allow the equipment to function while subjected to the roll and
pitch of the FPSO. The production system is capable of processing 150 MMcfd
(expandable to 300 MMcfd) of natural gas, 50 MBPD
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of crude oil and condensate and 25 MBPD of produced water. Oil and condensate is
processed to an export quality for storage on the FPSO and then offloaded to
shuttle tankers. Natural gas is dehydrated and compressed for export via a 24
inch 33-mile spur pipeline. Water is cleaned to below 20 parts per million of
oil in water and discharged overboard.

The FPSO has sufficient storage for optimum offloading of oil to export
tankers, as well as providing spare capacity in the event of unscheduled delays
in tanker arrival. The storage capacity is 1,000 MBbl, of which 700 MBbl
comprises saleable crude. 200 MBbl is required to store ballast water to control
hull stresses and 100 MBbl will be used to store oily water which does not meet
the discharge concentration criteria. Oil stored on the FPSO is offloaded
periodically to export tankers using the tandem system where the tankers are
moored end to end. Offtake tankers are provided by purchasers.

The FPSO Operator is responsible for the operation and maintenance of the
FPSO. Thaipo provides a limited number of crew members who handle platform and
well operations. The crew members, along with the FPSO Operator's personnel, are
housed on the FPSO.

Benchamas Production Facilities. The initial plan of development for the
Benchamas Field incorporates the installation of three satellite wellhead
platforms, a central processing facility platform with a daily capacity of 150
MMcf of natural gas, 25 MBbl of oil and condensate and 25 MBbl of water and a
living quarters platform. Full wellstream production will flow through a
gathering system to the processing platform where the natural gas, oil and water
will be separated. Any produced water will be treated to meet minimum
specifications and discharged. Oil will be stored on a Floating, Storage and
Offloading vessel ("FSO"), from which it will be periodically offloaded into
offtake tankers. Since production at Benchamas is scheduled to commence in the
third quarter of 1999, the Concessionaires are currently in the process of
negotiating a lease for such an FSO vessel. As the central processing facility
is sized to handle additional wellhead platforms, the Concessionaires
contemplate that additional production facilities will be required to fully
exploit the field.

The natural gas will be dehydrated, metered and compressed for delivery
through a 16-inch, 32-mile pipeline which will tie directly into the PTT
pipeline which connects the Tantawan FPSO to the main trunk lines.

MARKETING AND CONTRACTS

Gas Sales Agreement ("GSA"). Under the terms of the Concession, the Kingdom
of Thailand has first priority to purchase natural gas produced from the Block.
PTT is currently the sole purchaser of natural gas in Thailand and buys all gas
at the well-head from private producers. PTT also maintains a monopoly over
natural gas transmission and distribution in the country. The GSA was signed on
November 7, 1995, requiring PTT to take, or pay for if not taken, a yearly
aggregate amount from the Tantawan Concessionaires of at least 75 MMcfd of
natural gas ("Daily Contract Quantity" or "DCQ") for the first year of
production (which commenced in February 1997) rising to 85 MMcfd from October
1997 to August 1999 and thereafter based upon reserve additions at the Tantawan
and Benchamas Fields. The GSA terminates on the earlier of (i) termination of
the petroleum production period, (ii) the date when there are no field reserves
remaining, or (iii) 30 years from the contractual delivery date.

In November 1997, the GSA was amended to incorporate gas production from
the Benchamas Field. At the time that Benchamas production commences and the
Concessionaires complete a 72-hour production test, the minimum purchases will
be increased from 85 MMcfd to 125 MMcfd. The price for Benchamas gas will be
identical to that received for Tantawan Field gas production.

The natural gas price is based on formulae which provide adjustments to the
base price for natural gas on each April 1 and October 1. Adjustments will be
made to reflect changes in (i) wholesale prices in Thailand, (ii) the U.S.
producer price index for oil field machinery and tools, and (iii) medium fuel
oil prices. Adjustment factors for oil field machinery and medium fuel oil
prices are subsequently adjusted for Thai Baht/U.S. Dollar fluctuations. Payment
is made monthly in Thai Baht. Gas price realizations for December 1997 were
$1.64/MCF, and the average price realized for the year was $1.86/MCF.

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In early July 1997, the Company had its first oil lifting from the Tantawan
Field and sold 278,000 barrels of oil for Thai Baht pursuant to a Memorandum of
Understanding (the "MOU") with PTT. Subsequent to that lifting, the MOU was
terminated and the Concessionaires received the right to export their oil on the
spot market to any purchasers, provided the price exceeds that bid by PTT. As of
December 31, 1997 the Company had sold two cargoes for U.S. Dollars on the spot
market, and expects to continue to do so at market prices.

THAI CONCESSION TERMS

Term. The Concession agreement provided for an exploration period of 6
years ending July 31, 1997, which may be renewed for an additional 3-year term
upon agreement between the parties. At the end of the initial exploration term
on July 31, 1997, Thai petroleum law permitted the government to grant, upon
application by the Concessionaires, an additional three-year exploration term on
up to 50% of the Concession acreage that had not been previously designated as a
production area or relinquished, subject to agreement on certain terms and
conditions. In May 1997, the Concessionaires received an extension of the
exploration period, which will end on July 31, 2000, by agreeing to undertake a
work program composed of a 3-D seismic survey and drilling two exploration
wells, both of which must be completed by July 2000.

Before the expiration of the exploration period, the Concessionaires may
pay annual lease rentals to retain acreage subject to forfeiture. The Department
of Mineral Resources sets the rentals on the date that the Concessionaires
submit the application for payment of rentals.

If production does not commence within four years of the designation of the
production area, the production period will expire. The petroleum production
period for producing areas is a 20-year period beginning on the last day of the
exploration period, which 20-year period may be extended for 10 years upon
agreement on the terms of the extension.

Production Bonuses. Pursuant to the terms of the Concession agreement, the
Concessionaires are required to make the following payments ("Production
Bonuses") to the Ministry of Finance: (i) $2.0 million upon the first production
of petroleum from the Block; (ii) $3.0 million when petroleum production from
the Block reaches an average of 50,000 barrels of crude oil equivalent per day
in any one calendar month; and (iii) $7.5 million when the petroleum production
from the Concession area reaches an average of 100,000 barrels of crude oil
equivalent per day in any calendar month. The Company paid to the Ministry of
Finance in January 1997 the sum of $927,000 representing the Company's 46.34%
share of the first Production Bonus.

Royalties. The following table summarizes the monthly royalties required to
be paid to the Thai government based on barrels of oil equivalent produced
within Block B8/32 (natural gas is converted to an equivalent under the royalty
using a ratio of 10 Mmbtu of natural gas to one barrel of oil):

PERCENT OF VALUE
OF PRODUCT SOLD
MONTHLY VOLUME OF PRODUCT (IN EQUIVALENT BARRELS) OR DISPOSED
------------------------------------------------- ----------------

Not exceeding 60,000........................................ 5.00%
Portion exceeding 60,000 but not exceeding 150,000.......... 6.25
Portion exceeding 150,000 but not exceeding 300,000......... 10.00
Portion exceeding 300,000 but not exceeding 600,000......... 12.50
Portion exceeding 600,000................................... 15.00

Special Remuneratory Benefit ("SRB"). The Concessionaires must also pay an
SRB, which is calculated annually on a concession-wide basis as a percentage of
Annual Petroleum Profit (hydrocarbon revenues net of, among other things,
royalties, Production Bonuses, capital expenditures and operating expenses). No
SRB is payable if the block has no Annual Petroleum Profit after consideration
of carryforwards. The SRB varies from zero to 75% of Annual Petroleum Profit,
depending on the level of annual revenue per meter drilled in the Block. The
Company does not anticipate paying any SRB's for the forseeable future in light
of anticipated drilling activity.

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Termination and Revocation. The Concession agreement terminates (i) upon
the termination of the petroleum production period; (ii) when the Effective
Concession Area (as defined in the Concession) ceases to exist by virtue of the
provisions of the Petroleum Income Tax Act B.E. 2514, which governs statutory
percentage relinquishment, or through the voluntary relinquishment made by the
Concessionaires; (iii) upon revocation of the Concession agreement; or (iv) upon
termination of the Concessionaires' status as a juristic person (i.e., subject
to the jurisdiction of Thai courts). Under the Thai Petroleum Act, the Ministry
of Industry may revoke the Concession agreement if the Concessionaires (i) fail
to pay the Production Bonuses, the royalties, the SRB or income taxes; (ii)
become bankrupt; or (iii) fail to comply with good petroleum industry practice
or to conduct petroleum operations with due diligence or violate certain other
provisions of the Concession agreement or the Thai Petroleum Act. In addition,
all production, storage and transportation equipment and facilities must be
turned over to the Thai government at the end of the production term.

Joint and Several Liability. Under the terms of the Concession agreement,
each of the Concessionaires is jointly and severally liable for the obligations
of the Concessionaires, including payment of income taxes, under the Concession.

Currency Repatriation. The concession agreement allows the Concessionaires
an unfettered right to retain and remit money abroad in foreign currency.

JOINT OPERATING AGREEMENT

Tantawan. As a result of Maersk's decision not to participate in the
development of the Tantawan Field, the Tantawan Concessionaires entered into a
separate Joint Operating Agreement effective as of March 3, 1995, with regard to
the operation of the Tantawan Field (the "Tantawan JOA"). Thaipo was designated
as Operator. Subject to the supervision of the Operating Committee, the Operator
has the exclusive right and is obligated to conduct all operations relating to
the Tantawan Field, including but not limited to the preparation and
implementation of proposed work programs, budgets and authorizations for
expenditure, obtaining all requisite services and materials and providing to
each of the Tantawan Concessionaires reports, data and information concerning
the operation in the Tantawan Field. The Operating Committee consists of one
representative of each Tantawan Concessionaire with the Operator as the
Chairman. Each party has a percentage vote on the Operating Committee equal to
its percentage interest. For information on the percentage interest of each
party, see "Business and Properties -- History of Block B8/32". All decisions of
the Operating Committee require the affirmative votes of two or more
non-affiliated parties having an aggregate percentage interest of not less than
51%. The approval of the Operating Committee is required with regard to the
general outline of all work programs, appraisal and development operations and
the budgets pertaining to operations in the Tantawan Field.

Remainder of Block B8/32. Thai Romo, Thaipo, MOTL and Palang are parties to
the Joint Operating Agreement dated August 1, 1991 (the "JOA"). MOTL was
appointed Operator for the Block. Terms and conditions under the JOA relating to
the Operator and the Operating Committee are substantially similar to those in
the Tantawan JOA, except all decisions of the Operating Committee require the
affirmative votes of two or more non-affiliated parties having an aggregate
percentage interest of not less than 60%. In March 1997, MOTL was sold to the
Concessionaires. At that time, the Concessionaires executed a letter agreement
appointing Thaipo as operator to replace MOTL and agreeing that operations under
the JOA will be governed by the Tantawan JOA.

BUSINESS CONDITIONS

Since the latter half of 1997, many countries in Southeast Asia, including
Thailand, have experienced significant reductions in economic growth. The
Company does not believe that this situation, even if prolonged, will
significantly impact its business position. Natural gas produced in Thailand by
the Company and other producers is primarily used for electrical power
generation. The Company believes that its natural gas will displace either
imported crude oil, lignite or imported natural gas as power generation
feedstock, because domestic natural gas is cheaper to purchase, environmentally
preferable and enables the government to retain its U.S. Dollars reserves during
a period of economic uncertainty.

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As the Company has the right to export its crude oil to the highest bidder
for U.S. Dollars, it does not believe that the recent events in Thailand and
other countries in Southeast Asia will impact its ability to market crude oil.

PRIMARY CUSTOMERS

All natural gas produced from the Tantawan Field is being sold to PTT,
which maintains a monopoly gas transmission and distribution in Thailand.

PTT is an agency of the Kingdom of Thailand, which has a Ba1 sovereign debt
rating from Moody's Investors Services, Inc. and a BBB- sovereign debt rating
from Standard & Poor's Corporation, both U.S. rating agencies.

The Concessionaires are able to sell their crude oil to a variety of
potential purchasers.

OIL AND GAS PROPERTIES

The table below summarizes the Company's net proved oil (including
condensate and crude oil) and natural gas reserves and discounted net present
value ("NPV") by field as of December 31, 1997, as determined by Ryder Scott
Company, independent petroleum reserve engineers. Oil has been converted at a
ratio of 6 MCF of gas to 1 barrel of crude oil when presenting natural gas
equivalents (MCFE):

NPV BEFORE % OF
OIL NATURAL GAS TOTAL INCOME TAX TOTAL
FIELD (MBO) (MMCF) (MMCFE) ($ IN 000'S) NPV
----- ------ ----------- -------- ------------ ------

Tantawan...................... 8,967 75,838 129,640 $37,407 59
Benchamas..................... 18,899 93,312 206,706 22,687 36
Maliwan....................... 956 16,157 21,893 2,846 5
------ ------- ------- ------- ---
Total............... 28,822 185,307 358,239 $62,940 100
====== ======= ======= ======= ===

RESERVES

The following table sets forth estimates of the net proved oil (including
condensate and crude oil) and natural gas reserves of the Company at December
31, 1997, as determined by Ryder Scott Company.

OIL(MBO) NATURAL GAS(MMCF)
---------------------------------- -----------------------------------
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ------ --------- ----------- -------

Tantawan............. 7,021 1,946 8,967 60,193 15,645 75,838
Benchamas............ -- 18,899 18,899 -- 93,312 93,312
Maliwan.............. -- 956 956 -- 16,157 16,157
----- ------ ------ ------ ------- -------
Total Company...... 7,021 21,801 28,822 60,193 125,114 185,307
===== ====== ====== ====== ======= =======

NATURAL GAS EQUIVALENTS(MMCFE)
-----------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------

Tantawan.............................................. 102,319 27,321 129,640
Benchamas............................................. -- 206,706 206,706
Maliwan............................................... -- 21,893 21,893
------- ------- -------
Total Company............................... 102,319 255,920 358,239
======= ======= =======

The Company has not filed any different estimates of its December 31, 1997
reserves with any federal agency.

The reserve data set forth in this Form 10-K represents only estimates.
Reserve engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and adjustment.
As a result, estimates of different

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11

engineers often vary. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revision of such estimates.
Accordingly, reserve estimates often differ from the quantities of crude oil and
natural gas that are ultimately recovered. Estimates of economically recoverable
crude oil and natural gas reserves and of future net revenues are based upon a
number of variables and assumptions, all of which may vary considerably from
actual results. The reliability of such estimates is highly dependent upon the
accuracy of the assumptions upon which they were based.

