NUEVO ENERGY CO - 10-K Annual Report

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

FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

OR

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

FOR THE TRANSITION PERIOD FROM _____________________ TO _______________________

COMMISSION FILE NUMBER 1-10537

NUEVO ENERGY COMPANY
(Exact Name of Registrant as Specified in Its Charter)

DELAWARE 76-0304436
(State or Other Jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)

1021 MAIN, SUITE 2100, HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)

Registrant's telephone number, including area code: (713) 652-0706

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

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. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b.2 of the Act). Yes [X] No [ ].

THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF
THE REGISTRANT:

As of March 24, 2003, the aggregate market value of the voting stock of the
registrant held by non-affiliates of the registrant was approximately $244.9
million.

As of June 28, 2002, the aggregate market value of the voting stock of the
registrant held by non-affiliates of the registrant was approximately $270.1
million.

THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S CLASSES OF COMMON
STOCK AS OF THE LATEST PRACTICABLE DATE:

As of March 24, 2003, number of shares of Common Stock outstanding:
19,209,290.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant's annual proxy statement, to be filed within 120
days after December 31, 2002, are incorporated by reference into Part III.

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NUEVO ENERGY COMPANY
TABLE OF CONTENTS

i

PART I

ITEM 1. BUSINESS

GENERAL

Nuevo Energy became a public company in 1990 and is engaged in the
acquisition, exploitation, exploration, development and production of crude oil
and natural gas. Our core areas in the U.S. are onshore and offshore California
and West Texas. We also have international crude oil production in the Republic
of Congo.

We are the largest independent oil and gas exploration and production
company in California. At year-end 2002, approximately 87% of our proved
reserves were in California (63% onshore and 24% offshore) which have a long
reserve life and shallow production decline curves. Our California production
was approximately 88% of our 2002 oil and gas production. The high asset
concentration combined with a high proportion of operated properties enables us
to control the timing of exploitation and development expenditures.

In September 2002, we created a new core area in West Texas with
approximately 100 Bcfe of natural gas reserves through the acquisition of
Athanor Resources, Inc. ("Athanor"). In 2002, approximately 11% of our natural
gas production was from West Texas and it accounted for 6% of our proved
reserves and 39% of our proved natural gas reserves at year-end 2002. As a
result of the acquisition, we are the operator of the Pakenham field, which has
significant exploitation and exploration inventory.

Our only international producing property is offshore the Republic of
Congo, which had approximately 7% of our proved reserves at year-end 2002. This
property is non-operated and provides a stable production profile with 10% of
our 2002 production.

We achieved significant objectives in 2002 from an operational and
financial perspective. We terminated outsourcing contracts and now manage our
field operations, oil marketing, human resources, accounting, treasury and land
administration. We implemented cost reduction measures which were successful in
lowering lease operating costs 17%, lowering exploration costs 79%, lowering
general and administrative costs 30% and lowering interest expense 12%. A
disciplined capital allocation resulted in a 58% reduction of capital additions
to oil and gas properties excluding acquisitions, while increasing oil and gas
production. After completing a $101.4 million acquisition in 2002, we reduced
debt and increased liquidity by year-end.

In 2003 we will continue to maintain our strategy of disciplined
allocation of capital, continued cost reductions throughout the organization,
monetization of non-core assets, diversification of our asset base and the
strengthening of our balance sheet.

Our annual report on Form 10-K, quarterly reports on Form 10-Q and
current reports on Form 8-K are made available on our website at
www.nuevoenergy.com.

As used in this annual report, the words "we", "our", "us", "Nuevo" and
the "Company" refer to Nuevo Energy Company, except as otherwise specified, and
to our subsidiaries.

1

RESERVES

The following table details our estimated proved reserves at December
31, 2002:

(1) Brea-Olinda is reflected as an asset held for sale at December 31, 2002 and
the results of operations from this field are reflected as discontinued
operations in our financial statements. The sale was completed in February
2003.

OIL AND GAS OPERATIONS

Domestic Operations

The following discussion pertains to our domestic oil and gas assets
that are held for continuing use and, accordingly, does not include the
Brea-Olinda field which was sold in February 2003.

Our domestic operations are concentrated in three areas: California
onshore, California offshore and West Texas. At December 31, 2002, our U.S.
proved reserves totaled approximately 203.0 MMBOE or 93% of our total proved
reserve base. During 2002, domestic production averaged 43.4 MBOE/day, or 89% of
total production.

We continue to increase the value of our domestic oil and gas assets
through development drilling, workovers, recompletions, secondary and tertiary
recovery operations and other production enhancement techniques to maximize
current production and the ultimate recovery of reserves. Capital additions to
our domestic oil and gas properties excluding acquisitions was $53 million in
2002 and are currently budgeted at approximately $60 to 65 million in 2003. The
main focus of our 2003 exploitation program will be directed

2

toward the continued successful development of our thermal properties in the
Cymric, Belridge and Midway-Sunset fields in California and our newly acquired
Pakenham field in West Texas.

California Onshore. Net proved reserves were 137.1 MMBOE at December
31, 2002, and production averaged 27.8 MBOE/day in 2002. Our main California
onshore properties include interests in the Cymric, Midway-Sunset and Belridge
fields in the San Joaquin Basin in Kern County, California. We have onshore
properties that utilize thermal operations to maximize current production and
the ultimate recovery of reserves. We own a 100% working interest (93% net
revenue) in our properties in the Cymric field and the entire working interest
and an average net revenue interest of approximately 97% in our properties in
the Midway-Sunset field. Production is from several zones in the Cymric field,
including the Tulare, Diatomite and Point of Rocks formations and the Antelope
Shale. The Midway-Sunset field produces from five zones with the Potter Sand and
the thermal Diatomite accounting for the majority of the total production. We
operate the deeper zones of the Belridge field in fee with 100% working and net
revenue interests. Production from the Belridge field is from the Tulare
formation.

California Offshore. Net proved reserves were 51.9 MMBOE at December
31, 2002, and production averaged 14.7 MBOE/day in 2002. Offshore California, we
operate 12 platforms; 10 in federal waters and 2 in state waters. The Point
Pedernales, Dos Cuadras and East Dos Cuadras, and Santa Clara fields are our
largest fields. We own an 80% working interest (67% net revenue) in the Point
Pedernales field which is located 3.5 miles offshore Santa Barbara County,
California, in federal waters. Production is from the Monterey Shale at depths
from 3,500-5,150 feet. The Dos Cuadras and East Dos Cuadras fields are located
offshore five and one-half miles from Santa Barbara in the Santa Barbara
Channel. We operate three platforms with a 50% working interest (42% net
revenue) and a fourth platform with a 67.5% working interest (56% net revenue).
We have a 100% working interest (83% net revenue) in the Santa Clara field.

West Texas. We have properties located in West Texas that were acquired
in September 2002 with a total proved reserve base of 14.0 MMBOE at December 31,
2002, and production in the fourth quarter of 2002 was 18.6 MMcfe/day. The main
asset is the Pakenham field in Terrell County, Texas. We are the operator of the
Pakenham field and own approximately a 98% working interest (73% net revenue) in
this field.

International Operations

At December 31, 2002, our estimated international net proved reserves
totaled 14.2 MMBOE, or 7% of our total proved reserve base. During 2002, our
international production averaged 5.2 MBOE/day, or 11% of our total production.
See "Risk Factors and Cautionary Statement for Purposes of the "Safe Harbor"
Provisions of the Private Securities Litigation Reform Act of 1995" for a
discussion of the risks of our international investments.

Congo. Our international reserves and production consist primarily of a
non-operating 50% working interest (37.0% average net revenue) in the Yombo oil
field located in the Marine 1 Permit offshore the Republic of Congo in West
Africa ("Congo"). Estimated net proved reserves of the Yombo oil field as of
December 31, 2002 were 13.9 MMBbl, and production during 2002 averaged 5.2
MBOE/day. In 2002 revenues relating to production from the Yombo field accounted
for approximately 11% of our total oil and gas revenues. The properties are
located 27 miles offshore in approximately 370 feet of water. We also own a 50%
interest in a converted super tanker with storage capacity of over one million
barrels of oil for use as a floating production, storage and off loading vessel
("FPSO"). Our production is converted on the FPSO to No. 6 fuel oil with less
than 0.3% sulfur content. We also have a 50% interest in the Masseko field which
is currently under renewed analysis for possible development by Perenco, the new
operator. Should circumstances change in the future, we may pursue development
of the field.

During 2000 and 2001, a five well development program was implemented.
This highly successful program increased our net production in the Congo from
5,000 BOPD in October 2000 to a peak production rate of 6,450 BOPD in August
2001. The individual wells produced at rates between 500 and 1,800 BOPD. The
field is currently fully developed, due to the lack of slots for new wells. As
additional slots become available, additional drilling activity is possible.

3

Tunisia. We have a 42.86% participating interest in the 768,900 acre
Fejaj Permit located onshore central Tunisia. Beginning in December 2002, the
partnership re-entered the Chott Fejaj #3-A well and deepened the well from
3,532 meters to a total depth of 4,637 meters to evaluate the pre-Jurassic
section of the Chott Fejaj structure. This well has subsequently been plugged
and abandoned as a dry hole. Our net cost for the well is estimated to be
approximately $1.1 million, of which $0.4 million was expensed in the fourth
quarter 2002. We have no further plans for involvement in Tunisia.

