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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: 1-12088

UNITED MERIDIAN CORPORATION
(Exact name of registrant as specified in its charter)

DELAWARE 75-2160316
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

1201 LOUISIANA
SUITE 1400 77002
HOUSTON, TEXAS (Zip Code)
(Address of principal executive offices)

Registrant's telephone number, including area code: (713) 654-9110

Securities registered pursuant to Section 12(b) of the Act:

NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ----------------------
Common Stock, $0.01 par value New York Stock Exchange
10-3/8% Senior Subordinated Notes due 2005 New York Stock Exchange
Rights to Purchase Series A Junior Preferred Stock New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

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. [X]

THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF
THE REGISTRANT AS OF FEBRUARY 13, 1998 WAS $979,638,275 BASED UPON A CLOSING
PRICE OF $27 5/8 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 FEBRUARY 13, 1998
------------------- ----------------------------
Common Stock, $0.01 par value 35,792,891

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 CONTENTS

Page
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Part I. Items 1. and 2. Business and Properties
(a) General..............................................................................1
(b) Business Strategy....................................................................1
(c) Oil and Gas Properties...............................................................3
(d) Reserves.............................................................................7
(e) Acreage and Productive Wells.........................................................8
(f) Production, Unit Prices and Costs....................................................9
(g) Drilling Activity...................................................................10
(h) Marketing and Contracts.............................................................10
(i) Customers...........................................................................11
(j) Competition.........................................................................11
(k) Environmental Matters...............................................................11
(l) Employees...........................................................................12
(m) Offices.............................................................................12
Item 3. Legal Proceedings..........................................................................13
Item 4. Submission of Matters to a Vote of Security Holders........................................13
Part II. Item 5. Market for Registrant's Common Equity and Related Stockholder Matters......................14
Item 6. Selected Financial Data....................................................................15
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
(a) Introduction........................................................................16
(b) Overview............................................................................16
(c) Results of Operations...............................................................17
(d) Capital Resources and Liquidity.....................................................19
(e) Net Operating Loss Carryforwards and Canadian Tax Pools.............................20
(f) Foreign Currency Transactions.......................................................21
(g) Changes in Prices and Inflation.....................................................21
(h) Forward-Looking Statements..........................................................21
(i) Impact of Recently Issued Accounting Standards......................................22
Item 8. Financial Statements and Supplementary Data................................................23
Item 9. Changes In and Disagreements with Accountants on Accounting and
Financial Disclosure......................................................................53
Part III. Item 10. Directors and Executive Officers of the Registrant.........................................53
Item 11. Executive Compensation.....................................................................53
Item 12. Security Ownership of Certain Beneficial Owners and Management.............................53
Item 13. Certain Relationships and Related Transactions.............................................53
Part IV. Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................53

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

(a) GENERAL

United Meridian Corporation (UMC or the Company) is a leading independent
energy company engaged in the exploration for and development, production and
acquisition of oil and natural gas in North America and certain international
regions. In North America, the Company's production is concentrated in the Gulf
Coast, Permian Basin, Midcontinent and Rocky Mountain regions and in Western
Canada. Internationally, the Company currently operates in the West African oil
and natural gas producing regions of Cote d'Ivoire and Equatorial Guinea and
also has production sharing contracts (PSCs) on five blocks in Pakistan and on
one block in Bangladesh. On February 6, 1998, the Company announced that it was
awarded a participation in Block 19 offshore Angola. The Company has two
applications pending for additional PSCs in West Africa.

The Company was organized under the laws of Delaware in 1987. Between 1987
and 1989, the Company acquired three publicly held companies (Ensource Inc., MCO
Resources, Inc. and General Energy Development, Ltd.) and one privately held
company (General Drilling and Producing Company). During 1993, UMC made three
additional corporate acquisitions, Norfolk Holdings Inc., KPX, Inc., and
Sterling Energy Limited, all of which were privately held oil and gas production
companies. In 1994, UMC acquired General Atlantic Resources, Inc., a publicly
traded company. All of the aforementioned transactions were accounted for under
the purchase method.

On December 22, 1997, UMC and Ocean Energy, Inc. (OEI) entered into a
merger agreement that provides for a stock-for-stock merger (Merger) of the
companies pursuant to which UMC stockholders will receive 1.30 shares of the
combined company for each existing outstanding share of UMC and OEI shareholders
will receive 2.34 shares of the combined company for each existing outstanding
share of OEI. UMC stockholders will own approximately 46% of the equity of the
combined company. The Merger is expected to qualify as a tax-free transaction
and is subject to each Company's stockholders' approval and certain other
conditions. The transaction is expected to be treated as a pooling of interests
for accounting purposes and is anticipated to close by the end of the first
quarter of 1998.

At December 31, 1997, the Company's proved reserves were estimated to be
162.2 MMBOE, 42% oil and 58% gas.

The Company's principal executive offices are located at 1201 Louisiana,
Suite 1400, Houston, TX 77002 and the Company's telephone number is (713)
654-9110. Unless the context otherwise requires, the term "Company" or "UMC" as
used in this Form 10-K shall mean United Meridian Corporation and its
subsidiaries. The offices of UMC Petroleum Corporation (Petroleum), the primary
operating subsidiary of the Company, are also located at the above address. All
operations are conducted by Petroleum and its subsidiaries.

(b) BUSINESS STRATEGY

UMC's business strategy is to increase reserves and production in a
cost-effective manner through a drilling program that balances primarily lower
risk development drilling on UMC's North American acreage with high potential
exploratory drilling on international prospects, supplemented by opportunistic
property and corporate acquisitions. Supporting this strategy are the Company's
substantial portfolio of high return exploration opportunities, a large
exploitation inventory and a successful history of acquisitions.

North America. The Company is aggressively exploiting its North American
properties through the integration of advanced 3-D seismic technology,
horizontal drilling and geoscience studies. UMC conducts a North American
exploration program focused on internally-generated prospects, primarily in the
Gulf Coast region, including East Texas, and in the Permian and Williston
Basins, where the Company believes high success rates and excellent reserve
potential exist. The Company manages its domestic exploration risk by applying
state-of-the-art technology to identify prospects, emphasizing prospects over
which it will have operational control. The risks of these prospects are shared
primarily with industry partners and a group of institutional investors on terms
considered favorable to the Company. The Company has generated a significant
number of development drilling opportunities as a result of its exploration
efforts and through producing property acquisitions. UMC has in its current
portfolio a large North American exploitation inventory

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including 137 proved undeveloped drilling sites and 327 probable and possible
drilling sites. During 1997, the Company's North American drilling comprised 262
development wells, 240 of which were successfully completed, and 48 exploratory
wells, 25 of which were successfully completed. Total capital expenditures for
North American activities in 1997 were $182.0 million, including $62.6 million
for acquisitions and $7.1 million for corporate assets.

International. The Company's business strategy in the international arena
is to pursue selected opportunities generally characterized by low initial
costs, high reserve potential and the availability of existing technical data
that may be further developed using current technology. The Company believes
that it has unique management and technical expertise in identifying
international opportunities and establishing favorable operating relationships
with host governments. The Company generally attempts to manage major
exploration commitments by negotiating directly with host governments for terms
which minimize bonuses and initial work commitments. Additionally, the Company
forms joint ventures under which partners provide a significant amount of the
initial exploration costs. This strategy permits the Company to limit its
capital exposure until commercial development is assured. The Company has
identified a large number of exploration prospects on its international acreage
and has two development programs in progress. International drilling in 1997
comprised 14 development wells, 13 of which were successfully completed, and 13
exploratory wells, 5 of which were successfully completed. Total capital
expenditures for international activities in 1997 were $188.1 million, including
$17.2 million for a Liquid Propane Gas (LPG) plant in Cote d'Ivoire.

Acquisitions and asset management. The Company is continually evaluating
opportunities to acquire oil and natural gas properties, primarily focusing on
properties that complement its existing reserve base. This focus allows the
Company to apply its engineering knowledge and expertise to maximize future
development potential and minimize reserve risk. The acquisitions must meet
well-defined return, payout and cash flow criteria. During 1997, the Company
completed several such acquisitions of both additional interests in various
properties from several of its institutional partners and interests in other
North American properties. Total consideration paid for these acquisitions was
$62.6 million. In addition, as part of its business strategy, the Company
periodically evaluates and, from time to time, sells certain of its producing
properties. Such sales enable the Company to maintain financial flexibility,
reduce overhead and operating expenses and redeploy capital to activities which
are expected to have higher financial returns. Consistent with this strategy,
the Company realized $19.4 million in proceeds from sales of various non-
strategic North American properties in 1997.

Technology. Utilization of state-of-the-art technology is an important
element in the Company's strategy to reduce normal exploration and development
risk. Two of the most relevant tools used are 3-D and 2-D seismic technologies.
Depending upon the hydrocarbon basin, one technology may provide better results
than another. Where appropriate, 3-D seismic allows a better multi-dimensional
geological picture to be developed than could be obtained from 2-D seismic,
enhancing the Company's ability to obtain favorable drilling results.

Low cost operating structure. Management strives to maintain a low cost
operating structure through the implementation of the aforementioned strategies
and by employing an experienced and stable workforce. Controllable cash costs,
which are continuously monitored by management, include production costs and
general and administrative expenses. During 1997, UMC's lifting costs, before ad
valorem and production taxes, and general and administrative costs averaged
$2.65 and $0.79 per BOE of production, respectively, down from $3.12 and $0.93
per BOE of production, respectively, for 1996.

Sound financial structure. As part of its business strategy, the Company
maintains a sound financial structure which allows it to effectively implement
its operating strategy. The Company funded its 1997 capital expenditures program
of $370.1 million through a combination of cash flows from operations, asset
sales, residual cash proceeds from the Company's 1996 equity offering and draws
under the Global Credit Facility. The Company maintained a favorable debt to
total book capitalization ratio of 38% with unused capacity under bank lines
exceeding $170 million at December 31, 1997.

The Merger. UMC and OEI have entered into a merger agreement that will
combine UMC's extensive North American onshore and international operations
with OEI's rapidly growing Gulf of Mexico property base. As a result of the
Merger, the combined company will become one of the top ten largest independent
oil and natural gas companies in the country, based upon total market
capitalization, with total proved reserves of approximately 271 MMBOE as of
December 31, 1997, and combined average production of approximately 117,000
BOEPD in December of 1997. The larger scale provided by the combination will
allow the combined company the financial flexibility necessary to retain a
larger

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share of the existing high impact exploration prospects contained in each
company's portfolio, and therefore a larger proportion of the related upside
potential. Acceleration of several of these projects is expected given the
financial strength provided by the increased size and diversification of a
larger entity. OEI and UMC believe that the larger scale will facilitate the
securing of scarce drilling rigs and other oilfield services critical to
exploration and exploitation activities, especially in respect of the combined
deepwater operations.

The table below summarizes the Company's proved reserves and discounted
present value by geographic region as of December 31, 1997.

PROVED RESERVES
--------------------------------------------------------
DPV(1)
Natural Before % of
Oil Gas Total Income Tax Total
REGION (MBO) (MMCP) (MMBOE) ($ in 000s) DPV
------ ------ ------ ------- ----------- ------

Gulf of Mexico/Gulf Coast Onshore .... 2,008 68,091 13.4 $ 98,507 14%
Permian Basin ........................ 7,341 31,516 12.6 63,201 9%
Midcontinent ......................... 2,370 68,765 13.8 82,599 11%
Rocky Mountains ...................... 8,447 157,727 34.7 171,947 24%
------ ------- ----- -------- ---
Total U.S ........................ 20,166 326,099 74.5 416,254 58%

Equatorial Guinea .................... 40,014 -- 40.0 145,216 20%

Cote d'Ivoire ........................ 5,257 136,290 28.0 97,739 13%

Canada ............................... 3,383 97,862 19.7 64,624 9%
------ ------- ----- -------- ---

Total .......................... 68,820 560,251 162.2 $723,833 100%
====== ======= ===== ======== ===

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(1) Discounted (at 10%) present value as of December 31, 1997 (year-end prices
held constant). The amounts are before income taxes and therefore are not the
same as the "Standardized Measure" disclosed in Note 18 of the Notes to
Consolidated Financial Statements.

NORTH AMERICA

The Company conducts a focused exploration program designed to find
significant reserves at low costs. The Company's North American exploration
efforts are predominantly in the Gulf of Mexico, East Texas and the Permian and
Williston Basins. Typically, the Company seeks to operate these projects and to
retain a 25-60% working interest. In 1997, the Company committed 14% of its
capital expenditures to North American exploration and drilled a total of 48
exploratory wells, of which 25 were completed as productive.

UMC focuses its development activities in those areas which offer the most
attractive potential returns to the Company, including development opportunities
resulting from exploration activities. During 1997, UMC committed 34% of its
capital expenditures to North American development and participated in the
drilling of 262 development wells, 240 of which were completed as productive
wells. The Company has identified approximately 137 proved undeveloped and 327
probable and possible drilling opportunities within its existing North American
inventory. UMC has prioritized development projects which will maximize the
production potential per dollar of investment in view of the large number of
North American opportunities available to the Company.

- 3 -

The following paragraphs highlight certain of the Company's more significant
North American producing oil and gas properties and exploration opportunities:

Bear Paw Area, Montana. The Bear Paw area, located in Blaine, Hill and
Chouteau Counties, comprises most of the Company's reserves in Montana and is
the Company's largest North American field. Natural gas is produced from the
Eagle Sandstone at depths of less than 2,000 feet. The Company has an average
77% working interest in the area. The Company's net production averaged
approximately 38.1 MMCFD of natural gas for December 1997. The Company drilled
48 wells (65% success rate) in the Bear Paw area resulting in 12.9 BCF of new
reserves for the $2.5 million investment. In August 1997, the Company acquired
additional interests in the Bear Paw area for $5.8 million, with estimated
proved reserves of 13.2 BCF and an initial production rate of 4.2 MMCFD.

Longhorn Area, Texas. The Longhorn project area, in which the Company owns
a 50% working interest in 5,125 gross (2,562 net to UMC) acres, was purchased in
1996 at the Texas university lease sale. A 37-square mile 3-D seismic survey was
shot over this area in 1996 to define deep Ellenberger and Fusselman structures
within the Deep Delaware Basin. The initial discovery well was drilled in 1997
and is currently being completed in the Ellenberger formation. An additional
deep prospect remains to be drilled in 1998.

Buffalo Area, Texas. In the Buffalo project area, the Company owns and
operates a 37.5% working interest in 18,660 gross (6,997 net to UMC) acres that
are controlled by seismic options. The Company recently completed a 97-square
mile 3-D seismic survey to define several deep structural features in the
Ellenberger and Fusselman formations. Additional acreage acquisitions and
drilling will occur in 1998.

East Triangle Field, Wyoming. UMC discovered the East Triangle Field in
June 1997. Oil is produced from the Sussex "B" Sand at a depth of 8,300 feet.
The Company drilled eight (100% success rate) wells in the field in 1997 and
plans to drill 14 additional wells in 1998. UMC holds a major position in this
new field, controlling 19,967 gross (18,229 net to UMC) acres.

High Island A-560, Gulf of Mexico. The High Island A-560 lease, in which
the Company owns a 55% working interest, was purchased in the August 1993 Outer
Continental Shelf (OCS) lease sale. The discovery well was drilled in early 1994
followed by a confirmation development well. The platform was installed in
mid-1995 and the first two wells were completed as dual and single gas wells.
First production was in July 1995. One additional producing well was drilled and
completed during December 1995. The platform is currently producing at a rate of
1.2 MBOD (0.7 MBOD net to UMC) and 5.4 MMCFD (3.0 MMCFD net to UMC).

West Cameron 541, Gulf of Mexico. The West Cameron 541 lease, in which the
Company owns a 55% working interest, was purchased in the March 1994 OCS lease
sale. The discovery well was drilled in July 1995 followed by a confirmation
development well. The platform was installed in June 1996 and two additional
wells were drilled and completed off of this structure. First production was in
September 1996 with a current production rate of 5.7 MMCFD (3.1 MMCFD net to
UMC).

High Island 98-L, Gulf of Mexico. The High Island 98-L Texas state lease,
in which the Company owns a 55% working interest, was purchased in October 1995
at the Texas state lease sale. The discovery well was drilled and completed in
July 1996. The production platform was installed in November 1996 and first
production was in December 1996 with a current production rate of 7.8 MMCFD (4.3
MMCFD net to UMC) and 157 BOD (86.4 BOD net to UMC).

Young Mendota Field, Texas. The Young Mendota field is the Company's
largest field in the Midcontinent region and is located in Hemphill County.
Natural gas is produced from several formations including the Granite Wash,
Morrow and Douglas formations at depths ranging from 7,000 to 11,500 feet. The
Company operates 45 of the 90 wells in which it has interests in this field with
a current production rate of 10.9 MMCFD (4.3 MMCFD net to UMC) of natural gas
for 1997. A 34-square mile 3-D seismic survey will be acquired in 1998 to define
exploratory objectives in the Morrow formation.

Bindloss, Alberta. The Bindloss area comprises 34% of the Company's
Canadian natural gas reserves. Natural gas is produced primarily from the Viking
sands at depths of less than 2,000 feet. Production averaged approximately 10.2
MMCFD (5.6 MMCFD net UMC) of natural gas for December 1997. In May 1997, the
Company acquired an additional 50% working interest for $9.1 million and assumed
operatorship of the area.

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INTERNATIONAL

The Company's business strategy in the international arena is to pursue
selected international opportunities generally characterized by low initial
costs, high reserve potential and the availability of technical data that may be
further developed by the Company. The Company attempts to manage major
exploration commitments by negotiating directly with host governments for terms
which minimize bonuses and initial work commitments. Additionally, the Company
forms joint ventures where industry partners pay a disproportionate share of the
initial exploration costs. This strategy permits the Company to limit its
capital exposure until commercial development is assured.

Cote d'Ivoire. During 1991, UMC initiated negotiations with the Republic
of Cote d'Ivoire for a PSC covering Block CI-11, most of which is located
offshore in the Atlantic Ocean. Since acquiring the initial PSC in 1992, the
Company has negotiated four additional PSCs. Under the five PSCs, UMC holds
contract interests ranging from 25% to 80% in five blocks totaling approximately
2.1 million gross (0.9 million net to UMC) acres.

On Block CI-11, the Company, as operator and holder of a 25% contract
interest, has drilled 15 oil and natural gas wells in the Lion oil and Panthere
natural gas fields since late 1993. As a result of the successful discoveries
and subsequent production history, UMC has proved reserves of 2.6 MMBO of oil
and 52.7 BCF of natural gas on Block CI-11 at December 31, 1997. The Company's
net production from the Block totaled 66.7 MBO and 472 MMCF in December 1997. In
addition to its continuing development activities on Block CI-11, UMC has
identified several exploration opportunities on the Block. A 3-D seismic survey
is currently being evaluated which will further delineate the Company's
opportunities in that area. In 1997, the Company drilled one exploratory well
and three development wells on CI-11, all of which were successful.

On Block CI-12, which is immediately west of Block CI-11, UMC has
identified several seismic anomalies which it believes are on trend with the
Lion oil sands. In late 1996, the Company spud the initial exploratory well on
the Block (Leopard #1). In February 1997, this well was plugged and abandoned.
The Company drilled two additional exploratory dry holes in 1997, and is
reevaluating seismic before drilling any additional wells. UMC currently owns a
37.5% contract interest in Block CI-12. The Company's ultimate contract
percentage interest in Block CI-12 is subject to final election by Petroci, the
national petroleum company of Cote d'Ivoire.

Block CI-105 is located due south of Block CI-12 with water depths ranging
from 1,500 feet to 6,000 feet. In 1996, the Company executed an agreement with
Shell Exploration B.V. (Shell), a unit of Royal Dutch/Shell, to sell a 55%
contract interest in Block CI-105. Under the terms of the agreement, Shell paid
100% of the first $3.0 million incurred for a 1996 3-D seismic survey covering
1,100 square kilometers. In 1997, the survey was processed and is currently
being evaluated and interpreted. UMC and its partner recently committed to
purchase additional seismic lines covering the balance of the Block for $7.0
million ($2.7 million net to UMC). The contract participants have until July
1998 to make an election to drill on the Block. Total costs incurred to date on
the Block approximate $5.9 million ($0.8 million net to UMC). UMC will be
carried for up to $3.5 million (net) of any initial drilling commitment.

Blocks CI-01 and CI-02, located approximately 80 miles east of Block CI-11,
possess proven accumulations of oil and natural gas in reservoirs drilled by
major oil companies in the 1980s. The Company recognized net proved reserves of
2.7 MMBO of oil and 83.6 BCF of natural gas at December 31, 1997 based on an 80%
contract interest. Mapping of existing 3-D seismic on Block CI-01 and a new 3-D
seismic survey on Block CI-02 will permit further evaluation of the reserve
potential of these Blocks. In 1997, the Company drilled a discovery at Kudu on
Block CI-01 that encountered 75 feet of net pay and flowed 27.7 MMCF of natural
gas and 740 barrels of condensate per day in a test restricted by mechanical
facilities. The Company drilled the Gazelle #2, an exploratory well on Block
CI-02, that tested 32 MMCF of natural gas and 858 barrels of condensate per day.
In addition, the Company drilled one exploratory and one development dry hole.
Effective December 31, 1997, the Company executed agreements with Petroci and
Yukong, partners in Block CI-01, whereby Yukong assigned their interest and
Petroci assigned a portion of its interest in the Block to the Company. In
exchange, the Company agreed to carry future exploration and appraisal
expenditures until payout. As a result of these agreements, UMC owns an 80%
contract interest in Block CI-01 and currently holds a 75% contract interest in
Block CI-02. However, the Company's ultimate contract interest in Block CI-02 is
subject to final election by Petroci.

UMC has been in discussions with the governments of Ghana and Cote
d'Ivoire for the export and sale of natural gas production from Block CI-01.
Ghana is currently buying electricity from Cote d'Ivoire. The governments of
Ghana and Cote d'Ivoire have tentatively approved the sale of natural gas from
Block CI-01 to Ghana for power generation.

- 5 -

The plan, if concluded, would call for UMC to develop Block CI-01 and export a
portion of the natural gas to a power plant that has been built on the coast of
Ghana. Development alternatives for export and local sales are currently being
evaluated by the Company.

In 1997, UMC constructed a LPG plant to extract liquids (propane, butane
and natural gasoline) from the current natural gas production in the country.
The first phase of this project includes a plant using the turbo-expander
technology. The plant is capable of handling 75 to 95 MMCFD of natural gas flow
producing up to 45,000 metric tons of LPG per year and is expected to come on
stream in the first quarter of 1998. Total costs incurred through December 31,
1997 were approximately $17.2 million.

A new wholly-owned subsidiary, Lion G.P.L., S.A., was incorporated in Cote
d'Ivoire to own and operate the plant. During 1998, it is anticipated that 65%
of the outstanding shares of this subsidiary will be sold to others. Gas
processing agreements have been executed with Block CI-11 partners, currently
the only natural gas producers in the country. The extracted LPG will be sold
into the local market.