The following table sets forth, at December 31, 1997, the discounted net
present value attributable to the Company's estimated net proved reserves at
that date as estimated by Ryder Scott Company, the Company's independent
petroleum reserve engineers:

TANTAWAN BENCHAMAS MALIWAN TOTAL
-------- --------- -------- --------
(IN THOUSANDS OF U.S. DOLLARS)

Future cash inflows.................... $285,994 $483,015 $ 45,021 $814,030
Future production costs................ (207,576) (121,328) (6,256) (335,160)
Future development costs............... (29,337) (196,513) (20,941) (246,791)
-------- -------- -------- --------
Future net cash inflows................ 49,081 165,174 17,824 232,079
Discount at 10% per annum.............. (11,674) (142,487) (14,978) (169,139)
-------- -------- -------- --------
Present value of future net cash flows,
before income taxes.................. $ 37,407 $ 22,687 $ 2,846 $ 62,940
======== ======== ======== ========

In computing this data, assumptions and estimates have been utilized, and
no assurance can be given that such assumptions and estimates will be indicative
of future economic conditions. The future net cash inflows are determined by
using estimated quantities of proved reserves and the periods in which they are
expected to be developed and produced based on December 31, 1997 economic
conditions. The estimated future production is based on prices the Company
estimated it would have received at December 31, 1997, except where fixed and
determinable price escalations or oil hedges are provided by contract. The
resulting estimated future gross revenues are reduced by estimated future costs
to develop and produce the proved reserves based on December 31, 1997 cost
levels, but not for debt service and general and administrative expenses.

ACREAGE AND PRODUCTIVE WELLS

The following table sets forth the Company's developed and undeveloped
acreage position at December 31, 1997. A net acre is deemed to exist when the
sum of fractional ownership of working interest in gross acres equals one:

DEVELOPED UNDEVELOPED
ACREAGE ACREAGE TOTAL
-------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
(IN THOUSANDS) (IN THOUSANDS) (IN THOUSANDS)

Gulf of Thailand................ 67.9 31.5 666.4 308.8 734.3 340.3

At December 31, 1997, the Company owned interests in the following wells
capable of production pending completion and installation of production
facilities. The number of net wells is the sum of fractional ownership of
working interest owned directly by the Company in gross wells expressed as whole
numbers and percentages thereof:

GROSS NET
----- ----

Oil and Gas Wells........................................... 57 26.4

The above well count does not include 14 wells (6.5 net) that are currently
under evaluation.

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DRILLING ACTIVITY

The following table sets forth the number of gross and net successful and
dry development wells and exploratory wells drilled by the Company during the
years indicated.

GROSS GROSS NET NET
DEVELOPMENT EXPLORATORY DEVELOPMENT EXPLORATORY
WELLS WELLS WELLS WELLS
---------------- --------------- --------------- ----------------
YEAR SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY
---- ---------- --- ---------- --- ---------- --- ---------- ----

1997................................ 18 -- 9 3 8.3 -- 4.2 1.4
1996................................ 15 -- 9 -- 7.0 -- 4.2 --
1995................................ 7 -- 4 -- 3.2 -- 1.9 --
1994................................ -- -- 5 -- -- -- 2.3 --
1993 and prior...................... -- -- 4 1 -- -- 1.9 0.5
-- --- ---------- --- ---------- --- ---------- ----
Total..................... 40 -- 31 4 18.5 -- 14.5 1.9
== === ========== === ========== === ========== ====

Tantawan

Through December 31, 1997, the Company has participated in drilling a total
of 34 development and 14 exploration wells in the Tantawan Field. Of the 48
total wells, 40 are deemed capable of commercial flow rates while 8 wells are
being evaluated. All of these successful wells were drilled in the southern
portion of the Tantawan Field and have encountered an average of 178 feet of net
hydrocarbon pay. As of December 31, 1997, net proved reserves for the Tantawan
Field were 129.6 Bcfe.

In August 1996, the Company set its "A" and "B" twelve slot production
platforms and mobilized two drilling rigs to tie-back and complete a total of 19
wells. To facilitate moving the natural gas and crude oil to market, the
operator participated in a long-term lease for an oceangoing tanker, the T/T
Bayern, the only FPSO vessel in the Gulf of Thailand. The vessel, recommissioned
as the Tantawan Explorer, was delivered in December 1996.

During 1997, Thai Romo and its partners installed the nine slot "C"
platform and production commenced from it during the fourth quarter of 1997.
Also during that quarter, the Concessionaires installed the nine slot "D"
platform and began drilling and completing development wells. Production from
these wells commenced in February 1998.

Benchamas

In January 1997, the Concessionaires submitted a plan of development to the
Thai government and applied for approval to produce oil and gas from the
Benchamas Field and part of the Pakakrong area. In June 1997, the
Concessionaires received a production license covering approximately 101,000
acres from the Ministry of Industry in these areas. The Company believes this is
the largest production license area ever awarded in the Gulf of Thailand.

Through December 31, 1997, the Company has participated in drilling a total
of 11 exploration wells and 6 development wells in the Benchamas Field, all of
which were hydrocarbon bearing and 15 of which were considered to be capable of
commercial flowrates, while 2 are under evaluation. The wells encountered an
average of 222 feet of net hydrocarbon pay. As of December 31, 1997, net proved
reserves for the Benchamas Field were 206.7 Bcfe. The Company expects to conduct
an active program of development drilling in the Benchamas Field in 1998 with
first production expected to commence in the third quarter of 1999.

The Benchamas Field phase one plan of development calls for the
construction and installation of:

- Central process/compression platform,

- Living quarters/utilities platform,

- Wellhead platforms 'A' 'B', and 'C',

- Platform interconnecting bridges at wellhead platform 'A',

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13

- 16 inch, 32 mile gas sales tie-in pipeline and infield flowlines,

- Floating storage and offloading vessel.

The central process/compression platform will be a large eight-leg
structure located adjacent to wellhead platform 'A'. Its primary function will
be to separate the produced wellstreams into three components -- oil, gas, and
water -- and to prepare the gas for entry into PTT's sales pipeline. Produced
oil will be prepared for delivery through the oil pipeline into the FSO vessel.
Produced water will be treated and discharged. The FSO will provide sufficient
storage for optimal offloading of oil to export tankers, as well as providing
spare capacity in the event of delays in tanker arrival. The Concessionaires are
currently negotiating for a ten year bareboat charter and related operating
agreement for a ship with a capacity of approximately 1.35 million barrels.

The living quarters/utilities platform will also be a part of the central
complex. It will be bridge connected to the central process/compression platform
opposite wellhead platform 'A'. The platform will be a large four-pile platform
containing a multi-story 60-man accommodation module, a power generation module
and utility systems to support both the quarters facilities and the process
platform.

The three wellhead platforms will be set in the vicinity of the Benchamas
Nos. 1, 3, and 12 wells. Wellhead platforms 'A', 'B', and 'C' will be four-pile
jackets and have twelve, sixteen and six well conductors, respectively. All
three platforms can accommodate either a jack-up or platform rig.

Flowlines will bring segregated production from the wellhead platforms to
the central process/compression platform for final separation, dehydration,
compression, and measurement. The production facilities have been designed to
handle up to 150 MMcf and 50 MBbl of produced liquids per day through a single
separation train. The crude oil and condensate will flow to the FSO. Based on
test data, the Benchamas Field is expected to produce a sweet, light crude
oil/condensate blend with a moderate paraffin content. The average CO(2) content
of the natural gas produced during the various drill stem tests was 7.8%.

The Concessionaires expect that the gross cost of this development
(drilling and facilities) to be approximately $400 million and have awarded
construction contracts to Nippon Steel Company and Hyundai Heavy Industries Ltd.
for the wellhead platforms and central process/compression platform,
respectively. The wellhead platforms have been designed to accept either a
jack-up rig or a low cost, tender assisted rig with the capability of drilling
directional wells to a depth of 13,000 feet measured depth.

Projected Drilling and Completion Program. Plans for the drilling of wells
in the initial development phase are based on the utilization of only one
drilling rig. The Concessionaires have signed a letter of intent with a
contractor to utilize a tender assisted rig. The majority of the development
wells at Benchamas Field will be drilled using slim hole drilling and completion
technology and should result in significant cost savings over conventional
programs.

Estimated Project Timing. Production from Benchamas phase one development
is projected to commence during the third quarter of 1999. The producing life of
phase one reserves is estimated at 15 years. Future production rates may be more
or less than estimated because of changes in project timing, reservoir
performance or market conditions.

The Company believes that additional drilling will be required to fully
develop the Benchamas Field, however additional geological and geophysical
assessment must occur before such development is undertaken.

Maliwan

During 1997, four exploration wells were drilled in the Maliwan area,
located between the Tantawan and Benchamas Fields. All wells encountered
hydrocarbons with 2 deemed successful and 2 under evaluation. The wells
encountered an average of 129 feet of net hydrocarbon pay. In July 1997, the
Concessionaires made formal application for a production license. The
Concessionaires received a 91,000 acre production license in November 1997. As
of December 31, 1997, net proved reserves for the Maliwan 2 and 4 were 21.9
BCFE. The Company also expects to have an active drilling program in the Maliwan
area during 1998.

10
14

Pakakrong

In late 1995, a 100 square mile 3-D seismic survey of the Pakakrong
prospect was acquired, processed and interpreted. The prospect is centered 8.5
miles southwest of the Benchamas-1 well. Production tests in the two Pakakrong
wells drilled in early 1996 have established potential commercial reservoirs at
depths considerably shallower than found to date elsewhere within the Block.
Both wells are currently under evaluation. The production license awarded for
the Benchamas Field includes a portion of Pakakrong.

Drill stem tests ("DST") conducted on the Pakakrong-1 yielded cumulative
flow rates of 25.5 MMcfd of natural gas and 0.7 Mbpd of oil or condensate. Three
DSTs were conducted in the Pakakrong-2 well. Two of the tests conducted across
intervals at 7,400 feet and 7,640 feet produced approximately 60% and 80%,
respectively, of CO(2). The third test, conducted at a depth of 4,200 feet,
yielded a flow of 1.6 MBPD. Based on seismic interpretation, the Company
believes that this zone may be the same zone observed but not tested in the
Pakakrong-1 well located one mile northwest. However, the Company expects that
additional delineation drilling and further geological assessment will be
required prior to formulation of a development plan.

North Benchamas

During 1997, the Company drilled three exploratory wells in the North
Benchamas portion of Block B8/32. Two of the three wells encountered
non-commercial accumulations of hydrocarbons and all three wells were deemed
unsuccessful. The Company intends to further examine and refine its existing
seismic data before deciding on further drilling in this area.

Jarmjuree

During 1997, the Concessionaires shot a 900 square kilometer 3-D seismic
survey of the Jarmjuree Area, which is located in the southern portion of Block
B8/32. The Company will interpret this data in 1998 before deciding on future
drilling activities.

THAILAND TAXES

Under the Petroleum Income Tax Act B.E. 2514 and (No. 4) B.E. 2532, Thai
Romo's and B8/32 Partners' net profits derived from the petroleum business are
subject to Thai income tax at the rate specified by the Royal Decree Prescribing
Petroleum Income Tax Rates B.E. 2514, which must not be lower than 50% and not
be higher than 60% of such net profits. Under the Royal Decree, the Thai income
tax rate to be imposed on Thai Romo's and B8/32 Partners' anticipated net
profits derived from their petroleum business is 50%.

In computing Thai Romo's and B8/32 Partners' anticipated net profits from
its petroleum business that will be subject to Thai tax, any interest paid on
loans by Thai Romo and B8/32 Partners to any lenders or shareholders, whether or
not resident or doing business in Thailand, is not deductible. Royalties to be
paid by Thai Romo and B8/32 Partners to the Ministry of Industry that are
required under the Concession are deductible in computing Thai Romo's and B8/32
Partners' net profits from their petroleum business.

COMPETITION

The Company experiences competition from other oil and gas companies in its
operations. Although many of these companies have financial resources greater
than the Company, management believes based upon its accomplishments to date
that the Company is positioned to continue to compete effectively.

EMPLOYEES

At January 31, 1998, the Company employed 14 people (excluding Messrs.
Rutherford and Moran) in its Houston, Texas headquarters whose functions are
associated with management, engineering, geology, finance and administration.
The Company has no collective bargaining arrangement with employees and believes
its relations with its employees are good.

11
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OFFICES

The Company leases its Houston office under a lease covering approximately
11,000 square feet, expiring in February 2002. The monthly rent and expenses are
approximately $11,000.

ITEM 3. LEGAL PROCEEDINGS

As of December 31, 1997, the Company is not aware of any pending or
threatened legal proceedings.

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

None during the fourth quarter of 1997.

PART II

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

Since June 21, 1996, the Company's Common Stock, $0.01 par value (the
"Common Stock"), has been traded on the NASDAQ National Market System under the
symbol "RMOC." As of February 28, 1998, there were 25,614,000 shares of Common
Stock outstanding. The Company has never paid dividends on its Common Stock and
does not expect to pay dividends in the near future. The Company currently is
prohibited under its Credit Agreement from paying dividends on its common stock.
In addition, the Indenture governing the Company's 10.75% Subordinated Notes Due
2004 (the "Notes") contains covenants that, among others, restrict the Company's
ability to pay dividends and limit the incurrence of additional debt.

The following table shows the high and low prices, for each quarter, of the
Common Stock on the NASDAQ Stock Exchange during 1996 and 1997:

QUARTER ENDED,
1997 HIGH LOW
-------------- ------ ------

March 31.................................................... $30.00 $16.75
June 30..................................................... 24.50 17.12
September 30................................................ 26.75 19.88
December 31................................................. 30.25 16.25

QUARTER ENDED,
1996 HIGH LOW
-------------- ------ ------

June 30..................................................... $25.25 $23.00
September 30................................................ 30.00 23.87
December 31................................................. 30.75 25.00

ITEM 6. SELECTED FINANCIAL DATA

The financial data as of and for the years ended December 31, 1993 through
1997 were derived from audited and unaudited consolidated financial statements
of the Company and its predecessors. The data set forth in this table should be
read in connection with "Management's Discussion and Analysis of Financial

12
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Condition and Results of Operations," the more detailed consolidated financial
statements and related notes included elsewhere herein.

YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
1997 1996(B) 1995(B) 1994(B) 1993(B)
-------- ------- ------- ------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA)

Oil and gas revenues.......... $ 35,034 $ -- $ -- $ -- $ --
Interest income............... 431 170 5 6 24
Costs and expenses:
Operating expenses.......... 24,243 -- -- -- --
General and
administrative........... 5,737 2,268 322 290 187
Depreciation, depletion and
amortization............. 18,055 29 5 2 --
Interest expense............ 7,157 806 190 107 76
Exploration costs........... 7,630 3,025 1,525 1,346 2,614
Foreign exchange loss....... 6,323 -- -- -- --
Gain on futures contract.... (506) -- -- -- --
-------- ------- ------- ------- -------
Loss before income tax
benefit..................... (33,174) (5,958) (2,037) (1,739) (2,853)
Income tax benefit............ (10,523) (3,521) -- -- --
-------- ------- ------- ------- -------
Net loss...................... $(22,651) $(2,437) $(2,037)(a) $(1,739)(a) $(2,853)(a)
======== ======= ======= ======= =======
Loss per share of common
stock.................... $ (0.88) $ (0.10) $ (0.10) $ (0.08) $ (0.14)
======== ======= ======= ======= =======
Weighted average shares
outstanding................. 25,612 23,358 21,000(a) 21,000(a) 21,000(a)
======== ======= ======= ======= =======

AT DECEMBER 31,
----------------------------------------------------
1997 1996(B) 1995(B) 1994(B) 1993(B)(C)
-------- -------- ------- ------- ----------
(IN THOUSANDS)

Balance Sheet Data (at end of period):
Property and equipment, net......... $220,649 $113,643 $49,210 $13,721 $7,015
Total assets........................ 279,700 123,379 60,877 14,160 7,113
Long-term debt, including current
maturities....................... 189,000 22,842 34,385 1,400 --
Stockholders' equity.................. 73,380 95,720 16,477 10,217 4,768

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

(a) RMOC became a public entity in June 1996. See Note 2 to Consolidated
Financial Statements -- Significant Accounting Policies.

(b) Restated for a change to the successful efforts method of accounting for
oil and gas properties.

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

INTRODUCTION

The following discussion is intended to assist in understanding the
Company's financial position and results of operations for each year in the
three-year period ended December 31, 1997. The Consolidated Financial Statements
and the notes thereto should be referred to in conjunction with this discussion.

From time to time, the Company may elect to make certain statements that
provide the Company's stockholders and the investing public with
"forward-looking" information (as defined in the Private Securities Litigation
Reform Act of 1995). Words such as "anticipate", "believe", "estimate",
"project" and similar expressions are intended to identify such forward-looking
statements. Forward-looking statements may be made by management orally or in
writing, including, but not limited to, in press releases, as part the "Business
and Properties" and "Management's Discussion and Analysis of Financial Condition
and Results of

13
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Operations" sections of this report and as part of other sections of the
Company's filings with the Securities and Exchange Commission under the
Securities Act of 1933 and the Securities Exchange Act of 1934. Such
forward-looking statements may include, but not be limited to, statements
concerning estimates of current and future results of operations, earnings,
reserves, the timing and commencement of wells and the production therefrom,
production estimates based upon drill stem tests and other test data, future
capacity under its credit arrangements, and future capital expenditures and
liquidity requirements.

Such forward-looking statements are subject to certain risks, uncertainties
and assumptions, including without limitation those identified below. Should one
or more of these risks or uncertainties materialize, or should any of the
underlying assumptions prove incorrect, actual results of current and future
operations may vary materially from those anticipated, estimated or projected.
Readers are cautioned not to place undue reliance on these forward-looking
statements.

Among the factors that have a direct bearing on the Company's results of
operations and the oil and gas industry in which it operates are uncertainties
inherent in estimating reserves and future cash flows; changes in the price of
oil and natural gas; the limited production and exploration histories in Block
B8/32; the status of the Company's existing and future contractual relationships
with the Government of Thailand, including the Concession and the GSA; risks
associated with having the Government of Thailand as the sole purchaser of the
Company's gas production, including the potential for political instability and
economic downturns in the Thailand economy and a reduction in demand for oil and
natural gas in Thailand; foreign currency fluctuation risks; access to
additional capital; the Company's substantial indebtedness; the presence of
competitors with greater financial resources and capacity; difficulties and
risks associated with delivering the Company's production, including inherent
risks associated with offshore oil and gas exploration and development
operations and risks associated with offshore marine operations such as
capsizing, sinking, grounding, collision and damage from severe weather
conditions.

OVERVIEW

RMEC, currently a wholly owned subsidiary of the Company, was formed on
September 21, 1990 for the purpose of holding an interest in an oil and gas
concession in Thailand. RMEC paid all of the expenses of the concession on
behalf of Thai Romo through November 4, 1993.

Effective September 24, 1990, the stockholders of RMEC elected to have it
treated as an S Corporation under the Internal Revenue Code of 1986, as amended.
As such, RMEC did not incur federal income taxes at the corporate level prior to
June 18, 1996, and its taxable income or loss was passed through to its
stockholders based on their interests.

In November 1993, Thai Romo amended its Article of Association so that it
would be treated as a partnership for U.S. income tax purposes and added
additional partners, including the Company's current Chairman of the Board and
current President and Chief Executive Officer. As such, Thai Romo was not
subject to federal income taxes from November 1993 to June 17, 1996. Income and
losses earned by Thai Romo were passed through to the partners on the basis of
their interest in Thai Romo.

In June 1996, the Company entered into an exchange transaction whereby the
partners of Thai Romo (other than RMEC) exchanged their interests (including
outstanding notes payable to them) in Thai Romo for common stock, $.01 par value
("Common Stock"), of the Company, which interests in Thai Romo were
simultaneously transferred to TRH, a wholly-owned subsidiary of the Company, and
the stockholders of RMEC (the Company's current Chairman of the Board and
current President and Chief Executive Officer) exchanged their shares of RMEC
for shares of Common Stock. Immediately following the Exchange, RMEC and Thai
Romo (indirectly) were wholly-owned by the Company. The Company's results of
operations and financial positions prior to the Exchange reflect the results of
operations and financial position of RMEC, TRH and Thai Romo as the Company's
predecessors.

Following the Exchange, the Company completed its initial public offering
of Common Stock, raising net proceeds, after deducting underwriting commissions
and discounts and expenses of the offering, of approxi-

14
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mately $97 million, which were utilized to repay outstanding debt to the
Company's principal stockholders, repay bank debt and fund cash outlays.

The Company began producing oil and gas from the Tantawan Field, its first
development in the Block, in February 1997. Prior to that time, the Company was
classified as a development stage company. As a result, the Company's historical
results of operations and period-to-period comparisons of such results and
certain financial data may not be meaningful or indicative of future results. In
regard to the Company's financial condition, results of operations, and future
growth and the carrying value of its proved reserves will depend substantially
on its ability to acquire or find and successfully develop additional oil and
gas reserves within the Block. The revenues expected to be generated by the
Company's future operations will be highly dependent upon the prices of and
demand for oil and natural gas. Natural gas produced from the Company's Tantawan
and Benchamas Fields is subject to the GSA with PTT with prices subject to
semi-annual adjustment (or more frequent adjustments under certain
circumstances) based on movements in, among other things, inflation, oil prices
and the Thai Baht/U.S. Dollar exchange rate. The price received by the Company
for its oil production and the level of production will depend on numerous
factors beyond the Company's control, including the condition of the world
economy, political and regulatory conditions in Thailand and other oil and gas
producing countries, and the actions of the Organization of Petroleum Exporting
Countries. Decreases in the prices of oil or gas could have an adverse effect on
the carrying value of the Company's proved reserves and the Company's revenues,
profitability, cash flow and borrowing base availability under the Revolving
Credit Facility.

During the fourth quarter of 1997, the Company changed its method of
accounting for its investment in oil and gas properties from the full cost to
the successful efforts method. Under the successful efforts method of
accounting, costs of exploration and development, including lease acquisition
and intangible drilling costs associated with exploration efforts which result
in the discovery of proved reserves and costs associated with development
drilling, whether or not successful, are capitalized. Geological and geophysical
costs are expensed as incurred. Gain or loss is recognized when a property is
sold or ceases to produce and is abandoned. Capitalized drilling costs of
producing properties are amortized using the units-of-production method based on
units of proved developed reserves for each field. Lease acquisition costs
related to producing oil and gas properties are amortized using the units of
production method based on units of proved reserves for each field.

The Company believes that the successful efforts method of accounting is
preferable as it will more accurately reflect the Company's future operations.
The Company believes that the significant number of exploratory wells drilled
annually, as well as the amount of geological and geophysical costs necessary to
evaluate the Company's large acreage position, justifies the utilization of the
successful efforts method. Additionally, the Company expects such activities to
increase and remain at such an increased level for an indefinite period of time,
given the potential of the Block and the prospective nature of the acreage. As a
result, the Company believes that a change in accounting principle to successful
efforts is appropriate at this time. The change to this method resulted in no
impairment to long-lived assets in accordance with Statement of Financial
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of". See Note 2 Consolidated Financial
Statements.

All prior years' financial statements presented herein have been restated
to reflect the aforementioned change in accounting policy. See Note 3 to
Consolidated Financial Statements.

RESULTS OF OPERATIONS

Year Ended December 31, 1997, compared with the year ended December 31, 1996

The Company's net loss of $22,651,000 or $0.88 per basic and diluted share
increased from a net loss of $2,437,000 or $0.10 per basic and diluted share for
the twelve months ended December 31, 1996. The increase in net loss is primarily
due to higher interest expense caused by increased debt levels, depletion and a
foreign exchange loss, offset by the revenues associated with the commencement
of production from the Tantawan Field, net of related operating costs, and a
related tax benefit.

The Company's total revenues for the twelve months ended December 31, 1997
were $35,465,000 compared to $170,000 for the twelve months ended December 31,
1996. Oil and gas revenues were $35,034,000 and interest income was $431,000 for
the current year, as compared to interest income of $170,000 for the twelve
months ended December 31, 1996.

Production volumes for the twelve months ended December 31, 1997, before
royalties, were 906,700 barrels of oil and 13,696,800 MCF of gas, compared to no
production volumes previously.

Operating expenses incurred for the twelve months ended December 31, 1997,
were $24,243,000 as compared to no operating expenses previously. This increase
is due to the commencement of production in the Tantawan Field February 1997.

Exploration cost increased for the twelve months ended December 31, 1997,
due to drilling three unsuccessful exploration wells in the North Benchamas Area
as well as the completion of a large 3-D seismic survey of the Jarmjuree Area
located in the southern portion of Block B8/32.

Depreciation, depletion and amortization expenses recorded for the twelve
months ended December 31, 1997 was $18,055,000 as compared to $29,000 for the
twelve months ended December 31, 1996. This increase is primarily due to the
commencement of production in February 1997.

Interest expense of $7,157,000 for the twelve months ended December 31,
1997 increased compared to $806,000 for the twelve months ended December 31,
1996. This increase is due to an increase in borrowings and the amortization of
deferred financing costs partially offset by increases in capitalized interest.
Outstanding debt at December 31, 1997 was $189,000,000 as compared to
$22,842,000 at December 31, 1996.

General and administrative expenses of $5,737,000 for the twelve months
ended December 31, 1997 increased compared to $2,268,000 for the twelve months
ended December 31, 1996. These increases are related to higher activity levels
in 1997 as well as a significantly larger amount of general and administrative
expenses capitalized in 1996.

The Company had foreign exchange losses of $6,323,000 for the twelve months
ended December 31, 1997 compared to none in 1996. As the Company is paid for its
gas in Thai Baht and also has some Baht denominated working capital, the
decision of the Kingdom of Thailand to allow the Baht to float against the U.S.
Dollar, tantamount to a devaluation of the Baht, resulted in the recording of
foreign exchange losses by the Company as the value of the Baht declined during
the second half of 1997.

Year ended December 31, 1996, compared with the year ended December 31, 1995

The Company's net loss of $2,437,000 for the twelve months ended December
31, 1996 increased from the Company's net loss of $2,037,000 for the twelve
months ended December 31, 1995. This increase in net loss is primarily due to an
increase in exploration cost related to an extensive 3-D seismic survey shot
during 1996, and higher general and administrative expenses offset partially by
an increase in interest income and an income tax benefit.

As RMEC and Thai Romo became part of the Company's consolidated federal tax
return following the Exchange, RMEC and Thai Romo recorded an income tax benefit
and a corresponding deferred tax asset of $1,283,000, for the difference between
the book basis and tax basis of oil and gas properties on June 17, 1996. This
benefit was increased by a $2,238,000 tax benefit recorded in the third and
fourth quarters associated with the operating loss generated by the Company.

16
20

Exploration costs for the twelve months ended December 31, 1996 were
$3,025,000 compared to $1,525,000 for the twelve months ended December 31, 1995.
This increase was due primarily to a large 3-D seismic survey incurred in 1996
for the purposes of evaluating a large area of prospective acreage in Block
B8/32.

Interest income of $170,000 for the twelve months ended December 31, 1996,
increased compared to $5,000 for the twelve months ended December 31, 1995, due
principally to the investment of cash available from the proceeds of the initial
public offering.

Interest expense of $806,000 for the twelve months ended December 31, 1996,
increased compared to $190,000 for the twelve months ended December 31, 1995.
This increase is caused by higher levels of outstanding debt and an increase in
the amortization of deferred financing costs, partially offset by the
capitalization of $1,600,000 in interest during 1996. There was no
capitalization of interest in 1995.

General and administrative expenses of $2,268,000 for the twelve months
ended December 31, 1996 increased compared to $322,000, for the twelve months
ended December 31, 1995. These increases are primarily due to the capitalization
of a greater portion of salaries and wages and direct costs related to oil and
gas property development in 1995 compared to 1996 and, to a lesser extent, an
increase in compensation expense.

LIQUIDITY AND CAPITAL RESOURCES

During the period from the inception of the Company on September 21, 1990
through December 31, 1997, the Company invested approximately $248 million
primarily for development and exploration activities conducted in Block B8/32
and the acquisition of interests in or rights to the Concession. During this
period, the Company had negative operating cash flow. Since its inception, the
Company has financed its growth with a combination of equity infusions by its
principal stockholders (primarily Messrs. Rutherford and Moran), bank and
stockholders loans, the sale of common stock and, most recently the issuance of
10.75% Senior Subordinated Notes ("Notes").

In June 1996, RMOC completed the Offering which resulted in RMOC raising
net proceeds of approximately $97 million. The proceeds were used to repay
outstanding debt to the Company's principal stockholders, repay bank debt, and
fund cash expenditures.

On September 20, 1996, the Company entered into a $150 million Revolving
Credit Facility (the "Revolving Credit Facility") with a group of commercial
lenders. The Revolving Credit Facility matures on September 30, 1999 and
contains a borrowing base limitation. The Revolving Credit Facility is secured
by the stock of certain subsidiaries and affiliates of the Company.

On September 29, 1997, the Company issued $120 million of Notes. The net
proceeds from this offering were used to repay $93 million of outstanding debt
under the Revolving Credit Facility and the Credit Agreement and to purchase a
portfolio of U.S. Government obligations of approximately $24 million, which is
sufficient to provide for payment in full when due, of the first four scheduled
interest payments on the Notes. The Indenture pursuant to which the Notes were
issued imposes customary financial and other restrictions on the Company and its
subsidiaries.