In January 2002, we withdrew our request for formal government approval
of the Convention and Joint Venture Agreement resulting in the relinquishment of
our 100% interest in the Alyane Permit located offshore Tunisia in the Gulf of
Gabes. In June 2002, we conveyed our 22.5% participating interest and future
obligations in the Anaguid Permit, located onshore southern Tunisia in the
Ghadames Basin, to our partners Anadarko Tunisia Anaguid Company and Pioneer
Natural Resources Anaguid Ltd.

Canada. We acquired a 50% working interest in 22,140 acres in the
Marten Hills heavy oil play in Alberta, Canada for approximately $0.4 million in
2000. The cyclic steaming potential of the acreage was evaluated in 2001, and
was determined to be non-commercial and we relinquished the acreage in 2002.

Ghana. In 2001, we relinquished our 1.9 million acre Accra-Keta Permit
offshore the Republic of Ghana and recorded an impairment of $1.0 million. The
Permit was relinquished prior to the commencement of the second phase of the
work program. We were the operator of this Permit and held a 50% working
interest.

DRILLING ACTIVITIES

The following discussion pertains to our oil and gas assets that are
held for continuing use and, accordingly, does not include the Brea-Olinda field
which was sold in February 2003.

Acreage

The following table sets forth the acres of developed and undeveloped
oil and gas properties in which we held an interest as of December 31, 2002.
Undeveloped acreage are leased acres on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas, regardless of whether or not such acreage contains proved
reserves. A gross acre refers to the number of acres in which we directly own a
working interest. The number of net acres is the sum of the fractional ownership
of working interests we directly own in the gross acres expressed as a whole
number and percentages. A "net acre" is deemed to exist when the sum of our
fractional ownership of working interests in gross acres equals one.

The following table sets forth our undeveloped acreage at December 31,
2002:

- ----------
(1) Includes COOGER acreage which is offshore

4

Productive Wells

The following table sets forth our gross and net interests in
productive oil and gas wells at December 31, 2002. Productive wells are
producing wells and wells capable of production.

Drilling Activity

Our drilling activities in 2002 were in the continental United States
and offshore California in state and federal waters, and offshore Congo.

At December 31, 2002, we had 1 gross (0.43 net) exploration well in
progress. The following table details the results of our drilling activity, net
to our interest, for the last three calendar years. Gross wells are the number
of wells in which we own a direct working interest. The number of net wells is
the sum of the fractional ownership of working interests we directly own in
gross wells.

In 2002, we drilled 42 development wells in the Cymric field in central
California, which contained 31% of our total estimated net proved equivalent
reserves at December 31, 2002, and anticipate drilling approximately 27
development wells in the Cymric field during 2003. In the Midway-Sunset field in
central California, which contained 9% of the total estimated net proved
equivalent reserves at December 31, 2002, we drilled 40 development wells during
2000, and deferred the development in this field to 2002 where we drilled 32
development wells and plan to drill 20 development wells in 2003. In the
Belridge field which contained 6% of the total estimated net proved equivalent
reserves at December 31, 2002, we drilled 27 development wells during 2002, and
plan to drill approximately 30 development wells in 2003.

We initiated a waterflood project in the Yombo field offshore Congo to
enhance production from existing Upper Sendji and Tchala zones in 1999. The
development program continued during 2000 and 2001, drilling a total of 5 infill
wells which increased our production approximately 30% from 2000 to 2001. Both
pipelines originating from our platforms to the Conkouati (FPSO) were replaced
in 2001. Plans for 2003 include two conversions of producing wells to water
injection, two recompletions and facility maintenance.

5

ACQUISITIONS AND DIVESTITURES OF OIL AND GAS PRODUCING PROPERTIES

We have, from time to time, been an active participant in the market
for oil and gas properties. We also seek to divest lower growth assets at times
when those assets are valued highly by the marketplace.

In September 2002, we acquired Athanor Resources, Inc. for $101.4
million. Proved reserves from this acquisition were approximately 6% of our
total estimated net proved equivalent reserves at December 31, 2002. The
reserves are located in Terrell County in West Texas. We drilled 4 development
wells in the fourth quarter of 2002 and plan to drill 8 to 10 development wells
in 2003. We have increased production from the property by 15% since closing the
acquisition in September 2002.

In 2002, we sold a majority of our oil and gas properties located in
Texas, Alabama and Louisiana (Eastern properties) for approximately $9.0
million.

In January 2001, we acquired producing properties located southeast of
our interest in the Cymric field in Kern County, California for approximately
$28.5 million.

In 2000, we sold our working interest in the Las Cienegas field in
California for approximately $4.6 million.

REAL ESTATE

In 1996, along with our acquisition of certain California oil and gas
properties, we acquired tracts of land in Orange and Santa Barbara Counties in
California, and nearly 8,000 acres of agricultural property in the central
valley of California. As of December 31, 2002, the carrying amount of this land
totaled $40.8 million of which $35.8 million is classified as assets held for
sale.

In 2003, we expect to monetize a significant portion of our California
real estate portfolio. Our entitlement application for the Tonner Hills
residential development covering approximately 810 acres in northern Orange
County received unanimous approval from the Orange County Board of Supervisors
on November 19, 2002. On December 18, 2002, Hills for Everyone, a non-profit
organization, filed suit against Orange County ("Respondent") and Nuevo Energy
Company ("Real Party in Interest") in an effort to set aside the Orange County
approval. We will be actively addressing this lawsuit during 2003 as we continue
our project development activities.

MARKETS

The markets for hydrocarbons continue to be quite volatile. Our
financial condition, operating results, future growth and the carrying value of
our oil and gas properties are substantially dependent on oil and gas prices.
The ability to maintain or increase our borrowing capacity and to obtain
additional capital on attractive terms is also substantially dependent upon oil
and gas prices. Prices for oil and gas are subject to large fluctuations in
response to relatively minor changes in the supply of and demand for oil and
gas, market uncertainty and a variety of additional factors beyond our control.
These factors include weather conditions in the United States, the condition of
the United States economy, the actions of the Organization of Petroleum
Exporting Countries, governmental regulation, political stability in the Middle
East and elsewhere, the foreign supply of oil and gas, the price of foreign oil
imports and the availability of alternate fuel sources. Any substantial and
extended decline in the price of oil and gas could have an adverse effect on the
carrying value of our proved reserves, borrowing capacity, our ability to obtain
additional capital, and our revenues, profitability and cash flows from
operations.

The price of natural gas and the threat of electrical disruptions are
factors that can create volatility in our California oil operations. We have
historically had a long position in natural gas in California where we produce
more natural gas than we consume in thermal crude production. As gas prices
escalated in late 2000, we began to sell our California gas production to the
market rather than consume it in less economic steaming operations. In 2002, we
entered into certain natural gas purchase and crude oil sales hedges to protect
the economic margin on a portion of our thermal oil production beginning in
2003.

6

In California, we generate a total of 13 Megawatts ("MW") of power at
various sites and consume approximately 65% in our operations. Three turbines in
Kern County produce 12 MW of power and cogenerate 15% of our total steam needs
in thermal operation. By self-generating power consumption in Kern County, we
have reduced our exposure to rising electricity prices. With the exception of
the Point Pedernales field, for which we have contracted for firm electric power
service, most of our facilities receive power under interruptible service
contracts. Considering the fact that California has experienced shortages of
electricity and some of our facilities receive interruptible service, we could
experience periodic power interruptions. In addition, the State of California
could increase power costs, change existing rules or impose new rules or
regulations with respect to power that could impact our operating costs.

Production of California San Joaquin Valley heavy oil (defined herein
as those fields which produce primarily 15 degrees API quality crude oil or
heavier through thermal operations) constituted 53% of our total 2002 crude
output. In addition, properties which produce primarily other grades of
relatively heavy oil (generally, 20 degrees API or heavier, but produced through
non-thermal operations) constituted 12% of our total 2002 crude output. The
market price for California heavy oil differs from the established market
indices for oil elsewhere in the U.S., due principally to the higher
transportation and refining costs associated with heavy oil. We entered into a
15-year contract, effective January 1, 2000, to sell all of our current and
future California crude oil production to Tosco Corporation (now
ConocoPhillips). The contract provides pricing based on a fixed percentage of
the NYMEX crude oil price for each type of crude oil that we produce in
California. Effective January 1, 2003, we renegotiated this contract relative to
our Point Pedernales production, effectively increasing our price on 10% of our
2003 crude output by 14.5% on the NYMEX price. While the contract does not
reduce our exposure to price volatility, it does effectively eliminate the risk
of widening basis differential between the NYMEX price and the field price of
our California oil production. In doing so, the contract makes it substantially
easier for us to hedge our realized prices. The ConocoPhillips contract permits
us, under certain circumstances, to separately market up to ten percent of our
California crude oil production. We exercised this right in 2001 and 2002 and
sold 5,000 BOPD of our San Joaquin Valley oil production to a third party under
a one-year contract containing NYMEX pricing. A new contract was entered into
for a two-year period on January 1, 2003.

Our Yombo field production in Marine 1 Permit offshore Congo produces a
relatively heavy crude oil (16-20 degrees API gravity) which is processed into a
low-sulfur, No. 6 fuel oil product for sale to worldwide markets. Production
from this property constituted 11% of our total 2002 oil production. The market
for residual fuel oil differs from the markets for WTI and other benchmark
crudes due to its primary use as an industrial or utility fuel versus the higher
value transportation fuel component, which is produced from refining most grades
of crude oil.