Equatorial Guinea. UMC has negotiated four PSCs with the Republic of
Equatorial Guinea for Blocks located offshore in the Atlantic Ocean. Under the
PSCs, UMC holds approximately 1.8 million gross (1.2 million net to UMC) acres.

Block A was evaluated during 1993 and 1994 with a 2-D seismic program and
a test well, the Dorado #1, a dry hole in which UMC had a carried interest. UMC
is evaluating further exploration opportunities on the Block based on new 2-D
seismic. The Company currently owns a 100% contract interest in Block A.

Block B was also evaluated by a 1993 seismic program, in which UMC had a
carried interest. Mobil Equatorial Guinea Corporation (Mobil) carried UMC in the
drilling of a test well on the Delta prospect, which was a dry hole in late
1994. Mobil, as operator, and UMC then drilled three successful oil wells on the
Zafiro prospect and one successful oil well on the Opalo prospect in 1995. The
Jade, Serpentina and Opalo East fields were discovered on the Block during 1997
and will be developed over the next 18 to 24 months. A total of fourteen wells
were drilled in 1997, nine development and five exploratory wells. All nine of
the development wells and two of the exploratory wells were successful and were
tested at rates ranging from 4,000 to 10,500 BOD (gross). At December 31, 1997,
six of the development wells and two of the exploratory wells were producing and
the other three development wells were being completed. Total expenditures to
date have been $833.0 million ($208.3 million net to UMC). The Company
recognized proved reserves of 40.0 MMBO (177.8 MMBO gross) on Block B at
December 31, 1997. However, the Company's current and future investment is based
upon a significantly higher anticipated level of reserve recovery. The Company
owns a 25% contract interest in Block B. Negotiations with the government of
Equatorial Guinea are currently underway to modify certain terms of the Block B
PSC. Management does not anticipate any material adverse economic impact on the
Company as a result of any such modifications to the PSC.

Initial oil production from Block B commenced in late August 1996 at a
rate of 10,000 BOD (2,300 BOD net to UMC) and was producing at levels
approaching 77,500 BOD (17,400 BOD net to UMC) at December 31, 1997. Work on the
Phase III development project is expected to begin in 1998 to provide additional
production capacity to develop the existing Block B field discoveries.

Block C is adjacent to Block B and potentially holds extensions of the
prospects developed on Block B. The discovery of high quality reservoirs and
high oil flow rates on Block B increases the likelihood of successful
exploration on this Block. The Company currently owns a 75% contract interest. A
second seismic acquisition is currently underway. A well is expected to be
drilled on the Block within the upcoming 18 months.

Block D, in which the Company owns a 75% contract interest, is adjacent to
Block B, which increases the prospectiveness of the Block. During 1997, the
Company drilled two exploratory wells on Block D. The Tsavorita #1/1A, has been
temporarily abandoned pending further evaluation. An extensive 3-D seismic shoot
is currently underway to further evaluate opportunities on Block D. Additional
drilling is anticipated late in 1998.

Pakistan. During 1996 and 1997, UMC signed five PSCs with the government
of Pakistan, covering 7.7 million gross (5.8 million net to UMC) acres.
Geological and geophysical studies have begun and will be conducted during the
next two years of the exploration license on the five Blocks, with possible
drilling within the upcoming 18 months.

Bangladesh. In February 1997, UMC signed a PSC covering Block 22,
Chittagong Hills Tracts. UMC has geological

- 6 -

and geophysical work currently underway toward possible drilling in 1998. The
Block covers 3.3 million gross (1.3 million net to UMC) acres. UMC currently
holds a 40% contract interest.

Angola. In February 1998, the government of the Republic of Angola awarded
UMC a participation in the Block 19 concession group with a 20% interest. The
Block covers 1.2 million gross (0.2 million net to UMC) acres and is located in
the high potential deepwater basins offshore Angola, where several major
discoveries were announced in 1996 and 1997.

(d) RESERVES

The Company holds interests in producing properties in 15 states, Canada,
Equatorial Guinea and Cote d'Ivoire, with most of its proved reserves located in
five major natural gas producing areas of the United States (Gulf of Mexico/Gulf
Coast Onshore, Permian Basin, Midcontinent, Rocky Mountains and Montana), in the
Alberta and Saskatchewan provinces of Canada and in West Africa. At December 31,
1997, the Company had estimated proved reserves of 68.8 MMBO of oil and 560.3
BCF of natural gas, or 162.2 MMBOE, an increase of 36% from 1996 year end
reserves of 119.7 MMBOE.

The following table sets forth estimates of the proved oil and natural gas
reserves of the Company at December 31, 1997, as evaluated by Ryder Scott
Company, Netherland, Sewell & Associates, Inc. and McDaniel & Associates
Consultants Ltd., the Company's independent petroleum reserve engineers:

Barrels of Oil Equivalents
Oil (MBO) Natural Gas (MMCF) (MBOE)
---------------------------------- -------------------------------- --------------------------------
Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total
---------- ----------- ------- --------- ----------- ------- ---------- ----------- -----

Gulf Coast ........... 1,912 96 2,008 53,168 14,923 68,091 10,774 2,583 13,357
Permian Basin ........ 6,796 545 7,341 27,450 4,066 31,516 11,371 1,223 12,594
Midcontinent ......... 1,966 404 2,370 60,667 8,098 68,765 12,077 1,754 13,831
Rocky Mountains ...... 6,669 1,778 8,447 130,954 26,773 157,727 28,495 6,240 34,735
------ ------ ------ ------- ------- ------- ------- ------ -------
Sub-Total U.S. ..... 17,343 2,823 20,166 272,239 53,860 326,099 62,717 11,800 74,517
Canada ............... 3,383 -- 3,383 97,862 -- 97,862 19,693 -- 19,693
Cote d'Ivoire ........ 1,861 3,396 5,257 40,313 95,977 136,290 8,580 19,393 27,973
Equatorial Guinea .... 11,482 28,532 40,014 -- -- -- 11,482 28,532 40,014
------ ------ ------ ------- ------- ------- ------- ------ -------
Total Company ..... 34,069 34,751 68,820 410,414 149,837 560,251 102,472 59,725 162,197
====== ====== ====== ======= ======= ======= ======= ====== =======

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 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 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.

- 7 -

The following table sets forth, at December 31, 1997, the discounted
present value attributable to the Company's estimated proved reserves at that
date as estimated primarily by Ryder Scott Company, Netherland, Sewell &
Associates, Inc. and McDaniel & Associates Consultants Ltd., the Company's
independent petroleum reserve engineers:

IN THOUSANDS OF U.S. DOLLARS
-----------------------------------------------------------------------------------
COTE EQUATORIAL
UNITED STATES CANADA D'IVOIRE GUINEA TOTAL
------------- ----------- ----------- ----------- --------------

Future cash inflows ............... $ 1,034,813 $ 178,899 $ 384,217 $ 573,360 $ 2,171,289
----------- ----------- ----------- ----------- -----------
Future production costs ........... 319,171 58,588 85,717 111,822 575,298
Future development costs .......... 61,524 2,024 110,047 239,750 413,345
Future income taxes ............... 102,748 26,464 41,001 37,417 207,630
----------- ----------- ----------- ----------- -----------
Total future costs ................ 483,443 87,076 236,765 388,989 1,196,273
----------- ----------- ----------- ----------- -----------
Future net cash inflows ........... 551,370 91,823 147,452 184,371 975,016
Discount at 10% per annum ......... (159,055) (35,489) (58,883) (49,719) (303,146)
----------- ----------- ----------- ----------- -----------
Standardized measure of
discounted future net
cash flows ..................... $ 392,315 $ 56,334 $ 88,569 $ 134,652 $ 671,870
=========== =========== =========== =========== ===========

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 priced at December 31, 1997,
except where fixed and determinable price escalations 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.

(e) ACREAGE AND PRODUCTIVE WELLS

The following table sets forth the Company's developed and undeveloped
acreage at December 31, 1997. In North America, the Company holds its acreage
through oil and natural gas leases. The leases have a variety of primary terms
and may require delay rentals to continue the primary term if not productive.
The leases may be surrendered by the operator at any time by notice to the
lessors, by the cessation of production, by the fulfillment of commitments, or
by failure to make timely payment of delay rentals.

The Company's acreage holdings in Cote d'Ivoire, Equatorial Guinea,
Pakistan, Bangladesh and Angola are evidenced by PSCs or other concession
agreements with the governments of those countries. Among the terms that may be
in place are obligations of UMC to conduct exploration operations (including the
drilling of wells) and the manner in which any oil and natural gas that may be
produced will be allocated among the parties to the contract. See Oil and Gas
Properties - International for further discussion of the PSCs.

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

Gulf Coast Onshore ...... 61 15 357 52 418 67
Gulf Coast Offshore ..... 149 41 253 145 402 186
Midcontinent ............ 181 64 190 42 371 106
Rocky Mountains ......... 412 253 648 238 1,060 491
Other U.S. .............. 43 8 67 8 110 16
------ ------ ------ ------ ------ ------
Sub-Total U.S. ... 846 381 1,515 485 2,361 866
Canada .................. 498 118 445 158 943 276
Bangladesh .............. -- -- 3,309 1,323 3,309 1,323
Cote d'Ivoire ........... 13 4 2,136 851 2,149 855
Equatorial Guinea ....... 36 9 1,798 1,202 1,834 1,211
Pakistan ................ -- -- 7,689 5,843 7,689 5,843
------ ------ ------ ------ ------ ------
Total (1) ........ 1,393 512 16,892 9,862 18,285 10,374
====== ====== ====== ====== ====== ======

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

(1) Does not include 1.2 million gross acres (0.2 million net acres) in Angola
where the Company was awarded a participation in the deepwater Block 19 in
February 1998.

- 8 -

At December 31, 1997, the Company had 5,948 gross productive wells (1,302
net), of which 3,994 gross wells (467 net) were oil and 1,954 gross wells (835
net) were natural gas. Productive wells consist of producing wells and wells
capable of production. Wells that are completed in more than one producing
horizon are counted as one well. Of the gross wells reported above, six had
multiple completions.

(f) PRODUCTION, UNIT PRICES AND COSTS

The following table sets forth information with respect to the Company's
production and average unit prices and costs for the periods indicated:

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

Production:

Oil (MBO)
United States ................................ 2,214 2,022 1,826
Canada ....................................... 439 511 649
Cote d'Ivoire ................................ 1,027 894 285
Equatorial Guinea ............................ 4,453 967 --
--------- --------- ---------
Total ..................................... 8,133 4,394 2,760
========= ========= =========

Natural gas (MMCF)
United States ................................ 42,238 47,719 38,878
Canada ....................................... 7,630 5,339 5,383
Cote d'Ivoire ................................ 4,939 2,387 192
--------- --------- ---------
Total ..................................... 54,807 55,445 44,453
========= ========= =========

Average net sales price, including hedging:

Oil ($ per bbl)
United States ................................ $ 17.96 $ 20.91 $ 16.41
Canada ....................................... $ 17.97 $ 19.43 $ 16.59
Cote d'Ivoire ................................ $ 18.35 $ 20.56 $ 15.45
Equatorial Guinea ............................ $ 17.71 $ 22.17 $ --
Average ................................... $ 17.87 $ 20.94 $ 16.35

Natural gas ($ per MCF)
United States ................................ $ 2.18 $ 2.15 $ 1.58
Canada ....................................... $ 1.40 $ 1.44 $ 1.17
Cote d'Ivoire ................................ $ 1.81 $ 1.80 $ 1.72
Average ................................... $ 2.04 $ 2.07 $ 1.53

Additional disclosures ($ per BOE):
Production and operating costs(1) ............... $ 2.65 $ 3.12 $ 3.50
Ad valorem and production taxes ................. $ 0.62 $ 0.64 $ 0.72
Oil and natural gas depletion and depreciation(2) $ 5.45 $ 6.00 $ 5.19

- ------------------
(1) Costs incurred to operate and maintain wells and related equipment,
excluding ad valorem and production taxes.
(2) Does not include impairments of proved oil and gas property.

-9-
12

(g) DRILLING ACTIVITY

During the periods indicated, the Company drilled or participated in the
drilling of the following exploratory and development wells:

Years Ended December 31,
------------------------------------------------
1997 1996 1995
------------ --------------- ---------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ------

Exploratory:
Productive............................................. 30 13.8 23 7.8 18 5.2
Non-Productive......................................... 31 12.9 25 8.6 15 3.2
--- ----- --- ---- --- ----
Total.............................................. 61 26.7 48 16.4 33 8.4
=== ===== === ==== === ====
Development:
Productive............................................. 253 69.9 113 26.8 114 19.4
Non-Productive......................................... 23 12.9 9 4.4 22 3.3
--- ----- --- ---- --- ----
Total.............................................. 276 82.8 122 31.2 136 22.7
=== ===== === ==== === ====
Total:
Productive............................................. 283 83.7 136 34.6 132 24.6
Non-Productive......................................... 54 25.8 34 13.0 37 6.5
--- ----- --- ---- --- ----
Total.............................................. 337 109.5 170 47.6 169 31.1
=== ===== === ==== === ====

At December 31, 1997, the Company was participating in the drilling or
completion of 57 gross (17.2 net) wells. All of the Company's drilling
activities are conducted with independent contractors.

(h) MARKETING AND CONTRACTS

A substantial portion of the Company's current natural gas production is
sold on the spot market or under market sensitive agreements with a variety of
purchasers, including intrastate and interstate pipelines, their marketing
affiliates, independent marketing companies and other purchasers who have the
ability to move the gas under firm transportation or interruptible agreements.

During 1997, the Company continued to market the majority of its gas from
the Bear Paw area in Montana to premium-priced markets in Minnesota and
Michigan. The Company's 35 MMCFD of firm capacity on TransCanada Pipeline and
Great Lakes Transmission is used to transport these volumes. In addition, the
Company contracted for a ten-year term, 8 MMCFD additional firm capacity on
TransCanada Pipeline from Empress, Alberta to Emerson, Manitoba. Effective
November 1, 1998, the Company will extend the 8 MMCFD firm capacity into Great
Lakes Transmission from Emerson, Manitoba, to St. Clair, Michigan. This
additional capacity is to support increased net production from the Bear Paw
area which exceeded 38 MMCFD in December 1997.

Prices for the Company's natural gas production throughout the remainder
of the United States are subject to regional discounts or premiums tied to
regional spot market prices.

Deregulation in Canada has facilitated access to alternative markets for
oil and natural gas, such as direct sales to end-users and export sales to
United States markets. Generally, one-year renewable contracts in which price is
negotiated annually have been used to access these markets. Firm transportation
and gas processing capacity from major aggregators have been obtained in Canada
to provide continued ability to produce under these contracts. Approximately 67%
of the Company's Canadian gas is currently sold under market sensitive contracts
redetermined annually. The remaining 33% is sold on the spot market.

In September 1994, UMC executed a take-or-pay contract under which UMC and
its partners will sell 50 MMCFD of natural gas production from Block CI-11 to
the Government of Cote d'Ivoire. UMC and its partners will receive approximately
$1.70 per MMBTU for the first four years, after which time the price will be
benchmarked against West Texas Intermediate crude. The government is paying UMC
for the natural gas with a portion of its oil production.

In March 1997, UMC executed a take-or-pay contract under which UMC and its
partners will sell natural gas production from Block CI-01 to the Government of
Cote d'Ivoire with initial volumes of 30 MMCFD beginning January 1, 1999,
increasing to a maximum of 50 MMCFD on January 1, 2001. UMC and its partners
will receive approximately $1.70 per MMBTU until February 1, 2000, after which
time the price will be benchmarked against West Texas Intermediate crude.

- 10 -

In Equatorial Guinea, UMC has executed a marketing arrangement with Mobil
Sales and Supply Corporation to market the Company's share of production. The
crude oil is sold at market prices at discounts from Dated Brent. The marketing
arrangement can be terminated by either party upon 90 days notice.

(i) CUSTOMERS

The Company markets its oil and gas production to numerous purchasers
under a combination of short and long-term contracts. During 1997 and 1996,
Mobil Sales and Supply Corporation accounted for 31% and 10%, respectively, of
the Company's oil and gas revenues as the purchaser of the Company's production
in Equatorial Guinea. In addition, during 1997 and 1996, H&N Gas Limited Inc.
accounted for 6% and 16%, respectively, of the Company's oil and gas revenues.
During 1997, 1996 and 1995, the Company had no other purchasers that accounted
for greater than 10% of its oil and gas revenues. The Company believes that the
loss of any single customer would not have a material adverse effect on the
results of operations of the Company.

(j) COMPETITION

The exploration for and production of oil and natural gas is highly
competitive. In seeking to obtain desirable producing properties, new leases and
exploration prospects, the Company faces competition from both major and
independent oil and natural gas companies, as well as from numerous individuals
and drilling programs. Extensive competition also exists in the market for
natural gas produced by the Company. Many of these competitors have financial
and other resources substantially in excess of those available to the Company
and, accordingly, may be better positioned to acquire and exploit prospects,
hire personnel and market production. In addition, many of the Company's larger
competitors may be better able to respond to factors such as changes in
worldwide oil and natural gas prices and levels of production, the cost and
availability of alternative fuels and the application of government regulations,
which affect demand for the Company's oil and natural gas production and which
are beyond the control of the Company. Generally, the competition factors for
international and North American opportunities are fairly similar.

Natural gas prices, which were once effectively determined by government
regulations, are now influenced largely by the effects of competition.
Competitors in this market include other producers, gas pipelines and their
affiliated marketing companies, independent marketers and providers of alternate
energy supplies, such as residual fuel oil.

(k) ENVIRONMENTAL MATTERS

United States Environmental Regulations. Operations of the Company are
subject to numerous laws and regulations governing the discharge of materials
into the environment or otherwise relating to environmental protection. These
laws and regulations may require the acquisition of a permit before drilling
commences, restrict the types, quantities and concentration of various
substances that can be released into the environment in connection with drilling
and production activities, limit or prohibit drilling activities on certain
lands lying within wilderness, wetlands and other protected areas, and impose
substantial liabilities for pollution resulting from the Company's operations.
Moreover, the recent trend toward stricter standards in environmental
legislation and regulation is likely to continue. For instance, legislation has
been proposed in Congress from time to time that would reclassify certain oil
and gas production wastes as "hazardous wastes" which would make the
reclassified exploration and production wastes subject to much more stringent
handling, disposal and clean-up requirements. If such legislation were to be
enacted, it could have a significant impact on the operating costs of the
Company, as well as the oil and gas industry in general. State initiatives to
further regulate the disposal of oil and gas wastes are also pending in certain
states, and these various initiatives could have a similar impact on the
Company. Management believes that the Company is in substantial compliance with
current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse impact on
the Company.

The U.S. Environmental Protection Agency has indicated that the Company
may be potentially responsible for costs and liabilities associated with alleged
releases of hazardous substances at two sites in Louisiana under the
Comprehensive Environmental Response, Compensation and Liability Act. Given the
extremely large number of companies that have been identified as potentially
responsible for releases of hazardous substances at the sites and the small
volume of hazardous substances allegedly disposed of by the companies whose
properties the Company acquired, management believes that the Company's
potential liability arising from these sites, if any, will not have a material
adverse impact on the Company.

During the three year period ended December 31, 1997, neither UMC, nor any
of its subsidiaries, have been cited by

-11-

any governmental authority with respect to environmental matters. The Company
has spent less than $100,000 per year during the years 1997, 1996 and 1995 for
the routine clean-up of oil, salt water or other substances in the ordinary
course of business. The Company has no significant commitments for capital
expenditures to comply with existing environmental requirements.

The Oil Pollution Act of 1990 (OPA) and regulations thereunder impose a
variety of regulations on "responsible parties" related to the prevention of oil
spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of a facility or
vessel, or the lessee or permittee of the area in which an offshore facility is
located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. While liability limits apply
in some circumstances, a party cannot take advantage of liability limits if the
spill was caused by gross negligence or willful misconduct or resulted from
violation of a federal safety, construction or operating regulation. If the
party fails to report a spill or to cooperate fully in the cleanup, liability
limits likewise do not apply. Few defenses exist to the liability imposed by the
OPA.

The OPA also imposes ongoing requirements on a responsible party,
including proof of financial responsibility, to cover at least some costs in a
potential spill. On August 25, 1993, an advance notice of intention to adopt a
rule under the OPA was published that would require owners and operators of
offshore oil and gas facilities to establish $150 million in financial
responsibility. Under the proposed rule, financial responsibility could be
established through insurance, guarantee, indemnity, surety bond, letter of
credit, qualification as a self-insurer or a combination thereof. There is
substantial uncertainty as to whether insurance companies or underwriters will
be willing to provide coverage under the OPA because the statute provides for
direct lawsuits against insurers who provide financial responsibility coverage,
and most insurers have strongly protested this requirement. On October 19, 1996,
Congress adopted an amendment to OPA that lowered the financial requirement for
certain offshore facilities to $35 million. That amendment, however, also
authorizes the U.S. Department of the Interior to adopt rules increasing that
requirement in circumstances that the agency deems appropriate. The Company
cannot predict the final form of the financial responsibility rule that might be
adopted. However, the impact of any such rule should not be any more adverse to
the Company than it will be to other similarly situated or less capitalized
owners or operators.

Canadian Environmental Regulations. The oil and natural gas industry is
subject to environmental regulation pursuant to local, provincial and federal
legislation in Canada. Environmental legislation provides for restrictions and
prohibitions on releases or emissions of various substances produced in
association with certain oil and gas industry operations. In addition,
legislation requires that well and facility sites be abandoned and reclaimed to
the satisfaction of provincial authorities. A breach of such legislation may
result in the imposition of fines and penalties. Environmental legislation in
Alberta was substantially revised in 1993 to update and consolidate the various
acts applicable to environmental protection. The various acts were consolidated
into the Environmental Protection and Enhancement Act, proclaimed April 22, 1993
and became effective September 1, 1993. Under the new Act, environmental
standards and compliance for releases, clean-up and reporting are stricter.
Also, the range of enforcement actions available and severity of penalties are
significantly increased. The changes had an incremental but not material effect
on the cost of conducting operations in Alberta. The full extent of the impact
will not be known until the Government of Alberta releases its enforcement
policy. Federal environmental regulations are generally restricted to the use
and transport of certain restricted and prohibited substances and the
environmental assessment of projects which require an approval from a federal
authority. The Company anticipates making necessary expenditures of both a
capital and expense nature as a result of the increasingly stringent laws
relating to the protection of the environment. The Company believes that it is
in material compliance with applicable environmental laws and regulations in
Canada.

(l) EMPLOYEES

At January 31, 1998, the Company employed approximately 380 people in its
United States, Canada, Cote d'Ivoire, Equatorial Guinea, Bangladesh, Pakistan
and Angola offices and various field locations whose functions are associated
with management, engineering, geology, geophysics, operations, land, legal,
accounting, financial planning and administration. Of this amount, approximately
100 full-time employees are responsible for the supervision and operation of its
field activities. The Company, which has no collective bargaining arrangement
with employees, believes its relations with its employees are satisfactory.

(m) OFFICES

The Company leases its Houston headquarters under a lease covering
approximately 108,000 square feet, expiring in

- 12 -

December 2006. The monthly rent expense recognized under generally accepted
accounting principles is approximately $107,000. The Company also leases
additional space for two division offices, seven field operating offices and
five offices outside North America.