In December 1997, the Company and two of its lenders amended the Revolving
Credit Facility, which provides for a fixed borrowing base of $150 million until
September 30, 1998 (or on the completion of certain new financings or other
specified events, if earlier). The amended Revolving Credit Facility provides
that the Company pays interest at rates based on a margin of 1.75% over LIBOR if
the aggregate outstanding principal amount of loans is less than or equal to a
threshold amount, which was set at $60 million on December 3, 1997, a margin of
2.75% over LIBOR if the principal amount outstanding is greater than the
threshold amount on or prior to June 30, 1998, and a margin of 3.50% over LIBOR
if the principal amount outstanding is greater than the threshold amount after
June 30, 1998. Alternatively, the Company may pay a margin over the prime rate
of 0.25%, 1% and 1.75% respectively, for similar levels of borrowings. The
Company is also assessed a commitment fee equal to 0.5% per annum on the average
daily balance of the unused borrowing base. As of September 30, 1998 and
semi-annually thereafter, the borrowing base will be redetermined by the lenders
on
17
21

customary industry terms based upon the Company's then current reserve base.
Bank borrowings in excess of the threshold amount, if any, will have to be
repaid upon such redetermination. The Revolving Credit Facility is also subject
to certain covenants, including limitations on additional indebtedness and
limitations on payment of dividends.

The Revolving Credit Facility also requires the Company to (i) make
principal payments from the proceeds of certain asset sales and in the event
that the Company's outstanding debt exceeds the Borrowing Base (as defined
therein), and (ii) maintain an Earnings Before Interest, Taxes and Non-Cash
Expenses ("EBITDA") to interest coverage ratio for fiscal quarters ending on and
after March 31, 1998 as follows: 1.5:1 for each quarter ending on or before
September 30, 1998 and 2.5:1 thereafter, such rates to be calculated excluding
interest payable from the interest escrow for the Notes. As of September 30,
1997, the Company was not in compliance with the covenant requiring the Company
to maintain an EBITDA to interest coverage ratio of 1.5:1 for the quarter ending
September 30, 1997. Such non-compliance, however, was waived by the Company's
lenders. There can be no assurance that these requirements or other material
requirements of the Revolving Credit Facility will be met in the future. If they
are not, the lenders under the Revolving Credit Facility would be entitled to
declare the indebtedness thereunder immediately due and payable. Additionally,
in the event of such an acceleration of indebtedness by the lenders under the
Revolving Credit Facility, a default would be deemed to occur under the terms of
the Notes. In addition, the Revolving Credit Facility contains covenants and
restrictions that may limit the Company's ability to engage in a transaction
constituting a change-of-control. At December 31, 1997, $69,000,000 was
outstanding under this Revolving Credit Facility.

The Company makes, and will continue to make, substantial capital
expenditures for the acquisition, exploration, development and production of oil
and natural gas reserves. Since its inception, the Company has financed these
expenditures primarily through a combination of equity infusions by its
principal stockholders, bank and stockholder loans, the issuance of the Notes
and the sale of common stock. The Company made approximately $120 million in
capital expenditures in 1997, of which approximately $29 million was used for
the MOTL acquisition and the balance of which was expended primarily to develop
the Tantawan and Benchamas Fields. The Company currently expects capital
expenditures for 1998 to be in the range of $120 million, of which approximately
70% to 80% is budgeted for development of the Benchamas Field. The Company also
expects to expend monies over the next several years to support additional
exploration and development activities in the Block. Should the Company not be
able to access additional sources of funds over that period, the Company might
not generate sufficient cash flow to pay the principal and interest on its
outstanding debt. The Company expects to fund these activities in the near-term
with net cash flow from operations and additional bank borrowings under the
Revolving Credit Facility, which was amended in December 1997 to allow for
additional borrowings. However, in order to continue to fund those activities
subsequent to the first half of 1998 at current or higher levels, the Company
will have to raise substantial additional funds through some combination of the
following: increasing the borrowing base under the Revolving Credit Facility as
well as in the total amount of the Revolving Credit Facility, arranging
additional debt, equity or other financing, and obtaining other additional
sources of funds. If production revenues are less than anticipated or reserves
decline, or, if its expected levels of capital expenditures increase materially,
the Company may have limited ability to obtain the capital necessary to
undertake or complete future drilling programs. There can be no assurance that
increased bank lines, debt, equity or other financing or other sources of funds
will be available or that, if available, will be on terms acceptable to the
Company or sufficient to meet these or other corporate requirements, however,
the Company has explored several alternatives which it believes should enable it
to meet its capital commitments at an acceptable cost.

On January 22, 1998, the Company announced that it intends to explore
various strategic alternatives regarding the ongoing development of its interest
in Block B8/32. Such alternatives include the possible merger or sale of the
Company. There can be no assurance that this process will result in any
transaction.

YEAR 2000

All of the Company's computer systems are Year 2000 compliant. As a result,
the Company believes that it will not incur any material cost associated with
this matter.
18
22

FOREIGN CURRENCY FLUCTUATION AND REPATRIATION

While the Company does not currently hold significant amounts of cash, cash
equivalents, long-term financial instruments or investments denominated in
foreign currencies, some of its working capital and all of its gas revenues are
denominated in Thai Baht. For many years, the Thai Baht/U.S. Dollar exchange
rate had been stable, as the Baht was linked to a basket of currencies,
primarily the U.S. Dollar. On July 2, 1997 the Thai government decided to allow
the value of the Baht to be determined by market forces. Since the announcement,
the value of the Baht has declined against the U.S. Dollar by approximately 40%
to 50%. The Concessionaires' Gas Sales Agreement contains an adjustment factor
which insulates the Company from much of the impact of the declining value of
the Baht paid in conjunction with gas sales.

Although this adjustment factor does not fully compensate the Company
immediately for such currency fluctuation, the Company believes that the
reductions in U.S. Dollar realizations that do occur should be substantially
recouped over time, because of other adjustment factors in the GSA. However, the
Thai Baht denominated working capital items, while ultimately converted to U.S.
Dollars, do subject the Company to exchange rate exposure along with the
uncovered portion of the gas revenues described above. The Company may consider
instruments intended to mitigate this risk through currency rate hedging
transactions such as options, futures or other derivative financial instruments.

The Company is not aware of any regulations in Thailand prohibiting the
repatriation of funds to the United States by those with a legitimate business
purpose, like the Company. Additionally, the Concession Agreement provides an
unfettered right to retain and remit abroad its non-Thai currency.

EFFECTS OF INFLATION

Currently, annual inflation in the United States, measured by the decrease
in the general purchasing power of the dollar, is running below annual inflation
rates experienced in the past. While the Company, like other companies,
continues to be affected by fluctuations in the purchasing power of the dollar,
such effect is not currently considered significant.

While inflation in Thailand has been low relative to rates of past years,
the recent devaluation of the Thai Baht could lead to increases in Thai
inflation. Since most of the Company's purchase obligations are denominated in
U.S. Dollars, the impact of Thai inflation should not be significant on its
results of operations.

CHANGING OIL PRICES

The Company is dependent on crude oil prices, which have historically been
volatile. The Company has used crude oil price swaps and other similar
arrangements to hedge against potential adverse effects of fluctuations in
prices for the Company's future oil production. While the swaps are intended to
reduce the Company's exposure to declines in the market price of crude oil, they
may limit the Company's gain from increases in the market price.

In 1996, the Company entered into crude oil swap agreements for 1997 in the
amount of 1,000,000 barrels at $15.92 per barrel, and 1998 in the amount of
1,750,000 barrels at $15.92 per barrel. As the Company's production in 1997 did
not reach its swap obligation and the Company expected that situation to
continue in 1998, a portion of the Company's obligation was considered
speculative in 1997, marked to market and recognized in consolidated net income.

During the first quarter of 1998, the Company entered into an offsetting
position for its entire 1998 swap position, thus resulting in no material
exposure to the original swaps. The cost of establishing this position was
insignificant.

The Company has also sold to an affiliate of its lender a swap option for
1,250,000 barrels of aggregate oil volumes for January through December 1999 at
a price of $18.30 per barrel. The Company has accounted for the swap option
separately as it does not qualify as a hedge. At December 1997, the Company
estimates the fair market value of this position to be $625,000 and has recorded
the amount as a liability on the consolidated balance sheet.

19
23

SFAS 130, 131 AND 132

In June 1997, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 130, "Reporting Comprehensive
Income" ("SFAS 130"), which establishes standards for reporting and display of
comprehensive income and its components. The components of comprehensive income
refer to revenues, expenses, gains and losses that are excluded from net income
under current accounting standards, including unrecognized foreign currency
translation items, minimum pension liability adjustments and unrealized gains
and losses on certain investments in debt and equity securities. SFAS 130
requires that all items that are recognized under accounting standards as
components of comprehensive income be reported in a financial statement
displayed in equal prominence with the other financial statements; the total of
other comprehensive income for a period is required to be transferred to a
component of equity that is separately displayed in a statement of financial
position at the end of an accounting period. SFAS 130 is effective for both
interim and annual periods beginning after December 15, 1997. The Company does
not expect SFAS 130 to have a material effect on reported results.

In June 1997, the FASB issued Statement of Financial Accounting Standards
No. 131, "Disclosures about Segments of an Enterprise and Related Information"
("SFAS 131"). SFAS 131 establishes standards for the way public enterprises are
to report information about operating segments in annual financial statements
and requires the reporting of selected information about operating segments in
interim financial reports issued to shareholders. It also establishes standards
for related disclosures about products and services, geographic areas, and major
customers. SFAS 131 is effective for periods beginning after December 15, 1997.
The Company does not expect SFAS 131 to have a material effect on its reported
results.

In February 1998, the FASB issued Statement of Financial Accounting
Standards No. 132, "Employers' Disclosures about Pensions and Other
Postretirement Benefits," ("SFAS 132"), which establishes standardized
disclosure requirements for such benefits. SFAS 132 is effective for fiscal
years beginning after December 15, 1997. The Company does not expect SFAS 132 to
have a material effect on reported results.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PAGE
----

Independent Auditors' Report................................ 21
Consolidated Statements of Operations, for the year ended
December 31, 1997 and the periods June 18, 1996 through
December 31, 1996 (Company), and January 1, 1996 through
June 17, 1996 and for the year ended December 31, 1995
(Predecessors)............................................ 22
Consolidated Balance Sheets, December 31, 1997 and 1996..... 23
Consolidated Statements of Changes in Stockholders' Equity,
for the year ended December 31, 1997 and the periods June
18, 1996 through December 31, 1996 (Company), and January
1, 1996 through June 17, 1996 and for the year ended
December 31, 1995
(Predecessors)............................................ 24
Consolidated Statements of Cash Flows for the year ended
December 31, 1997 and the periods June 18, 1996 through
December 31, 1996 (Company), and January 1, 1996 through
June 17, 1996 and for the year ended December 31, 1995
(Predecessors)............................................ 25
Notes to Consolidated Financial Statements.................. 26

20
24

INDEPENDENT AUDITORS' REPORT

The Board of Directors
Rutherford-Moran Oil Corporation:

We have audited the accompanying consolidated balance sheets of
Rutherford-Moran Oil Corporation as of December 31, 1997 and 1996 and the
related consolidated statements of operations, changes in stockholders' equity
and cash flows for the year ended December 31, 1997 and the period June 18, 1996
through December 31, 1996 and the Company's Predecessors' consolidated
statements of operations, changes in partners' equity and cash flows for the
period January 1, 1996 through June 17, 1996 and for the year ended December 31,
1995. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated 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 consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Rutherford-Moran Oil Corporation as of December 31, 1997 and 1996, and the
results of its operations and its cash flows for the year ended December 31,
1997 and the period June 18, 1996 through December 31, 1996, and those of its
Predecessors for the period January 1, 1996 through June 17, 1996 and for the
year ended December 31, 1995, in conformity with generally accepted accounting
principles.

As discussed in Note 3 to the consolidated financial statements, the
Company has given retroactive effect to the change in accounting for oil and gas
properties from the full cost method to the successful efforts method.

KMPG Peat Marwick LLP

March 2, 1998
Houston, Texas

21
25

RUTHERFORD-MORAN OIL CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

JUNE 18, JANUARY 1,
YEAR ENDED THROUGH THROUGH YEAR ENDED
DECEMBER 31, DECEMBER 31, JUNE 17, DECEMBER 31,
1997 1996* 1996* 1995*
------------ ------------ -------------- --------------
(COMPANY) (COMPANY) (PREDECESSORS) (PREDECESSORS)

Revenues:
Oil revenue............................. $ 11,281 $ -- $ -- $ --
Gas revenue............................. 23,753 -- -- --
Interest income......................... 431 170 -- 5
-------- ------- ------- -------
Total revenues.................. 35,465 170 -- 5
-------- ------- ------- -------
Expenses:
Operating expense....................... 24,243 -- -- --
Exploration costs....................... 7,630 2,882 143 1,525
Interest expense........................ 7,157 411 395 190
Depreciation, depletion and
amortization......................... 18,055 25 4 5
General and administrative.............. 5,737 1,980 288 322
Foreign exchange loss................... 6,323 -- -- --
Gain on futures contract................ (506) -- -- --
-------- ------- ------- -------
Total expenses.................. 68,639 5,298 830 2,042
-------- ------- ------- -------
Loss before income tax benefit............ (33,174) (5,128) (830) (2,037)
Income tax benefit........................ (10,523) (2,238) (1,283) --
-------- ------- ------- -------
Net income (loss)......................... $(22,651) $(2,890) $ 453 $(2,037)
======== ======= ======= =======
Net income (loss) per basic share......... $ (0.88) $ (0.11) $ 0.02 $ (0.10)
======== ======= ======= =======
Net income (loss) per diluted share....... $ (0.88) $ (0.11) $ 0.02 $ (0.10)
======== ======= ======= =======
Weighted average number of common shares
outstanding............................. 25,612 25,514 21,000(a) 21,000(a)
======== ======= ======= =======

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

* Restated

(a) Rutherford-Moran Oil Corporation became a public entity in June 1996. See
Note 2 to Consolidated Financial Statements -- Significant Accounting
Policies.

See accompanying notes to consolidated financial statements.