Sales to ConocoPhillips Corporation accounted for 73%, 63% and 84% of
2002, 2001 and 2000 oil and gas revenues. Sales to Torch Energy Marketing
("TEMI") accounted for 23% and 11% of 2001 and 2000 oil and gas revenues. In
January 2003, we brought in house the marketing of our oil production and we no
longer have sales to TEMI. Coral Energy began marketing our natural gas in
January 2002. The loss of any single significant customer or contract could have
a material adverse short-term effect. However, our management does not believe
that the loss of any single significant customer or contract would materially
affect our business in the long-term.

7

REGULATION

Oil and Gas Regulation

The availability of a ready market for oil and gas production depends
upon numerous factors beyond our control. These factors include state and
federal regulation of oil and gas production and transportation, as well as
regulations governing environmental quality and pollution control, state limits
on allowable rates of production by a well or proration unit, the amount of oil
and gas available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
For example, a productive gas well may be "shut-in" because of an over-supply of
gas or lack of an available gas pipeline in the areas in which we may conduct
operations. State and federal regulations are generally intended to prevent
waste of oil and gas, protect rights to produce oil and gas between owners in a
common reservoir, and control contamination of the environment. Pipelines and
gas plants are also subject to the jurisdiction of various Federal, state and
local agencies which may affect the rates at which they are able to process or
transport gas from our properties.

Our sales of natural gas are affected by the availability, terms and
costs of transportation. The rates, terms and conditions applicable to the
interstate transportation of gas by pipelines are regulated by the Federal
Energy Regulatory Commission ("FERC") under the Natural Gas Acts ("NGA"), as
well as under Section 311 of the Natural Gas Policy Act ("NGPA"). Since 1985,
the FERC has implemented regulations intended to increase competition within the
gas industry by making gas transportation more accessible to gas buyers and
sellers on an open-access, non-discriminatory basis.

Our sales of oil are also affected by the availability, terms and costs
of transportation. The rates, terms, and conditions applicable to the interstate
transportation of oil by pipelines are regulated by the FERC under the
Interstate Commerce Act. FERC has implemented a simplified and generally
applicable ratemaking methodology for interstate oil pipelines to fulfill the
requirements of Title VIII of the Energy Policy Act of 1992 comprised of an
indexing system to establish ceilings on interstate oil pipeline rates. The FERC
has announced several important transportation-related policy statements and
rule changes, including a statement of policy and final rule issued February 25,
2000 concerning alternatives to its traditional cost-of-service rate-making
methodology to establish the rates interstate pipelines may charge for their
services. The final rule revises FERC's pricing policy and current regulatory
framework to improve the efficiency of the market and further enhance
competition in natural gas markets.

With respect to transportation of natural gas on the Outer Continental
Shelf ("OCS'), the FERC requires, as a part of its regulation under the Outer
Continental Shelf Lands Act ("OCSLA"), that all pipelines provide open and
non-discriminatory access to both owner and non-owner shippers. Although to date
the FERC has imposed light-handed regulation on offshore facilities that meet
its traditional test of gathering status, it has the authority to exercise
jurisdiction under the OCSLA over gathering facilities, if necessary, to permit
non-discriminatory access to service. For those facilities transporting natural
gas across the OCS that are not considered to be gathering facilities, the
rates, terms and conditions applicable to this transportation are regulated by
FERC under the NGA and NGPA, as well as the OCSLA. With respect to the
transportation of oil and condensate on or across the OCS, the FERC requires, as
part of its regulation under the OCSLA, that all pipelines provide open and
non-discriminatory access to both owner and non-owner shippers. Accordingly, the
FERC has the authority to exercise jurisdiction under the OCSLA, if necessary,
to permit non-discriminatory access to service.

In the event we conduct operations on federal, state or Indian oil and
gas leases, such operations must comply with numerous regulatory restrictions,
including various nondiscrimination statutes, royalty and related valuation
requirements, and certain of such operations must be conducted pursuant to
certain on-site security regulations and other appropriate permits issued by the
Bureau of Land Management ("BLM") or Minerals Management Service ("MMS") or
other appropriate federal or state agencies.

Our OCS leases in federal waters are administered by the MMS and
require compliance with detailed MMS regulations and orders. The MMS has
promulgated regulations implementing restrictions on various production-related
activities, including restricting the flaring or venting of natural gas. Under
certain circumstances, the MMS may require any of our operations on federal
leases to be suspended or terminated. Any

8

such suspension or termination could materially and adversely affect our
financial condition and operations. On March 15, 2000, the MMS issued a final
rule effective June 1, 2000, that amends its regulations governing the
calculation of royalties and the valuation of crude oil produced from federal
leases. Among other matters, this rule amends the valuation procedure for the
sale of federal royalty oil by eliminating posted prices as a measure of value
and relying instead on arm's length sales prices and spot market prices as
market value indicators. Because we generally sell our production to third
parties and pay royalties based on proceeds actually received from the sale of
production from federal leases, it is not anticipated that this final rule will
have a substantial impact on us.

The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or
indirect ownership of any interest in federal onshore oil and gas leases by a
foreign citizen of a country that denies "similar or like privileges" to
citizens of the United States. Such restrictions on citizens of a
"non-reciprocal" country include ownership or holding or controlling stock in a
corporation that holds a federal onshore oil and gas lease. If this restriction
is violated, the corporation's lease can be canceled in a proceeding instituted
by the United States Attorney General. Although the regulations of the BLM
(which administers the Mineral Act) provide for agency designations of
non-reciprocal countries, there are presently no such designations in effect. We
own interests in numerous federal onshore oil and gas leases. It is possible
that holders of equity interests in us may be citizens of foreign countries,
which at some time in the future might be determined to be non-reciprocal under
the Mineral Act.

Our pipelines used to gather and transport our oil and gas are subject
to regulation by the Department of Transportation ("DOT") under the Hazardous
Liquids Pipeline Safety Act of 1979, as amended ("HLPSA") relating to the
design, installation, testing, construction, operation, replacement and
management of pipeline facilities. The HLPSA requires us and other pipeline
operators to comply with regulations issued pursuant to HLPSA designed to permit
access to and allowing copying of records and to make certain reports and
provide information as required by the Secretary of Transportation.

The Pipeline Safety Act of 1992 (The "Pipeline Safety Act") amends the
HLPSA in several important respects. It requires the Research and Special
Programs Administration ("RSPA") of DOT to consider environmental impacts, as
well as its traditional public safety mandate, when developing pipeline safety
regulations. In addition, the Pipeline Safety Act mandates the establishment by
DOT of pipeline operator qualification rules requiring minimum training
requirements for operators, and requires that pipeline operators provide maps
and records to RSPA. It also authorizes RSPA to require certain pipeline
modifications as well as operational and maintenance changes. We believe our
pipelines are in substantial compliance with HLPSA and the Pipeline Safety Act.
Nonetheless, significant expenses would be incurred if new or additional safety
measures are required.

Environmental Regulation

General. Our activities are subject to existing federal, state and
local laws and regulations governing environmental quality and pollution control
in the United States and may be subject to laws and regulations of the Republic
of Congo, West Africa. It is anticipated that, absent the occurrence of an
extraordinary event, compliance with existing federal, state and local laws,
rules and regulations governing the release of materials in the environment or
otherwise relating to the protection of the environment will not have a material
effect upon our operations, capital expenditures, earnings or competitive
position.

Our activities with respect to exploration, drilling and production
from wells, natural gas facilities, including the operation and construction of
pipelines, plants and other facilities for transporting, processing, treating or
storing natural gas and other products, are subject to stringent environmental
regulation by state and federal authorities including the Environmental
Protection Agency ("EPA"). Such regulation can increase the cost of planning,
designing, installing and operating such facilities. In most instances, the
regulatory requirements relate to water and air pollution control measures. (See
Note 12 to the Notes to the Consolidated Financial Statements).

With respect to our oil and gas operations in California, we have
significant exit cost liabilities. These liabilities include costs for
dismantlement, rehabilitation and abandonment. As of December 31, 2002, our
total estimated costs for future dismantlement, abandonment and site restoration
was $177.6 million. We are not indemnified for any part of these exit costs.
(See Note 2 to the Notes to the Consolidated Financial Statements).

9

Waste Disposal. We currently own or lease, and have in the past owned
or leased, numerous properties that have been used for production of oil and gas
for many years. Although we utilized operating and disposal practices that were
standard in the industry at the time, hydrocarbons or other wastes may have been
disposed of or released on or under the properties that we currently own or
lease or properties that we have in the past owned or leased. In addition, many
of these properties have been operated by third parties over whom we had no
control as to such entities' treatment of hydrocarbons or other wastes or the
manner in which such substances may have been disposed of or released. State and
federal laws applicable to oil and gas wastes and properties have become
stricter. Under new laws, we could be required to remediate property, including
ground water, containing or impacted by previously disposed wastes (including
wastes disposed of or released by prior owners or operators) or to perform
remedial plugging operations to prevent future or mitigate existing
contamination.

We may generate wastes, including hazardous wastes that are subject to
the federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The EPA has limited the disposal options for certain wastes that are
designated as hazardous under RCRA ("Hazardous Wastes"). Furthermore, it is
possible that certain wastes generated by our oil and gas operations that are
currently exempt from treatment as Hazardous Wastes may in the future be
designated as Hazardous Wastes, and therefore be subject to more rigorous and
costly operating and disposal requirements.