ITEM 3. LEGAL PROCEEDINGS

On December 29, 1997, a class action complaint (Newman v. Carson, et. al.,
Civil Action No. 16109-NC) was filed in the Court of Chancery of the State of
Delaware, by a person claiming to represent the stockholders of UMC against UMC
and each of its directors. On January 9, 1998, a similar class action complaint
(Ross v. Brock, et. al., Civil Action No. 98-00845) was filed in the District
Court of Harris County, Texas, 164th Judicial District by another person
claiming to represent the stockholders of UMC against UMC and each of its
directors. Among other things, the complaints seek to (i) preliminarily and
permanently enjoin the Merger, (ii) require the UMC directors to maximize
stockholder value by placing UMC up for auction and/or to conduct a
"market-check", (iii) require the defendants to make a full and fair disclosure
of all material facts to the class members before the consummation of the
Merger, (iv) rescind the Merger should it be consummated prior to the resolution
of the lawsuit, and/or (v) recover unspecified damages and costs from the UMC
directors for the alleged breach of their fiduciary duties.

Management of UMC believes that the complaints are without merit and
intends to vigorously defend the actions.

The Company is a named defendant in lawsuits and is a party in
governmental proceedings from time to time arising in the ordinary course of
business. While the outcome of such lawsuits or other proceedings against the
Company cannot be predicted with certainty, management does not expect these
matters to have a material adverse effect on the financial condition or results
of operations of the Company.

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

None during the fourth quarter of 1997.

- 13 -

PART II

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

Since July 22, 1993, the Company's Series A Voting Common Stock, $0.01 par
value (the "Common Stock"), has been traded on the New York Stock Exchange under
the symbol "UMC". As of February 13, 1998, there were 35,792,891 shares of
Common Stock outstanding held by approximately 184 stockholders of record. The
Company has never paid dividends on its Common Stock and does not expect to pay
dividends in the near future.

The Company's Global Credit Facility and the 103/8% Senior Subordinated
Notes (see Note 5 of the Notes to Consolidated Financial Statements) contain
certain restrictions on the Company's ability to declare and pay dividends. The
payment of future cash dividends, if any, will be reviewed periodically by the
Board of Directors and will depend upon, among other things, the Company's
financial condition, funds from operations, the level of its capital and
exploration expenditures, its future business prospects and any restrictions
imposed by the Company's present or future credit facilities.

The following table shows the high and low sales prices of the Common
Stock on the New York Stock Exchange for the last two years:

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

March 31................... $ 25.88 $ 15.00

June 30.................... $ 36.25 $ 23.13

September 30............... $ 48.38 $ 32.13

December 31................ $ 53.50 $ 43.88

QUARTER ENDED, 1997
- -------------------

March 31................... $ 52.38 $ 28.38

June 30.................... $ 38.25 $ 26.50

September 30............... $ 42.25 $ 29.25

December 31................ $ 40.25 $ 26.00

- 14 -

ITEM 6. SELECTED FINANCIAL DATA

The financial data as of and for the years ended December 31, 1993 through
1997 were derived from the audited consolidated financial statements of the
Company and should be read in connection with the consolidated financial
statements and related notes included elsewhere herein (amounts in thousands,
except per share data).

YEARS ENDED DECEMBER 31,
---------------------------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------

Operating revenues:
Gas sales ....................................... $ 111,663 $ 114,498 $ 68,228 $ 67,763 $ 60,457
Oil sales ....................................... 145,351 92,031 45,122 26,675 19,877
Gain on sale of assets and other (1) ........... 7,851 29,875 33,691 3,379 1,984
--------- --------- --------- --------- ---------
264,865 236,404 147,041 97,817 82,318
--------- --------- --------- --------- ---------
Costs and expenses:
Production costs ................................ 56,492 51,298 42,891 36,938 30,539
General and administrative ...................... 13,580 12,727 10,425 12,504 8,097
Exploration, including dry holes ................ 38,845 40,325 15,682 16,187 6,811
Depreciation, depletion and amortization ........ 96,418 84,979 53,942 50,727 35,938
Impairment of proved oil and gas properties (2) . -- -- 8,317 94,793 10,051
Interest and debt expense ....................... 21,749 22,811 17,945 9,040 6,532
Interest and other expense (income) ............. (1,681) 844 (375) 141 (2,102)
--------- --------- --------- --------- ---------
225,403 212,984 148,827 220,330 95,866
--------- --------- --------- --------- ---------
Income (loss) before taxes and cumulative effect of
changes in accounting principles.................. 39,462 23,420 (1,786) (122,513) (13,548)
Income tax benefit (provision):
Current ......................................... (6,220) (785) (332) (25) (1,131)
Deferred ........................................ (13,455) (5,231) 4,217 41,549 7,436
--------- --------- --------- --------- ---------
Income (loss) before cumulative effect of changes in
accounting principles ............................ 19,787 17,404 2,099 (80,989) (7,243)
Cumulative effect of change in accounting principle,
net of tax (2) ................................... -- -- -- -- (3,543)
--------- --------- --------- --------- ---------
Net income (loss) ................................... $ 19,787 $ 17,404 $ 2,099 $ (80,989) $ (10,786)
========= ========= ========= ========= =========

Net income (loss) applicable to common stockholders $ 19,787 $ 15,873 $ 615 $ (80,989) $ (12,284)
========= ========= ========= ========= =========

Basic earnings per share of common stock:
Income (loss) before cumulative effect of changes
in accounting principles ..................... $ 0.56 $ 0.53 $ 0.02 $ (3.47) $ (0.75)
Cumulative effect of changes in accounting
principles...... ............................. -- -- -- -- (0.31)
--------- --------- --------- --------- ---------
Net income (loss) per common share .............. $ 0.56 $ 0.53 $ 0.02 $ (3.47) $ (1.06)
========= ========= ========= ========= =========

Weighted average number of common shares (3) .... 35,590 30,120 27,935 23,330 11,588

Diluted earnings per share of common stock:
Income (loss) before cumulative effect of changes
in accounting principles .................... $ 0.54 $ 0.51 $ 0.02 $ (3.47) $ (0.75)
Cumulative effect of changes in accounting
principles .................................. -- -- -- -- (0.31)
--------- --------- --------- --------- ---------
Net income (loss) per common share .............. $ 0.54 $ 0.51 $ 0.02 $ (3.47) $ (1.06)
========= ========= ========= ========= =========

Weighted average number of common shares and
common share equivalents outstanding (3) .... 36,662 31,428 29,259 23,330 11,588

Balance Sheet Data (at end of period):
Property, plant and equipment - net (1) ......... $ 740,972 $ 524,189 $ 468,673 $ 424,930 $ 291,723
Total assets .................................... 885,025 718,293 578,450 511,214 343,223
Long-term debt, including current maturities .... 283,557 157,731 247,899 239,634 92,149
Stockholders' equity (4) ........................ 459,399 432,236 212,312 171,438 189,672

- -----------------------
(1) See Note 4 of the Notes to Consolidated Financial Statements for a
discussion of significant acquisitions and dispositions for the applicable
periods.

(2) See Note 3 of the Notes to Consolidated Financial Statements regarding the
company's policy for assessing the recoverability of proved oil and gas
properties. In 1993, the Company adopted a policy to assess recoverability
of its proved properties by individual property groups having similar
geological or operating characteristics utilizing estimates of undiscounted
future net revenues attributable to proved reserves based on current prices
and to provide impairment reserves as conditions warrant.

(3) See Note 6 of the Notes to Consolidated Financial Statements for the
calculation of the weighted average number of common shares and common
share equivalents outstanding.

(4) The Company has never paid dividends on its common stock.

- 15 -

The following is a condensed summary of the results of operations for the
quarters of 1997 and 1996 (amounts in thousands, except per share amounts):

Quarters Ended (Unaudited)
------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------

1997
- ----
Revenues ..................... $65,005 $55,545 $62,370 $81,945
Income from operations ....... 15,370 7,011 14,136 23,013
Net income ................... 6,199 1,820 3,303 8,465
Basic earnings per share ..... 0.18 0.05 0.09 0.24
Diluted earnings per share ... 0.17 0.05 0.09 0.23

1996
- ----
Revenues ..................... $52,168 $61,323 $54,068 $68,845
Income from operations ....... 11,745 14,400 10,927 10,003
Net income ................... 3,716 5,235 2,838 5,615
Basic earnings per share (1) . 0.10 0.16 0.09 0.17
Diluted earnings per share (1) 0.10 0.15 0.09 0.16

- ---------------------
(1) The sum of the quarterly reported amounts for earnings per share do not
equal full year amounts.

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

(a) 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.

On December 22, 1997, UMC and OEI entered into a merger agreement that
provides for a stock-for-stock merger of the companies pursuant to which UMC
stockholders will receive 1.30 shares of the combined company for each existing
outstanding share of UMC and OEI shareholders will receive 2.34 shares of the
combined company for each existing outstanding share of OEI. UMC stockholders
will own approximately 46% of the equity of the combined company. The Merger is
expected to qualify as a tax-free transaction and is subject to each Company's
stockholders' approval and certain other conditions. The transaction is expected
to be treated as a pooling of interests for accounting purposes and is
anticipated to close by the end of the first quarter of 1998.

(b) OVERVIEW

The Company was organized in 1987 to pursue opportunities to acquire oil and
natural gas properties. Since its inception, the Company has grown through a
series of strategic corporate and property acquisitions combined with an
exploration program that focuses on UMC's existing properties in North America
and in certain international regions. Management's strategy is to (i) balance
the risk of exploration prospects with lower risk exploitation and development
of existing reserves, (ii) concentrate its activities in specific regions where
the Company has expertise, while retaining geographical diversification and
(iii) augment its industry and institutional relationships to access new
opportunities.

UMC's exploration strategy provides that essentially all prospects will be
generated in-house. This approach usually means that a portion of the interest
in each property is available for farmout, sale or other arrangement. A sales
transaction is often used in the case of international prospects that have been
acquired by UMC and subsequently enhanced by the acquisition and interpretation
of seismic data, geologic and engineering analysis and possibly the drilling of
wells. UMC's exploration and engineering staff have consistently shown the
ability to add value to both domestic and international prospects.

In recent years, UMC has developed its business strategy to include the sale
of both developed and undeveloped properties. With respect to developed
properties, sales may be made to (i) redeploy capital in regions where returns
are greater, (ii) eliminate properties that do not fit the Company's geographic
profile, (iii) dispose of marginal assets and (iv) accept offers where the buyer
gives significantly greater value to a property than UMC's technical staff and
outside engineers. As a result of a significant portion of the Company's growth
coming through large acquisitions, the sale of developed properties selected
using the above criteria is a frequent occurrence.

- 16 -

The Company's international activities are focused in the countries of
Equatorial Guinea, Cote d'Ivoire, Pakistan, Bangladesh and Angola, where it
holds substantial acreage positions in highly prospective geologic regions.
Management believes that these areas have the potential to significantly
increase the Company's proved oil and gas reserves based upon results of
drilling to date and analysis of technical data regarding additional prospects.

Although the Company's reserves have historically been concentrated in
natural gas, international discoveries have shifted the percentage of reserves
represented by crude oil and condensate toward a more equal balance with natural
gas reserves. Concurrently, the Company expects to continue the historical trend
of adding to its North American reserve base.

YEAR ENDED DECEMBER 31, 1997 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1996

Oil and gas revenues for 1997 were $257.0 million, or 24% greater than 1996
oil and gas revenues of $206.5 million. The increase in oil and gas revenues is
due to increased oil volumes in West Africa resulting from a full years'
production from Block B in Equatorial Guinea, offset by lower U.S. gas volumes
due primarily to property sales and natural production declines.

Oil revenues increased 58% to $145.4 million, the result of significantly
increased worldwide production volumes offset by a drop in the average realized
price received. Oil production increased 85% to 8,133 MBO in 1997 due primarily
to increased oil production in Cote d'Ivoire and Equatorial Guinea. The average
sales price after hedging for oil decreased 15% to $17.87 in 1997 compared to
1996. The impact of hedging on oil prices received and oil revenues for 1997 and
1996 was not significant.

Natural gas revenues declined 3% to $111.7 million, the result of slight
declines in natural gas prices, asset sales and the impact of certain hedging
activities. The average sales price after hedging for natural gas decreased to
$2.04 per MCF, or 2%, in 1997 from 1996. The impact of hedging on natural gas
prices received and natural gas revenues for 1997 and 1996 was a decrease of
$0.02 and $0.06 per MCF and $1.2 million and $3.7 million, respectively. The
Company has consistently entered into hedging transactions for the purpose of
managing the overall impact of commodity price volatility. Depending upon
commodity price movement, gains or losses recognized are offset by lower or
higher prices at the wellhead. Natural gas production for 1997 was 54,807 MMCF,
a decrease of 1% over 1996 volumes due primarily to property sales and natural
production declines, offset by acquisitions and increased production in Cote
d'Ivoire and Canada.

Gains on sales of assets totaled $4.9 million in 1997, as compared to $29.0
million in 1996. The 1997 gains on sales of assets primarily resulted from
dispositions of various non-strategic North American properties. The largest
contributors to the gains recognized in 1996 were sales of unproved
international interests, including the final installment of the sale to Mobil
Equatorial Guinea Corporation (Mobil) of a 10% interest in Block B in Equatorial
Guinea and the sale of a 55% contract interest in Block CI-105 in Cote d'Ivoire
to Shell Exploration B.V. (Shell), a unit of Royal Dutch/Shell.

Production costs, excluding ad valorem and production taxes, for 1997 of
$45.8 million increased 8% from $42.5 million for 1996, primarily due to
production in Equatorial Guinea for the full 1997 period. However, on a BOE
basis, production costs for 1997 decreased $0.47 per BOE (15%) when compared to
1996.

General and administrative expense for 1997 was $13.6 million compared to
$12.7 million in 1996. This increase was primarily due to outside consulting
fees, a new systems implementation and an overall increase in the activity level
of the Company. However, general and administrative expenses per BOE of
production decreased from $0.93 in 1996 to $0.79 in 1997.

Exploration, dry hole and lease impairment expenses for 1997 totaled $38.9
million as compared to $40.3 million in 1996. The components of exploration
expense for 1997 reflect seismic activities worldwide, certain exploratory dry
holes primarily in Equatorial Guinea, Cote d'Ivoire and Gulf of Mexico, and
certain initial costs in other international areas.

Depreciation, depletion and amortization (DD&A) expense for 1997 of $96.4
million increased 13% from $85.0 million for 1996. This increase is primarily
attributable to increased production levels in Cote d'Ivoire and Equatorial
Guinea. The rate per BOE of oil and gas DD&A decreased 9% from $6.00 per BOE in
1996 to $5.45 per BOE in 1997. This decrease is primarily due to a change in the
Company's geographic production mix and proved reserve additions in 1997.

-17-
20

Interest and debt expense for 1997 was $21.7 million compared to $22.8
million for 1996. The decrease in interest expense is primarily due to the
reduced debt levels through the majority of 1997 resulting primarily from the
paydown of the Global Credit Facility in the fourth quarter of 1996 with
proceeds from the Company's 1996 equity offering.

An income tax provision of $19.7 million (of which $6.2 million is a current
provision and $13.5 million is a deferred provision) was recognized for 1997,
compared to a provision of $6.0 million (of which $0.8 was a current provision
and $5.2 was a deferred provision) for 1996. A significant portion of current
taxes in 1997 is a $4.6 million non-cash provision representing current taxes
incurred in Cote d'Ivoire which, under the terms of the production sharing
contract, will be paid by the Ivorian government from their production proceeds.
Consistent with Statement of Financial Accounting Standards (SFAS) No. 109,
Accounting for Income Taxes, the income tax provision or benefit was derived
primarily from changes in deferred income tax assets and liabilities recorded on
the balance sheet. The 1996 deferred tax benefit was affected by the use of
$13.0 million of net operating loss (NOL) carryforwards to essentially eliminate
1996 taxable income and the deferred tax effect of exercised stock options. At
December 31, 1997, the Company had $84.9 million of United States (U.S.) NOL
carryforwards, $67.0 million of Equatorial Guinea NOL carryforwards and $32.2
million of Canadian federal tax pools. The Company paid cash income taxes in
1997 and 1996 of $1.8 million, and $0.4 million, respectively, to several
states, Canada and the U.S.

The Company reported net income of $19.8 million, or $0.56 basic earnings
per share, for 1997 compared to a net income of $17.4 million, or $0.53 basic
earnings per share, for 1996.

Year 2000 problems do not present a material consideration for the Company's
current operations. The Company is currently engaged in a comprehensive project
to upgrade its computer software in its production , land and accounting systems
to programs which are year 2000 compliant. The Company does not anticipate year
2000 problems will have a material adverse impact on its business.

YEAR ENDED DECEMBER 31, 1996 COMPARED WITH THE YEAR ENDED DECEMBER 31, 1995

Oil and gas revenues for 1996 were $206.5 million, or 82% greater than 1995
oil and gas revenues of $113.4 million primarily due to significant improvements
in oil and natural gas prices and production volumes. The average sales price
after hedging for natural gas increased to $2.07 per MCF, or 35%, in 1996 from
1995. The impact of hedging on natural gas prices received and natural gas
revenues for 1996 and 1995 was an increase (decrease) of ($0.06) and $0.07 per
MCF and ($3.7) million and $3.5 million, respectively. Natural gas production
for 1996 was 55,445 MMCF, an increase of 25% over 1995 volumes due primarily to
new production from the Gulf of Mexico and a full year of gas production in Cote
d'Ivoire which commenced in late 1995. Oil production increased 59%, or 1,634
MBO, in 1996 due primarily to increased oil production in Cote d'Ivoire and
commencement of production in Equatorial Guinea in August 1996. The average
sales price after hedging for oil increased to $20.94, or 28%, in 1996 compared
to 1995. The impact of hedging on oil prices received and oil revenues for 1996
and 1995 was an increase (decrease) of ($0.04) and $0.22 per barrel and ($0.2)
million and $0.6 million, respectively.

The aforementioned business strategy of selling both developed and
undeveloped properties generated gains on sales of assets of $29.0 million in
1996, as compared to $31.2 million in 1995. The 1996 gains on sales of assets
resulted primarily from sales of unproved international interests including a
$15.8 million pre-tax gain recognized as the final installment on the assignment
of a portion of the Company's interest in Block B in Equatorial Guinea to Mobil
in October 1995, and the sale in September 1996 of a 55% contract interest in
Block CI-105 in Cote d'Ivoire to Shell from which the Company recognized a
pre-tax gain of $3.3 million. Gains on sales of producing properties in North
America were primarily generated by a pre-tax gain of $4.7 million recognized as
a result of the sale by UMC Resources Canada Ltd., the Company's wholly-owned
Canadian subsidiary, of its interest in the Rocanville area in June 1996, and a
pre-tax gain of $3.6 million recognized as a result of the sale of interests in
the Elk City and Arapaho fields in December 1996. The largest contributors to
the gain in 1995 were the sales of partial interests to Yukong Limited of a
portion of the Company's interests in Block CI-01 and CI-02 in Cote d'Ivoire and
Blocks C and D in Equatorial Guinea and the first installments of the sale to
Mobil of a 10% interest in Block B in Equatorial Guinea. For these international
sales in 1995, a pre-tax gain of $18.3 million was recognized on proceeds of
$22.1 million. During 1995, the Company recognized pre-tax gains of $12.9
million on sales of producing properties in North America.

Production costs, excluding ad valorem and production taxes, for 1996 of
$42.5 million increased 19% from $35.6 million for 1995, primarily due to a full
year of production in Cote d'Ivoire and commencement of production in Equatorial
Guinea. However, on a cost per BOE basis, production costs for 1996 decreased
$0.38 per BOE, a decrease of 11%, when compared to 1995.

- 18 -

General and administrative expenses for 1996 were $12.7 million compared to
$10.4 million in 1995. This increase was primarily due to nonrecurring severance
expenses of $0.9 million in 1996, $0.7 million of expenses associated with
miscellaneous non-cash benefits accruals and an overall expansion of the
Company's operations. However, general and administrative expenses per BOE of
production decreased from $1.03 per BOE in 1995 to $0.93 per BOE in 1996.

Exploration, dry hole and lease impairment expenses for 1996 totaled $40.3
million as compared to $15.7 million in 1995. This increase of $24.6 million was
primarily due to increased dry hole costs experienced in the Gulf of Mexico,
certain onshore areas and Equatorial Guinea Block D. In addition, the Company
had increased geological and geophysical costs in 1996 reflecting a higher level
of exploration activity in Cote d'Ivoire, Equatorial Guinea and North America.

DD&A expense for 1996 of $85 million increased 58% from $53.9 million for
1995. This increase is primarily attributable to increased production levels in
Cote d'Ivoire and Equatorial Guinea. The rate per BOE of oil and gas DD&A
increased 16% from $5.19 per BOE in 1995 to $6.00 per BOE in 1996. This increase
is a result of capitalized costs in Equatorial Guinea which reflect certain
development expenditures in anticipation of significant future reserve
extensions and additions that were not recognized as proved reserves at December
31, 1996. In addition, certain downward revisions of proved oil and gas reserves
in the United States were recognized by the Company during 1996, increasing DD&A
rates. Furthermore, a greater proportion of the Company's North American oil and
gas volumes were produced from the Gulf of Mexico region in 1996 versus 1995,
which historically has higher depletion rates.

Interest and debt expense for 1996 was $22.8 million compared to $17.9
million in 1995. Non-cash amortization of debt issue costs totaled $2.1 million
for 1996, as compared to $1.2 million for 1995. The $0.9 million increase is
primarily due to the amortization of the original issue discount on the 103/8%
Senior Subordinated Notes (Notes) due 2005 and the write-off of debt issue costs
upon the purchase of the Cote d'Ivoire Project Loan in November 1996 by the
Company with a portion of the proceeds from the November 1996 offering of common
stock. The additional $4.0 million increase is primarily due to a higher average
interest rate in 1996, resulting from the issuance of the Notes in the fourth
quarter 1995, and higher average debt levels in 1996 as compared to 1995.

An income tax provision of $6.0 million was recognized for 1996, compared to
a benefit of $3.9 million for 1995. Consistent with SFAS No. 109, the income tax
provision or benefit was derived primarily from changes in deferred income tax
assets and liabilities recorded on the balance sheet. The primary items
affecting the 1996 deferred tax provision were the use of $13.0 million of NOL
carryforwards to eliminate 1996 taxable income and the deferred tax effect of
exercised stock options. The 1995 deferred tax benefit was affected by property
sales, the impairment of proved properties relating to the adoption of SFAS No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of, during the fourth quarter of 1995, and offset by the
use of $31.0 million of NOL carryforwards. At December 31, 1996, the Company had
$98.0 million of U. S. NOL carryforwards, $52.0 million of Equatorial Guinea NOL
carryforwards and $17.6 million of Canadian federal tax pools. The Company paid
cash income taxes in 1996 and 1995 of $0.4 million and $0.6 million,
respectively, to several states, Canada and the U.S. for the Alternative Minimum
Tax.