22
26

RUTHERFORD-MORAN OIL CORPORATION

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT FOR SHARE INFORMATION)

ASSETS

DECEMBER 31,
--------------------
1997 1996*
-------- --------

Current assets:
Cash and cash equivalents................................. $ 1,979 $ 444
Accounts receivable....................................... 10,457 --
Value added tax receivable................................ 5,579 2,806
Joint interest receivable................................. 2,169 --
Other..................................................... 1,916 17
-------- --------
Total current assets.............................. 22,100 3,267
Property and equipment (successful efforts method).......... 238,651 113,680
Accumulated depreciation, depletion, and amortization....... (18,002) (37)
-------- --------
Net property and equipment........................ 220,649 113,643
Deferred charges:
Loan acquisition costs, net............................... 8,493 1,548
Escrowed funds, net....................................... 21,263 --
Deferred charge........................................... 1,026 1,400
Deferred income tax....................................... 6,169 3,521
-------- --------
Total deferred assets............................. 36,951 6,469
-------- --------
Total assets.................................... $279,700 $123,379
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities.................. $ 16,695 $ 852
Joint interest payable.................................... -- 2,565
-------- --------
Total current liabilities......................... 16,695 3,417
-------- --------
Note payable to bank........................................ 69,000 22,842
10.75% senior subordinated notes............................ 120,000 --
Premium on written option................................... 625 1,400
Stockholders' equity:
Preferred stock, $0.01 par value, 10,000,000 shares
authorized, no shares issued and outstanding........... -- --
Common stock, $0.01 par value, 40,000,000 shares
authorized, and 25,614,000 and 25,607,000 shares issued
and outstanding at December 31, 1997 and 1996,
respectively........................................... 256 256
Additional paid-in capital................................ 99,571 99,412
Deferred compensation..................................... (906) (1,058)
Accumulated deficit....................................... (25,541) (2,890)
-------- --------
Total stockholders' equity........................ 73,380 95,720
-------- --------
Commitments and contingencies............................. -- --

Total liabilities and stockholders' equity...... $279,700 $123,379
======== ========

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

* Restated

See accompanying notes to consolidated financial statements.

23
27

RUTHERFORD-MORAN OIL CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN
STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT FOR SHARE INFORMATION)

COMMON STOCK
-------------------- ADDITIONAL TOTAL
PREDECESSORS' SHARES PAID-IN ACCUMULATED DEFERRED STOCKHOLDERS'
EQUITY OUTSTANDING AMOUNT CAPITAL DEFICIT COMPENSATION EQUITY
------------- ----------- ------ ---------- ----------- ------------ -------------

Balance at December 31, 1994..... $ 15,484 -- $ -- $ -- $ -- $ -- $ 15,484
Cumulative effect of change in
accounting principle, as
retroactively applied.......... (5,267) -- -- -- -- -- (5,267)
Capital contributions............ 8,297 -- -- -- -- -- 8,297
Net loss......................... (2,037) -- -- -- -- -- (2,037)
-------- ---------- ---- -------- -------- ------- --------
Balance at December 31, 1995*.... 16,477 -- -- -- -- -- 16,477
Net income from January 1, 1996
to June 17, 1996............... 453 -- -- -- -- -- 453
Transfer of interests and
issuance of common stock in
initial public offering........ (16,930) 24,955,662 250 100,889 -- -- 84,209
Redemption of Rutherford-Moran
Exploration Company stock by
majority shareholders.......... -- -- -- (12,360) -- -- (12,360)
Exercise of call option on Thai
Romo Limited stock............. -- -- -- (3,130) -- -- (3,130)
Issuance of common stock for
initial public offering
over-allotment................. -- 600,000 6 12,828 -- -- 12,834
Grant of restricted stock
awards......................... -- 51,338 -- 1,185 -- (1,185) --
Amortization of restricted stock
awards......................... -- -- -- -- -- 127 127
Net loss from June 18, 1996 to
December 31, 1996.............. -- -- -- -- (2,890) -- (2,890)
-------- ---------- ---- -------- -------- ------- --------
Balance at December 31, 1996*.... -- 25,607,000 256 99,412 (2,890) (1,058) 95,720
Grant of restricted stock
awards......................... -- 7,000 -- 159 -- (159) --
Amortization of restricted stock
awards......................... -- -- -- -- -- 311 311
Net loss......................... -- -- -- -- (22,651) -- (22,651)
-------- ---------- ---- -------- -------- ------- --------
Balance at December 31, 1997..... $ -- 25,614,000 $256 $ 99,571 $(25,541) $ (906) $ 73,380
======== ========== ==== ======== ======== ======= ========

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

* Restated

See accompanying notes to consolidated financial statements.

24
28

RUTHERFORD-MORAN OIL CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

JUNE 18, JANUARY 1,
THROUGH THROUGH
YEAR ENDED DECEMBER 31, JUNE 17, YEAR ENDED
1997 1996* 1996* 1995*
---------- ------------ -------------- --------------
(COMPANY) (COMPANY) (PREDECESSORS) (PREDECESSORS)

Cash flows from operating activities:
Net income (loss).................................. $ (22,651) $ (2,890) $ 453 $ (2,037)
Adjustments to reconcile net income (loss) to cash
provided by (used in) operating activities:
Depreciation, depletion, and amortization........ 18,055 25 4 5
Deferred income tax benefit...................... (10,523) (2,238) (1,283) --
Foreign exchange loss............................ 6,323 -- -- --
Dry hole cost.................................... 2,768 -- -- --
Other............................................ 791 268 -- --
Changes in assets and liabilities
Accounts receivable............................ (10,457) (764) (559) (1,628)
Value added tax receivable..................... (5,367) -- -- --
Joint interest receivable...................... (4,734) -- -- --
Accounts payable and accrued liabilities....... 15,843 (4,116) 6,336 479
Other.......................................... (1,899) 13 (172) (25)
--------- -------- -------- --------
Cash provided by (used in) operating
activities................................ (11,851) (9,702) 4,779 (3,206)
--------- -------- -------- --------
Cash flows from investing activities:
Capital expenditures............................... (90,451) (34,023) (30,272) (35,263)
Acquisition of Maersk, net of cash acquired........ (29,414) -- -- --
--------- -------- -------- --------
Cash used in investing activities........... (119,865) (34,023) (30,272) (35,263)
--------- -------- -------- --------
Cash flows from financing activities:
Subordinated debt borrowings....................... 120,000 -- -- --
Deferred financing costs........................... (7,916) (1,689) -- --
Exercise of call option on Thai Romo Limited
stock............................................ -- (3,130) -- --
Capital contributions.............................. -- -- -- 7,898
Proceeds from initial public offering.............. -- 97,043 -- --
Redemption of Rutherford-Moran Exploration Company
stock by majority stockholders................... -- (12,360) -- --
Proceeds from loans from stockholders.............. 4,000 -- 15,654 6,993
Payments on loans from stockholders................ (4,000) (24,144) -- --
Repayments of bank notes........................... (99,176) (49,664) (13,885) --
Borrowings under bank notes........................ 145,334 22,842 29,164 32,985
Escrowed funds..................................... (21,263) -- -- --
--------- -------- -------- --------
Cash provided by financing activities....... 136,979 28,898 30,933 47,876
--------- -------- -------- --------
Net increase (decrease) in cash and cash
equivalents............................... 5,263 (14,827) 5,440 9,407
Effect of foreign exchange rate on cash............ (3,728) -- -- --
Cash and cash equivalents, beginning of period..... 444 15,271 9,831 424
--------- -------- -------- --------
Cash and cash equivalents, end of period........... $ 1,979 $ 444 $ 15,271 $ 9,831
========= ======== ======== ========
Supplemental disclosures of cash flow information:
Cash paid during the period of interest............ $ 2,468 $ 1,139 $ 767 $ 211
========= ======== ======== ========
Cash paid during the period for income tax......... $ -- $ -- $ -- $ --
========= ======== ======== ========
Supplemental disclosure of noncash investing and
financing activities:
Issuance of partnership interest in Thai Romo
Limited for loan acquisition costs............... $ -- $ -- $ -- $ 400
========= ======== ======== ========
Capitalization of amortized loan acquisition
costs............................................ $ 3,938 $ -- $ 168 $ 231
========= ======== ======== ========
Interests in Thai Romo Limited and Rutherford-Moran
Exploration Company contributed for common
stock............................................ $ -- $ -- $ 16,930 $ --
========= ======== ======== ========
Premium deferred and premium on written option..... $ 775 $ 843 $ 557 $ --
========= ======== ======== ========

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

* Restated

See accompanying notes to consolidated financial statements.

25
29

RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 ORGANIZATION

The accompanying consolidated financial statements of Rutherford-Moran Oil
Corporation ("RMOC" or the "Company"), a Delaware corporation, have been
prepared pursuant to the rules and regulation of the Securities and Exchange
Commission ("SEC").

The Company is an independent energy company engaged in the acquisition,
exploration, development and production of oil and gas properties in Southeast
Asia. As of December 31, 1997, the Company's exploration activities are entirely
in the Gulf of Thailand and are conducted through its subsidiary, Thai Romo,
Limited ("Thai Romo"), and its affiliate, B8/32 Partners, Ltd. ("B8/32
Partners").

The financial statements reflect all adjustments that, in the opinion of
management, are necessary for a fair presentation.

NOTE 2 SIGNIFICANT ACCOUNTING POLICIES

PRINCIPLES OF CONSOLIDATION

In April 1996, Rutherford/Moran Oil Corporation changed its name to
Rutherford-Moran Exploration Company ("RMEC"). RMEC was formed on September 21,
1990 for the purpose of holding an interest in an oil and gas concession in
Thailand through its subsidiary, Thai Romo, which was organized as a foreign
corporation under the laws of the Kingdom of Thailand. Thai Romo was formed as a
wholly-owned subsidiary of RMEC. Thai Romo is one of the concessionaires under
the Petroleum Concession No. 1/2534/36 (the "Concession") awarded by the
Ministry of Industry of the Kingdom of Thailand for the development and
production of oil and gas reserves in offshore Block B8/32 in the central
portion of the Gulf of Thailand. The Concession was awarded on August 1, 1991,
to Thai Romo, Thaipo Limited ("Thaipo"), a wholly-owned subsidiary of Pogo
Producing Company, and Maersk Oil (Thailand), Limited ("MOTL"), a wholly-owned
subsidiary of Maersk Olie og Gas As. Subsequent to the award, the Sophonpanich
Co., Limited ("Sophonpanich") elected to participate in the Concession as a
co-venturer. Thaipo has been the operator of the Tantawan Field within the
Concession, while prior to March 1997 the remainder of the Concession was
operated by MOTL. Subsequent to March 1997, Thaipo operated the remainder of the
Concession, as the shares of MOTL were sold to the Concessionaires.

Effective June 17, 1996, the stockholders of RMEC and the partners of Thai
Romo exchanged their interests for shares of common stock of a newly formed
entity, RMOC. RMOC is the parent company of RMEC and Thai Romo Holdings, Inc.
("TRH"). RMEC and TRH collectively own the outstanding shares of Thai Romo.
During June 1996, RMOC sold 16% of its common stock in an initial public
offering (the "Offering") in conjunction with the consummation of the exchange
of RMEC common stock and Thai Romo interests for common stock of RMOC. In
conjunction with the Offering, RMEC redeemed for $12.4 million approximately
56,000 shares of its common stock from Patrick R. Rutherford and John A. Moran,
majority stockholders of RMEC (the "Redemption"), exercised RMEC's call option
on 3% of the partners' interest in Thai Romo held by Red Oak Holdings, Inc. (an
affiliate of Chase Manhattan Bank, the Company's primary lender) for $3.1
million and repaid outstanding debt of $62 million owed stockholders and banks.
On June 18, 1996, the stockholders' equity accounts were adjusted to reflect the
transfer of accumulated deficit to additional paid-in capital upon RMEC and Thai
Romo becoming subject to federal income taxes. During July 1996, an additional
2.4% of RMOC's common stock was sold when the underwriters exercised their over-
allotment option.

The consolidated financial statements for 1997 and 1996 include the
accounts of RMOC and its wholly owned subsidiaries, RMEC, Thai Romo, TRH and
Thai-Tex Insurance Company, Inc., as well as a proportionate interest in B8/32
Partners since its purchase on March 3, 1997. All material intercompany accounts
and transactions have been eliminated in consolidation.

26
30
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The financial statements for the year ended December 31, 1995 and the
period from January 1, 1996 to June 17, 1996 include the accounts of RMEC, Thai
Romo and TRH (the "Predecessors"). All material intercompany accounts and
transactions have been eliminated in the combination. The combined financial
statements are presented due to the commonality of the stockholders and partners
of RMEC and Thai Romo.

The Company's planned principal operations did not commence until February
1997. As a result, the Company was considered a development stage company until
that time.

OIL AND GAS PROPERTIES

During the fourth quarter of 1997, the Company changed its method of
accounting for its investment in oil and gas properties from the full cost to
the successful efforts method (See Note 3). Under the successful efforts method
of accounting, costs of exploration, including lease acquisition and intangible
drilling costs associated with exploration efforts, which result in the
discovery of proved reserves and costs associated with development drilling,
whether of not successful, are capitalized. Gain or loss is recognized when a
property is sold or ceases to produce or is abandoned.

The cost of unproved leasehold is capitalized pending the results of
exploration efforts. Significant unproved leasehold costs are reviewed
periodically and a loss is recognized to the extent, if any, that the cost of
the property has been impaired. Exploratory dry holes, geological and
geophysical costs and delay rentals are expensed as incurred.

Capitalized drilling costs for oil and gas properties are amortized using
the units of production method based on units of proved developed reserves for
each field. Lease acquisition costs related to producing oil and gas properties
are amortized using the units of production method based on units of proved
reserves for each field.

The Company reviews proved oil and gas properties on a depletable unit
basis whenever events or circumstances indicate that the carrying value of those
assets may not be recoverable. An impairment loss is recognized whenever the
carrying value of an asset exceeds the fair value. Fair value, on a depletable
unit basis, is estimated to be the present value of expected future net revenues
computed by application of estimated future oil and gas prices, production, and
expenses, as determined by management, over the economic life of the reserves.
No such impairment was recognized as a result during 1997, 1996 or 1995.

CASH AND CASH EQUIVALENTS

The Company considers all currency and any liquid investments with a
maturity of three months or less to be cash equivalents.

HEDGING

During the first quarter of 1996, the Company entered into crude oil price
swaps with an affiliate of its lender in the amount of 1,000,000 barrels at
$15.92 per barrel for the period April through December of 1997, and in the
amount of 1,750,000 barrels at $15.92 per barrel for the year 1998. As the
Company's production in 1997 did not meet its swap obligation and the Company
expected that situation to continue in 1998, a portion of the Company's
obligation was considered speculative in 1997, marked to market and recognized
in consolidated net income.

During the first quarter of 1998, the Company entered into an offsetting
position for its entire 1998 swap position, thus resulting in no material future
exposure to the original swaps. The cost of establishing this position was
insignificant.

27
31
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company also sold to an affiliate of its bank lender an option to
purchase 1,250,000 barrels of aggregate oil volumes from January through
December 1999 at a price of $18.30 per barrel. The Company has accounted for the
swap option separately as it does not qualify as a hedge. At December 31, 1997,
the Company estimates the fair market value of this position to be $625,000 and
has recorded the amount as a liability on the consolidated balance sheet. The
Company has recorded a net gain of $506,000 in the 1997 Consolidated Statement
of Operations for the effect of speculative swap transactions.