Superfund. The federal Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law,
imposes joint and several liability for costs of investigation and remediation
and for natural resource damages, without regard to fault or the legality of the
original conduct, on certain classes of persons with respect to the release into
the environment of substances designated under CERCLA as hazardous substances
("Hazardous Substances"). These classes of persons or potentially responsible
parties ("PRP's") include the current and certain past owners and operators of a
facility where there is or has been a release or threat of release of a
Hazardous Substance and persons who disposed of or arranged for the disposal of
the Hazardous Substances found at such a facility. CERCLA also authorizes the
EPA and, in some cases, third parties to take actions in response to threats to
the public health or the environment and to seek to recover from the PRP's the
costs of such action. Although CERCLA generally exempts petroleum from the
definition of Hazardous Substances in the course of our operations, we may have
generated and may generate wastes that fall within CERCLA's definition of
Hazardous Substances. We may also be an owner of facilities on which Hazardous
Substances have been released by previous owners or operators. We may be
responsible under CERCLA for all or part of the costs to clean up facilities at
which such substances have been released and for natural resource damages. Crude
oil exempt under Superfund may be modified increasing compliance costs. We have
not been named a PRP under CERCLA nor do we know of any prior owners or
operators of our properties that are named as PRP's related to their ownership
or operation of such property.

Air Emissions. Our operations are subject to local, state and federal
regulations for the control of emissions of air pollution. Local air quality
districts do much of the air quality regulation of sources in California.
California requires new and modified sources of air pollutants to obtain permits
prior to commencing construction. Major sources of air pollutants are subject to
more stringent, federally imposed permitting requirements, including additional
permits. Because of the severity of the ozone (smog) problems in portions of
California, the state has the most severe restrictions on the emissions of
volatile organic compounds (VOC) and nitrogen oxides (Nox) of any state.
Producing wells, gas plants and electric generating facilities, all of which are
owned by us generate VOC and Nox. Some of our producing wells are in counties
that are designated as nonattainment for ozone and are therefore potentially
subject to restrictive emission limitations and permitting requirements. If the
ozone problems in the state are not resolved by the deadlines imposed by the
federal Clean Air Act (2005 - 2010), even more restrictive requirements may be
imposed including financial penalties based upon the quantity of ozone producing
emissions. California also operates a stringent program to control hazardous
(toxic) air pollutants, which might require installation of additional controls.
Administrative enforcement actions for failure to comply strictly with air
pollution regulations or permits are generally resolved by payment of monetary
fines and correction of any identified deficiencies. Alternatively, regulatory
agencies could require us to forego construction, modification or operation of
certain air emission sources, although we believe that in the latter cases we
would have enough permitted or permittable capacity to continue our operations
without a material adverse effect on any particular producing field.

10

Clean Water Act. The Clean Water Act ("CWA") imposes restrictions and
strict controls regarding the discharge of wastes, including produced waters and
other oil and natural gas wastes, into waters of the United States, a term
broadly defined. These controls have become more stringent over the years, and
it is probable that additional restrictions will be imposed in the future.
Permits must be obtained to discharge pollutants into federal waters. The CWA
provides for civil, criminal and administrative penalties for unauthorized
discharges of oil, hazardous substances and other pollutants. It imposes
substantial potential liability for the costs of removal or remediation
associated with discharges of oil or hazardous substances. State laws governing
discharges to water also provide varying civil, criminal and administrative
penalties and impose liabilities in the case of a discharge of petroleum or it
derivatives, or other hazardous substances, into state waters. In addition, the
EPA has promulgated regulations that may require us to obtain permits to
discharge storm water runoff, including discharges associated with construction
activities. In the event of an unauthorized discharge of wastes, we may be
liable for penalties and costs.

Oil Pollution Act. The Oil Pollution Act of 1990 ("OPA"), which amends
and augments oil spill provisions of CWA, imposes certain duties and liabilities
on "responsible parties" related to the prevention of oil spills and damages
resulting from such spills in United States waters and adjoining shorelines. A
"responsible party" includes the owner or operator of a facility or vessel, that
is a source of an oil discharge or poses the substantial threat of discharge, or
the lessee or permittee of the area in which a facility covered by OPA is
located. OPA assigns joint and several liability, without regard to fault, to
each responsible party for oil removal costs and a variety of public and private
damages. Few defenses exist to the liability imposed by OPA. In the event of an
oil discharge, or substantial threat of discharge from our properties, vessels
and pipelines, we may be liable for costs and damages.

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. Certain amendments to the OPA that were enacted in 1996 require
owners and operators of offshore facilities that have a worst case oil spill
potential of more than 1,000 barrels to demonstrate financial responsibility in
amounts ranging from $10 million in specified state waters and $35 million in
federal outer continental shelf waters, with higher amounts, up to $150 million
based upon worst case oil-spill discharge volume calculations. We believe that
we currently have established adequate proof of financial responsibility for our
offshore facilities.

California Coastal Act. The California Coastal Act regulates the
conservation and development of California's coastal resources. The California
Coastal Commission ("The Commission") works with local government to make permit
decisions for new development in certain coastal areas and reviews local coastal
programs, such as land use restrictions. The Commission also works with the
California State Office of Oil Spill Prevention and Response to protect against
and respond to coastal oil spills. The Commission has direct regulatory
authority over offshore oil and gas development within the State's three mile
jurisdiction and has authority, through the Federal Coastal Zone Management Act,
over federally permitted projects that affect the State's coastal zone
resources. We conduct activities that may be subject to the California Coastal
Act and the jurisdiction of The Commission.

Our management believes that we are in substantial compliance with
current applicable environmental laws and regulations and that continued
compliance will not have a material adverse impact on us.

COMPETITION

We operate in the highly competitive areas of oil and gas exploration,
development and production. The availability of funds and information relating
to a property, the standards established by us for the minimum projected return
on investment and the availability of alternate fuel sources are factors that
affect our ability to compete in the marketplace. Competitors include major
integrated oil companies and a substantial number of independent energy
companies, many of which possess greater financial and other resources. We
compete to acquire producing properties, exploration leases, licenses,
concessions and marketing agreements.

11

PERSONNEL

At December 31, 2002, we had 412 full time employees. In 2002, we
brought California field operations, oil marketing, human resources, accounting,
treasury and land administration in house.

ITEM 2. PROPERTIES

A description of our properties is included in Item 1, Business, and is
incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS

See Item 7, Management's Discussion and Analysis of Financial Condition
and Results of Operations, which is incorporated herein by reference.

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

None.

12

PART II

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

Our common stock is traded is the New York Stock Exchange under the
Symbol NEV. On March 24, 2003, we had 19,209,290 shares of common stock
outstanding. There were approximately 955 stockholders of record and
approximately 2,566 additional beneficial owners as of March 24, 2003. We have
not paid dividends on our common stock and do not anticipate paying cash
dividends in the immediate future. In addition, certain restrictions contained
in our financing arrangements restrict the payment of dividends. See Note 9 to
the Notes to Consolidated Financial Statements. The high and low recorded prices
of our common stock during 2002 and 2001 are presented in the following table.

Treasury Stock Repurchases

Our Board of Directors has authorized the open market repurchase of up
to 5.6 million shares of common stock. Repurchases may be made at times and at
prices deemed appropriate by management and consistent with the authorization of
our Board. There were no shares repurchased in 2002. As of December 31, 2002, we
had 3.9 million shares of treasury stock.

Shareholder Rights Plan

In 1997, we adopted a Shareholder Rights Plan to protect our
shareholders from coercive or unfair takeover tactics. Under the Shareholder
Rights Plan, each outstanding share and each share of subsequently issued common
stock has attached to it one Right. Generally, in the event a person or group
("Acquiring Person") acquires or announces an intention to acquire beneficial
ownership of 15% or more of the outstanding shares of common stock without our
prior consent, or we are acquired in a merger or other business combination, or
50% or more of our assets or earning power is sold, each holder of a Right will
have the right to receive, upon exercise of the Right, that number of shares of
common stock of the acquiring company, which at the time of such transaction
will have a market price of two times the exercise price of the Right. We may
redeem the Right for $0.01 at any time before a person or group becomes an
Acquiring Person without prior approval. The Rights will expire on March 21,
2007, subject to earlier redemption by us.

In 2000, we amended the Shareholder Rights Plan to provide that if we
receive and consummate a transaction pursuant to a qualifying offer, the
provisions of the Shareholder Rights Plan are not triggered. In general, a
qualifying offer is an all cash, fully funded tender offer for all of our
outstanding common stock by a person who, at the commencement of the offer,
beneficially owns less than 5% of the outstanding common stock. A qualifying
offer must remain open for at least 120 days, must be conditioned on the person
commencing the qualifying offer acquiring at least 75% of the outstanding common
stock and the per share consideration must exceed the greater of: (1) 135% of
the highest closing price of our common stock during the one-year period prior

13

to the commencement of the qualifying offer or (2) 150% of the average closing
price of our common stock during the 20 day period prior to the commencement of
the qualifying offer.

Executive Compensation Plan

In 1997, we adopted a plan to encourage senior executives to personally
invest in our stock, and to regularly review executives' ownership versus
targeted ownership objectives. These incentives include a deferred compensation
plan (the "Plan") that gives key executives the ability to defer all or a
portion of their salaries and bonuses and invest in our common stock or make
other investments at the employee's discretion. Stock acquired at a discount
prior to the 2001 amendment of the Plan is restricted for a two-year period. All
stock acquired is held in a benefit trust. Target levels of ownership are based
on multiples of base salary and are administered by the Compensation Committee
of the Board of Directors. The Plan applies to certain highly compensated
employees and all executives at a level of Vice-President and above. The Plan
was amended in 2001 to remove the discount on investments in our common stock
and to provide additional investment alternatives. The Plan was further amended
in July 2002 to remove the right to receive withdrawals in cash.

14

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data should be read in conjunction
with the consolidated financial statements and supplementary information
included in Item 8, Financial Statements and Supplementary Data.