The Company reported net income of $17.4 million, basic earnings per share
of $0.53, for 1996 compared to a net income of $2.1 million, or basic earnings
per share of $0.02, for 1995.

(d) CAPITAL RESOURCES AND LIQUIDITY

The Company has historically funded its operations, acquisitions,
exploration and development expenditures from cash flows from operating
activities, bank borrowings, sales of common and preferred stock, issuance of
senior subordinated notes, sales of non-strategic oil and natural gas
properties, sales of partial interests in exploration concessions and project
finance borrowings.

The primary sources of cash for the Company during the year ended December
31, 1997, included proceeds from funds generated from operations, cash on hand,
proceeds from asset sales, exercise of stock options and borrowings under the
Global Credit Facility. In the comparable period of 1996, the primary sources
of cash included proceeds from the November 1996 offering of common stock,
funds generated from operations, bank borrowings, proceeds from asset sales and
exercise of stock options and warrants. For the year ended 1995, the primary
sources of cash included the issuance of the 103/8% Senior Subordinated Notes,
funds generated from operations, proceeds from sales of certain oil and gas
properties, project financing borrowings and the issuance of the Series F
preferred stock. Primary cash uses for the years ended December 31, 1997 and
1996 included capital expenditures (including exploration expenses) which
totaled $370.1 million and $190.4 million, respectively. In the comparable
period of 1995, the primary cash uses included capital expenditures (including
exploration expenses) of $163.0 million.

- 19 -

The Company has used the Global Credit Facility (see Note 5 of the Notes to
Consolidated Financial Statements) to partially finance its expenditures. As of
December 31, 1997, the borrowing base under the Global Credit Facility was $300
million, and the Company had outstanding loans thereunder of approximately $127
million and outstanding letters of credit of approximately $4 million. Resulting
liquidity (including cash) exceeded $181 million as compared to $254 million at
December 31, 1996.

Effective January 18, 1994, the Company entered into five-year fixed LIBOR
interest rate swap contracts that provide for fixed interest rates to be
realized on notional amounts of $45.0 million in 1998. The agreements include
varying annual fixed interest rates ranging from 3.66% in 1994 to 6.40% in 1998,
plus interest rate margins.

Equity financings have represented a significant source of funds for the
Company. Since its inception, over $197 million of private equity capital and
approximately $343 million of public equity capital has been raised to support
its growth. The Company completed its initial public offering in July 1993,
resulting in net proceeds to the Company of $68.7 million. In November 1994, the
Company issued approximately $64 million in common equity as partial
consideration for the General Atlantic Resources, Inc. acquisition. In June and
July 1995, the Company sold an aggregate $35.0 million of Series F Preferred
Stock in a private placement to institutional investors which was converted to
1.845 million common shares in accordance with its automatic conversion terms in
July 1996. In November 1996, the Company issued 4.089 million common shares for
$182.7 million in cash to be used to fund planned capital expenditures and for
general corporate purposes. Proceeds of $20.5 million relating to exercise of
stock options and warrants have been realized since the July 1993 initial public
offering.

As part of its on-going operations, the Company periodically sells interests
in proved reserves and enhanced exploration prospects. This practice continued
in 1997 and 1996, with net cash proceeds from sales of assets of $19.4 million
and $50.2 million, respectively. The 1997 proceeds consisted of sales of various
non-strategic North American properties.

The Company's capital expenditure budget for 1998 is expected to be
approximately $350 million. Primary areas of emphasis will be West Africa, East
Texas, the Gulf of Mexico and other international areas. In addition, the
Company will evaluate its level of capital spending throughout the year based
upon drilling results, commodity prices, cash flows from operations, property
acquisitions and consummation of the Merger. Actual capital spending may vary
from the initial capital expenditure budget.

The Company continues to maintain a sound financial structure. The Company's
debt to total capitalization ratio has increased to 38% at December 31, 1997,
from 27% at December 31, 1996. However, the Company's interest coverage ratio
(calculated as the ratio of income from operations plus DD&A, impairment of
proved oil and gas properties and exploration expense to interest plus
capitalized interest less non-cash amortization of debt issue costs) was 9.7 to
1 for 1997 compared with 7.6 to 1 for 1996. This measure provides investors with
a measure of the Company's ability to service debt. The high ratio in 1997 and
improvement over 1996 are indicators of the Company's strong financial position
and future capability to service debt and fund operations. Access to various
capital markets, combined with cash flows from operating activities, provide the
Company with the financial strength, leverage and liquidity that will allow it
to fund its 1998 capital expenditure program, including the international
exploration and development opportunities in Cote d'Ivoire, Equatorial Guinea,
Pakistan and Bangladesh, and continue to selectively pursue strategic corporate
and property acquisitions.

(e) NET OPERATING LOSS CARRYFORWARDS AND CANADIAN TAX POOLS

At December 31, 1997, the Company had $84.9 million of United States NOL
carryforwards, $67.0 million of Equatorial Guinea NOL carryforwards and $32.2
million of Canadian federal tax pools which it expects to use in sheltering
future taxable income in the United States, Equatorial Guinea and Canada,
respectively, as compared to December 31, 1996 amounts of $98.0 million, $52.0
million and $17.6 million for the United States, Equatorial Guinea and Canada,
respectively.

The Company's United States NOL carryforward is subject to certain
limitations. Under Section 382 of the Internal Revenue Code, the taxable income
of UMC available for offset by pre-ownership change NOL carryforwards and
certain built-in losses is subject to an annual limitation (the 382 Limitation)
if an "ownership change" occurs. The Company has

- 20 -

determined that an ownership change under Section 382 occurred in 1994. As a
result of this ownership change, the total amount of UMC's NOL carryforwards
will not be affected, but the annual 382 Limitation will equal the fair market
value of the Company immediately before the ownership change multiplied by the
long-term tax exempt interest rate, subject to adjustment for certain built-in
gains of the Company. To the extent the 382 Limitation exceeds the federal
taxable income of the post-merger company for a given year, the 382 Limitation
for the subsequent year will be increased by such excess. The Merger is not
expected to have a material impact on the Company's 382 Limitation. NOL
carryforwards of the Company will be disallowed entirely if certain continuity
of business enterprise requirements are not met. It is expected these
requirements will be met. The effect of the 382 Limitation may be to defer the
use of the Company's existing NOL carryforwards.

(f) FOREIGN CURRENCY TRANSACTIONS

The financial position and results of operations attributable to the
Company's Canadian operations are translated into U.S. currency in accordance
with SFAS No. 52, Foreign Currency Translation. Accordingly, the assets and
liabilities of the Canadian financial statements are translated using the
currency exchange rate in effect at the balance sheet date while the revenues,
expenses, gains and losses are translated using the exchange rate for the
periods in which they occurred. The effect of such translations are reflected as
adjustments to stockholders' equity as reflected in the Statement of Changes in
Stockholders' Equity in the Company's Consolidated Financial Statements.

Essentially all revenues and expenditures for the Company's international
operations are settled, and all books and records are maintained, in U.S.
dollars.

(g) CHANGES IN PRICES AND INFLATION

The Company's revenues and the value of its oil and natural gas properties
have been, and will continue to be, affected by changes in oil and natural gas
prices. The Company's ability to maintain current borrowing capacity and to
obtain additional capital on attractive terms is also substantially dependent on
oil and natural gas prices. Oil and natural gas prices are subject to
significant seasonal and other market fluctuations that are beyond the Company's
ability to control or predict. Although certain of the Company's costs and
expenses are affected by the level of inflation, inflation did not have a
significant effect on the Company's results of operations during 1997 and 1996.

(h) FORWARD-LOOKING STATEMENTS

Certain statements in this report, including statements of the Company's and
management's expectations, intentions, plans and beliefs, including those
contained in or implied by "Business and Properties," "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and the Notes to
Consolidated Financial Statements, are "forward-looking statements", within the
meaning of Section 21E of the Securities Exchange Act of 1934, that are subject
to certain events, risk and uncertainties that may be outside the Company's
control. These forward-looking statements include statements of management's
plans and objectives for the Company's future operations and statements of
future economic performance; information about the Merger such as general
economic conditions and possible or assumed results of operations or impacts of
the Merger; information regarding drilling schedules, expected or planned
production or transportation capacity, future production levels of international
and domestic fields, the Company's capital budget and future capital
requirements, the Company's meeting its future capital needs, the Company's
realization of its deferred tax assets, the level of future expenditures for
environmental costs and the outcome of regulatory and litigation matters; and
the assumptions described in this report underlying such forward-looking
statements. Actual results and developments could differ materially from those
expressed in or implied by such statements due to a number of factors,
including, without limitation, those described in the context of such
forward-looking statements, fluctuations in the price of crude oil and natural
gas, the success rate of exploration efforts, timeliness of development
activities, risks incident to the drilling and completion for oil and gas wells,
future production and development costs, the political and economic climate in
which the Company conducts operations and the risk factors described from time
to time in the Company's other documents and reports filed with the Securities
and Exchange Commission.

- 21 -

(i) IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS

In February 1997, the Financial Accounting Standards Board (FASB) issued
SFAS No. 128, Earnings Per Share, which establishes standards for computing and
presenting earnings per share. This standard, effective for fiscal year 1997,
replaces the presentation of primary earnings per share, as prescribed by
Accounting Principles Board (APB) No. 15, with a presentation of basic earnings
per share. In addition, this standard requires dual presentation of basic and
diluted earnings per share on the Consolidated Statement of Income.

In June 1997, the FASB issued SFAS No. 130, Reporting Comprehensive Income,
which requires the reporting of comprehensive income and its components to be
displayed with the same prominence as other financial statements. This statement
requires a company to classify items of other comprehensive income by their
nature in a financial statement and display the accumulated balance of other
comprehensive income separately from retained earnings and additional paid-in
capital in the equity section of the statement of financial position. It is
effective for the fiscal years beginning after December 15, 1997.

In June 1997, the FASB issued SFAS No. 131, Disclosures about Segments of an
Enterprise and Related Information. This statement requires a company to report
financial information by operating segment. Operating segments are defined as
the basis on which the chief operating decision maker disaggregates the company
for making operating decisions and assessing performance. The Company adopted
the provisions of SFAS No. 131, and has included segment information in Notes 17
and 18 to the Consolidated Financial Statements.

- 22 -

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Page
----

Report of Independent Public Accountants........................................................................ 24
Consolidated Statement of Income, Years Ended December 31, 1997, 1996 and 1995.................................. 25
Consolidated Balance Sheet, December 31, 1997 and 1996.......................................................... 26
Consolidated Statement of Changes in Stockholders' Equity, Years Ended December 31,
1997, 1996 and 1995.......................................................................................... 28
Consolidated Statement of Cash Flows, Years Ended December 31, 1997, 1996 and 1995.............................. 29
Notes to Consolidated Financial Statements...................................................................... 30

- 23 -

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

The Board of Directors and Stockholders of
United Meridian Corporation:

We have audited the accompanying consolidated balance sheet of United
Meridian Corporation (a Delaware corporation) and subsidiaries as of December
31, 1997 and 1996, and the related consolidated statements of income, changes in
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1997. 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 financial position of United
Meridian Corporation and subsidiaries as of December 31, 1997 and 1996, and the
results of its operations and its cash flows for each of the three years in the
period ended December 31, 1997, in conformity with generally accepted accounting
principles.

As discussed in Note 3 to the Consolidated Financial Statements, during
1995, the Company adopted the provisions of Statement of Financial Accounting
Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of.

ARTHUR ANDERSEN LLP

Houston, Texas
February 9, 1998

- 24 -

UNITED MERIDIAN CORPORATION

CONSOLIDATED STATEMENT OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

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

Operating revenues:
Gas sales ........................................... $ 111,663 $ 114,498 $ 68,228
Oil sales ........................................... 145,351 92,031 45,122
Contract settlements and other ...................... 3,000 854 2,507
Gain on sale of assets .............................. 4,851 29,021 31,184
--------- --------- ---------
264,865 236,404 147,041
--------- --------- ---------

Costs and expenses:
Production costs .................................... 56,492 51,298 42,891
General and administrative .......................... 13,580 12,727 10,425
Exploration, including dry holes and impairments .... 38,845 40,325 15,682
Depreciation, depletion and amortization ............ 96,418 84,979 53,942
Impairment of proved oil and gas properties ......... -- -- 8,317
--------- --------- ---------
205,335 189,329 131,257
--------- --------- ---------

Income from operations .................................. 59,530 47,075 15,784
Other income, expenses and deductions:
Interest and other income (expense) ................. 1,681 (844) 375
Interest and debt expense ........................... (21,749) (22,811) (17,945)
--------- --------- ---------

Income (loss) before income taxes ....................... 39,462 23,420 (1,786)
Income tax benefit (provision):
Current ............................................. (6,220) (785) (332)
Deferred ............................................ (13,455) (5,231) 4,217
--------- --------- ---------

Net income .............................................. 19,787 17,404 2,099

Preferred stock dividends ............................... -- (1,531) (1,484)
--------- --------- ---------

Net income available to common stockholders ............. $ 19,787 $ 15,873 $ 615
========= ========= =========

Basic earnings per share ................................ $ 0.56 $ 0.53 $ 0.02
========= ========= =========

Weighted average number of common shares outstanding .... 35,590 30,120 27,935
========= ========= =========

Diluted earnings per share .............................. $ 0.54 $ 0.51 $ 0.02
========= ========= =========

Weighted average number of common shares and common
share equivalents outstanding ....................... 36,662 31,428 29,259
========= ========= =========

The accompanying notes are an integral part of these
consolidated financial statements.

-25-
28

UNITED MERIDIAN CORPORATION

CONSOLIDATED BALANCE SHEET
(IN THOUSANDS)

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

ASSETS

Current assets:
Cash and cash equivalents .......................... $ 11,689 $ 54,942
Accounts receivable, net of allowance
for doubtful accounts of
$1,190 at December 31, 1997 and 1996:
Oil and gas sales .............................. 36,565 36,238
Joint interest and other ....................... 42,463 45,447
Deferred income taxes .............................. 1,547 2,839
Inventory .......................................... 10,025 11,389
Prepaid expenses and other ......................... 5,875 5,306
----------- -----------
108,164 156,161
----------- -----------

Property and equipment, at cost:
Oil and gas (successful efforts method)
Proved properties .............................. 1,110,877 851,818
Unproved properties ............................ 34,538 14,667
Other property and equipment ....................... 16,138 8,295
----------- -----------
1,161,553 874,780
Accumulated depreciation, depletion and amortization (420,581) (350,591)
----------- -----------
740,972 524,189
----------- -----------
Other assets:
Gas imbalances receivable .......................... 6,227 5,702
Deferred income taxes .............................. 19,597 23,035
Debt issue cost .................................... 9,193 8,370
Other .............................................. 872 836
----------- -----------
35,889 37,943
----------- -----------

TOTAL ASSETS ................................ $ 885,025 $ 718,293
=========== ===========

The accompanying notes are an integral part of these
consolidated financial statements.

-26-
29

UNITED MERIDIAN CORPORATION

CONSOLIDATED BALANCE SHEET
(IN THOUSANDS, EXCEPT FOR SHARE AMOUNTS)

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

LIABILITIES & STOCKHOLDERS' EQUITY

Current liabilities:
Accounts payable ...................................... $ 88,958 $ 80,593
Advances from joint owners ............................ 8,491 5,575
Interest payable ...................................... 3,698 3,800
Accrued liabilities ................................... 4,654 7,525
Current maturities of long-term debt .................. 911 899
-------- --------
106,712 98,392
-------- --------

Long-term debt:
Global credit facility ................................ 126,496 --
103/8% senior subordinated notes ...................... 150,000 150,000
Other ................................................. 6,150 6,832
-------- --------
282,646 156,832
-------- --------

Deferred credits and other liabilities:
Deferred income taxes ................................. 24,456 20,797
Gas imbalances payable ................................ 4,617 3,994
Other ................................................. 7,195 6,042
-------- --------
36,268 30,833
-------- --------

Commitments and contingencies

Stockholders' equity:
Preferred stock, $0.01 par value, 32,000,000
shares authorized, no shares
issued and outstanding at December 31, 1997 and
1996 ............................................... -- --
Common stock, $.01 par value, 46,000,000 shares
authorized, 35,792,891 and 35,217,206 shares
issued and outstanding at December 31, 1997
and 1996, respectively ............................. 358 352
Additional paid-in capital ............................ 550,613 540,661
Foreign currency translation adjustment ............... (6,839) (4,257)
Retained earnings (deficit) ........................... (84,733) (104,520)
-------- --------
459,399 432,236
-------- --------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY ..... $885,025 $718,293
======== ========

The accompanying notes are an integral part of these
consolidated financial statements.

- 27 -

30
UNITED MERIDIAN CORPORATION

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)

FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995

SERIES F
PREFERRED STOCK COMMON STOCK
--------------- ----------------------
SHARES AMOUNT SHARES AMOUNT
------ ------ ------ ------

Balance, December 31, 1994 ............................ -- -- 27,721,881 $ 277
Foreign currency translation adjustment ............
Preferred stock issuance
- June 30 ........................................ 833,333 $ 8
- July 24 ........................................ 333,334 4
Exercise of common stock options ................... 428,343 4
Preferred stock dividends ..........................
Net income .........................................

------------ ------- ------------ ------
Balance, December 31, 1995 ............................ 1,166,667 $ 12 28,150,224 $ 281
Foreign currency translation adjustment ............
Automatic conversion of Series F preferred
stock to common stock ............................ (1,166,667) (12) 1,845,284 19
Common stock offering .............................. 4,088,942 41
Exercise of common stock options ................... 897,007 9
Exercise of warrants ............................... 235,749 2
Preferred stock dividends ..........................
Net income .........................................

------------ ------- ------------ ------
Balance, December 31, 1996 ............................ -- $ -- 35,217,206 $ 352
Foreign currency translation adjustment ............
Common shares issued in exchange for shares
tendered from a prior acquisition ................ 2,662 --
Exercise of common stock options ................... 573,023 6
Net income .........................................

------------ ------- ------------ ------
Balance, December 31, 1997 ............................ -- $ -- 35,792,891 $ 358
============ ======= ============ ======

ADDITIONAL FOREIGN RETAINED
PAID-IN CURRENCY EARNINGS
CAPITAL ADJUSTMENT (DEFICIT) TOTAL
------------ ------------ ------------ ------------

Balance, December 31, 1994 ............................ $ 296,168 $ (3,999) $ (121,008) $ 171,438
Foreign currency translation adjustment ............ (58) (58)
Preferred stock issuance
- June 30 ........................................ 24,992 25,000
- July 24 ........................................ 9,902 9,906
Exercise of common stock options ................... 5,407 5,411
Preferred stock dividends .......................... (1,484) (1,484)
Net income ......................................... 2,099 2,099

------------ ------------ ------------ ------------
Balance, December 31, 1995 ............................ $ 336,469 $ (4,057) $ (120,393) $ 212,312
Foreign currency translation adjustment ............ (200) (200)
Automatic conversion of Series F preferred
stock to common stock ............................ (7)
Common stock offering .............................. 182,629 182,670
Exercise of common stock options ................... 17,951 17,960
Exercise of warrants ............................... 3,619 3,621
Preferred stock dividends .......................... (1,531) (1,531)
Net income ......................................... 17,404 17,404

------------ ------------ ------------ ------------
Balance, December 31, 1996 ............................ $ 540,661 $ (4,257) $ (104,520) $ 432,236
Foreign currency translation adjustment ............ (2,582) (2,582)
Common shares issued in exchange for shares
tendered from a prior acquisition ................
Exercise of common stock options ................... 9,952 9,958
Net income ......................................... 19,787 19,787
------------ ------------ ------------ ------------

Balance, December 31, 1997 ............................ $ 550,613 $ (6,839) $ (84,733) $ 459,399
============ ============ ============ ============

These accompanying notes are an integral part of these
consolidated financial statements.

-28-
31

UNITED MERIDIAN CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS
(IN THOUSANDS)

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

Cash flows from operating activities:
Net income ................................................ $ 19,787 $ 17,404 $ 2,099
Adjustments to reconcile net income to cash from
operating activities:
Exploration, including dry holes and impairments ........ 38,845 40,325 15,682
Depreciation, depletion and amortization ................ 96,418 84,979 53,942
Impairment of proved oil and gas properties ............. -- -- 8,317
Amortization of debt issue cost ......................... 1,576 2,127 1,173
Deferred income tax provision (benefit) ................. 13,455 5,231 (4,217)
Gain on sale of assets .................................. (4,851) (29,021) (31,184)
--------- --------- ---------
165,230 121,045 45,812
Changes in assets and liabilities:
Increase in receivables ............................... (8,707) (22,868) (9,618)
Decrease (increase) in inventory ...................... (1,364) (6,715) 1,773
Increase (decrease) in payables and accrued liabilities 7,039 (1,495) 8,150
Increase (decrease) in net gas imbalances ............. 98 (2,233) 729
Other ................................................. 3,492 (4,300) (840)
--------- --------- ---------
Net cash provided by operating activities .......... 165,788 83,434 46,006
--------- --------- ---------

Cash flows from investing activities:
Exploration ............................................... (109,282) (64,191) (32,914)
Development ............................................... (179,694) (112,639) (97,934)
Acquisition of properties ................................. (62,616) (6,686) (28,538)
Additions to other property and equipment ................. (5,769) (2,385) (1,441)
Net proceeds from the sale of assets ...................... 19,375 50,152 78,119
--------- --------- ---------
Net cash used in investing activities .............. (337,986) (135,749) (82,708)
--------- --------- ---------

Cash flows from financing activities:
Repayment of long-term debt ............................... (50,595) (274,831) (337,033)
Additions to total debt ................................... 176,421 176,932 345,298
Debt issue cost ........................................... (2,447) (251) (6,089)
Net proceeds from issuance of preferred stock ............. -- -- 34,906
Net proceeds from common stock offering ................... -- 182,670 --
Preferred stock dividends ................................. -- (1,531) (1,484)
Proceeds from common stock options and
warrants exercised ...................................... 5,566 10,682 2,865
--------- --------- ---------
Net cash provided by financing activities .......... 128,945 93,671 38,463
--------- --------- ---------

Net increase (decrease) in cash and cash equivalents ......... (43,253) 41,356 1,761
Cash and cash equivalents at beginning of period ............. 54,942 13,586 11,825
--------- --------- ---------
Cash and cash equivalents at end of period ................... $ 11,689 $ 54,942 $ 13,586
========= ========= =========

The accompanying notes are an integral part of these
consolidated financial statements

32
UNITED MERIDIAN CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 ORGANIZATION

The accompanying consolidated financial statements of United Meridian
Corporation (UMC or the Company), a Delaware corporation, have been prepared
pursuant to the rules and regulations of the Securities and Exchange Commission
(SEC).

The Company is an independent energy company engaged in the exploration,
development, production and acquisition of natural gas and crude oil across
North America and in the oil and natural gas producing regions of Cote d'Ivoire,
Equatorial Guinea, Pakistan and Bangladesh.

The consolidated 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

The consolidated financial statements include the accounts of the Company
and its majority-owned affiliates. Interests in joint ventures, limited
liability companies and partnerships are accounted for under the proportional
consolidation method. All significant intercompany balances and transactions
have been eliminated in consolidation.