REVENUE RECOGNITION

The Company recognizes revenues from the sale of natural gas when it is
discharged from the FPSO to the PTT pipeline. Revenue from the sale of crude oil
is recorded at the time of sale to a customer. Both oil and gas revenues are
also recorded using the entitlements method. Under that method, production
volumes received in excess of the Company's ownership percentage in the property
are recorded as a liability whereas production volumes less than the Company's
entitlement are recorded as a receivable. At December 31, 1997, there were no
gas imbalances.

GEOGRAPHICAL CONCENTRATION

The Concession is located in the Gulf of Thailand. Consequently,
substantially all the assets of Thai Romo and B8/32 Partners are subject to
regulation by the government of Thailand. Political changes, such as increases
in tax rates, nationalization of strategic or other assets, abrogation of
contracts or limitations on the convertibility of currency by the government of
Thailand, could adversely affect the Company and have an impact on future
results.

USE OF ESTIMATES

Management of the Company has made a number of estimates and assumptions
relating to the reporting of assets and liabilities, the reporting of quantities
of proved oil and gas reserves, and the disclosure of contingent assets and
liabilities to prepare these financial statements in conformity with generally
accepted accounting principles. Actual results could differ from those
estimates.

FOREIGN TRANSLATION GAIN/LOSS

Business transactions and foreign operations recorded in a foreign currency
are restated in U.S. Dollars, which is the Company's functional currency.
Revenues, operating and general and administrative expenses are translated at an
average exchange rate for the period. Transaction gains and losses that arise
from exchange rate fluctuations on transactions denominated in a currency other
than the functional currency are recognized in consolidated income in the year
of occurrence. Net current assets and liabilities are translated monthly at
current rates and recognized in consolidated income in the year of occurrence.
Currency translations resulted

28
32
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

in a loss of $6,323,000 during the year ended December 31, 1997; no such gains
or losses resulted in prior periods.

VALUE ADDED TAX REFUND RECEIVABLE

Expenditures on certain concession joint operations are assessed a value
added tax by the government of Thailand. Because the Thai Petroleum Income Tax
Act provides an exemption from value added taxes, all value added taxes are
refundable. Accordingly, a refund due is recorded when value added taxes are
paid by the operator. As such taxes are denominated in Thai Baht, translation
gains and losses are included in consolidated income in the year of occurrence.

CAPITALIZATION OF INTEREST EXPENSE

Interest in connection with expenditures on major exploration and
development projects is capitalized. During the year ended December 31, 1997,
approximately $2,200,000 of interest was capitalized as compared to
approximately $1,600,000 for the year ended December 31, 1996.

STOCK-BASED COMPENSATION

During 1996, the Company adopted Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" ("SFAS No. 123").
SFAS No. 123 allows a company to adopt a fair value based method of accounting
for a stock-based employee compensation plan or to continue to use the intrinsic
value based method of accounting prescribed by Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees ("APB No. 25"). The
Company has chosen to continue to account for stock-based compensation under APB
No. 25. Under this method, the Company has not recorded any compensation expense
related to stock options granted. The disclosures required by SFAS No. 123,
however, have been included in Note 10.

EARNINGS PER SHARE

During the fourth quarter of 1997, the Company adopted Statement of
Financial Accounting Standards No. 128, "Earnings per Share" ("SFAS 128"). SFAS
128 introduces the concept of basic earnings per share, which represents net
income divided by the weighted average common shares outstanding -- without the
dilutive effects of common stock equivalents (options, warrants, etc.). Common
stock equivalents with a weighted average of 201,754 and 115,750 during 1997 and
the period June 18, 1996 through December 31, 1996, respectively are not
included in the calculation of diluted earnings per share due to the net loss
recorded during the periods.

NOTE 3 CHANGE IN ACCOUNTING PRINCIPLE

During the fourth quarter of 1997, the Company changed its method of
accounting for its investment in oil and gas properties from the full cost to
the successful efforts method. All prior years' financial statements presented
herein have been restated to reflect the change.

The effect of adopting the change in accounting principle resulted in a
decrease in net loss of $26,683,000 (or $1.04 per share) which would have been
recognized had the Company continued to use the full cost method through
December 31, 1997. The effect of adopting the change in accounting principle
resulted in an increase in net loss during the period July 18 through December
31, 1996 and the year ended December 31, 1995 of $1,174,000 (or $0.05 per share)
and $1,525,000 (or $0.07 per share), respectively, and a decrease in net loss
during the period January 1 through July 17, 1996 of $3,061,000 (or $0.15 per
share). The cumulative effect of this change in accounting principle through
December 31, 1997 was an increase in stockholders'

29
33
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

equity and net oil and gas properties of $21,780,000 and $47,972,000,
respectively, and a decrease in deferred income tax assets of $21,019,000

The Company believes that the successful efforts method of accounting is
preferable as it will accurately reflect the Company's future operations. The
Company believes that the significant number of exploratory wells drilled
annually, as well as the amount of geological and geophysical cost necessary to
evaluate the Company's large acreage position, justifies the utilization of the
successful efforts method. Additionally, the Company expects such activities to
increase and remain at such an increased level for an indefinite period of time,
given the size of the Company's Thai assets and the prospectivity of the
acreage. As a result, the Company believes that a change in accounting principle
to successful efforts is appropriate at this time.

NOTE 4 INCOME TAXES

Deferred taxes are accounted for under the asset and liability method of
accounting for income taxes. Under this method deferred income taxes and related
benefits are recognized for the tax consequences of "temporary differences" by
applying enacted statutory tax rates applicable to future years to differences
between the financial statement carrying amounts and the tax basis of existing
assets and liabilities. The effect on deferred income taxes of a change in tax
rates is recognized in income in the period the change occurs.

The Predecessors were a limited partnership and an S Corporation under the
Internal Revenue Code of 1986, as amended. As such, they did not incur federal
income taxes; the taxable income or loss was passed through to the partners or
stockholders. As a result of the initial public offering in June 1996, the
Company became a taxable entity and recorded a one-time benefit of $1,283,000,
representing the difference between the financial statement and income tax basis
of its foreign oil and gas properties. The deferred income tax benefit recorded
for the year ended December 31, 1997 and the period June 18, 1996 through
December 31, 1996, was $10,523,000 and $2,238,000, respectively, which
represents foreign income tax benefits.

Total income tax benefit for the year ended December 31, 1997 and the
period June 18, 1996, through December 31, 1996, differs from the amount
computed by applying the federal income tax rate of 34% to the loss before
income taxes. The reasons for this difference follows (amounts in thousands):

PERIOD JUNE 18, 1996
1997 THROUGH DECEMBER 31, 1996
------- -------------------------

Expected federal income tax benefit................. $11,279 $1,744
Nondeductible costs for foreign income tax
purposes.......................................... (5,250) (394)
Foreign income tax rate difference.................. 4,494 888
------- ------
$10,523 $2,238
======= ======

30
34
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The tax effects of temporary differences that result in a significant
portion of the deferred income tax assets and liabilities and a description of
the financial statement items creating these differences are as follows on
December 31, 1997 and 1996 (amounts in thousands):

1997 1996
-------- -------

Deferred tax assets:
Net operating loss carryforwards:
Foreign................................................ $ 40,337 $ --
U.S.................................................... 7,555 1,954
Property and equipment
Foreign................................................ -- 5,866
U.S.................................................... 2,983 --
-------- -------
Deferred tax assets......................................... 50,875 7,820
Less: valuation allowance................................... (11,226) (1,622)
-------- -------
Net deferred tax assets..................................... 39,649 6,198
-------- -------
Deferred tax liabilities:
Property and equipment
Foreign................................................ (33,480) --
U.S.................................................... -- (2,677)
-------- -------
Deferred tax liabilities.................................... (33,480) (2,677)
-------- -------
Net deferred tax assets..................................... $ 6,169 $ 3,521
======== =======

In assessing the realizability of deferred tax assets, management considers
whether it is more likely than not that some portion or all of the deferred tax
assets will not be realized. Management considers the scheduled reversal of
deferred tax liabilities, projected future taxable income and tax planning
strategies in making this assessment. Based upon projections for future taxable
income over the periods which the deferred tax assets are deductible, management
believes it is more likely than not that the Company will realize the benefits
of these deductible differences, net of the existing valuation allowances at
December 31, 1997. During 1997, the valuation allowance increased $9.6 million
primarily due to the increase in net operating loss carryforwards generated.

At December 31, 1997, the Company had a net operating loss carryforward of
$80.7 million for Thai tax purposes, which expires in 2007, and $22.2 million
for U.S. tax purposes, which expires in 2011 and 2012.

NOTE 5 ACQUISITIONS

On December 19, 1996, Rutherford-Moran Oil Corporation, through its
wholly-owned subsidiary, Thai Romo, exercised its preferential right to purchase
46.34% of the outstanding shares of Maersk Oil (Thailand), Limited ("MOTL"), a
wholly owned subsidiary of Maersk Olie og Gas As of Copenhagen, Denmark
("Maersk"). MOTL was a former co-concessionaire in Block B8/32 located offshore
Thailand with a 31.67% interest in the Concession but had no previous
operations. The purchase was consummated on March 3, 1997, with TRH, a wholly
owned subsidiary of the Company and Thai Romo's nominee under the Share Sales
Agreement with Maersk, purchasing the shares for $28,617,000, which included
$1,554,000 in satisfaction of outstanding debt. After the closing, MOTL was
renamed B8/32 Partners, Ltd.

The purchase price was established in a Share Sale Agreement dated November
2, 1996, between Maersk and BG Egypt S.A. Pursuant to the Joint Operating
Agreement among the co-concessionaires, Thai Romo and the remaining
co-concessionaires jointly had a preferential right to purchase the stock of
MOTL on the terms and conditions agreed between Maersk and BG Egypt S.A.

In connection with the purchase the Company recorded $7,875,000 for the
deferred tax liability related to the excess of the acquisition price over the
tax basis of the MOTL property.

31
35
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The remaining 53.66% of MOTL's stock was purchased by Thaipo Limited
("Thaipo") and by Palang Sophon Limited ("Palang") of Bangkok, Thailand. Thaipo,
Palang and MOTL were co-concessionaires with Thai Romo prior to the sale of
MOTL. As a result, RMOC's interest in the entire Block B8/32 increased from
31.67% to 46.34%.

NOTE 6 DEBT

CREDIT FACILITY

On September 20, 1996, the Company entered into a $150 million Revolving
Credit Facility with a group of commercial lenders. The Revolving Credit
Facility has a final maturity of September 30, 1999, and contained an initial
borrowing base limitation of $60 million. On April 29, 1997, the borrowing base
limitation was redetermined to $120 million. Subsequent to the issuance of the
Company's 10.75% Senior Subordinated Notes (the "Notes") in September 1997, the
borrowing base was reset to $60 million. The Revolving Credit Facility is
secured by the stock of certain subsidiaries and affiliates of the Company.

On September 8, 1997, the Company entered into a Credit Agreement with
Chase Manhattan Bank for an additional borrowing of $5 million. The Credit
Agreement contains covenants substantially identical to those in the Revolving
Credit Facility. The Credit Agreement was repaid on September 29, 1997 with
proceeds from the Notes.

In December 1997, the Company and two of its lenders amended the Revolving
Credit Facility. The borrowing base was reset at a fixed amount of $150 million
until September 30, 1998 (or on the completion of certain new financings or
other specified events, if earlier). The amended Facility provides that the
Company pays interest at rates based on a margin of 1.75% over LIBOR if the
aggregate outstanding principal amount is less than or equal to a threshold
amount, which was set at $60 million, a margin of 2.75% over LIBOR if the
principal amount outstanding is greater than the threshold amount on or prior to
June 30, 1998, and a margin of 3.50% over LIBOR if the principal amount
outstanding is greater than the threshold amount after June 30, 1998.
Alternatively, the Company may pay a margin over the prime rate of 0.25%, 1% and
1.75% respectively, for similar levels of borrowings. The Company is also
assessed a commitment fee equal to 0.5% per annum on the average daily balance
of the unused borrowing base. As of September 30, 1998 and semi-annually
thereafter, the borrowing base will be redetermined by the lenders on customary
industry terms and the Company's then current reserve base. Bank borrowings in
excess of the borrowing base, if any, will have to be repaid upon such
redetermination.

The Revolving Credit Facility also provides for semi-annual borrowing base
redeterminations subsequent to September 30, 1998 as well as certain
restrictions, including limitations on additional indebtedness, payment of
dividends and maintenance of an interest coverage ratio, as well as the issuance
of 200,000 common stock warrants under specified circumstances.

At December 31, 1997, $69 million was outstanding under the Revolving
Credit Facility at an interest rate of 8.375% per annum.

NOTES

On September 29, 1997, the Company issued $120 million of Senior
Subordinated Notes due 2004 (the "Notes") at an annual interest rate of 10.75%.
The net proceeds were used to repay $93 million of outstanding indebtedness
under the Revolving Credit Facility and Credit Agreement and to purchase $24
million of securities which were escrowed to pay interest on the Notes. The
Notes contain customary covenants, including limitations on the incurrence of
additional indebtedness, restricted payments and the establishment of certain
liens.

32
36
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In February 1998, the Company completed the exchange of the Notes, which
had been privately placed, for publicly registered notes. The new Notes
otherwise contain identical terms and conditions to the privately placed notes.

The Company expects to expend monies over the next several years to support
additional exploration and development activities in Block B8/32. Should the
Company not be able to access additional sources of funds over that period, the
Company might not generate sufficient cash flow to pay the principal and
interest on its outstanding debt.

LOANS FROM STOCKHOLDERS

RMEC had loans from stockholders at December 31, 1995 as follows (amounts
in thousands):

PAYMENT INTEREST
STOCKHOLDER TERMS RATES 1995
----------- --------- -------- ------

Patrick R. Rutherford................................ On demand Prime $4,254
John A. Moran........................................ On demand Prime 4,036
Sidney F. Jones, Jr.................................. On demand Prime 200
------
$8,490
======

The loans from stockholders were retired on June 28, 1996 with proceeds
from the initial public offering.

Interest of $368,000 and $190,000 was expensed by RMEC under the above
loans during January 1, 1996 through June 17, 1996 and the year ended December
31, 1995, respectively.

On November 14, 1997, the Company borrowed $4 million from Patrick R.
Rutherford, President and Chief Executive Officer of the Company. The note
matured on December 12, 1997 and carried an interest rate of 8.75%. The note was
repaid on December 4, 1997.