- ----------
(1) No common stock dividends have been declared since our formation. See
Note 9 to the Notes to Consolidated Financial Statements concerning
restrictions on the payment of common stock dividends

15

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

Nuevo Energy is engaged in the acquisition, exploitation, development,
exploration and production of crude oil and natural gas. Our core areas in the
U.S. are onshore and offshore California and West Texas. We also have
international crude oil production in the Republic of Congo. The following
review should be read in conjunction with our Consolidated Financial Statements
and Notes thereto.

In September 2002, we acquired Athanor Resources, Inc. (Athanor).
Effective September 18, 2002, the results of Athanor's operations are included
in the consolidated financial statements. The purchase price totaling
approximately $101.4 million was comprised of a combination of $61.3 million of
available cash and additional borrowings, the issuance of approximately $20.1
million of our common stock to Athanor stockholders, and the assumption of net
liabilities with a fair value of approximately $20.0 million. The allocation of
the purchase price resulted in the allocation of approximately $19.7 million to
goodwill.

RESULTS OF OPERATIONS

Our results of operations are significantly affected by fluctuations in
oil and gas prices. The following table reflects our production and average
prices for oil and natural gas:

16

YEAR ENDED DECEMBER 31, 2002 COMPARED TO YEAR ENDED DECEMBER 31, 2001

We had net income of $12.3 million, or $0.69 per diluted share for 2002
as compared to a net loss of $79.2 million, or ($4.73) per diluted share in
2001.

Revenues

Oil and Gas Revenues. Oil and gas revenues were $319.0 million in 2002
compared to $327.0 million in 2001 principally due to lower natural gas prices
which were partially offset by higher crude oil prices realized, lower hedging
losses and higher crude oil and natural gas production. The realized oil price
in 2002 was $18.21 per Bbl, an increase of $2.29 per Bbl from 2001. Crude oil
production averaged 42.9 MBbls/day in 2002, an increase of 0.4 MBbls/day from
2001. The increased production was due to higher production at Point Pedernales
and Santa Clara due to improved performance which was partially offset by lower
production at Cymric where production was curtailed for well repairs. We had a
hedging loss of $9.4 million in 2002 compared to a hedging loss of $47.6 million
in 2001. Natural gas production averaged 34.4 MMcf per day in 2002, an increase
of 13% from 30.5 MMcf per day in 2001 primarily due to production from the
Pakenham field acquired in September 2002. The realized natural gas price in
2002 was $2.69 per Mcf, which decreased 63% from $7.18 per Mcf in 2001.

Other Revenue. Other revenue of $4.1 million in 2002 was $3.8 million
higher than 2001 principally due to $3.0 million of business interruption
insurance recoveries received in 2002, related to the repair of our pipelines at
the Point Pedernales field.

Costs and Expenses

Costs and Expenses. Lease operating expenses ("LOE") of $138.0 million
in 2002 decreased 17% from 2001. We use gas as a feedstock to generate steam
which is injected into reservoirs to facilitate the production of heavy
California oil. Excluding the cost of steam used in our oil production
operations, LOE decreased 12% in 2002 compared to 2001. Exploration costs of
$4.5 million in 2002 were $17.6 million lower than $22.1 million in 2001. The
2002 exploration costs included a $2.3 million non-cash write off the Anaguid
permit in Tunisia which was conveyed to third parties while the 2001 costs
included $14.1 million of dry hole costs. Depreciation, depletion and
amortization ("DD&A") was $75.3 million in 2002 compared to $71.6 million in the
prior year primarily due to higher production and a higher DD&A rate. The DD&A
rate was $4.24 per BOE in 2002 compared to $4.12 per BOE in 2001. Due to lower
outsourcing costs, legal fees and project costs, general and administrative
expense of $25.9 million in 2002 was $11.0 million lower than 2001. We had no
impairments in 2002 compared to $103.5 million in 2001. The impairment in 2001
was on our Santa Clara, Huntington Beach, Pitas Point, Masseko (Congo) and Point
Pedernales fields and certain other oil and gas properties. In 2002, there were
no restructuring and severance charges as compared to $4.9 million in 2001. The
2001 restructuring charges were related to the termination of two outsourcing
contracts and the reorganization of our exploration and production operations.
Other expenses were $1.9 million in 2002 compared to $14.9 million in 2001 which
included the termination of hedging contracts with Enron and various consulting
and legal costs.

Loss on Assets Held for Sale. In 2002, we made the decision to sell
certain real estate in California. Accordingly, we transferred the underlying
net book value of this real estate to assets held for sale and recorded a $1.3
million loss, representing the write down to its estimated fair market value,
less costs to sell. In 2001, we made the decision not to proceed with our power
plant project in Santa Barbara and Kern County California and transferred our
remaining equipment to assets held for sale and recorded a $3.5 million loss
representing the write down to estimated fair market value less estimated costs
to sell these assets. (See Note 4 to the Consolidated Financial Statements.)

Gain on Disposition of Properties. Our net gain from the sales of
assets for 2002 of $16.6 million was primarily related to the settlement
agreement with ExxonMobil, where we conveyed to them our interest in the Santa
Ynez Unit, our non-consent interest in the adjacent Pescado field and
relinquished our right to participate in the Sacate field, all of which were
unproved properties. In 2001, the gain on disposition of properties of $0.9
million is primarily related to the gain of $1.1 million from our sale of a
parcel of real estate in Brea, California.

17

Derivative Gain (Loss). Our derivative loss was $4.7 million in 2002
compared to a gain of $0.2 million in 2001. The derivative loss in 2002 includes
mark-to-market losses on derivatives which did not qualify as hedges and
ineffectiveness on hedges.

Interest Expense. Interest expense of $37.9 million in 2002 decreased
12% compared to interest expense of $43.0 million in 2001 due to the benefit of
our interest rate swaps in 2002 of $5.4 million.

Dividends. Dividends on the TECONS were $6.6 million in 2002 and 2001.
The TECONS pay dividends at a rate of 5.75%. (See Note 10 to the Notes to
Consolidated Financial Statements.)

Income Tax. We had income tax expense of $18.2 million including
current tax of $1.3 million in 2002 compared to a tax benefit of $57.9 million
in 2001 which had no current tax. The current tax relates to California State
income tax which deferred the use of net operating losses for two years. Our
effective income tax rate was 41.7% in 2002 and 40.1% in 2001.

Discontinued Operations. We had a loss from discontinued operations of
$13.2 million in 2002 compared to income of $7.4 million in 2001. In 2002, we
sold our properties located in Texas, Alabama and Louisiana (Eastern properties)
for approximately $9.0 million and recognized a $0.9 million after-tax loss. We
also made the decision to sell our Brea-Olinda field in California in 2002 and
recognized a $30.5 million loss in connection with writing down the associated
assets to their estimated fair value less our costs to sell them. In 2001 the
income from discontinued operations consists of after-tax operating income from
our Eastern properties and Brea-Olinda field.

YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000

We had a net loss of $79.2 million for 2001, or ($4.73) per diluted
share as compared to net income of $11.6 million, or $0.64 per diluted share in
2000.

Revenues

Oil and Gas Revenues. Oil and gas revenues increased 14% to $327.0
million in 2001 from $286.5 million in 2000 principally due to higher commodity
prices and lower hedging losses during 2001, partially offset by lower
production. The realized oil price in 2001 was $15.92 per Bbl, an increase of
$1.69 per Bbl from 2000. Crude oil production averaged 42.5 MBbls/day, a
decrease of 2.4 MBbls/day due to an eight-month curtailment of steaming
operations in California as well as production shut-ins for facility repairs in
2001. Our hedging losses were $47.6 million in 2001 and $117.7 million in 2000.
Natural gas production averaged 30.5 MMcf per day in 2001, declining 10% from
33.8 MMcf per day in 2000. The decline was due to lower domestic production
offshore California. The 2001 realized natural gas price was $7.18 per Mcf,
which increased 67% from $4.31 per Mcf in 2000.

Costs and Expenses

Costs and Expenses. LOE for 2001 totaled $167.2 million, as compared to
$140.2 million for 2000. The 19% increase in LOE from 2000 to 2001 is primarily
due to a 67% increase in gas prices in 2001 compared to 2000. We use gas as a
feedstock to generate steam which is injected into reservoirs to facilitate the
production of heavy California oil. Exploration costs, including geological and
geophysical costs, dry hole costs and delay rentals, were $22.1 million in 2001,
an increase of $12.3 million from 2000, primarily due to $14.1 million of dry
hole costs associated with non-commercial wells drilled onshore California and
certain international properties. Depreciation, depletion and amortization
increased 21% in 2001 to $71.6 million due to higher depletion rates which were
primarily driven by a lower reserve base. General and administrative expense of
$36.9 million in 2001 was $3.9 million higher than 2000 primarily due to higher
investment advisory fees.

Impairments of Oil and Gas Properties. During 2001, we recorded an
impairment totaling $103.5 million on our Santa Clara, Huntington Beach, Pitas
Point, Masseko (Congo) and Point Pedernales fields and certain other oil and gas
properties. Statement of Financial Accounting Standards ("SFAS") No. 144
requires an impairment

18

loss be recognized when the carrying value of an asset exceeds the sum of the
undiscounted estimated future net cash flows. We recognized an impairment loss
equal to the difference between the carrying amount and the fair value of the
assets. We had no impairments in 2000. (See Note 2 to the Notes to the
Consolidated Financial Statements.)

Restructuring and Severance Charges. We incurred $4.9 million of
restructuring and severance charges in 2001 related to the termination of two
outsourcing contracts and the reorganization of our exploration and production
operations. These costs included termination fees and severance. We had no such
costs in 2000. (See Note 5 to the Notes to the Consolidated Financial
Statements.)