Certain reclassifications of amounts previously reported have been made to
conform to current year presentation.

CASH AND CASH EQUIVALENTS

The Company considers all highly liquid investments with an original
maturity of three months or less when purchased to be cash equivalents.

INVENTORY

UMC conducts a portion of its oil and gas activities with a small group of
institutional and corporate investors. In connection therewith, the Company
periodically acquires oil and gas properties with the intention of selling a
portion of its interests to such investors. To the extent those properties are
to be resold to investors, costs are carried as a current asset and classified
as inventory. No gain or loss is recognized on inventoried properties. At
December 31, 1996, costs of properties to be resold included in inventory
totaled $2,270,000. The balance at December 31, 1997 was not significant. The
remaining inventory consists of tubular goods and other equipment.

OIL AND GAS PROPERTIES

The Company and its subsidiaries follow the successful efforts method of
accounting for oil and gas producing activities. Under this method, all costs to
acquire mineral interests in oil and gas properties, to acquire production
sharing contracts with foreign governments, to drill and equip exploratory wells
which find proved reserves and to drill and equip development wells are
capitalized. Geological and geophysical costs, delay rentals and technical
support costs are expensed as incurred except in those circumstances where the
Company has a contractual right to recover such costs from proved reserves, in
which case they are capitalized. Other internal costs related to oil and gas
acquisitions, exploration and development activities are generally expensed as
general and administrative, exploration or production expenses. The

-30-

costs of drilling exploratory wells which do not find proved reserves are
expensed upon determination that a well does not justify commercial development.
The capitalized costs of producing oil and gas properties are depreciated and
depleted by the units-of-production method based upon estimated proved reserves.
Unproved oil and gas properties are periodically assessed for impairment of
value and a loss is recognized as appropriate.

OTHER PROPERTY AND EQUIPMENT

Other property consists primarily of furniture, office equipment, leasehold
improvements and computers. The majority of these assets are depreciated on a
straight-line basis with useful lives of three to seven years.

GAS IMBALANCES

The Company follows the entitlements method of accounting for production
imbalances. Under this method, the Company recognizes revenues based on its
interest in production from a well. Imbalance payables are recorded at
historical amounts and imbalance receivables are valued at the lower of (i) the
price in effect at the time of production, (ii) the current market value or
(iii) the contract price net of selling expenses. Gas imbalances arise when a
purchaser takes delivery of more or less gas volume from a well than UMC's
actual interest in the production from that well. Such imbalances are reduced
either by subsequent recoupment of over and under deliveries or by cash
settlement, as required by applicable contracts. Under-deliveries are included
in Other Assets and over-deliveries are included in Deferred Credits and Other
Liabilities.

HEDGING

UMC periodically enters into contracts in order to hedge against the
volatility in oil and gas prices. The Company enters into such transactions for
the purpose of managing the overall impact of commodity price volatility. These
transactions generally take the form of swaps or price collars, and are placed
with major financial institutions. The results of such transactions are included
as Oil or Gas Sales in the Consolidated Statement of Income as the related
production volumes are sold.

The Company enters into interest rate hedge contracts from time to time
with major financial institutions. These transactions are made to protect
against higher future interest costs on the Company's floating rate long-term
debt. The results of interest rate hedges are included in Interest and debt
expense on the Consolidated Statement of Income.

FEDERAL INCOME TAXES

The Company follows the provisions of Statement of Financial Accounting
Standards (SFAS) No. 109, Accounting for Income Taxes, under which deferred tax
assets or liabilities are estimated at the financial statement date based upon
(i) temporary differences between the tax basis of assets and liabilities and
their reported amounts in the financial statements and (ii) net operating loss
and tax credit carryforwards for tax purposes.

EARNINGS PER SHARE

The Company adopted SFAS No. 128, Earnings Per Share, during the fourth
quarter of 1997. In accordance with this new pronouncement, basic earnings per
share is computed by dividing net income available to common stockholders by the
weighted average number of common shares outstanding during the period. Diluted
earnings per share is determined on the assumption that outstanding stock
options have been converted using the average price for the period. Prior period
amounts have been restated in accordance with the requirements of the
pronouncement.

STATEMENT OF CASH FLOWS

Cash flows from operating activities for 1997, 1996 and 1995, include cash
payments for interest of $18,013,000, $22,032,000, and $14,642,000 and income
taxes of $1,815,000, $446,000 and $553,000, respectively.

FOREIGN CURRENCY TRANSLATION

-31-

revenues, expenses, gains and losses are translated using the exchange rate for
the periods in which they occurred. The effect of such translations are
reflected as adjustments to stockholders' equity as shown in the Statement of
Changes in Stockholders' Equity in the Company's Consolidated Financial
Statements.

USE OF ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.

NOTE 3 CHANGES IN METHOD OF ACCOUNTING FOR ASSESSING RECOVERABILITY OF
PROVED OIL AND GAS PROPERTIES

During 1995, the Financial Accounting Standards Board issued SFAS No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of. The Company adopted the provisions of SFAS No. 121 and recorded
a pre-tax impairment of $8,317,000 (after-tax effect: $5,125,000) during the
fourth quarter of 1995. No such provision was required in 1996 or 1997.

NOTE 4 ACQUISITIONS AND DISPOSITIONS

As part of its on-going operations, the Company continually sells producing
and undeveloped reserves and related assets. Significant acquisitions and
dispositions for the years ending December 31, 1997, 1996 and 1995 are shown
below.

1997 TRANSACTIONS

In 1997, the Company acquired additional interests in various properties it
operates and in which it holds an existing working interest position from
several of its institutional partners. The net cost of the additional interests
acquired from the Company's institutional partners was approximately
$49,579,000. In addition, the Company acquired interests in other North American
properties for total consideration of $13,037,000.

During 1997, the Company sold various non-strategic North American
properties for total proceeds of $19,375,000, resulting in pre-tax gains of
$4,851,000.

1996 TRANSACTIONS

In 1995, the Company agreed to assign to Yukong Limited a portion of its
interests in Blocks CI-01 and CI-02 in Cote d'Ivoire and Blocks B, C and D in
Equatorial Guinea. Mobil subsequently exercised its preferential right to
purchase the interest in Block B in lieu of the proposed assignment to Yukong
Limited. Under the agreements, the Company received $40,135,000 in cash in 1996
and 1995, resulting in pre-tax gains of $15,774,000 and $18,278,000,
respectively.

In June 1996, UMC Resources Canada Ltd. (Resources), the Company's
wholly-owned Canadian subsidiary, sold all of its interest in the Rocanville
area in the province of Saskatchewan, effective May 1, 1996. Net proceeds from
the sale were $6,722,000 and a pre-tax gain of $4,679,000 was recognized.

In September 1996, the Company executed an agreement with Shell to sell a
55% contract interest in Block CI-105 in Cote d'Ivoire. The sale resulted in the
Company recognizing a pre-tax gain of $3,260,000 on cash proceeds of an
equivalent amount. An additional $900,000 was received relating to reimbursement
of exploration expense previously incurred by the Company.

During 1996, the Company sold various other non-strategic North American
properties, including Elk City and Arapaho fields, for total proceeds of
$22,093,000, resulting in pre-tax gains of $5,308,000.

1995 TRANSACTIONS

In February 1995, UMC sold all of its interest in oil and gas properties in
West Virginia, effective January 1, 1995. Net proceeds from the sale were
$41,200,000 and a pre-tax gain of $7,000,000 was recognized.

-32-

In March 1995, UMC sold all of its interest in the Main Pass 108 offshore
Louisiana field effective February 1, 1995. Net proceeds from the sale were
$6,900,000 with a recognized pre-tax gain of $4,700,000.

In October 1995, the Company and its institutional partners acquired
certain oil and natural gas properties at a cost of $58,626,000 (approximately
$21,300,000 net to the Company). The acquired interests relating to one of the
institutional partners (in an additional amount of approximately $10,250,000)
were included in inventory until January 1996, at which time the partner
reimbursed UMC for its proportionate share of the acquisition, including
carrying costs. A separate short-term facility was negotiated for the financing
of this interest in the properties and was paid at closing in January 1996.

NOTE 5 DEBT

Long-term debt consisted of the following at December 31, 1997 and 1996 (in
thousands):

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

Global Credit Facility.......................... $ 126,496 $ --
103/8% senior subordinated notes................ 150,000 150,000
Other........................................... 7,061 7,731
---------- ---------
283,557 157,731
Less: current maturities....................... (911) (899)
---------- ---------
Long-term debt.................................. $ 282,646 $ 156,832
========== =========

Current maturities at December 31, 1997 include the annual amortization of
the Other Long-Term Debt. The 103/8% Senior Subordinated Notes are due 2005.
Maturities of long-term debt by calendar year are as follows (in thousands):

1998........................................................ $ 911
1999........................................................ 911
2000........................................................ 911
2001........................................................ 911
2002........................................................ 127,407
Thereafter.................................................. 152,506
---------
$ 283,557
=========

GLOBAL CREDIT FACILITY

At the beginning of 1997, the Global Credit Facility provided a borrowing
base amount of $200,000,000. During March 1997, the Company expanded the Global
Credit Facility to $300,000,000 with an initial borrowing base of $275,000,000.
In November 1997, the borrowing base was increased to $300,000,000.

The Global Credit Facility, which is with a group of commercial banks,
currently consists of two parts: (i) a credit facility among UMC, certain of its
subsidiaries and certain lenders (the U.S. Lenders) pursuant to which the U.S.
Lenders agree to make a portion of the Global Credit Facility (subject to
Borrowing Base limitations) available to UMC (Credit Facility) and (ii) a credit
facility between UMC and certain lenders (the Canadian Lenders) pursuant to
which the Canadian Lenders agree to make the remaining part of the Global Credit
Facility (subject to aggregate Borrowing Base limitations under the Credit
Facility and a specific Canadian Borrowing Base sub-limit) available to UMC (the
Canadian Credit Facility). The amount of the Borrowing Base, which governs the
aggregate Global Credit Facility jointly under both the U.S. Credit Facility and
the Canadian Credit Facility, and the sub-limit on the portion of the Global
Credit Facility that will be made by the Canadian Lenders, are both determined
on an annual basis jointly by the U.S. Lenders and the Canadian Lenders.

The Global Credit Facility has a term of five years with amortization of the
Borrowing Base to begin in 1999, unless extended or modified by the Company and
the Lenders. At December 31, 1997, the Company had outstanding loans thereunder
of approximately $126,496,000.

During 1997, 1996 and 1995, the Global Credit Facility provided the Company
with various interest rate options based upon prime and LIBOR rates.

-33-

103/8% SENIOR SUBORDINATED NOTES

On October 30, 1995, the Company closed a public offering of $150,000,000 of
103/8% Senior Subordinated Notes (Notes) due 2005 at an initial price of 99.5%
of face value. Proceeds of $144,933,000 (after deducting underwriting discounts,
commission and expenses of the offering) were used to reduce debt under the
Global Credit Facility. Interest is payable semiannually on April 15 and October
15 of each year, commencing April 15, 1996. The Notes are general unsecured
senior obligations of the Company and are guaranteed by UMC Petroleum
Corporation (Petroleum) but are subordinate to the Global Credit Facility (see
Note 19). The Notes are redeemable at the option of the Company, in whole or in
part, at anytime after October 15, 2000 at certain premiums to face value.

OTHER LONG-TERM DEBT

Havre Pipeline Company LLC, a limited liability corporation in which the
Company had a 56% interest at December 31, 1997, has previously entered into a
Credit Agreement which provided a Term Loan due September 30, 2005. The
Company's proportionate share outstanding at December 31, 1997 is $7,061,000,
including current maturities. Principal installments are due at the end of each
quarter. Additional principal payments may be required under the Credit
Agreement if operating cash flows of the limited liability corporation exceed
predetermined levels.

OTHER DISCLOSURES

During 1996 and 1995, $2,109,000 and $1,049,000, respectively, of total
interest incurred was capitalized. No interest was capitalized in 1997.

Effective January 18, 1994, UMC entered into five-year fixed LIBOR interest
rate swap contracts that provide for fixed interest rates to be realized on
notional amounts totaling $45,000,000 from 1995 through 1998. The agreement
includes varying annual fixed interest rates ranging from 3.66% in 1994 to 6.40%
in 1998, plus interest rate margins. In 1995 and 1996, the Company had in place
a two-year LIBOR interest rate cap contract on an additional notional amount of
$45,000,000 at interest rate caps of 7.60% and 8.30%, respectively, plus
interest rate margins.

The Company's actual average interest rate for 1997, 1996 and 1995 was
9.46%, 9.17% and 7.47%, respectively. Additionally, a facility fee of 0.25% to
0.375% per annum on the unused portion of the Global Credit Facility is payable
quarterly by UMC.

NOTE 6 CAPITAL STOCK

COMMON STOCK

The authorized shares of Series A Voting Common Stock and Series B Nonvoting
Common Stock at December 31, 1997, and December 31, 1996, were 45,000,000 and
1,000,000, respectively. Of the 1,000,000 shares of Series B stock authorized,
none were outstanding at December 31, 1997 and 1996.

On June 11, 1993, the Company issued warrants to purchase 250,004 shares of
the Company's Common Stock in connection with the acquisition of KPX, Inc. The
exercise price of the warrants was $15.36 per share for a three year term ending
June 11, 1996. During 1996, proceeds of $3,621,000 for the exercise of warrants
were received and 235,749 shares of common stock were issued. The remaining
unexercised warrants expired in June 1996.

On February 14, 1996, the Company granted one shareholder's right (Rights)
for each share of Series A Voting Common Stock to holders of record at the close
of business on February 29, 1996. The Rights will automatically become part of
and trade with existing and future shares of UMC's Series A Voting Common Stock.
As amended in September 1997, the Rights will become exercisable only in the
event, with certain exceptions, an acquiring party accumulates 10% or more of
UMC's voting stock, or if a party announces an offer to acquire 30% or more of
UMC's voting stock. No separate right certificates will be issued until after
these thresholds are met. The Rights will expire on February 28, 2006. Each
Right will entitle the holder, other than the acquiring party, to purchase
either United Meridian Corporation stock or shares in an "acquiring entity" at a
50% discount to the then current market value. The Company generally will be
entitled to redeem the Rights at $0.01 per Right at any time until the tenth day
following the acquisition of a 10% position in its voting stock.

-34-

During November 1996, the Company completed an offering of 4,088,942 shares
of the Company's Series A Voting Common Stock and received $182,670,000 in
proceeds after underwriting fees and offering expenses.

The following table summarizes the calculation of annual weighted average
common shares outstanding for purposes of the computations of earnings per share
(in thousands):

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

Shares outstanding from beginning of period........................... 35,217 28,150 27,722

Exercise of stock options and warrants................................ 373 561 213

Conversion of Series F Preferred Stock ............................... -- 802 --

Common Shares issued in connection with the November 1996
offering of common stock........................................... -- 607 --
------ ------ ------

Weighted average number of common shares outstanding.................. 35,590 30,120 27,935

Common Stock equivalents of:
Series F Preferred Stock........................................... -- * *
Stock options and warrants......................................... 1,072 1,308 1,324
------ ------ ------

Weighted average number of common shares and
common share equivalents outstanding............................... 36,662 31,428 29,259
====== ====== ======

* Not included in computation for the period because it is antidilutive.

SERIES F CONVERTIBLE PREFERRED STOCK

In June and July 1995, the Company sold an aggregate $35,000,000 of Series
F Convertible Preferred Stock in a private placement to institutional investors.
The Series F Convertible Preferred Stock had an 8.75% cumulative dividend,
payable quarterly commencing on September 30, 1995. A total of 1,166,667
authorized shares were sold at $30 per share. On July 25, 1996, the Company
converted $35,000,000 of Series F Convertible Preferred Stock to 1,845,000
shares of common stock in accordance with the automatic conversion terms of the
original private offering. The conversion eliminates the 8.75% dividend on the
preferred stock. Had the conversion of the Series F Convertible Preferred Stock
occurred at January 1, 1996, the reported basic and diluted earnings per share
would have been $0.56 and $0.54, respectively for the year ended December 31,
1996.

-35-

NOTE 7 INCOME TAXES

Under the provisions of SFAS No. 109, the components of the net deferred
income tax assets and liabilities recognized in the Company's Consolidated
Balance Sheet at December 31, 1997 and 1996, were as follows (in thousands):

1997 1996
------------------------------------------ --------------------------------------------
FEDERAL FOREIGN STATE TOTAL FEDERAL FOREIGN STATE TOTAL
-------- -------- -------- -------- -------- -------- ------- ---------

Deferred tax assets -
Net operating loss
carryforward................ $ 29,715 $ 16,774 $ 4,011 $ 50,500 $ 34,177 $ 13,115 $ 4,520 $ 51,812
Percentage depletion
carryforward................ 2,508 -- 131 2,639 2,333 -- 229 2,562
Investment tax credit
carryforward................ 989 -- -- 989 1,720 -- -- 1,720
Alternative minimum tax
credit carryforward......... 3,964 -- -- 3,964 3,662 -- -- 3,662
Deferred foreign tax
credit carryforward......... 9,209 -- -- 9,209 3,790 -- -- 3,790
Other......................... 79 -- 4 83 50 -- 4 54
Valuation allowance........... (2,971) -- (70) (3,041) (3,551) -- (151) (3,702)
-------- -------- -------- -------- -------- -------- ------- --------
43,493 16,774 4,076 64,343 42,181 13,115 4,602 59,898
-------- -------- -------- -------- -------- -------- ------- --------
Deferred tax liabilities -
Excess of basis in oil
and gas properties
for financial reporting
purposes over the tax
basis....................... 21,135 41,230 4,029 66,394 15,551 33,912 4,042 53,505
Other......................... 1,186 -- 75 1,261 1,186 -- 130 1,316
-------- -------- -------- -------- -------- -------- ------- --------
22,321 41,230 4,104 67,655 16,737 33,912 4,172 54,821
-------- -------- -------- -------- -------- -------- ------- --------
Net deferred tax asset
(liability)................. 21,172 (24,456) (28) (3,312) 25,444 (20,797) 430 5,077
Current portion of deferred
tax assets classified as
current asset................. 1,365 -- 182 1,547 2,836 -- 3 2,839
-------- -------- -------- -------- -------- -------- ------- --------
Total non-current deferred tax
asset (liability)............. $ 19,807 $(24,456) $ (210) $ (4,859) $ 22,608 $(20,797) $ 427 $ 2,238
======== ======== ======== ======== ======== ======== ======= ========

As of December 31, 1997 and 1996, the Company and its subsidiaries had U.S.
federal net operating loss (NOL) carryforwards of approximately $84,900,000 and
$98,000,000, respectively, and Equatorial Guinea NOL carryforwards of
approximately $67,000,000 and $52,000,000, respectively. The Company's Canadian
subsidiary also had $32,200,000 and $17,600,000 in Canadian Tax Pool
carryforwards as of December 31, 1997 and 1996, respectively.

The Company is subject to taxation under the laws of Cote d'Ivoire and
Equatorial Guinea and other foreign jurisdictions. Income taxes in these
jurisdictions will be taken as a credit or deduction against the Company's
United States tax liability.

Management believes the Company will realize the benefit of all NOLs.
Accordingly, the Company has recognized a deferred tax asset relating to these
carryforwards. The U.S. federal NOLs expire as follows (in thousands):

1998................................................................ $ --
1999................................................................ 400
2000................................................................ 23,900
2001................................................................ 16,500
2002................................................................ 6,300
2003................................................................ 1,200
2004................................................................ 19,400
2005................................................................ 3,200
Beyond 2005......................................................... 14,000
-----------
$ 84,900
===========

-36-

39
For federal income tax purposes, certain limitations are imposed on an
entity's ability to utilize its NOLs in future periods if a "change of control",
as defined for federal income tax purposes, has taken place. In general terms,
the limitation on utilization of NOLs and other tax attributes during any one
year is determined by the value of an acquired entity at the date of the "change
of control" multiplied by the then-existing long-term, tax-exempt interest rate.
The manner of determining an acquired entity's "value" has not yet been
addressed by the Internal Revenue Service. The Company has determined that, for
federal income tax purposes, a "change of control" occurred in 1994 as a result
of the stock purchases made by the Company's shareholders in 1994 and in
previous years, and future utilization of NOLs will be limited in the manner
described above. The use of NOLs acquired as a result of corporate acquisitions
prior to 1994 were already subject to limitations computed at the time of each
acquisition. While the effect of such limitations may be to defer the use of
existing NOL carryforwards, the Company does not believe such limitations will
impact the Company's ability to fully utilize the NOLs.

As of December 31, 1997 and 1996, the Company and its subsidiaries had
investment tax credit carryforwards of approximately $1,000,000 and $1,700,000,
respectively. To the extent not utilized, these carryforwards will expire in the
years 1998 through 2001. For purposes of computing the net deferred tax
liability as of December 31, 1997 and 1996, none of these carryforwards were
utilized.

The components of the Income tax provision (benefit) recognized on the
Consolidated Statement of Income are as follows (in thousands):

1997 1996 1995
------- ------- --------

Current taxes -
Federal ......................... $ 169 $ 455 $ 340
Foreign ......................... 4,716 98 (370)
State ........................... 1,335 232 362
------- ------- ------
6,220 785 332
------- ------- ------
Deferred taxes -
Federal ......................... 8,664 3,136 (2,762)
Foreign ......................... 4,333 3,496 (339)
State ........................... 458 (1,401) (1,116)
------- ------- ------
13,455 5,231 (4,217)
------- ------- ------
Total income tax provision (benefit) $19,675 $ 6,016 (3,885)
======= ======= =======

The following is a reconciliation of the income tax provision (benefit)
computed by applying the federal statutory income tax rate to net income (loss)
before income taxes to the Income tax provision (benefit) shown on the
Consolidated Statement of Income (in thousands):

1997 1996 1995
-------- ------- --------

Income tax provision (benefit) computed at the
federal statutory rate of 35% .............................. $13,812 $8,197 $ (625)
State and local taxes (net of federal effect) .................. 1,280 (760) (490)
Foreign income taxes (net of federal effect) ................... 2,977 -- --
Tax effect of:
Provision (benefit) for net book deductions not
available for tax due to differences in book/tax
basis ................................................... 1,490 1,169 (927)
Excess of taxes on foreign income over federal
statutory rate .......................................... 43 291 165
Provision (benefit) resulting from adjustments
from estimate to actual in estimating taxable income .... 459 (2,139) (181)
Benefit of deferred foreign tax credit carryforward ........ -- -- (1,138)
Alternative minimum tax credit carryforward benefit ........ (151) (193) (321)
Other ...................................................... (235) (549) (368)
------- ------ -------
Income tax provision (benefit) ................................. $19,675 $6,016 $(3,885)
======= ====== =======

-37-
40

NOTE 8 EMPLOYEE BENEFIT PLANS

STOCK OPTION PLANS

At December 31, 1997, UMC had three non-qualified stock option plans:

AUTHORIZED AVAILABLE
SHARES OUTSTANDING FOR ISSUANCE
--------- ----------- ------------

1987 Employee Plan........................................ 1,700,000 583,749 -
1994 Employee Plan........................................ 4,050,000 1,974,906 1,149,357
1994 Outside Directors Plan............................... 250,000 150,000 97,000
--------- --------- ---------
6,000,000 2,708,655 1,246,357
========= ========= =========

The two 1994 plans were approved by the shareholders of the Company on May
17, 1994, and have been subsequently amended to increase the number of
authorized shares under the plans. The plans were further amended during 1997 to
allow transferability of stock options to family members and eliminate forced
termination of stock options in the event of a change in control.