As of December 31, 1997, the total debt maturities by year are as follows
(amounts in thousands):

1998.............................................. $ --
1999.............................................. 69,000
2000.............................................. --
2001.............................................. --
2002.............................................. --
Thereafter........................................ 120,000
--------
$189,000
========

NOTE 7 ESCROWED FUNDS

In conjunction with the issuance of the Notes (See Note 6) the Company was
required to purchase $24,300,000 of U.S. Government securities and placed the
proceeds in escrow with the Trustee. The amount of the securities purchased will
be sufficient upon receipt of scheduled interest and principal payments to
provide for payment in full of the first four scheduled interest payments due on
the Notes. As the result, the utilization of escrowed funds will be amortized
over that period of time.

NOTE 8 CAPITAL STOCK

COMMON AND PREFERRED STOCK

The Certificate of Incorporation of the Company authorizes the issuance of
up to 40,000,000 shares of common stock and 10,000,000 shares of preferred
stock, the terms, preferences, rights and restrictions of

33
37
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

which will be established by the Board of Directors of the Company. All shares
of common stock have equal voting rights of one vote per share on all matters to
be voted upon by stockholders. Cumulative voting for the election of directors
is not permitted.

On June 17, 1996, the Company sold 4,000,000 shares of its common stock in
an initial public offering at $23 per share. During July 1996, the Company sold
an additional 600,000 shares at $23 per share when the underwriters exercised
their over-allotment option.

NOTE 9 RELATED PARTY TRANSACTIONS

Historically, Rutherford Oil Corporation ("Rutherford Oil"), which is
controlled by Patrick R. Rutherford, obtained certain oil and gas related and
medical insurance on behalf of the Company and performed certain payroll related
services for the Company. The Company has reimbursed Rutherford Oil for its
out-of-pocket expenses relating to such insurance and services, which aggregated
$133,000 and $731,000, during period January 1, 1996 to June 17, 1996 and the
year ended December 31, 1995. Subsequent to June 1996 Rutherford Oil no longer
obtained insurance or performed any such services on behalf of the Company.

NOTE 10 EMPLOYEE BENEFIT PLANS

KEY EMPLOYEE STOCK PLAN

During 1996, the Company established its 1996 Key Employee Stock Plan (the
"Stock Plan"). Under the Stock Plan, an aggregate of 500,000 shares will be
available for the granting of either stock options or restricted stock awards.
The Compensation Committee of the Board of Directors administers this plan.

Stock options issued under the Stock Plan may not exceed a term of more
than ten years and the stock option price may not be less than the fair market
value of the shares at the time the option is granted. The options are
exercisable ratably over a five year period. During 1997 and 1996, 157,250 and
105,750 stock options were issued. At December 31, 1997, 263,000 stock options
were outstanding, of which 21,150 are currently exercisable. The weighted
average exercise prices for options granted during 1997 and 1996 were $22.04 and
$23.00 per share, respectively, with exercise prices ranging from $18.19 to
$23.00 per share.

The Compensation Committee may award shares of restricted stock to
employees for no payment by the employee or for a payment below the fair market
value on the date of grant. Issuance of the stock may be subject to certain
restrictions, but in no case can the conditions continue for more than ten years
from the date of the award. As the shares vest, each employee receiving such
restricted stock has all of the rights of a stockholder, including without
limitation, the right to vote such shares. At December 31, 1997, restricted
stock awards for 58,338 shares had been granted at no cost to the employees, of
which 7,000 and 51,338 shares were granted during 1997 and 1996, respectively.
Deferred compensation is recorded at the date of the restricted stock award and
is amortized into compensation expense over the vesting period. At December 31,
1997, deferred compensation of $906,000 was recorded and related compensation
expense in 1997 and 1996 of $311,000 and $127,000, respectively, was recognized.
Substantially all restricted stock awards outstanding at December 31, 1997, vest
ratably over a five year period. At December 31, 1997, 12,368 shares were
vested.

NON-EMPLOYEE DIRECTOR STOCK OPTION PLAN

During 1996, the Company established its 1996 Non-Employee Director Stock
Option Plan (the "Director Plan"). Under the Director Plan, an aggregate of
50,000 shares of common stock will be available for the granting of stock
options to non-employee directors of the Company. The exercise price of a stock
option granted pursuant to the Director Plan may not be less than the fair
market value of the common stock on the date of grant and the stock option term
may not exceed ten years. Stock options granted under the Director Plan are
exercisable in full after the first anniversary of grant. The Director Plan
provides for an initial

34
38
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

grant of stock options to each non-employee director to purchase 2,500 shares of
common stock contemporaneously with the initial public offering and the annual
grant of stock options to acquire 1,000 shares of stock to each non-employee
director serving on the board of directors following each annual meeting of the
stockholders. As of December 31, 1997, non-employee directors have been granted
stock options to acquire 14,000 shares of common stock, of which 10,000 shares
are exercisable. The range of exercise prices for all options granted to date is
$22.00 to $23.00 per share.

ACCOUNTING FOR STOCK-BASED COMPENSATION

The Company applies Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees", and related interpretations in accounting for
its Stock Plan and Director Plan. Accordingly, no compensation has been
recognized for stock-based compensation other than for restricted stock awards.
Had compensation cost for the stock options issued under the Stock Plan and
Director Plan been determined based upon SFAS No. 123, the fair value at the
grant date for awards under these plans consistent with the methodology
prescribed under the Company's net loss and net loss per share would have
increased by approximately $348,279, or $.01 per share during 1997 and
$1,812,000, or $0.07 per share during 1996. The fair value of the stock options
granted during the twelve-month periods ended December 31, 1997 and 1996 are
estimated as $10.63 and $16.32, respectively on the date of grant using the
Black-Scholes option pricing model with the following assumptions: dividend
yield of 0%, volatility of 55.10% and 23%, respectively, risk-free interest rate
of 5.54% and 6.42%, respectively, assumed forfeiture rate of 0%, and an expected
life of 4 years and 9.5 years, respectively.

At December 31, 1997, 239,962 and 36,000 shares of common stock were
reserved for issuance pursuant to the Stock Plan and the Director Plan,
respectively. The remaining weighted average life of the 273,000 options
outstanding at December 31, 1997, is 9 years.

NOTE 11 COMMITMENTS AND CONTINGENCIES

GUARANTY AND INDEMNITY AGREEMENT

On February 9, 1996, Thai Romo entered into a Guaranty and Indemnity
Agreement ("Guaranty") associated with a Bareboat Charter Agreement between
Tantawan Services, LLC ("Tantawan Services"), as charterer, and Tantawan
Production B.V., as lessor, for the leasing and operation of a Floating
Production Storage and Offloading system (FPSO) known as the Tantawan Explorer.
The initial duration of the Bareboat Charter Agreement is 10 years commencing
upon delivery of crude oil to the FPSO. The hire rate under the Bareboat Charter
Agreement is $55,000 per day. Thai Romo has guaranteed payment of 46.34% of
these costs or $25,448 per day. The Guaranty terminates upon the expiration of
the Bareboat Charter Agreement, notwithstanding the lawful termination or
cancellation of the Bareboat Charter Agreement. Should the initial term of the
Guaranty be extended or the FPSO purchased, Thai Romo would remain obligated for
46.34% of any subsequent obligations incurred by Tantawan Services.

35
39
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

LEASE COMMITMENTS

RMEC is subject to an office lease which expires in February 2002. The
commitment under this lease is as follows (amounts in thousands):

YEAR
----

1998.................................................. $133
1999.................................................. 142
2000.................................................. 159
2001.................................................. 159
2002.................................................. 27
----
$620
====

Rental expense paid during 1997 and the years ended December 31, 1996 and
1995 was $133,000, $97,000, and $67,000, respectively.

NOTE 12 LITIGATION

As of December 31, 1997, the Company is not aware of any current or
potential legal proceedings.

NOTE 13 PRIMARY CUSTOMERS

All natural gas produced from the Tantawan and Benchamas Fields will be
sold to PTT, which maintains a monopoly over gas transmission and distribution
in Thailand.

A Gas Sales Agreement (the "GSA") with PTT for the Tantawan Field was
signed on November 7, 1995. Under the GSA, which is a take or pay agreement,
contracted deliveries of gas to PTT began in 1997 at a reduced price and was
sold at full contractual price at the conclusion of a 72-hour production test,
which was completed in March 1997. The natural gas price is based on formulae
which provide adjustments to the base price for natural gas on each April 1 and
October 1. Adjustments will be made to reflect changes in (i) wholesale prices
in Thailand, (ii) the U.S. producer price index for oil field machinery and
tools, and (iii) medium fuel oil prices. Adjustment factors for oil field
machinery and medium fuel oil prices will be subsequently adjusted for Thai
Baht/U.S. Dollar fluctuations, since payments from PTT are in Thai Baht. The
realized price was estimated to be equivalent to $1.64 per thousand cubic feet
(Mcf) in December 1997.

The GSA was amended in November 1997 to incorporate production from the
Benchamas Field and the daily contract quantity will be increased upon the
conclusion of a 72 hour production test at Benchamas Field once such production
commences.

The crude oil and condensate blend is sold on the spot market. The Company
believes that it can sell the blend to a variety of purchasers.

NOTE 14 SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

At December 31, 1997 and 1996 the Concession accounted for 100% of the
Company's future net cash flow from proved reserves.

Included herein is information with respect to oil and gas acquisition,
exploration, development and production activities, which is based on estimates
of year-end oil and gas reserve quantities and estimates of future development
costs and production schedules. The prices used in the reserve estimates are
prices the Company estimated it would have received at the respective date had
the Tantawan and Benchamas fields been producing at such time, except where
fixed and determinable price escalations or oil hedges are provided by contract.
Reserve quantities and future production are based primarily upon reserve
reports prepared by the

36
40
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

independent petroleum engineering firm of Ryder Scott Company. These estimates
are inherently imprecise and subject to substantial revision.

All reserve estimates presented herein were prepared by Ryder Scott
Company, independent petroleum engineers. The Company cautions that there are
many uncertainties inherent in estimating proved reserve quantities, and in
projecting future production rates and the timing of future development
expenditures, including many factors beyond the control of the producer.
Accordingly, these estimates are subject to change as additional information
becomes available. Reservoir engineering is a subjective process of estimating
underground accumulations of oil and gas that cannot be measured in an exact
way, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of drilling, testing and production subsequent to the date of an
estimate may justify revision of the estimate. Accordingly, reserve estimates
are often different from the quantities of oil and gas that are ultimately
recovered.

Estimates of future net cash flows from proved reserves of oil and gas were
made in accordance with Statement of Financial Accounting Standards No. 69,
"Disclosures about Oil and Gas Producing Activities." The estimates are based on
prices the Company estimated it would have received at the respective date had
the Tantawan and Benchamas fields been producing at such time. Estimated future
cash inflows are reduced by estimated future development and production costs
based on year-end cost levels, assuming continuation of existing economic
conditions, and by estimated future tax expense. Tax expense is calculated by
applying the existing U.S. and Thailand statutory tax rates, including any known
future changes. The results of these disclosures should not be construed to
represent the fair market value of the Company's oil and gas properties. A
market value determination would include many additional factors including: (i)
anticipated future increases and decreases in oil and gas prices and production
and development costs; (ii) an allowance for return on investment; (iii) the
value of additional reserves not considered proved at the present, which may be
recovered as a result of further exploration and development activities; and
(iv) other business risks.

In computing the present value of the estimated future net cash flows, a
discount factor of 10% was used pursuant to SEC regulations to reflect the
timing of those net cash flows. Present value, regardless of the discount rate
used, is materially affected by assumptions about timing of future production,
which may prove to have been inaccurate. The following reserve value data
represent estimates only, which are subject to uncertainty given the current
energy markets.

Capitalized Costs of Oil and Gas Producing Activities

The following table sets forth the aggregate amounts of capitalized costs
relating to the Company's oil and gas producing activities and the aggregate
amount of related accumulated depreciation, depletion and amortization as of the
dates indicated (amounts in thousands).

DECEMBER 31,
--------------------
1997 1996
-------- --------

Productive and nonproductive properties being depleted...... $151,176 $ --
Unevaluated leasehold and property costs not subject to
amortization.............................................. 87,092 113,484
Less accumulated depreciation, depletion and amortization... (17,893) --
-------- --------
Net capitalized costs....................................... $220,375 $113,484
======== ========

37
41
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Costs Incurred in Oil and Gas Producing Activities

The following table reflects the costs incurred in oil and gas property
acquisition, exploration and development activities during the periods indicated
(amounts in thousands).

YEAR ENDED DECEMBER 31,
------------------------------
1997 1996 1995
-------- ------- -------

Property acquisition costs........................... $ 29,354 $ -- $ 4,224
Exploratory costs.................................... 23,485 7,460 26,601
Development cost..................................... 71,703 59,890 6,182
-------- ------- -------
$124,542 $67,350 $37,007
======== ======= =======

The following table sets forth the Company's interest in estimated total
proved oil and gas reserves for the years ended December 31, 1997, 1996, and
1995:

OIL GAS
(BBLS) (MMCF)
----------- -------

Total proved reserves at December 31, 1994.................. 7,674,372 56,739
New discoveries and extensions.............................. 7,634,009 43,376
Revisions of previous estimates............................. 133,636 5,208
Purchase of reserves........................................ 3,554,975 26,284
----------- -------
Total proved reserves at December 31, 1995.................. 18,996,992 131,607
New discoveries and extensions.............................. 6,209,030 46,447
Revisions of previous estimates............................. (3,874,242) (33,056)
----------- -------
Total proved reserves at December 31, 1996.................. 21,331,780 144,998
New discoveries and extensions.............................. 4,665,021 42,404
Revisions of previous estimates............................. (1,119,811) (10,731)
Purchase of reserves........................................ 4,766,073 21,400
Production.................................................. (820,289) (12,764)
----------- -------
Total proved reserves at December 31, 1997.................. 28,822,774 185,307
=========== =======
Proved developed reserves:
December 31, 1995......................................... -- --
=========== =======
December 31, 1996......................................... 5,191,993 45,998
=========== =======
December 31, 1997......................................... 7,020,943 60,193
=========== =======

Proved reserves are estimated quantities of natural gas, crude oil, and
condensate which geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
existing economic and operating conditions. Proved developed reserves are proved
reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods.