Loss on Assets Held for Sale. In 2001, we made the decision not to
proceed with our power plant project in Santa Barbara and Kern County,
California and transferred our remaining equipment to assets held for sale and
recorded a $3.5 million loss representing the write down to estimated fair
market value less estimated costs to sell these assets. We had no such costs in
2000. (See Note 4 to the Notes to the Consolidated Financial Statements.)

Other Expenses. Other expenses were $14.9 million in 2001 increased
$9.8 million from 2000 principally due to the termination of hedging contracts
with Enron and various consulting and legal costs.

Gain on Disposition of Properties. Our net gain from the sales of
assets for 2001 was $0.9 million, primarily related to the $1.1 million gain
from our sale of real estate in Brea, California. The net gain on sale of assets
for 2000 was $0.7 million primarily representing a $0.9 million gain on the sale
of our working interest in the Las Cienegas field in California.

Interest Income and Interest Expense. Interest income for 2001 of $1.3
million was earned on the overnight investment of excess cash. Interest income
for 2000 of $1.9 million resulted from higher cash balances in 2000. Interest
expense of $43.0 million in 2001 increased 15% compared to interest expense of
$37.5 million in 2000. The increase is primarily due to the inclusion of a full
year of interest for our 9 ?% Senior Subordinated Notes issued in September
2000, offset by a decrease in the use of a line of credit and an increase of
interest capitalized.

Dividends. Dividends on the TECONS were $6.6 million in 2001 and 2000.
The TECONS pay dividends at a rate of 5.75%. (See Note 10 to the Notes to
Consolidated Financial Statements.)

Income Tax. We had an income tax benefit of $57.9 million in 2001
compared to minimal income tax expense in 2000. Our effective income tax rate
was 40.1% in 2001 and 40.3% in 2000.

Discontinued Operations. We had income from discontinued operations of
$7.4 million in 2001 compared to income of $12.4 million in 2000. This
represents our operating income from the Eastern properties sold in 2002 and the
Brea-Olinda field sold in 2003.

CAPITAL RESOURCES AND LIQUIDITY

We have grown and diversified our operations through low-cost
acquisitions of oil and gas properties and the subsequent exploitation and
development of these properties. We have historically funded our operations and
acquisitions with operating cash flows, bank financing, private and public
placements of debt and equity securities, property divestitures and joint
ventures with industry participants.

Net cash provided by operating activities was $122.7 million, $88.9
million and $94.5 million in 2002, 2001 and 2000. We invested $74.5 million,
$133.2 million and $105.2 million in oil and gas properties in 2002, 2001 and
2000. Additionally, we spent $5.7 million, $8.6 million, and $3.4 million on
other properties in 2002, 2001 and 2000.

In 2002, we acquired Athanor Resources, Inc. for approximately $101.4
million including $61.3 million of available cash. In 2001, we acquired a
producing property in California for $28.5 million.

19

We believe our working capital, cash flow from operations and available
financing sources are sufficient to meet our obligations as they become due and
to finance our capital budget through 2003. Under our Credit Agreement which
provides for secured revolving credit, we have a $175.0 million borrowing base
with $146.3 million available and undrawn at December 31, 2002 and had drawn
$28.7 million under the agreement. In late December 2001, and early January
2002, we entered into interest rate swaps totaling $200 million; $150.0 million
on our 9 3/8% Notes and $50.0 million on our 9 1/2% Notes. In late August and
early September 2002, we terminated our swap transactions relating to these
Notes and received $12.1 million which will be amortized as a credit to interest
expense through 2008 and 2010. In late August and early November 2002, we
entered into interest rate swaps totaling $100.0 million on our 9 3/8% Notes.
(See Item 7A, Qualitative and Quantitative Disclosures About Market Risk).

CONTRACTUAL CASH OBLIGATIONS

The following table summarizes our contractual cash obligations by
payment due date:

Long-term Debt

The following table details our long-term debt (excluding outstanding
borrowings under our bank credit facility and interest rate swaps) at December
31:

9 3/8% Notes due 2010. In 2000, we issued $150.0 million of 9 3/8%
Senior Subordinated Notes due October 1, 2010. Interest on these Notes accrues
at 9 3/8% per annum and is payable semi-annually in arrears on April 1 and
October 1. The Notes are redeemable, in whole or in part, at our option, on or
after October 1, 2005, under certain conditions. We are not required to make
mandatory redemption or sinking fund payments with respect to these Notes. The
Notes are unsecured general obligations, and are subordinated in right of
payment to all existing and future senior indebtedness. In the event of a
defined change in control, we will be required to make an offer to repurchase
all outstanding 9 3/8% Notes at 101% of the principal amount, plus accrued and
unpaid interest to the date of redemption.

9 1/2% Notes due 2008. In July 1999, we authorized a new issuance of
$260.0 million of 9 1/2% Senior Subordinated Notes due June 1, 2008. In August
1999, we exchanged $157.5 million of our 9 1/2% Notes due 2006 and $99.9 million
of our 8 7/8% Senior Subordinated Notes due 2008. In connection with the
exchange offers, we solicited consents to proposed amendments to the indentures
under which the exchanged notes were issued. Interest on these Notes accrues at
the rate of 9 1/2% per annum and is payable semi-annually in arrears on June 1
and December 1. These Notes are redeemable, in whole or in part, at our option,
on or after June 1, 2003, under certain conditions. We are not required to make
mandatory redemption or sinking fund payments on these Notes. The 9 1/2% Notes
are unsecured general obligations, and are subordinated in right of payment to
all existing and future senior indebtedness. In the event of a defined change in
control, we will be required to make an offer to

20

repurchase all outstanding Notes at 101% of the principal amount, plus accrued
and unpaid interest to the date of redemption.

9 1/2% Notes due 2006. In 1996, we issued $160.0 million of 9 1/2%
Notes and in 1999, we exchanged $157.5 million of these Notes for 9 1/2% Notes
due 2008 and have repurchased some of the Notes in the open market. Interest on
these Notes accrues at the rate of 9 1/2% per annum and is payable semi-annually
in arrears on April 15 and October 15 and are redeemable, in whole or in part,
at our option, on or after April 15, 2001, under certain conditions. These Notes
have not been redeemed, in whole or in part, at December 31, 2002. We are not
required to make mandatory redemption or sinking fund payments with respect to
these Notes and they are unsecured general obligations, and are subordinated in
right of payment to all existing and future senior indebtedness.

Operating Leases

We have operating leases in the normal course of business, which
include those for office space and operating facilities and office and operating
equipment, with varying terms from 2002 to 2009. At December 31, 2002, our total
commitments under operating leases were approximately $8.9 million.

Minimum annual rental commitments at December 31, 2002, were as
follows:

Capital Commitments

At December 31, 2002, we had capital commitments of $0.5 million
relating to our international oil and gas exploration and development activity.
In early 2003, we fulfilled this obligation. Our other planned capital projects
are discretionary in nature, with no substantial capital commitments made in
advance of the actual expenditures.

COMMERCIAL COMMITMENTS

The following table summarizes our Commercial Commitments by date of
expiration. Each of these commitments is discussed in further detail below:

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Lines of Credit

Bank Credit Facility. Our Third Amended and Restated Credit Agreement,
dated June 7, 2000, provides for secured revolving credit availability of up to
$250 million and issuance of letters of credit from a bank group led by Bank of
America, N.A., Bank One, N.A., and Bank of Montreal until its expiration on June
7, 2005.

Availability under the Credit Facility is determined pursuant to a
semi-annual borrowing base determination which establishes the maximum
borrowings that may be outstanding under the credit facility. The borrowing base
is determined by a 60% vote of participant banks (two-thirds in the event of an
increase in the borrowing base), each of which bases its judgement on: (i) the
present value of our oil and gas reserves based on their own assumptions
regarding future prices, production, costs, risk factors and discount rates, and
(ii) projected cash flow coverage ratios calculated under varying scenarios. If
amounts outstanding under the credit facility exceed the borrowing base, as
redetermined from time to time, we would be required to repay such excess over a
defined period of time. We have a $175.0 million borrowing base under our Credit
Facility with $146.3 million available at December 31, 2002 and had drawn $28.7
million under the agreement. Amounts outstanding under the credit facility bear
interest at a rate equal to the London Interbank Offered Rate ("LIBOR") plus an
amount which varies according to our Indebtedness to Capitalization ratio (as
defined under the Credit Agreement).

Letters of Credits

We had one letter of credit outstanding at December 31, 2002 in the
amount of $0.8 million, which expires in August 2003.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Oil and Gas Properties

We use the successful efforts method to account for our investments in
oil and gas properties. Under the successful efforts method, oil and gas lease
acquisition costs and intangible drilling costs associated with exploration
efforts that result in the discovery of proved reserves and costs associated
with development drilling, whether or not successful, are capitalized when
incurred. When a proved property is sold, ceases to produce or is abandoned, a
gain or loss is recognized. When an entire interest in an unproved property is
sold for cash or cash equivalent, a gain or loss is recognized, taking into
consideration any recorded impairment. When a partial interest in an unproved
property is sold, the amount received is treated as a reduction of the cost of
the interest retained.