The plans provide that directors, officers and key employees may be awarded
options to purchase Common Stock of the Company at a price equal to the market
value of UMC Common Stock on the award date. Options generally vest over a
five-year period. The following table reflects summarized information about
stock options outstanding at December 31, 1997:

Options Outstanding Options Exercisable
------------------------------------------------- --------------------------------
Weighted
Average Weighted Weighted
Number Remaining Average Number Average
Range of Outstanding Contractual Exercise Exercisable Exercise
Exercise Price at 12/31/97 Life (in years) Price at 12/31/97 Price
-------------- ----------- --------------- --------- ----------- --------

$2.75 to $6.64 ....... 310,615 3.3 $ 4.77 310,615 $ 4.77
$9.875 to $15.50 ..... 1,235,540 5.6 12.42 766,824 11.68
$17.50 to $23.875 .... 366,000 9.2 23.62 7,500 17.88
$27.00 to $38.00 ..... 539,500 10.2 30.99 11,000 29.50
$44.125 to $47.50 .... 257,000 9.8 44.19 188,500 44.13
--------- ---------
2,708,655 1,284,439
========= =========

-38-

A summary of actual options granted and exercised follows:

1997 1996 1995
--------- ----------- ----------

Option shares outstanding -
Beginning of year 2,808,181 3,148,612 3,185,065
Granted 517,000 683,000 446,000
Exercised (574,261) (897,999) (428,354)
Canceled (42,265) (125,432) (54,099)
--------- --------- ---------
End of year ........................................ 2,708,655 2,808,181 3,148,612
========= ========= =========

Shares available for grant at end of year ................. 1,246,357 521,091 478,659
Shares exercisable at end of year ......................... 1,284,439 1,472,474 2,070,664
Average price of options exercised
during the year......................................... $ 10.44 $ 7.88 $ 6.69
Average exercise price of options
outstanding at end of year.............................. $ 19.77 $ 15.82 $ 10.05
Weighted average fair value of options
granted during the year................................. $ 18.30 $ 16.93 $ 7.33
Weighted average exercise price for
options granted during the year......................... $ 31.06 $ 31.64 $ 13.47

The Company accounts for these plans under APB Opinion No. 25, Accounting
for Stock Issued to Employees, under which no compensation cost has been
recognized. Had compensation cost for these plans been determined consistent
with SFAS 123, Accounting for Stock-Based Compensation, the Company's reported
net income and earnings per share would have been adjusted to the following pro
forma amounts (in thousands, except per share amounts):

FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
-------- -------- ------

Net Income: As Reported $19,787 $17,404 $2,099
Pro Forma - Basic $17,018 $14,487 $1,769
Pro Forma - Diluted $16,960 $14,458 $1,757

Basic EPS: As Reported $ 0.56 $ 0.53 $ 0.02
Pro Forma $ 0.48 $ 0.43 $ 0.01

Diluted EPS: As Reported $ 0.54 $ 0.51 $ 0.02
Pro Forma $ 0.46 $ 0.43 $ 0.01

The fair value of each option is estimated on the date of grant using the
Black-Scholes option pricing model, with the following assumptions used for
grants in 1997 and 1996, respectively; risk-free interest rates of 6.16% to
6.83% and 5.40% to 6.76%; expected dividend yields of 0% and 0%; expected lives
of 6.5 years and 6.5 years; and, expected volatility of 54.13% and 39.34% to
43.14%.

SAVINGS PLAN

The Company maintains a defined contribution savings plan for the benefit of
its U.S. employees. Under the Plan, employees may contribute up to 16% of their
base salary to a trust for investments (including UMC stock) selected by each
participating employee. The Company makes a matching contribution of 75% up to a
participant's contribution of 8% of total compensation paid, resulting in a
maximum Company contribution of 6% of salary. During 1997, the Company made an
additional discretionary contribution of 2% to plan participants subject to
limitations imposed by the Internal Revenue Service.

During 1997, 1996 and 1995, the Company made contributions to the Plan on
behalf of all participants totaling $872,000, $780,000 and $696,000,
respectively.

- 39 -

Resources maintains a separate group savings plan for its employees. During
1997, 1996 and 1995, this subsidiary contributed $76,000, $67,000 and $63,000,
respectively, to the Plan for the benefit of its employees.

NOTE 9 COMMITMENTS AND CONTINGENCIES

The Company has entered into operating leases for office space and equipment
for which $2,222,000, $1,174,000 and $1,547,000 in rental expense has been
included in the accompanying financial statements for the years ended December
31, 1997, 1996 and 1995, respectively. Future minimum rental payments required
for the years ending December 31, 1998 through 2002 are $1,803,000, $1,692,000,
$1,436,000, $1,351,000 and $1,279,000, respectively.

Resources has an agreement with Nova Corporation, a natural gas pipeline
company, to transport specified quantities of natural gas. Future minimum
transportation expense payments required for years ending December 31, 1998
through 2002 are $251,000, $157,000, $55,000, $55,000 and $55,000, respectively.

The Company has entered into agreements for transportation of natural gas
across Canada for sales to the Great Lakes region for up to 35 MMCFD expiring at
various dates through 2002 and 8 MMCFD expiring in 2007. Future minimum
transportation expense payments required for years ending December 31, 1998
through 2002 are $4,972,000, $3,149,000, $3,149,000, $3,149,000 and $2,900,000,
respectively.

NOTE 10 OIL AND GAS PROPERTY COSTS

Capitalized costs at December 31, 1997 and 1996 relating to the Company's
oil and gas activities are shown below (in thousands):

EQUATORIAL
GUINEA
UNITED COTE AND OTHER
STATES CANADA D'IVOIRE FOREIGN TOTAL
------ ------ ---------- ---------- ----------

AS OF DECEMBER 31, 1997
Proved Properties ................... $669,315 $ 109,842 $ 124,994 $ 206,726 $1,110,877
Unproved oil and gas interests ...... 31,543 48 1,072 1,875 34,538
-------- ---------- ---------- ---------- ----------
Total capitalized costs ......... 700,858 109,890 126,066 208,601 1,145,415
Less: Accumulated depreciation,
depletion and amortization ........ 338,540 30,182 20,696 23,546 412,964
-------- ---------- ---------- ---------- ----------
Net capitalized costs ........... $362,318 $ 79,708 $ 105,370 $ 185,055 $ 732,451
======== ========== ========== ========== ==========
AS OF DECEMBER 31, 1996
Proved properties ................... $590,879 $ 92,545 $ 72,590 $ 95,804 $ 851,818
Unproved oil and gas interests ...... 12,656 50 1,072 889 14,667
-------- ---------- ---------- ---------- ----------
Total capitalized costs ......... 603,535 92,595 73,662 96,693 866,485
Less: Accumulated depreciation,
depletion and amortization ........ 309,401 25,792 7,006 2,884 345,083
-------- ---------- ---------- ---------- ----------
Net capitalized costs ........... $294,134 $ 66,803 $ 66,656 $ 93,809 $ 521,402
======== ========== ========== ========== ==========

-40-

Costs incurred during 1997, 1996 and 1995 in the Company's oil and gas
activities were as follows (in thousands):

EQUATORIAL
GUINEA
UNITED COTE AND OTHER
STATES CANADA D'IVOIRE FOREIGN TOTAL
-------- --------- --------- ---------- -------

YEAR ENDED DECEMBER 31, 1997
Property acquisition costs:
Proved ..................... $ 53,062 $ 9,554 $ -- $ -- $ 62,616
Unproved ................... 15,299 2,423 -- -- 17,722
Exploration costs .............. 25,825 6,263 16,240 94,326 142,654
Development costs .............. 53,163 9,308 23,462(1) 36,842 122,775
-------- -------- -------- -------- --------
Total costs incurred ....... $147,349 $ 27,548 $ 39,702(1) 131,168 $345,767
======== ======== ======== ======== ========

YEAR ENDED DECEMBER 31, 1996
Property acquisition costs:
Proved ..................... $ 6,239 $ 447 $ -- $ -- $ 6,686
Unproved ................... 4,277 865 -- 457 5,599
Exploration costs .............. 28,943 2,370 9,219 30,882 71,414
Development costs .............. 36,057 4,572 9,369 56,707 106,705
-------- -------- -------- -------- --------
Total costs incurred ....... $ 75,516 $ 8,254 $ 18,588 $ 88,046 $190,404
======== ======== ======== ======== ========

YEAR ENDED DECEMBER 31, 1995
Property acquisition costs:
Proved ..................... $ 24,819 $ 376 $ -- $ -- $ 25,195
Unproved ................... 3,032 311 -- -- 3,343
Exploration costs .............. 21,561 1,599 2,912 11,948 38,020
Development costs .............. 31,252 2,519 42,900 19,798 96,469
-------- -------- -------- -------- --------
Total costs incurred ....... $ 80,664 $ 4,805 $ 45,812 $ 31,746 $163,027
======== ======== ======== ======== ========

- ------------------------------
(1) Amounts do not include $17,229 incurred on a LPG plant in Cote d'Ivoire.

NOTE 11 RELATED PARTY TRANSACTIONS

UMC currently conducts a portion of its oil and gas activities in
conjunction with a group of institutional and corporate investors that
participate in UMC's acquisition, development and exploration programs, and
provide the Company with certain carried interests and management fees.
Management fee income of $2,954,070, $1,826,000 and $1,286,000, related to the
years ended December 31, 1997, 1996 and 1995, respectively, is included on the
Consolidated Statement of Income.

UMC and a company controlled by a former director of UMC are each 40% owners
of Energy Arrow Exploration L.L.C. (Arrow). Total UMC payments to Arrow in 1997,
1996 and 1995 were $82,000, $5,309,000 and $2,477,000, respectively, most of
which related to lease acquisitions, seismic and drilling costs.

UMC also conducts normal joint interest operations with Brigham Oil & Gas LP
(Brigham), a partnership owned in part by General Atlantic Partners LLC for
which a former director of UMC acts as Executive Managing Member. Total payments
to Brigham for the operation of jointly owned properties operated by Brigham
during 1997, 1996 and 1995 were $782,000, $430,000 and $75,000, respectively. At
December 31, 1997 and 1996, UMC's net receivable from Brigham was $275,000 and
$329,000, respectively. At December 31, 1995, UMC's net receivable from Brigham
was less than $100,000.

In 1996, UMC executed agreements with various entities controlled by two
former directors of UMC covering co- ventures in Pakistan, Bangladesh and
possible other international exploration opportunities.

All transactions with the aforementioned entities are under normal industry
terms and conditions.

NOTE 12 LITIGATION AND CLAIMS

-41-

was filed in the District Court of Harris County, Texas, 164th Judicial District
by another person claiming to represent the stockholders of UMC against UMC and
each of its directors. Among other things, the complaints seek to (i)
preliminarily and permanently enjoin the Merger, (ii) require the UMC directors
to maximize stockholder value by placing UMC up for auction and/or to conduct a
"market-check", (iii) require the defendants to make a full and fair disclosure
of all material facts to the class members before the consummation of the
Merger, (iv) rescind the Merger should it be consummated prior to the resolution
of the lawsuit and/or (v) recover unspecified damages and costs from the UMC
directors for the alleged breach of their fiduciary duties.

Management of UMC believes that the complaints are without merit and intends
to vigorously defend the actions.

The U.S. Environmental Protection Agency has indicated that the Company may
be potentially responsible for costs and liabilities associated with alleged
releases of hazardous substances at two sites in Louisiana under the
Comprehensive Environmental Response, Compensation and Liability Act. Given the
extremely large number of companies that have been identified as potentially
responsible for releases of hazardous substances at the sites and the small
volume of hazardous substances allegedly disposed of by the companies whose
properties the Company acquired, management believes that the Company's
potential liability arising from these sites, if any, will not have a material
adverse impact on the Company.

The Company is a named defendant in lawsuits and is a party in governmental
proceedings from time to time arising in the ordinary course of business. While
the outcome of such lawsuits or other proceedings against the Company cannot be
predicted with certainty, management does not expect these matters to have a
material adverse effect on the financial position or results of operations of
the Company.

NOTE 13 MAJOR CUSTOMERS

The Company markets its oil and gas production to numerous purchasers under
a combination of short and long-term contracts. During 1997 and 1996, Mobil
Sales and Supply Corporation accounted for 31% and 10%, respectively, of the
Company's oil and gas revenues as the purchaser of the Company's production in
Equatorial Guinea. In addition, during 1997 and 1996, H&N Gas Limited Inc.
accounted for 6% and 16%, respectively, of the Company's oil and gas revenues.
During 1997, 1996 and 1995, the Company had no other purchasers that accounted
for greater than 10% of its oil and gas revenues. The Company believes that the
loss of any single customer would not have a material adverse effect on the
results of operations of the Company. .

NOTE 14 GAS CONTRACT SETTLEMENTS

From time to time, the Company has had disagreements with certain purchasers
of the Company's natural gas production concerning the contractual obligations
of such purchasers to take specified quantities of gas at contract prices. In
order to resolve such disagreements, the Company has entered into gas contract
settlements, wherein, for a nonrefundable cash payment, the Company has released
the purchaser from its contractual obligations and, in some cases, the contract
itself. During 1997, 1996 and 1995, contract settlements of $59,000, $266,000
and $1,872,000, respectively, were included in revenues.

NOTE 15 CREDIT RISK AND PRICE PROTECTION AGREEMENTS

TRADE RECEIVABLES AND PAYABLES

Substantially all of the Company's accounts receivable at December 31, 1997,
result from oil and gas sales and joint interest billings to other companies in
the oil and gas industry and institutional partners. This concentration of
customers and joint interest owners may impact the Company's overall credit
risk, either positively or negatively, in that these entities may be similarly
affected by industry-wide changes in economic or other conditions. Receivables
from oil and gas sales are generally not collateralized. Credit losses incurred
by the Company on receivables generally have not been significant in prior
years.

OIL AND GAS MARKET HEDGES

The Company's revenues are primarily the result of sales of its oil and
natural gas production. Market prices of oil and natural gas fluctuate and may
adversely affect operating results. To mitigate this risk, the Company has, from
time to time, entered into crude oil and natural gas price hedging contracts to
reduce its exposure to price reductions on its production.
-42-

These transactions have been entered into with major financial institutions,
thereby minimizing credit risk. The Company hedged a portion of its natural gas
and oil production in 1997, 1996 and 1995, the results of which were included in
natural gas or oil revenues.

At December 31, 1996, the Company had oil collar contracts on 200,000
barrels of oil per month for January 1997 through June 1997, with a "floor"
price of $21.00 and an average "cap" price of $24.69. UMC's hedging agreements
are generally settled on a monthly basis and specify the third-party index to be
the New York Mercantile Exchange (NYMEX) futures contract prices for the
applicable commodity, matching the appropriate basis risk. There was no deferred
hedge gain or loss for crude oil at year end 1996. No contracts were in place at
December 31, 1997.

INTEREST RATE MARKET HEDGES

UMC has interest rate hedge contracts currently outstanding. The hedge
transactions have been entered into with major financial institutions,
minimizing credit risk associated with these agreements. See Note 5 for further
discussion of these contracts.

NOTE 16 FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company's financial instruments consist of cash and cash equivalents,
short-term trade receivables and payables, long-term debt, interest rate hedging
agreements and natural gas and crude oil hedging agreements. As of December 31,
1997 and 1996, the fair market values of the Company's financial instruments are
shown below:

CASH, TRADE RECEIVABLES AND PAYABLES: The carrying amount approximates fair
market value due to the highly liquid nature of these short-term instruments.

LONG-TERM DEBT: As of December 31, 1997, the carrying amount of the Notes
was $150,000,000 and the fair value was $164,250,000. As of December 31, 1996,
the fair value of the Notes was $163,875,000. The fair value was estimated based
on the market price of the publicly traded Notes. As of December 31, 1997 and
1996, the carrying amount of UMC's Global Credit Facility approximates fair
value due to the nature of the facility, whereby the interest rates offered by
the member banks are floating rates which reflect market rates.

INTEREST RATE HEDGING AGREEMENTS: The fair market value of the interest rate
swap contracts at December 31, 1997 and 1996 was ($297,000) and ($254,000),
respectively. The fair market value at December 31, 1997 and 1996 was determined
by the institutional holders of the hedges.

NATURAL GAS AND CRUDE OIL HEDGING AGREEMENTS: The fair market value of the
natural gas and crude oil swap contracts at December 31, 1996 were approximately
($942,000), as determined by the institutional holders of the hedges. No such
contracts were outstanding at December 31, 1997.

-43-

NOTE 17 GEOGRAPHIC DATA

UMC is an independent oil and gas company engaged in the exploration,
development, production and acquisition of oil and natural gas properties.
Information about the Company's operations by geographic area for the years
ended December 31, 1997, 1996, and 1995 is as follows (in thousands):

EQUATORIAL
GUINEA
AND OTHER
UNITED STATES CANADA COTE D'IVOIRE INTERNATIONAL TOTAL
-------------- ------------ ------------- ------------- -------------

YEAR ENDED DECEMBER 31, 1997
Revenues........................ $ 138,933 $ 19,268 $ 27,803 $ 78,861 $ 264,865
Depreciation, depletion
and amortization.............. $ 54,555 $ 7,251 $ 13,773 $ 20,839 $ 96,418
Operating profit ............... $ 20,412 $ 978 $ 4,025 $ 34,115 $ 59,530
Capital expenditures............ $ 154,165 $ 27,832 $ 56,931 $ 131,168 $ 370,096
Identifiable assets............. $ 749,470 $ 69,485 $ 7,965 $ 58,105 $ 885,025
YEAR ENDED DECEMBER 31, 1996
Revenues........................ $ 150,248 $ 23,011 $ 25,940 $ 37,205 $ 236,404
Depreciation, depletion
and amortization.............. $ 66,832 $ 9,482 $ 5,689 $ 2,976 $ 84,979
Operating profit................ $ 14,516 $ 4,318 $ 13,243 $ 14,998 $ 47,075
Capital expenditures............ $ 75,516 $ 8,254 $ 18,588 $ 88,046 $ 190,404
Identifiable assets............. $ 586,410 $ 65,167 $ 21,279 $ 45,437 $ 718,293
YEAR ENDED DECEMBER 31, 1995
Revenues........................ $ 107,112 $ 16,922 $ 7,106 $ 15,901 $ 147,041
Depreciation, depletion
and amortization.............. $ 44,265 $ 8,208 $ 1,420 $ 49 $ 53,942
Impairment of proved oil
and gas properties............ $ 8,317 $ - $ - $ - $ 8,317
Operating profit (loss)......... $ 2,269 $ (125) $ 502 $ 13,138 $ 15,784
Capital expenditures............ $ 80,664 $ 4,805 $ 45,812 $ 31,746 $ 163,027
Identifiable assets............. $ 392,490 $ 80,151 $ 77,875 $ 27,934 $ 578,450

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

NOTE 18 DISCLOSURES OF OIL AND GAS OPERATIONS (UNAUDITED)

PROVED RESERVES

Substantially all reserve estimates presented herein were prepared by either
Ryder Scott Company, Netherland, Sewell & Associates, Inc., or McDaniel &
Associates Consultants Ltd., independent petroleum engineers. The Company
cautions that there are many uncertainties inherent in estimating proved reserve
quantities, in projecting future production rates and in the timing of future
development expenditures. In addition, reserve estimates of new discoveries are
more imprecise than those of properties with a production history. Accordingly,
these estimates are subject to change as additional information becomes
available.

Proved oil and gas reserves are the estimated quantities of crude oil,
condensate, natural gas and natural gas liquids that 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 oil and gas reserves are those reserves expected to be recovered
through existing wells with existing equipment and operating methods.

Information presented for the Company's international locations relates to
contract interests held in multiple production sharing contracts between the
Company, its joint venture partners and the governments of Cote d'Ivoire and
Equatorial Guinea. The Company has no ownership interest in the oil and gas
reserves but does have the right to share revenues and/or production and is
entitled to recover most field and other operating costs. The reserve estimates
are subject to revision as prices fluctuate due to the cost recovery feature
under the production sharing contract.

-44-

47
Net quantities of proved reserves and proved developed reserves of crude oil
(including condensate and natural gas liquids) and natural gas, as well as the
changes in proved reserves during the periods indicated, are set forth in the
tables below:

UNITED COTE EQUATORIAL
STATES CANADA D'IVOIRE GUINEA TOTAL
------ ------ -------- ----------- -------

NATURAL GAS (MMCF)
PROVED:
December 31, 1994............................................... 338,965 67,835 32,612 - 439,412
Revisions of previous estimates............................... 4,655 (1,060) 5,746 - 9,341
Extensions, discoveries and other additions................... 35,558 2,060 58,290 - 95,908
Purchases..................................................... 21,839 - - - 21,839
Sales of reserves-in-place.................................... (68,113) (1,014) (13,995) - (83,122)
Production.................................................... (38,878) (5,383) (192) - (44,453)
--- ----- ------- ------ ------- ------- -------
December 31, 1995............................................... 294,026 62,438 82,461 - 438,925
Revisions of previous estimates............................... 19,705 (3,764) 7,848 - 23,789
Extensions, discoveries and other additions................... 22,900 8,567 2,488 - 33,955
Purchases..................................................... 17,869 894 - - 18,763
Sales of reserves-in-place.................................... (9,249) (15) - - (9,264)
Production.................................................... (47,719) (5,339) (2,387) - (55,445)
--- ----- ------- ------ ------- ------- -------
December 31, 1996............................................... 297,532 62,781 90,410 - 450,723
Revisions of previous estimates............................... 26,491 533 14,174 - 41,198
Extensions, discoveries and other additions................... 14,912 21,102 3,370 - 39,384
Purchases..................................................... 41,876 21,377 33,275 - 96,528
Sales of reserves-in-place.................................... (12,474) (301) - - (12,775)
Production.................................................... (42,238) (7,630) (4,939) - (54,807)
------- ------ ------- ------- -------
December 31, 1997............................................... 326,099 97,862 136,290 - 560,251
======= ====== ======= ======= =======

PROVED DEVELOPED:
December 31, 1995............................................... 245,860 62,438 21,722 - 330,020
======= ====== ====== ======= =======
December 31, 1996............................................... 245,847 62,781 21,433 - 330,061
======= ====== ====== ======= =======
December 31, 1997............................................... 272,239 97,862 40,313 - 410,414
======= ====== ====== ======= =======

UNITED COTE EQUATORIAL
STATES CANADA D'IVOIRE GUINEA TOTAL
------ ------ -------- ----------- -----

CRUDE OIL (MBO)
PROVED:
December 31, 1994 ................................ 12,478 5,563 4,626 -- 22,667
Revisions of previous estimates ................ 1,099 (201) 1,905 -- 2,803
Extensions, discoveries and other additions .... 801 151 1,440 5,258 7,650
Purchases ...................................... 4,757 -- -- -- 4,757
Sales of reserves-in-place ..................... (762) (82) (332) (1,502) (2,678)
Production ..................................... (1,826) (649) (285) -- (2,760)
------- ------- ------- ------- -------
December 31, 1995 ................................ 16,547 4,782 7,354 3,756 32,439
Revisions of previous estimates ................ 2,805 (297) (2,538) 1,564 1,534
Extensions, discoveries and other additions .... 101 530 228 15,587 16,446
Purchases ...................................... 100 4 -- -- 104
Sales of reserves-in-place ..................... (590) (1,009) -- -- (1,599)
Production ..................................... (2,022) (511) (894) (967) (4,394)
------- ------- ------- ------- -------
December 31, 1996 ................................ 16,941 3,499 4,150 19,940 44,530
Revisions of previous estimates ................ 30 192 854 441 1,517
Extensions, discoveries and other additions .... 2,140 181 218 24,086 26,625
Purchases ...................................... 4,436 45 1,062 -- 5,543
Sales of reserves-in-place ..................... (1,167) (95) -- -- (1,262)
Production ..................................... (2,214) (439) (1,027) (4,453) (8,133)
------- ------- ------- ------- -------
December 31, 1997 ................................ 20,166 3,383 5,257 40,014 68,820
======= ======= ======= ======= =======

PROVED DEVELOPED:
December 31, 1995 ................................ 14,967 4,735 3,302 -- 23,004
======= ======= ======= ======= =======
December 31, 1996 ................................ 14,801 3,499 1,926 4,353 24,579
======= ======= ======= ======= =======
December 31, 1997 ................................ 17,343 3,383 1,861 11,482 34,069
======= ======= ======= ======= =======

-45-
48
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

The following table sets forth the standardized measure of the discounted
future net cash flows attributable to the Company's proved oil and gas
reserves. Future cash inflows were computed by applying year-end prices of oil
and gas to the estimated future production of proved oil and gas reserves. Gas
prices were escalated only where existing contracts contained fixed and
determinable escalation clauses. Contractually provided gas prices in excess
of estimated market clearing prices were used in computing the future cash
inflows only if the Company expects to continue to receive higher prices under
legally enforceable contract terms. Future prices actually received may differ
from the estimates in the standardized measure.