38
42
RUTHERFORD-MORAN OIL CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Standardized Measure of Discounted Future Net Cash Flows

The following table reflects the Standardized Measure of Discounted Future
Net Cash Flows relating to the Company's interest in proved oil and gas reserves
as of December 31, 1997, 1996 and 1995 (amounts in thousands):

DECEMBER 31,
-----------------------------------
1997 1996 1995
--------- --------- ---------

Future cash inflows............................. $ 814,030 $ 811,239 $ 621,742
Future development costs........................ (246,791) (184,753) (127,198)
Future production costs......................... (335,160) (245,398) (207,352)
--------- --------- ---------
Future net cash inflows before income taxes..... 232,079 381,088 287,192
Future income taxes............................. (18,006) (134,276) (137,204)
--------- --------- ---------
Future net cash flows........................... 214,073 246,812 149,988
Discount at 10% per annum....................... (156,016) (103,446) (74,669)
--------- --------- ---------
Standardized measure of discounted future net
cash inflows.................................. $ 58,057 $ 143,366 $ 75,319
========= ========= =========

Principal changes in the Standardized Measure of Discounted Futures Net
Cash Flows attributable to the Company's proved oil and gas reserves for the
periods indicated are as follows (amounts in thousands):

YEAR ENDED DECEMBER 31,
---------------------------------
1997 1996 1995
--------- -------- --------

Sales, net........................................ $ (10,791) $ -- $ --
New discoveries and extensions.................... 23,106 101,776 52,372
Revisions of quantity estimates................... (11,381) (51,043) 6,027
Purchases of reserves in place.................... 19,189 -- 27,182
Net changes in sales and transfer prices, net of
production costs................................ (120,927) 5,647 (2,712)
Accretion of discount............................. 17,419 13,163 5,211
Net change in income taxes........................ 129,393 2,405 (38,163)
Changes in future development costs............... (5,059) -- --
Change in production rates (timing) and other..... (126,258) (3,901) (8,561)
--------- -------- --------
Net Change........................................ $ (85,309) $ 68,047 $ 41,356
========= ======== ========

NOTE 15 FINANCIAL INSTRUMENTS

Determination of Fair Values of Financial Instruments

Fair value for cash and cash equivalents, short-term investments,
receivables and payables at December 31, 1997, and December 31, 1996,
approximates carrying value.

The carrying amount of cash and cash equivalents approximates fair value
because of the short maturity of these instruments. The value added tax
receivable, which is denominated in Thai Baht, approximates fair value as it is
translated at the December 31, 1997 exchange rate and can be converted into cash
within a short period of time. The carrying amount of joint interest receivables
and payables and accounts payable and accrued expenses approximates fair value
because they are generally paid or earned within sixty days. The carrying amount
of the note payable to bank approximates fair value because the interest rate is
reset at periodic intervals based upon market rates. The carrying amount of the
Notes approximates fair value based upon current market prices. See Note 2 for
discussion of the fair value of hedging and swap options.

39
43

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

ITEM 11. EXECUTIVE COMPENSATION

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

For the information called for by Items 10, 11, 12 and 13, reference is
made to the Company's definitive proxy statement for its 1997 Annual Meeting of
Stockholders, which will be filed with the Securities and Exchange Commission
within 120 days after December 31, 1997, and portions of which are incorporated
herein by reference.

PART IV

ITEM 14. EXHIBITS, FINANCIAL SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. Financial Statements

The following financial statements and the Reports of Independent Public
Accountants are filed as a part of this report:

Independent Auditors' Report

Consolidated Statements of Operations, for the year ended December 31, 1997,
the periods June 18, 1996 through December 31, 1996 (Company), and January 1,
1996 through June 17, 1996 and for the year ended December 31, 1995
(Predecessors)

Consolidated Balance Sheets, December 31, 1997 and December 31, 1996 (Company)

Consolidated Statements of Changes in Stockholders' and Predecessors' Equity,
for the year ended December 31, 1997 and periods June 18, 1996 through December
31, 1996 (Company), and January 1, 1996 through June 17, 1996 and for the year
ended December 31, 1995 (Predecessors)

Consolidated Statements of Cash Flows, for the year ended December 31, 1997,
the periods June 18, 1996 through December 31, 1996 (Company), and January 1,
1996 through June 17, 1996 and for the year ended December 31, 1995
(Predecessors)

Notes to Consolidated Financial Statements

2. Financial Statements Schedules

Financial statement schedules have been omitted because they are not
applicable for the information required therein or are included elsewhere in the
financial statements or notes thereto.

3. Exhibits

EXHIBIT
NUMBER DESCRIPTION
------- -----------

40
44

EXHIBIT
NUMBER DESCRIPTION
------- -----------

***3.5 -- Certificate of Incorporation of Thai Romo Holdings, Inc.
***3.6 -- Bylaws of Thai Romo Holdings, Inc.
***3.7 -- Articles of Association of Thai Romo Limited
****4.1 -- Indenture between Rutherford-Moran Oil Corporation and
Bank of Montreal Trust Company, as trustee dated as of
September 29, 1997.
****4.2 -- Form of Note between Rutherford-Moran Oil Corporation and
Bank of Montreal Trust Company, as trustee relating to
10.75% Senior Subordinated Notes due 2004.
*10.1 -- Ministry of Industry Petroleum Concession dated August 1,
1991, awarded to Thai Romo, Thaipo and Maersk Oil.
*10.2 -- Ministry of Industry Supplementary Petroleum Concession
(No. 1) to Petroleum Concession No. 1/2534/36 dated March
6, 1992, awarded to Maersk Oil (Thailand) Ltd. and Thaipo
Limited and Thai Romo Limited.
*10.3 -- Ministry of Industry Supplementary Petroleum Concession
(No. 2) to Petroleum Concession No. 1/2535/36 dated
September 4, 1995, awarded to Thaipo Limited and Thai
Romo Limited.
*10.4 -- Joint Operating Agreement to be effective as of March 3,
1995 among Thai Romo, Thaipo and Sophonpanich.
*10.5 -- Joint Operating Agreement dated August 1, 1991 among Thai
Romo, Thaipo, Maersk Oil and Sophonpanich.
*10.6 -- Gas Sales Agreement dated November 7, 1995 between
Petroleum Authority of Thailand, Thai Romo, Thaipo, and
Sophonpanich.
****10.7 -- First Amendment to the Gas Sales Agreement dated November
12, 1997 between Petroleum Authority of Thailand and
B8/32 Partners Limited, Thaipo Limited, Thai Romo Limited
and Palang Sophon Limited
*10.8 -- Bareboat Charter Agreement dated February 9, 1996 between
Tantawan Production B.V. and Tantawan Services, L.L.C.
*10.9 -- Operating Agreement between SBM Marine Services Thailand
Ltd. and Tantawan Services, L.L.C. dated February 9,
1996.
*10.10 -- Guaranty and Indemnity Agreement dated February 9, 1996,
by Thai Romo to Tantawan Production B.V.
*10.11 -- Guaranty and Indemnity Agreement dated February 9, 1996,
by Thai Romo to SBM Marine Services Thailand Ltd.
*10.12 -- 1996 Key Employee Stock Plan (and form of option and
stock agreements).
*10.13 -- 1996 Non-Employee Director Stock Option Plan (and form of
option agreement).
*10.14 -- Letter Agreement dated March 28, 1996 with David
Chavenson.
***10.15 -- $150,000,000 Revolving Credit Facility dated as of
December 3, 1997 with The Chase Manhattan Bank as Lender
and Agent.
*10.16 -- Registration Rights Agreement.
**10.17 -- Share Sale Agreement between Maersk Olie Og and Thai Romo
Limited dated January 13, 1997
21.1 -- Subsidiaries of the Company.
27.1 -- Financial Data Schedule

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

* Incorporated by reference from the Company's Registration Statement on
Form S-1, as amended (File No. 333-4122).

** Incorporated by reference from the Company's Form 8-K dated March 3, 1997.

41
45

*** Incorporated by reference from the Company's Quarterly Report on Form 10-Q
for the period ended September 30, 1997.

**** Incorporated by reference from the Company's Registration Statement on
Form S-4, as amended (File No. 333-41015).

(b) Reports on Form 8-K

No reports on Form 8-K were filed by the Registrant during the fourth
quarter of the year ended December 31, 1997.

42
46

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

RUTHERFORD-MORAN OIL CORPORATION

By: /s/ PATRICK R. RUTHERFORD
-------------------------------------
Patrick R. Rutherford
Chief Executive Officer
(Principal Executive Officer)

Date:

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.

SIGNATURE TITLE DATE
--------- ----- ----

/s/ PATRICK R. RUTHERFORD President and Chief Executive March 31, 1998
- ----------------------------------------------------- Officer (Principal Executive
Patrick R. Rutherford Officer and Director)

/s/ JOHN A. MORAN Director and Chairman of the March 31, 1998
- ----------------------------------------------------- Board
John A. Moran

/s/ DAVID F. CHAVENSON Vice President and Chief March 31, 1998
- ----------------------------------------------------- Financial Officer (Chief
David F. Chavenson Financial and Accounting
Officer)

Director March 31, 1998
- -----------------------------------------------------
Howard Gittis

/s/ HARRY C. LEE Director March 31, 1998
- -----------------------------------------------------
Harry C. Lee

/s/ JERE MCKENNY Director March 31, 1998
- -----------------------------------------------------
Jere McKenny

Director March 31, 1998
- -----------------------------------------------------
Chote Sophonpanich

43
47

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Act
of 1934, the Registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.

RUTHERFORD-MORAN EXPLORATION
COMPANY

By: /s/ PATRICK R. RUTHERFORD

------------------------------------
Patrick R. Rutherford
President

SIGNATURE TITLE DATE
--------- ----- ----

/s/ JOHN A. MORAN Chairman of the Board
- -----------------------------------------------------
John A. Moran

/s/ PATRICK R. RUTHERFORD President and Director (principal
- ----------------------------------------------------- executive officer)
Patrick R. Rutherford

Vice President and Secretary and
- ----------------------------------------------------- Director
Michael D. McCoy

/s/ DAVID F. CHAVENSON Treasurer and Director (principal
- ----------------------------------------------------- financial officer and principal
David F. Chavenson accounting officer)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Act
of 1934, the Registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.

THAI ROMO HOLDINGS, INC.

By: /s/ PATRICK R. RUTHERFORD

------------------------------------
Patrick R. Rutherford
President

SIGNATURE TITLE DATE
--------- ----- ----

/s/ JOHN A. MORAN Chairman of the Board
- -----------------------------------------------------
John A. Moran

/s/ PATRICK R. RUTHERFORD President and Director (principal
- ----------------------------------------------------- executive officer)
Patrick R. Rutherford

Vice President and Secretary and
- ----------------------------------------------------- Director
Michael D. McCoy

/s/ DAVID F. CHAVENSON Treasurer and Director (principal
- ----------------------------------------------------- financial officer and principal
David F. Chavenson accounting officer)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Act
of 1934, the Registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.

THAI ROMO LIMITED

By: /s/ PATRICK R. RUTHERFORD

------------------------------------
Patrick R. Rutherford
Director and Principal Executive
Officer

SIGNATURE TITLE DATE
--------- ----- ----

/s/ PATRICK R. RUTHERFORD Director (principal executive
- ----------------------------------------------------- officer)
Patrick R. Rutherford

/s/ JOHN A. MORAN Director
- -----------------------------------------------------
John A. Moran

/s/ DAVID F. CHAVENSON Director (principal financial
- ----------------------------------------------------- officer and principal accounting
David F. Chavenson officer)

Director
- -----------------------------------------------------
Michael D. McCoy

INDEX TO EXHIBITS

EXHIBIT
NUMBER DESCRIPTION
------- -----------

*3.1 -- Restated Certificate of Incorporation of the Company.
*3.2 -- Bylaws of the Company dated April 1, 1996.
***3.3 -- Certificate of Incorporation of Rutherford-Moran
Exploration Company
***3.4 -- Bylaws of Rutherford-Moran Exploration Company
***3.5 -- Certificate of Incorporation of Thai Romo Holdings, Inc.
***3.6 -- Bylaws of Thai Romo Holdings, Inc.
***3.7 -- Articles of Association of Thai Romo Limited
****4.1 -- Indenture between Rutherford-Moran Oil Corporation and
Bank of Montreal Trust Company, as trustee dated as of
September 29, 1997.
****4.2 -- Form of Note between Rutherford-Moran Oil Corporation and
Bank of Montreal Trust Company, as trustee relating to
10.75% Senior Subordinated Notes due 2004.
*10.1 -- Ministry of Industry Petroleum Concession dated August 1,
1991, awarded to Thai Romo, Thiapo and Maersk Oil.
*10.2 -- Ministry of Industry Supplementary Petroleum Concession
(No. 1) to Petroleum Concession No. 1/2534/36 dated March
6, 1992, awarded to Maersk Oil (Thailand) Ltd. and Thaipo
Limited and Thai Romo Limited.
*10.3 -- Ministry of Industry Supplementary Petroleum Concession
(No. 2) to Petroleum Concession No. 1/2535/36 dated
September 4, 1995, awarded to Thaipo Limited and Thai
Romo Limited.
*10.4 -- Joint Operating Agreement to be effective as of March 3,
1995 among Thai Romo, Thaipo and Sophonpanich.
*10.5 -- Joint Operating Agreement dated August 1, 1991 among Thai
Romo, Thaipo, Maersk Oil and Sophonpanich.
*10.6 -- Gas Sales Agreement dated November 7, 1995 between
Petroleum Authority of Thailand, Thai Romo, Thaipo, and
Sophonpanich.
****10.7 -- First Amendment to the Gas Sales Agreement dated November
12, 1997 between Petroleum Authority of Thailand and
B8/32 Partners Limited, Thaipo Limited, Thai Romo Limited
and Palang Sophon Limited
*10.8 -- Bareboat Charter Agreement dated February 9, 1996 between
Tantawan Production B.V. and Tantawan Services, L.L.C.
*10.9 -- Operating Agreement between SBM Marine Services Thailand
Ltd. and Tantawan Services, L.L.C. dated February 9,
1996.
*10.10 -- Guaranty and Indemnity Agreement dated February 9, 1996,
by Thai Romo to Tantawan Production B.V.
*10.11 -- Guaranty and Indemnity Agreement dated February 9, 1996,
by Thai Romo to SBM Marine Services Thailand Ltd.
*10.12 -- 1996 Key Employee Stock Plan (and form of option and
stock agreements).
*10.13 -- 1996 Non-Employee Director Stock Option Plan (and form of
option agreement).
*10.14 -- Letter Agreement dated March 28, 1996 with David
Chavenson.
***10.15 -- $150,000,000 Revolving Credit Facility dated as of
December 3, 1997 with The Chase Manhattan Bank as Lender
and Agent.

EXHIBIT
NUMBER DESCRIPTION
------- -----------

*10.16 -- Registration Rights Agreement.
**10.17 -- Share Sale Agreement between Maersk Olie Og and Thai Romo
Limited dated January 13, 1997
21.1 -- Subsidiaries of the Company.
27.1 -- Financial Data Schedule

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

* Incorporated by reference from the Company's Registration Statement on
Form S-1, as amended (File No. 333-4122).

** Incorporated by reference from the Company's Form 8-K dated March 3, 1997.

*** Incorporated by reference from the Company's Quarterly Report on Form 10-Q
for the period ended September 30, 1997.

**** Incorporated by reference from the Company's Registration Statement on
Form S-4, as amended (File No. 333-41015).