Costs of successful wells, development dry holes and proved leases are
capitalized and depleted on a unit-of-production basis over the remaining proved
reserves. Capitalized drilling costs are depleted on a unit-of-production basis
over the lives of the remaining proved developed reserves. Total estimated costs
of $177.6 million for future dismantlement, abandonment and site remediation are
included when calculating depreciation and depletion using the
unit-of-production method. Through December 31, 2002, we had recorded $81.4
million as a component of accumulated depreciation, depletion and amortization
related to this future obligation. See Note 2 to the Consolidated Financial
Statements for a discussion of the provisions of SFAS No. 143, which will be
adopted effective January 1, 2003.

In October 2001, the Financial Accounting Standards Board ("FASB")
issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived
Assets. This Statement requires that long-lived assets that are to be disposed
of by sale be measured at the lower of book value or fair value less cost to
sell. The standard also expanded the scope of discontinued operations to include
all components of an entity with operations that can be distinguished from the
rest of the entity and that will be eliminated from the ongoing operations of
the entity in a disposal transaction. We adopted the provisions of this
statement effective January 1, 2002 and have presented certain property
dispositions as discontinued operations in accordance with SFAS No. 144. (See
Note 4 to the Notes to the Consolidated Financial Statements).

22

In accordance with SFAS No. 144, we review our long-lived assets to be
held and used, including proved oil and gas properties accounted for using the
successful efforts method of accounting, on a depletable unit basis whenever
events or circumstances indicate that the carrying value of those assets may not
be recoverable. SFAS No. 144 requires an impairment loss to be recognized when
the carrying amount of an asset exceeds the sum of the undiscounted estimated
future net cash flows and we recognize an impairment loss equal to the
difference between the carrying value and the fair value of the asset. Fair
value is estimated to be the expected present value of future net cash flows
from proved reserves, utilizing a risk-free rate of return. During 2001, we
recorded an impairment totaling $103.5 million on our Santa Clara, Huntington
Beach, Pitas Point, Masseko (Congo) and Point Pedernales fields and certain
other oil and gas properties. We recorded no impairments in 2000 and only those
required to be taken for the assets designated as held for sale in 2002. Also,
in accordance with SFAS No. 144, when the proved properties are classified as
held for sale, if the carrying amount of the assets is less than their fair
market value less our estimated costs to sell them, the difference is recognized
as a loss in that period and, if significant, the associated results of
operations are accounted for as discontinued.

Unproved leasehold costs are capitalized pending the results of
exploration efforts. Significant unproved leasehold costs are reviewed
periodically and a loss is recognized to the extent, if any, that the cost of
the property has been impaired. Exploration costs, including geological and
geophysical expenses, exploratory dry holes and delay rentals are charged to
expense as incurred.

During 2002 and 2001, interest costs associated with non-producing
leases and exploration and development projects were capitalized only for the
period that activities were in progress to bring these projects to their
intended use. The capitalization rates were based on our weighted average cost
of funds used to finance expenditures. We capitalized $1.9 million and $2.5
million of interest costs in 2002 and 2001. There were no interest costs
capitalized in 2000.

Recognition of Crude Oil and Natural Gas Revenue

Crude oil and natural gas revenue is recognized when title passes to
the purchaser. We use the entitlement method for recording sales of crude oil
and natural gas from producing wells. Under the entitlement method, revenue is
recorded based on our net revenue interest in production. Deliveries of crude
oil and natural gas in excess of our net revenue interests are recorded as
liabilities and under-deliveries are recorded as assets. Production imbalances
are recorded at the lower of the sales price in effect at the time of production
or the current market value. Substantially all such amounts are anticipated to
be settled with production in future periods. We did not have a material
imbalance position in terms of units or value at December 31, 2002 or 2001.

Derivative Financial Instruments and Price Risk Management Activities

We use price risk management activities to manage non-trading market
risks. We use derivative financial instruments such as swaps, collars and
options to hedge the impact market price risk exposures on our crude oil and
natural gas production, natural gas purchases and to mitigate our exposure to
interest rate risk. We account for derivatives under SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities, and have elected to designate
derivative instruments that qualify for hedge accounting as cash flow hedges
(for commodity related contracts) and fair value hedges (for interest rate
contracts).

Goodwill and Other Intangible Assets

In June 2001, the FASB issued SFAS No. 142, Goodwill and Other
Intangible Assets. This Statement requires discontinuing amortization of
goodwill after 2001 and requires that goodwill be tested for impairment. The
impairment test requires allocating goodwill and all other assets and
liabilities to business levels referred to as reporting units. The fair value of
each reporting unit that has goodwill is determined and compared to the book
value of the reporting unit. If the fair value of the reporting unit is less
than the book value (including goodwill), then a second test is performed to
determine the amount of the impairment.

If the second test is necessary, the fair value of the reporting unit's
individual assets and liabilities is deducted from the fair value of the
reporting unit. This difference represents the implied fair value of goodwill,

23

which is compared to the book value of the reporting unit's goodwill. Any excess
of the book value of goodwill over the implied fair value of goodwill is the
amount of the impairment.

The goodwill impairment test is performed annually, in the fourth
quarter and also at interim dates upon the occurrence of significant events.
Significant events include: a significant adverse change in legal factors or
business climate; an adverse action or assessment by a regulator; a
more-likely-than-not expectation that a reporting unit or significant portion of
a reporting unit will be sold; significant adverse trends in current and future
oil and gas prices; nationalization of any of the Company's oil and gas
properties; or, significant increases in a reporting unit's carrying value
relative to its fair value.

We adopted the provisions of this statement on January 1, 2002. We
recorded $19.7 million of goodwill in connection with our acquisition of Athanor
Resources, Inc. (See Note 3). The goodwill is recorded in our domestic reporting
unit. The annual impairment test will be performed in the fourth quarter of each
year, or more often if required.

Oil and Gas Reserves

There are uncertainties inherent in estimating crude oil and natural
gas reserve quantities, projecting future production rates and projecting 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 reserves are the estimated quantities of
crude oil, condensate and natural gas that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions at the end of
the respective years. Proved developed reserves are those reserves expected to
be recovered through existing equipment and operating methods.

NEW ACCOUNTING PRONOUNCEMENTS

Accounting for Asset Retirement Obligations. In August 2001, the FASB
issued SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement
requires companies to record a liability relating to the eventual retirement and
removal of assets used in their business. The liability is discounted to its
present value, with a corresponding increase to the related asset value. Over
the life of the asset, the liability will be accreted to its future value and
eventually extinguished when the asset is taken out of service. The provisions
of this Statement are effective for fiscal years beginning after June 15, 2002.
We will adopt the provisions of SFAS No. 143 effective January 1, 2003. In
connection with the initial application of SFAS No. 143, it is expected we will
record a cumulative effect of change in accounting principle, net of taxes, of
approximately $10 million to $15 million as an increase to net income, which
will be reflected in our results of operations for 2003. In addition, it is
expected we will record an asset retirement obligation of approximately $75
million to $80 million.

Accounting for Costs Associated with Exit or Disposal Activities. In
July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal Activities. This statement requires the recognition of costs
associated with exit or disposal activities when they are incurred rather than
at the date of a commitment to an exit or disposal plan. The provisions of this
Statement are effective for exit or disposal activities initiated after December
31, 2002.

Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Indirect Guarantees of the Indebtedness of Others. In November 2002,
the FASB issued Interpretation No. 45 ("FIN 45"), Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of the
Indebtedness of Others, which clarifies the requirements of SFAS No. 5,
Accounting for Contingencies, relating to a guarantor's accounting for and
disclosures of certain guarantees issued. FIN 45 requires enhanced disclosures
for certain guarantees. It also will require certain guarantees that are issued
or modified after December 31, 2002, including certain third-party guarantees,
to be initially recorded on the balance sheet at fair value. For guarantees
issued on or before December 3, 2002, liabilities are recorded when and if
payments become probable and estimable. The financial statement recognition
provisions are effective prospectively, and we cannot reasonably estimate the
impact of FIN 45 until guarantees are issued or modified in future periods, at
which time their results will be initially reported in the financial statements.

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CONTINGENCIES AND OTHER MATTERS

On December 18, 2002, a lawsuit was filed by Hills for Everyone, a
non-profit corporation, against Orange County and Nuevo Energy Company
challenging the adequacy of the Environment Impact Report for the Company's
Tonner Hills project. The suit seeks to compel Orange County to set aside its
decision to adopt the Environment Impact Report and seeks additional
environmental analysis and mitigation measures. The Company is contesting the
litigation and both the County and the Company are continuing to take the
necessary regulatory steps to move the project toward development.

On September 14, 2001, during an annual inspection, we discovered
fractures in the heat affected zone of certain flanges on our pipeline that
connects the Point Pedernales field with onshore processing facilities. We
voluntarily elected to shut-in production in the field while repairs were being
made. The daily net production from this field was approximately 5,000 barrels
of crude oil and 1.2 MMcf of natural gas, representing approximately 11% of our
daily production. We replaced the damaged flanges, as well as others which had
not shown signs of damage. We resumed production in January 2002. During the
third quarter 2002 we reached a final agreement with our underwriters with
respect to our business interruption claim. Accordingly, we recognized $3.0
million of business interruption recoveries during the third quarter 2002 which
is classified in other revenue and received payment on this claim by year-end
2002. Certain other costs related to repair are expected to be covered by
insurance based on a tentative agreement we have with our underwriters. We
expect payment with respect to the repair claims in the next nine months once
the claims are fully adjusted.