Future production and development costs represent the estimated future
expenditures (based on current costs) to be incurred in developing and
producing the proved reserves, assuming continuation of existing economic
conditions. Future income tax expenses were computed by applying statutory
income tax rates to the difference between pre-tax net cash flows relating to
the Company's proved oil and gas reserves and the tax basis of proved oil and
gas properties. In addition, the effects of statutory depletion in excess of
tax basis, available net operating loss carryforwards and investment tax credit
carryforwards were used in computing future income tax expense. The resulting
annual net cash inflows were then discounted using a 10% annual rate (in
thousands):

UNITED CoTE EQUATORIAL
STATES CANADA D'IVOIRE GUINEA TOTAL (1) (2)
------------ ----------- ----------- ----------- -------------

AT DECEMBER 31, 1997

Future cash inflows . . . . . . . $ 1,034,813 $ 178,899 $ 384,217 $ 573,360 $ 2,171,289
------------ ----------- ----------- ----------- -------------
Future production costs . . . . . 319,171 58,588 85,717 111,822 575,298
Future development costs . . . . . 61,524 2,024 110,047 239,750 413,345
Future income taxes . . . . . . . 102,748 26,464 41,001 37,417 207,630
------------ ----------- ----------- ----------- -------------
Total future costs . . . . . . 483,443 87,076 236,765 388,989 1,196,273
------------ ----------- ----------- ----------- -------------
Future net cash inflows . . . . . 551,370 91,823 147,452 184,371 975,016

Discount at 10% per annum . . . . (159,055) (35,489) (58,883) (49,719) (303,146)
------------ ----------- ----------- ----------- -------------
Standardized measure of discounted

future net cash flows . . . . . $ 392,315 $ 56,334 $ 88,569 $ 134,652 $ 671,870
============ =========== =========== =========== =============
AT DECEMBER 31, 1996

Future cash inflows . . . . . . . $ 1,445,872 $ 206,041 $ 305,988 $ 450,785 $ 2,408,686
------------ ----------- ----------- ----------- -------------
Future production costs . . . . . 379,096 55,993 53,927 102,275 591,291

Future development costs . . . . . 53,067 4,501 74,957 152,780 285,305

Future income taxes . . . . . . . 221,053 44,263 45,833 49,782 360,931
------------ ----------- ----------- ----------- -------------
Total future costs . . . . . . 653,216 104,757 174,717 304,837 1,237,527
------------ ----------- ----------- ----------- -------------
Future net cash inflows . . . . . 792,656 101,284 131,271 145,948 1,171,159

Discount at 10% per annum . . . . (253,431) (42,431) (40,465) (40,810) (377,137)
------------ ----------- ----------- ----------- -------------
Standardized measure of discounted

future net cash flows . . . . . $ 539,225 $ 58,853 $ 90,806 $ 105,138 $ 794,022
============ =========== =========== =========== =============
AT DECEMBER 31, 1995

Future cash inflows . . . . . . . $ 821,122 $ 157,548 $ 317,580 $ 65,789 $ 1,362,039
------------ ----------- ----------- ----------- -------------
Future production costs . . . . . 268,790 65,859 59,307 26,625 420,581
Future development costs . . . . . 35,782 5,337 103,538 16,250 160,907
Future income taxes . . . . . . . 50,573 19,448 37,232 7,562 114,815
------------ ----------- ----------- ----------- -------------
Total future costs . . . . . . 355,145 90,644 200,077 50,437 696,303
------------ ----------- ----------- ----------- -------------
Future net cash inflows . . . . . 465,977 66,904 117,503 15,352 665,736

Discount at 10% per annum . . . . (133,051) (24,011) (43,215) (1,458) (201,735)
------------ ----------- ----------- ----------- -------------
Standardized measure of discounted

future net cash flows . . . . . $ 332,926 $ 42,893 $ 74,288 $ 13,894 $ 464,001
============ =========== =========== =========== =============

(1) Total future net cash flows before income taxes are $1,182,646,000,
$1,532,090,000 and $780,551,000 as of
December31, 1997, 1996 and 1995, respectively.

(2) Total future net cash flows before income taxes discounted at 10% per annum
are $723,833,000, $966,895,000 and $505,153,000 as of December 31, 1997,
1996 and 1995, respectively.

-46-
49
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

The following are the principal sources of change in the standardized
measure of discounted future net cash flows (in thousands):

1997 1996 1995
---------- ---------- -----------

Beginning balance . . . . . . . . . . . . . . . . . . . . . . . . $ 794,022 $ 464,001 $ 303,310
---------- ---------- -----------
Revisions to reserves proved in prior years -
Net changes in prices and production costs . . . . . . . . . . (439,978) 304,349 58,564
Net changes due to revisions in quantity estimates . . . . . . 50,426 53,235 24,357
Net changes in estimated future development costs . . . . . . . 49,553 9,245 59,821
Accretion of discount . . . . . . . . . . . . . . . . . . . . . 96,350 50,495 32,247
Changes in production rates (timing) and other . . . . . . . . (93,218) (40,147) (10,462)
---------- ---------- -----------
Total revisions . . . . . . . . . . . . . . . . . . . . . . (336,867) 377,177 164,527
New field discoveries and extensions, net of future
production and development costs . . . . . . . . . . . . . . . 244,509 222,271 93,643
Purchases of reserves in-place . . . . . . . . . . . . . . . . . 77,572 29,871 38,631
Sale of reserves in-place . . . . . . . . . . . . . . . . . . . . (28,976) (13,560) (46,410)
Sales of oil and gas produced, net of production costs . . . . . (198,910) (155,231) (69,918)
Net change in income taxes . . . . . . . . . . . . . . . . . . . 120,520 (130,507) (19,782)
---------- ---------- -----------
Net change in standardized measure of discounted
future net cash flows . . . . . . . . . . . . . . . . . . . . (122,152) 330,021 160,691
---------- ---------- -----------
Ending balance . . . . . . . . . . . . . . . . . . . . . . . . . $ 671,870 $ 794,022 $ 464,001
========== ========== ===========

-47-

50
SUPPLEMENTAL OIL AND GAS DISCLOSURES (in thousands)

The following table sets forth revenue and direct cost, excluding interest
expense, general and administrative expense and other items, information
relating to the Company's oil and gas exploration and production activities.
UMC has no long-term supply or purchase agreements with governments or
authorities in which it acts as producer.

1997 1996 1995
---------- ---------- ----------

UNITED STATES
Oil and gas revenues . . . . . . . . . . . . . . . . . . . $ 131,755 $ 144,804 $ 91,541
---------- ---------- ----------
Operating costs:
Production cost . . . . . . . . . . . . . . . . . . . . . 39,289 36,990 34,028
Exploration, including dry holes and leasehold impairments 12,612 21,112 10,852
Depreciation, depletion and amortization . . . . . . . . 54,555 66,832 44,265
Impairment of oil and gas property . . . . . . . . . . . -- -- 8,317
Income tax provision (benefit) . . . . . . . . . . . . . 9,614 7,551 (2,250)
---------- ---------- ----------
116,070 132,485 95,212
---------- ---------- ----------
Results of operations . . . . . . . . . . . . . . . . . . $ 15,685 $ 12,319 $ (3,671)
========== ========== ==========

CoTE D'IVOIRE
Oil and gas revenues . . . . . . . . . . . . . . . . . . . $ 27,803 $ 22,680 $ 4,729
---------- ---------- ----------
Operating costs:
Production cost . . . . . . . . . . . . . . . . . . . . . 5,602 5,370 3,388
Exploration, including dry holes and leasehold impairments 4,403 1,638 900
Depreciation, depletion and amortization . . . . . . . . 13,773 5,689 1,469
Income tax provision (benefit) . . . . . . . . . . . . . 1,530 3,794 (391)
---------- ---------- ----------
25,308 16,491 5,366
---------- ---------- ----------
Results of operations . . . . . . . . . . . . . . . . . . $ 2,495 $ 6,189 $ (637)
========== ========== ==========

EQUATORIAL GUINEA AND OTHER FOREIGN
Oil and gas revenues . . . . . . . . . . . . . . . . . . . $ 78,861 $ 21,430 $ --
---------- ---------- ----------
Operating costs:
Production cost . . . . . . . . . . . . . . . . . . . . . 5,520 3,738 --
Exploration, including dry holes and leasehold impairments 18,387 15,492 2,681
Depreciation, depletion and amortization . . . . . . . . 20,839 2,976 --
Income tax provision (benefit) . . . . . . . . . . . . . 12,964 (295) (1,018)
---------- ---------- ----------
57,710 21,911 1,663
---------- ---------- ----------
Results of operations . . . . . . . . . . . . . . . . . . $ 21,151 $ (481) $ (1,663)
========== ========== ==========

CANADA
Oil and gas revenues . . . . . . . . . . . . . . . . . . . $ 18,595 $ 17,615 $ 17,080
---------- ---------- ----------
Operating costs:
Production cost . . . . . . . . . . . . . . . . . . . . . 6,081 5,200 5,475
Exploration, including dry holes and leasehold impairments 3,443 2,083 1,249
Depreciation, depletion and amortization . . . . . . . . 7,251 9,482 8,208
Income tax provision (benefit) . . . . . . . . . . . . . 692 323 816
---------- ---------- ----------
17,467 17,088 15,748
---------- ---------- ----------
Results of operations . . . . . . . . . . . . . . . . . . $ 1,128 $ 527 $ 1,332
========== ========== ==========

TOTAL
Oil and gas revenues . . . . . . . . . . . . . . . . . . . $ 257,014 $ 206,529 $ 113,350
---------- ---------- ----------
Operating costs:
Production cost . . . . . . . . . . . . . . . . . . . . . 56,492 51,298 42,891
Exploration, including dry holes and leasehold impairments 38,845 40,325 15,682
Depreciation, depletion and amortization . . . . . . . . 96,418 84,979 53,942
Impairment of oil and gas property . . . . . . . . . . . -- -- 8,317
Income tax provision (benefit) . . . . . . . . . . . . . 24,800 11,373 (2,843)
---------- ---------- ----------
216,555 187,975 117,989
---------- ---------- ----------
Results of operations . . . . . . . . . . . . . . . . . . $ 40,459 $ 18,554 $ (4,639)
========== ========== ==========

-48-

51
NOTE 19 SUPPLEMENTAL GUARANTOR INFORMATION

In connection with the sale by United Meridian Corporation of the Notes,
Petroleum, the Company's only direct subsidiary, has unconditionally guaranteed
the full and prompt performance of the Company's obligations under the Notes
and related indenture, including the payment of principal, premium (if any) and
interest. Other than intercompany arrangements and transactions, the
consolidated financial statements of Petroleum are equivalent in all material
respects to those of the Company and therefore the separate consolidated
financial statements of Petroleum are not material to investors and have not
been included herein. However, in an effort to provide meaningful financial
data relating to the guarantor (i.e., Petroleum on an unconsolidated basis) of
the Notes, the following condensed consolidating financial information has been
provided following the policies set forth below:

(1) Investments in subsidiaries are accounted for by the Company on the
cost basis. Earnings of subsidiaries are therefore not reflected in
the related investment accounts.

(2) Certain reclassifications were made to conform all of the financial
information to the financial presentation on a consolidated basis.
The principal eliminating entries eliminate investments in
subsidiaries and intercompany balances.

Certain intercompany notes and the related accrued interest were
transferred from UMC to a newly formed non- guarantor subsidiary effective as
of January 1, 1997.

-49-

52
SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF INCOME
For the years ended December 31, 1997, 1996 and 1995
(In thousands)

Unconsolidated
--------------------------------------------
Non-
Guarantor Guarantor Consolidated
1997 UMC Subsidiary Subsidiary UMC
- ---- --------- ---------- ---------- ------------

Revenues ................................................... $ -- $ 137,087 $ 127,778 $ 264,865
--------- --------- --------- ---------
Costs and expenses:
Production costs ......................................... -- 38,766 17,726 56,492
General and administrative ............................... 120 11,850 1,610 13,580
Exploration, including dry holes and impairments ......... -- 12,612 26,233 38,845
Depreciation, depletion and amortization ................. -- 53,645 42,773 96,418
--------- --------- --------- ---------
Income (loss) from operations .............................. (120) 20,214 39,436 59,530
Interest income (expense), net ........................... (16,115) (38,285) 32,651 (21,749)
Other credits, net ....................................... -- 1,247 434 1,681
--------- --------- --------- ---------
Income (loss) before income taxes .......................... (16,235) (16,824) 72,521 39,462
Income tax benefit (provision) ............................. 20,585 (32,578) (7,682) (19,675)
--------- --------- --------- ---------
Net income (loss) .......................................... $ 4,350 $ (49,402) $ 64,839 $ 19,787
========= ========= ========= =========
1996
- ----

Revenues ................................................... $ -- $ 149,917 $ 86,487 $ 236,404
--------- --------- --------- ---------
Costs and expenses:
Production costs ......................................... -- 36,932 14,366 51,298
General and administrative ............................... 180 10,554 1,993 12,727
Exploration, including dry holes and impairments ......... -- 21,107 19,218 40,325
Depreciation, depletion and amortization ................. -- 66,744 18,235 84,979
--------- --------- --------- ---------
Income (loss) from operations .............................. (180) 14,580 32,675 47,075
Interest income (expense), net ........................... 18,052 (32,067) (8,796) (22,811)
Other credits, net ....................................... -- (1,034) 190 (844)
--------- --------- --------- ---------
Income (loss) before income taxes .......................... 17,872 (18,521) 24,069 23,420
Income tax benefit (provision) ............................. (6,208) 6,707 (6,515) (6,016)
--------- --------- --------- ---------
Net income (loss) .......................................... $ 11,664 $ (11,814) $ 17,554 $ 17,404
========= ========= ========= =========
1995
- ----

Revenues ................................................... $ -- $ 107,108 $ 39,933 $ 147,041
--------- --------- --------- ---------
Costs and expenses:
Production costs ......................................... -- 34,028 8,863 42,891
General and administrative ............................... 415 6,966 3,044 10,425
Exploration, including dry holes and impairments ......... -- 10,852 4,830 15,682
Depreciation, depletion and amortization ................. -- 44,264 9,678 53,942
Impairment of proved oil and gas properties .............. -- 8,317 -- 8,317
--------- --------- --------- ---------
Income (loss) from operations .............................. (415) 2,681 13,518 15,784
Interest income (expense), net ........................... 12,629 (25,789) (4,785) (17,945)
Other credits, net ....................................... -- (28) 403 375
--------- --------- --------- ---------
Income (loss) before income taxes .......................... 12,214 (23,136) 9,136 (1,786)
Income tax benefit (provision) ............................. (4,275) 7,681 479 3,885
--------- --------- --------- ---------
Net income (loss) .......................................... $ 7,939 $ (15,455) $ 9,615 $ 2,099
========= ========= ========= =========

-50-

SUPPLEMENTAL CONDENSED CONSOLIDATING BALANCE SHEET
December 31, 1997 and 1996
(In thousands)

Unconsolidated
-----------------------------------------------
Guarantor Non-Guarantor Eliminating Consolidated
1997 UMC Subsidiary Subsidiaries Entries UMC
- ---- ----------- ----------- -------------- ----------- ------------

ASSETS
Current assets .............................. $ 2 $ 51,513 $ 56,649 $ -- $ 108,164
Intercompany investments .................... 682,885 339,673 335,024 (1,357,582) --
Property and equipment, net ................. -- 354,745 386,227 -- 740,972
Other assets ................................ 5,395 27,803 2,691 -- 35,889
----------- ----------- ----------- ----------- -----------
Total assets .......................... $ 688,282 $ 773,734 $ 780,591 $(1,357,582) $ 885,025
=========== =========== =========== =========== ===========
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities ......................... $ 3,326 $ 66,178 $ 37,208 $ -- $ 106,712
Long-term debt .............................. 150,000 117,300 15,346 -- 282,646
Deferred credits and other liabilities ...... -- 11,222 25,046 -- 36,268
Stockholders' equity ........................ 534,956 579,034 702,991 (1,357,582) 459,399
Total liabilities & stockholders' ----------- ----------- ----------- ----------- -----------
equity ............................ $ 688,282 $ 773,734 $ 780,591 $(1,357,582) $ 885,025
=========== =========== =========== =========== ===========
1996
- ----

ASSETS
Current assets .............................. $ 3 $ 93,023 $ 63,135 $ -- $ 156,161
Intercompany investments .................... 668,025 (346,861) (182,827) (138,337) --
Property and equipment, net ................. -- 282,236 241,953 -- 524,189
Other assets ................................ 5,947 36,714 (4,718) -- 37,943
----------- ----------- ----------- ----------- -----------
Total assets .......................... $ 673,975 $ 65,112 $ 117,543 $ (138,337) $ 718,293
=========== =========== =========== =========== ===========
LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities ......................... $ 3,327 $ 42,577 $ 52,488 $ -- $ 98,392
Long-term debt .............................. 150,000 (5,700) 12,532 -- 156,832
Deferred credits and other liabilities ...... -- 9,421 21,412 -- 30,833
Stockholders' equity ........................ 520,648 18,814 31,111 (138,337) 432,236
Total liabilities & stockholders' ----------- ----------- ----------- ----------- -----------
equity ............................ $ 673,975 $ 65,112 $ 117,543 $ (138,337) $ 718,293
=========== =========== =========== =========== ===========

-51-

SUPPLEMENTAL CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the years ended December 31, 1997, 1996 and 1995
(In thousands)

Unconsolidated
------------------------------------------
Guarantor Non-Guarantor Consolidated
1997 UMC Subsidiary Subsidiaries UMC
- ---- --------- ---------- ------------- ------------

Cash flows from operating activities:
Net income (loss) ............................................. $ 4,350 $ (49,402) $ 64,839 $ 19,787
Adjustments to reconcile net income
(loss) to cash from operating activities ..................... (20,033) 94,114 71,362 145,443
Changes in assets and liabilities ............................. (1) 20,554 (19,995) 558
--------- --------- --------- ---------
Net cash provided by (used in) operating activities ........ (15,684) 65,266 116,206 165,788
Cash flows used in investing activities ......................... -- (131,293) (206,693) (337,986)
Cash flows provided by financing activities ..................... 15,683 26,921 86,341 128,945
--------- --------- --------- ---------
Net decrease in cash and cash equivalents ....................... (1) (39,106) (4,146) (43,253)
Cash and cash equivalents at beginning of period ................ 3 41,759 13,180 54,942
--------- --------- --------- ---------
Cash and cash equivalents at end of period ...................... $ 2 $ 2,653 $ 9,034 $ 11,689
========= ========= ========= =========
1996
- ----

Cash flows from operating activities:
Net income (loss) ............................................. $ 11,664 $ (11,814) $ 17,554 $ 17,404
Adjustments to reconcile net income
(loss) to cash from operating activities ..................... 6,746 76,914 19,981 103,641
Changes in assets and liabilities ............................. 40 (25,641) (12,010) (37,611)
--------- --------- --------- ---------
Net cash provided by operating activities .................. 18,450 39,459 25,525 83,434
Cash flows used in investing activities ......................... -- (61,392) (74,357) (135,749)
Cash flows provided by (used in) financing activities ........... (18,478) 57,061 55,088 93,671
--------- --------- --------- ---------
Net increase (decrease) in cash and cash equivalents ............ (28) 35,128 6,256 41,356
Cash and cash equivalents at beginning of period ................ 31 6,631 6,924 13,586
--------- --------- --------- ---------
Cash and cash equivalents at end of period ...................... $ 3 $ 41,759 $ 13,180 $ 54,942
========= ========= ========= =========
1995
- ----

Cash flows from operating activities:
Net income (loss) ............................................. $ 7,939 $ (15,455) $ 9,615 $ 2,099
Adjustments to reconcile net income
(loss) to cash from operating activities ..................... 494 45,239 (2,020) 43,713
Changes in assets and liabilities ............................. 5,755 13,146 (18,707) 194
--------- --------- --------- ---------
Net cash provided used by operating activities ............. 14,188 42,930 (11,112) 46,006
Cash flows used in investing activities ......................... -- (18,488) (64,220) (82,708)
Cash flows provided by (used in) financing activities ........... (14,169) (21,539) 74,171 38,463
--------- --------- --------- ---------
Net increase (decrease) in cash and cash equivalents ............ 19 2,903 (1,161) 1,761
Cash and cash equivalents at beginning of period ................ 12 3,728 8,085 11,825
--------- --------- --------- ---------
Cash and cash equivalents at end of period ...................... $ 31 $ 6,631 $ 6,924 $ 13,586
========= ========= ========= =========

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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 1998 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 STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. FINANCIAL STATEMENTS

The following financial statements and the Report of Independent Public
Accountants are filed as a part of this report on the pages indicated:

Report of Independent Public Accountants -- page 24

Consolidated Statement of Income -- For the years ended December 31,
1997, 1996 and 1995-- page 25

Consolidated Balance Sheet -- December 31, 1997 and 1996 -- pages 26-27

Consolidated Statement of Changes in Stockholders' Equity -- For the
years ended December 31, 1997, 1996 and 1995 -- page 28

Consolidated Statement of Cash Flows -- For the years ended December
31, 1997, 1996 and 1995 -- page 29

Selected Quarterly Financial Data for the years ended December 31, 1997
and 1996 -- page 16

Selected Financial Data for the five years ended December 31, 1997 --
page 15

(a) 2. FINANCIAL STATEMENT SCHEDULES

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

-53-

56
INDEX TO EXHIBITS

Exhibit
Number Exhibit
------- ---------------------------------------------------------------------

3.1 Certificate of Incorporation of the Company, as amended, incorporated
by reference to Exhibit 3.1 to UMC's 1995 Form 10-K filed with the
Securities and Exchange Commission on March 7, 1996.

3.2 By-laws of the Company, as amended, incorporated by reference to
Exhibit 3.2 to UMC's Form S-8 (No. 333- 28017) filed with the
Securities and Exchange Commission on May 29, 1997.

4.1 Amendment No. 1 to Registration Rights Agreement dated as of August 9,
1994 among GARI, UMC, General Atlantic Corporation, John Hancock
Mutual Life Insurance Company and Fidelity Oil Holdings, Inc.,
incorporated by reference to Exhibit (c)(8) to UMC's Schedule 14D-1
(No. 5-44990) filed with the Securities and Exchange Commission on
August 11, 1994.

4.2 Specimen of certificate representing Series A Voting Common Stock,
$0.01 par value, of the Company, incorporated herein by reference to
Exhibit 4.13 to the Company's Form 10-Q for the period ended September
30, 1994, filed with the Securities and Exchange Commission on August
10, 1994.

4.9 Indenture between the Company, Petroleum and Bank of Montreal Trust
Company, dated October 30, 1995, incorporated by reference to Exhibit
4.20 to UMC's 1995 Form 10-K filed with the Securities and Exchange
Commission on March 7, 1996.

4.10 Rights Agreement by and between United Meridian Corporation and
Chemical Mellon Shareholder Services, L.L.C., as Rights Agent, dated
as of February 13, 1996, incorporated by reference as Exhibit 1 to
Form 8-K, filed with the Securities and Exchange Commission on
February 14, 1996.

4.11 Global Credit Agreement dated as of March 18, 1997, among United
Meridian Corporation, UMC Petroleum Corporation, The Chase Manhattan
Bank, N.A., as Administrative Agent, Morgan Guaranty Trust Company of
New York, as Syndication Agent, NationsBank of Texas, N.A. and Societe
Generale, as Documentation Agents, Banque Paribas, Wells Fargo Bank,
N.A., and Colorado National Bank, as Co-Agents and The Lenders Now or
Hereafter Signatory Hereto, incorporated by reference to Exhibit 4.11
to UMC's Form 10-Q for the quarterly period ended March 31, 1997,
filed with the Securities and Exchange Commission on May 9, 1997.

4.12 Credit Agreement dated as of March 18, 1997 among UMC Resources Canada
Ltd., as the Company, The Chase Manhattan Bank of Canada, as Agent,
and the Lenders Signatory Hereto, incorporated by reference to Exhibit
4.12 to UMC's Form 10-Q for the quarterly period ended March 31, 1997,
filed with the Securities and Exchange Commission on May 9, 1997.

4.13 Guaranty Agreement dated as of March 18, 1997, by UMC Petroleum
Corporation in favor of The Chase Manhattan Bank of Canada, as
Administrative Agent, and The Lenders Now or Hereafter Signatory to
the Credit Agreement, incorporated by reference to Exhibit 4.13 to
UMC's Form 10-Q for the quarterly period ended March 31, 1997, filed
with the Securities and Exchange Commission on May 9, 1997.

4.14 Guaranty Agreement dated as of March 18, 1997, by United Meridian
Corporation in favor of The Chase Manhattan Bank, as Administrative
Agent, Morgan Guaranty Trust Company of New York, as Syndication
Agent, NationsBank of Texas, N.A. and Societe Generale, as
Documentation Agents, Banque Paribas, Wells Fargo Bank, N.A., and
Colorado National Bank as Co-Agents, and The Lenders Now or Hereafter
Signatory to the Credit Agreement, incorporated by reference to
Exhibit 4.14 to UMC's Form 10-Q for the quarterly period ended March
31, 1997, filed with the Securities and Exchange Commission on May 9,
1997.

4.15 Guaranty Agreement dated as of March 18, 1997 by United Meridian
Corporation in favor of The Chase Manhattan Bank of Canada, as
Administrative Agent, and The Lenders Now or Hereafter Signatory to
the Credit Agreement,

-54-

Exhibit
Number Exhibit
------- ---------------------------------------------------------------------

incorporated by reference to Exhibit 4.15 to UMC's Form 10-Q for the
quarterly period ended March 31, 1997, filed with the Securities and
Exchange Commission on May 9, 1997.

4.16 Guaranty Agreement dated as of March 18, 1997 by Norfolk Holdings,
Inc. as the Guarantor, in favor of The Chase Manhattan Bank, as
Administrative Agent, Morgan Guaranty Trust Company of New York as
Syndication Agent, NationsBank of Texas, N.A. and Societe Generale, as
Documentation Agents, Banque Paribas, Wells Fargo Bank, N.A., and
Colorado National Bank, as Co-Agents, and The Lenders Now or Hereafter
Signatory to the Credit Agreement, incorporated by reference to
Exhibit 4.16 to UMC's Form 10-Q for the quarterly period ended March
31, 1997, filed with the Securities and Exchange Commission on May 9,
1997.

4.17 Guaranty Agreement dated as of March 18, 1997 by UMIC Cote d'Ivoire
Corporation, as the Guarantor, in favor of The Chase Manhattan Bank,
as Administrative Agent, Morgan Guaranty Trust Company of New York, as
Syndication Agent, NationsBank of Texas, N.A., and Societe Generale,
as Documentation Agents, Banque Paribas, Wells Fargo Bank, N.A., and
Colorado National Bank, as Co-Agents, and The Lenders Now or Hereafter
Signatory to the Credit Agreement, incorporated by reference to
Exhibit 4.17 to UMC's Form 10-Q for the quarterly period ended March
31, 1997, filed with the Securities and Exchange Commission on May 9,
1997.

4.18 Guaranty Agreement dated as of March 18, 1997 by UMC Equatorial Guinea
Corporation, as the Guarantor, in favor of The Chase Manhattan Bank,
as Administrative Agent, Morgan Guaranty Trust Company of New York, as
Syndication Agent, NationsBank of Texas, N.A. and Societe Generale, as
Documentation Agents, Banque Paribas, Wells Fargo Bank, N.A., and
Colorado National Bank, as Co-Agents, and The Lenders Now or Hereafter
Signatory to the Credit Agreement, incorporated by reference to
Exhibit 4.18 to UMC's Form 10-Q for the quarterly period ended March
31, 1997, filed with the Securities and Exchange Commission on May 9,
1997.

4.19 Intercreditor Agreement dated as of March 18, 1997, among United
Meridian Corporation, UMC Petroleum Corporation, Norfolk Holdings
Inc., UMC Resources Canada Ltd., UMIC Cote d'Ivoire Corporation, UMC
Equatorial Guinea Corporation, The Chase Manhattan Bank, as
Administrative Agent and Collateral Agent, Morgan Guaranty Trust
Company of New York, as Syndication Agent, NationsBank of Texas, N.A.
and Societe Generale, as Documentation Agents, Banque Paribas, Wells
Fargo Bank, N.A., as Co-Agents, The Chase Manhattan Bank of Canada, as
Canadian Agent, and The Lenders Now or Hereafter Signatory Hereto,
incorporated by reference to Exhibit 4.19 to UMC's Form 10-Q for the
quarterly period ended March 31, 1997, filed with the Securities and
Exchange Commission on May 9, 1997.

4.20 Amendment No. 1 to the Rights Agreement by and between United Meridian
Corporation and Chemical Mellon Shareholder Services, L.L.C., as
Rights Agent, dated as of September 30, 1997, incorporated by
reference as Exhibit 4.1 to Form 8-K, filed with the Securities and
Exchange Commission on October 3, 1997.

4.21* First Joint Amendment to Global Credit Agreement and to Credit
Agreement (Canada) effective as of December 3, 1997.

10.2 The UMC Petroleum Savings Plan as amended and restated incorporated
herein by reference to Exhibit 4.10 to the Company's Form S-8 (No.
33-73574) filed with the Securities and Exchange Commission on
December 29, 1993.

10.3 First Amendment to the UMC Petroleum Savings Plan, as Amended and
Restated as of January 1, 1993, dated April 18, 1994, incorporated by
reference to Exhibit 10.3 to UMC's 1994 Form 10-K filed with the
Securities and Exchange Commission on March 10, 1995.

10.4 UMC 1987 Nonqualified Stock Option Plan, as amended, incorporated
herein by reference to Exhibit 10.3 to the Company's Form S-1 (No.
33-63532) filed with the Securities and Exchange Commission on May 28,
1993.

-55-

Exhibit
Number Exhibit
------- ---------------------------------------------------------------------

10.5 Third Amendment to UMC 1987 Nonqualified Stock Option Plan dated
November 16, 1993 incorporated herein by reference to Exhibit 10.4 to
the Company's 1993 Form 10-K filed with the Securities and Exchange
Commission on March 7, 1994.

10.6 Fourth Amendment to UMC 1987 Nonqualified Stock Option Plan dated
April 6, 1994, incorporated by reference to Exhibit 10.6 to UMC's 1994
Form 10-K filed with the Securities and Exchange Commission on March
10, 1995.

10.7 UMC 1994 Employee Nonqualified Stock Option Plan incorporated by
reference to Exhibit 4.14 to the Company's Form S-8 (No. 33-79160)
filed with the Securities and Exchange Commission on May 19, 1994.

10.8 First Amendment to the UMC 1994 Employee Nonqualified Stock Option
Plan dated November 16, 1994, incorporated by reference to Exhibit
4.11.1 to the Company's Form S-8 (No. 33-86480) filed with the
Securities and Exchange Commission on November 18, 1994.

10.9 Second Amendment to the UMC 1994 Employee Nonqualified Stock Option
Plan dated May 22, 1996, incorporated by reference to Exhibit 4.3.2 to
the Company's Form S-8 (No. 333-05401) filed with the Securities and
Exchange Commission on June 6, 1996.

10.10 Third Amendment to the UMC 1994 Employee Nonqualified Stock Option
Plan dated November 13, 1996, incorporated by reference to Exhibit
4.3.3 to the Company's Form S-8 (No. 333-28017) filed with the
Securities and Exchange Commission on May 29, 1997.

10.11 UMC 1994 Outside Directors' Nonqualified Stock Option Plan
incorporated herein by reference to Exhibit 4.15 to the Company's Form
S-8 (No. 33-79160) filed with the Securities and Exchange Commission
on May 19, 1994.

10.12 First Amendment to the UMC 1994 Outside Directors' Nonqualified Stock
Option Plan dated May 22, 1996, incorporated by reference to Exhibit
4.4.1 to the Company's Form S-8 (No. 333-05401) filed with the
Securities and Exchange Commission on June 6, 1996.

10.14 UMC Petroleum Corporation Supplemental Benefit Plan effective January
1, 1994, approved by the Board of Directors on March 29, 1994,
incorporated by reference to Exhibit 10.10 to UMC's 1994 Form 10-K
filed with the Securities and Exchange Commission on March 10, 1995.

10.15 Form of Indemnification Agreement, with Schedule of Signatories,
incorporated herein by reference to Exhibit 10.4 to the Company's Form
S-1 (No. 33-63532) filed with the Securities and Exchange Commission
on May 28, 1993.

10.16 Petroleum Production Sharing Contract on Block CI-11 dated June 27,
1992 among the Republic of Cote d'Ivoire, UMIC Cote d'Ivoire
Corporation and Societe Nationale d'Operations Petrolieres de la Cote
d'Ivoire (including English translation), incorporated herein by
reference to Exhibit 10.5 to Amendment No. 3 to the Company's Form S-1
(No. 33-63532) filed with the Securities and Exchange Commission on
July 20, 1993.

10.17 Production Sharing Contract dated August 18, 1992 between the
Republic of Equatorial Guinea and United Meridian International
Corporation (Area A - Offshore NE Bioco), incorporated herein by
reference to Exhibit 10.6 to Amendment No. 1 to the Company's Form S-1
(No. 33-63532) filed with the Securities and Exchange Commission on
June 18, 1993.

10.18 Production Sharing Contract dated June 29, 1992 between the Republic
of Equatorial Guinea and United Meridian International Corporation
(Area B - Offshore NW Bioco), incorporated herein by reference to
Exhibit 10.7 to Amendment No. 1 to the Company's Form S-1 (No.
33-63532) filed with the Securities and Exchange Commission on June
18, 1993.

-56-

Exhibit
Number Exhibit
------- ---------------------------------------------------------------------

10.19 Production Sharing Contract dated June 29, 1994 between the Republic
of Equatorial Guinea and United Meridian International Corporation
(Area C - Offshore Bioco) incorporated by reference to Exhibit 10.15
to UMC's 1994 Form 10-K filed with the Securities and Exchange
Commission on March 10, 1995.

10.20 Production Sharing Contract on Block CI-01 dated December 5, 1994
among The Republic of Cote d'Ivoire, UMIC Cote d'Ivoire Corporation
and Societe Nationale d'Operations Petrolieres de la Cote d'Ivoire
(English translation) incorporated by reference to Exhibit 10.16 to
UMC's 1994 Form 10-K filed with the Securities and Exchange Commission
on March 10, 1995.

10.21 Production Sharing Contract on Block CI-02 dated December 5, 1994
among The Republic of Cote d'Ivoire UMIC Cote d'Ivoire Corporation and
Societe Nationale d'Operations Petrolieres de la Cote d'Ivoire
(English translation) incorporated by reference to Exhibit 10.17 to
UMC's 1994 Form 10-K filed with the Securities and Exchange Commission
on March 10, 1995.

10.22 Production Sharing of Block CI-12 dated April 27, 1995 among The
Republic of Cote d'Ivoire, UMIC Cote d'Ivoire Corporation and others
(English translation), incorporated by reference to Exhibit 10.18 to
UMC's 1995 Form 10-K filed with the Securities and Exchange Commission
on March 7, 1996.

10.23 Contract for Sale and Purchase of Natural Gas for Block CI-11 among
Caisse Autonome D'Amortissement, UMIC Cote d'Ivoire Corporation and
others dated September 30, 1994 (French and English translation)
incorporated by reference to Exhibit 10.7 to the Company's Form 10-Q
for the period ended September 30, 1994 filed with the Securities and
Exchange Commission on November 14, 1994.

10.24 Production Sharing Contract dated April 5, 1995 between The Republic
of Equatorial Guinea and UMIC Equatorial Guinea Corporation (Area D -
Offshore Bioco) incorporated by reference to Exhibit 10.20 to the
Company's Form 10-Q for the period ended September 30, 1995 filed with
the Securities and Exchange Commission on August 10, 1995.

10.25 Contract for Purchase and Sale of Lion Crude Oil between UMIC Cote
d'Ivoire Corporation, International Finance Corporation, G.N.R. (Cote
d'Ivoire) Ltd. and Pluspetrol S.A. and Total International Limited,
dated December 1, 1995, incorporated by reference to Exhibit 10.22 to
UMC's 1995 Form 10-K filed with the Securities and Exchange Commission
on March 7, 1995.

10.26 Amendment to United Meridian Corporation 1994 Non-Qualified Stock
Option Agreement for Former Employees of General Atlantic Resources,
Inc. dated as of April 16, 1996 among UMC and Donald D. Wolf,
incorporated by reference to Exhibit 10.22 to the Company's Form 10-Q
for the period ended September 30, 1996 filed with the Securities and
Exchange Commission on August 8, 1996.

10.28 Employment Agreement, dated October 9, 1996, between UMC, UMC
Petroleum Corporation and James L. Dunlap, incorporated by reference
to Exhibit 10.1 to UMC's Form S-3, Amendment No. 2 (No. 333-12823),
filed with the Securities and Exchange Commission on October 30, 1996.

10.29 Form of Indemnification Agreement with a schedule of director
signatories, incorporated by reference to Exhibit 10.2 to UMC's Form
S-3, Amendment No. 2 (No. 333-12823) filed with the Securities and
Exchange Commission on October 30, 1996.

10.30 Fourth Amendment to the UMC 1994 Employee Nonqualified Stock Option
Plan dated May 29, 1997, incorporated herein by reference to Exhibit
4.3.4 to the Company's Form S-8 (No. 333-28017) filed with the
Securities and Exchange Commission on May 29, 1997.

10.31 Second Amendment to the UMC 1994 Outside Directors' Nonqualified
Stock Option Plan dated November 13, 1996, incorporated herein by
reference to Exhibit 4.4 to the Company's Form S-8 (No. 333-28017)
filed with the Securities and Exchange Commission on May 29, 1997.

-57-

Exhibit
Number Exhibit
------- ---------------------------------------------------------------------

10.32 Fifth Amendment to the UMC 1987 Nonqualified Stock Option Plan dated
November 19, 1997, incorporated by reference to Exhibit 4.7 to the
Company's Form S-3 (No. 333-42467) filed with the Securities and
Exchange Commission on December 17, 1997.

10.33 Fifth Amendment to the UMC 1994 Employee Nonqualified Stock Option
Plan dated November 19, 1997, incorporated by reference to Exhibit 4.8
to the Company's Form S-3 (No. 333-42467) filed with the Securities
and Exchange Commission on December 17, 1997.

10.34 Third Amendment to the UMC 1994 Outside Directors' Nonqualified Stock
Option Plan dated November 19, 1997, incorporated by reference to
Exhibit 4.9 to the Company's Form S-3 (No. 333-42467) filed with the
Securities and Exchange Commission on December 17, 1997.

10.35 Agreement and Plan of Merger dated as of December 22, 1997, among
UMC, OEI and OEI Holding Corporation, incorporated by reference to
Exhibit 2.1 to UMC's Form 8-K (No. 001-12088) filed with the
Securities and Exchange Commission on December 23, 1997.

10.36 Form of Severance Protection Agreement, with Schedule of Signatories
dated December 20, 1997, incorporated by reference to Exhibit 10.1 to
UMC's Form 8-K (No. 001-12088) filed with the Securities and Exchange
Commission on December 23, 1997.

10.37* Amendment No.1 to Agreement and Plan of Merger, dated January 7,
1998, among UMC, OEI and OEI Holding Corporation.

10.38* Amendment No. 2 to Agreement and Plan of Merger, dated
February 20, 1998, among UMC, OEI and OEI Holding
Corporation.

21.1* Subsidiaries of United Meridian Corporation.

23.1* Consent of Arthur Andersen LLP.

23.2* Consent of Netherland, Sewell & Associates, Inc.

23.3* Consent of McDaniel & Associates Consultants Ltd.

23.4* Consent of Ryder Scott Company

27.1* Financial Data Schedule, included solely in the Form 10-K filed
electronically with the Securities and Exchange Commission.

- ------------------
* Filed herewith.

(b) REPORTS ON FORM 8-K

A Form 8-K dated October 3, 1997, was filed announcing the revision of the
Stockholder's Right Plan. A Form 8-K filed December 23, 1997, was filed
announcing the execution of a merger agreement with Ocean Energy, Inc. A Form
8-K filed February 11, 1998, was filed incorporating by reference certain press
releases of the Company announcing the record date for shareholders entitled to
vote at the UMC special meeting, participation in the Angola deepwater Block 19
concession, proved energy reserves and earnings.

-58-

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.

REGISTRANT UNITED MERIDIAN CORPORATION

February 20, 1998 /s/ JOHN B. BROCK
----------------------------------
John B. Brock
Chairman of the Board of Directors
and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on February 20, 1998 on
behalf of the registrant and in the capacities indicated.

Name Capacities

/s/ JOHN B. BROCK Chairman, Chief Executive Officer and Director
----------------------- (Principal Executive Officer)
John B. Brock

/s/ JAMES L. DUNLAP President, Chief Operating Officer and Director
-----------------------
James L. Dunlap

/s/ J. DENNIS BONNEY Director
-----------------------
J. Dennis Bonney

/s/ CHARLES R. CARSON Director
-----------------------
Charles R. Carson

/s/ ROBERT H. DEDMAN Director
-----------------------
Robert H. Dedman

/s/ ROBERT L. HOWARD Director
-----------------------
Robert L. Howard

/s/ ELVIS L. MASON Director
-----------------------
Elvis L. Mason

-59-

Name Capacities

/s/ JAMES L. MURDY Director
-----------------------
James L. Murdy

/s/ DAVID K. NEWBIGGING Director
-----------------------
David K. Newbigging

/s/ MATTHEW R. SIMMONS Director
-----------------------
Matthew R. Simmons

/s/ DONALD D. WOLF Director
-----------------------
Donald D. Wolf

/s/ JONATHAN M. CLARKSON Executive Vice President and Chief Financial Officer
-----------------------
Jonathan M. Clarkson

/s/ CHRISTOPHER E. CRAGG Vice President, Controller and Chief Accounting
----------------------- Officer
Christopher E. Cragg

-60-

63
INDEX TO EXHIBITS

Exhibit
Number Exhibit
------- ---------------------------------------------------------------------

3.1 Certificate of Incorporation of the Company, as amended, incorporated
by reference to Exhibit 3.1 to UMC's 1995 Form 10-K filed with the
Securities and Exchange Commission on March 7, 1996.

3.2 By-laws of the Company, as amended, incorporated by reference to
Exhibit 3.2 to UMC's Form S-8 (No. 333- 28017) filed with the
Securities and Exchange Commission on May 29, 1997.

-54-

Exhibit
Number Exhibit
------- ---------------------------------------------------------------------

incorporated by reference to Exhibit 4.15 to UMC's Form 10-Q for the
quarterly period ended March 31, 1997, filed with the Securities and
Exchange Commission on May 9, 1997.

4.21* First Joint Amendment to Global Credit Agreement and to Credit
Agreement (Canada) effective as of December 3, 1997.

-55-

Exhibit
Number Exhibit
------- ---------------------------------------------------------------------

-56-

Exhibit
Number Exhibit
------- ---------------------------------------------------------------------

-57-

Exhibit
Number Exhibit
------- ---------------------------------------------------------------------

10.37* Amendment No.1 to Agreement and Plan of Merger, dated January 7,
1998, among UMC, OEI and OE Holding Corporation.

10.38* Amendment No. 2 to Agreement and Plan of Merger, dated
February 20, 1998, among UMC, OEI and OEI Holding
Corporation.

21.1* Subsidiaries of United Meridian Corporation.

23.1* Consent of Arthur Andersen LLP.

23.2* Consent of Netherland, Sewell & Associates, Inc.

23.3* Consent of McDaniel & Associates Consultants Ltd.

23.4* Consent of Ryder Scott Company

27.1* Financial Data Schedule, included solely in the Form 10-K filed
electronically with the Securities and Exchange Commission.

- ------------------
* Filed herewith.

(b) REPORTS ON FORM 8-K

-58-