On June 15, 2001, we experienced a failure of a carbon dioxide
treatment vessel at the Rincon Onshore Separation Facility ("ROSF") located in
Ventura County, California. There were no injuries associated with this event.
Crude oil and natural gas produced from three fields offshore California are
transported onshore by pipeline to the ROSF plant where crude oil and water are
separated and treated, and carbon dioxide is removed from the natural gas
stream. The daily net production associated with these fields was 3,000 barrels
of crude oil and 2.4 MMcf of natural gas in 2001, representing approximately 6%
of our daily production. In early July 2001, crude oil production resumed and
full gas sales resumed by mid August 2001. The cost of repair, less a $50,000
deductible, is expected to be covered by insurance. We expect to settle the
insurance claims within the next six months.

On September 22, 2000, we were named as a defendant in the lawsuit
Thomas Wachtell et al. versus Nuevo Energy Company in the Superior Court of Los
Angeles County, California. We settled this lawsuit in June 2002 for, among
other matters, making a payment to plaintiffs of $3.4 million, and receiving
from plaintiffs certain interests in properties and extinguishing certain
contract rights of plaintiffs. We established a reserve for this contingency in
2001 and the settlement payment in 2002 did not have a material impact on our
results of operations or financial position.

On April 5, 2000, we filed a lawsuit against ExxonMobil Corporation in
the United States District Court for the Central District of California, Western
Division. We and ExxonMobil each owned a 50% interest in the Sacate field,
offshore Santa Barbara County, California. We believe that we had been denied a
reasonable opportunity to exercise our rights under the unit operating
agreement. We alleged that ExxonMobil's actions breached the unit operating
agreement and the covenant of good faith and fair dealing. We settled this
lawsuit in June 2002. Under the terms of the settlement agreement, we received
$16.5 million from ExxonMobil and conveyed to them our interest in the Santa
Ynez Unit, our non-consent interest in the adjacent Pescado field and
relinquished our right to participate in the Sacate field and recorded a $15.3
million gain related to the sale of this unproved property.

In September 1997, there was a spill of crude oil into the Santa
Barbara Channel from a pipeline that connects our Point Pedernales field with
shore-based processing facilities. The volume of the spill was estimated to be
163 Bbls of oil. Repairs were completed by the end of 1997, and production
recommenced in December 1997. The costs of the clean up and the cost to repair
the pipeline either have been or are expected to be covered by our insurance,
less a deductible of $0.1 million. As of December 31, 2002, we had received
insurance reimbursements of $4.2 million, with a remaining insurance receivable
of $0.5 million. Costs related to the

25

settlement of claims for natural resource damage asserted by certain federal and
state agencies are also expected to be covered by insurance.

Our international investments involve risks typically associated with
investments in emerging markets such as an uncertain political, economic, legal
and tax environment and expropriation and nationalization of assets. In
addition, if a dispute arises in our foreign operations, we may be subject to
the exclusive jurisdiction of foreign courts or may not be successful in
subjecting foreign persons to the jurisdiction of the United States. We attempt
to conduct our business and financial affairs to protect against political and
economic risks applicable to operations in the various countries where we
operate, but there can be no assurance that we will be successful in so
protecting ourselves. A portion of our investment in the Congo is insured
through political risk insurance provided by Overseas Private Investment Company
("OPIC"). The political risk insurance through OPIC covers up to $25.0 million
relating to expropriation and political violence, which is the maximum coverage
available through OPIC. During 1997, a new government was established in the
Congo. Although the political situation in the Congo has not to date had a
material adverse effect on our operations in the Congo, no assurances can be
made that continued political unrest in West Africa will not have a material
adverse effect on us or our operations in the Congo in the future.

In connection with our February 1995 acquisitions of two subsidiaries
owning interests in the Yombo field offshore Congo, we and a wholly-owned
subsidiary of CMS NOMECO Oil & Gas Co. ("CMS") agreed with the seller of the
subsidiaries not to claim certain tax losses ("dual consolidated losses")
incurred by such subsidiaries prior to the acquisitions. Under the tax law in
the Congo, as it existed when this acquisition took place, if an entity is
acquired in its entirety and that entity has certain tax attributes, for example
tax loss carryforwards from operations in the Republic of Congo, the subsequent
owners of that entity can continue to utilize those losses without restriction.
Pursuant to the agreement, we and CMS may be liable to the seller for the
recapture of dual consolidated losses (net operating losses of any domestic
corporation that are subject to an income tax of a foreign country without
regard to the source of its income or on a residence basis) utilized by the
seller in years prior to the acquisitions if certain triggering events occur,
including: (i) a disposition by either us or CMS of its respective Congo
subsidiary, (ii) either Congo subsidiary's sale of its interest in the Yombo
field, (iii) the acquisition of us or CMS by another consolidated group or (iv)
the failure of CMS's Congo subsidiary or us to continue as a member of its
respective consolidated group.

A triggering event will not occur, however, if a subsequent purchaser
enters into certain agreements specified in the consolidated return regulations
intended to ensure that such dual consolidated losses will not be claimed. The
only time limit associated with the occurrence of a triggering event relates to
the utilization of a dual consolidated loss in a foreign jurisdiction. A dual
consolidated loss that is utilized to offset income in a foreign jurisdiction is
only subject to recapture for 15 years following the year in which the dual
consolidated loss was incurred for U.S. income tax purposes. We and CMS have
agreed among ourselves that the party responsible for the triggering event shall
indemnify the other for any liability to the seller as a result of such
triggering event. Our potential direct liability could be as much as $35.4
million if a triggering event with respect to us occurs. Additionally, we
believe that CMS's liability (for which we would be jointly liable with an
indemnification right against CMS) could be as much as $53.1 million. CMS sold
their interest in the Yombo field in 2002, to a U.S. subsidiary of Perenco, S.A.
(Perenco), which is awaiting the approval from the government of Congo. The sale
was not a triggering event as both CMS and Perenco filed a request for a Closing
Agreement with the Internal Revenue Service in accordance with the U.S.
consolidated tax return regulations prior to the sale. Further, we do not expect
a triggering event to occur with respect to Nuevo, CMS or Perenco, and do not
believe the agreement will have a material adverse effect upon us.

In 1996, the Congo government requested that the convention governing
the Marine I Exploitation Permit be converted to a Production Sharing Agreement
("PSA"). We are under no obligation to convert to a PSA, and our existing
convention is valid and protected by law. Our position is that any conversion to
a PSA should have no detrimental impact to us, otherwise, we will not agree to
any such conversion. Discussions with the government have been ongoing
intermittently since early 1997. To date, no final agreement has been reached
concerning conversion to a PSA.

We have been named as a defendant in certain other lawsuits incidental
to our business. These actions and claims in the aggregate seek damages against
us and are subject to the inherent uncertainties in any litigation.

26

We are defending ourselves vigorously in all such matters. We have reserved an
amount that we deem adequate to cover any potential losses related to these
matters to the extent the losses are deemed probable and estimable. This amount
is reviewed periodically and changes may be made, as appropriate. Any additional
costs related to these potential losses are not expected to be material to our
operating results, financial condition or liquidity.

CONTINGENT PAYMENT AND PRICE SHARING AGREEMENTS

In connection with the acquisition from Unocal in 1996 of the
properties located in California, we are obligated to make a contingent payment
for the years 1998 through 2004 if oil prices exceed thresholds set forth in the
agreement with Unocal. Contingent payments are accounted for as a purchase price
adjustment to oil and gas properties. The contingent payment will equal 50% of
the difference between the actual average annual price received on a
field-by-field basis (capped by a maximum price) and a minimum price, less ad
valorem and production taxes, and certain other permitted deductions, multiplied
by the actual number of barrels of oil sold that are produced from the
properties acquired from Unocal during the respective year. The minimum price of
$17.75 per Bbl under the agreement (determined based on the near month delivery
of WTI crude oil on the NYMEX) is escalated at 3% per year and the maximum price
of $21.75 per Bbl on the NYMEX is escalated at 3% per year. Minimum and maximum
prices are reduced to reflect the field level price by subtracting a fixed
differential established for each field. The reduction was established at
approximately the differential between actual sales prices and NYMEX prices in
effect in 1995 ($4.34 per Bbl weighted average for all the properties acquired
from Unocal). We accumulate credits to offset the contingent payment when prices
are $0.50 per Bbl or more below the minimum price. On March 15, 2002, we paid
$10.8 million to Unocal attributable to calendar year 2001 and recorded the
payment in oil and gas properties. In March 2003, we advised Unocal that we had
failed to take deductions to the purchase price that we believe are permitted by
the agreement. Application of these deductions resulted in no payment due for
either calendar year 2001 or 2002, and resulted in a credit being available to
use against future obligations. Unocal disputes this position. Discussions are
taking place between the companies in an effort to resolve this issue for both
years. While the final outcome of this matter is not presently determinable, its
resolution is not expected to have a significant impact on our operating
results, financial condition or liquidity.

In connection with the acquisition of the Congo properties in 1995, we
entered into a price sharing agreement with the seller. Under the terms of the
agreement, if the average price received for the oil production during the year
is greater than the benchmark price established by the agreement, we are
obligated to pay the seller 50% of the difference between the benchmark price
and the actual price received, for all the production associated with this
acquisition. The benchmark price was $15.96 per Bbl for 2002, $15.78 per Bbl for
2001 and $15.19 per Bbl for 2000. The benchmark price increases each year, based
on the increase in the Consumer Price Index. For 2002, the effect of this
agreement was that we only owned upside above $15.96 per Bbl on approximately
66% of our Congo production. We were obligated to pay the seller $4.1 million in
2002, $3.4 million in 2001 and $5.4 million in 2000 under this price sharing
agreement. Because there is no termination date associated with this agreement,
it is accounted for as an oil royalty.

We acquired a 12% working interest in the Point Pedernales oil field
from Unocal in 1994 and the remainder of our 80.3 % working interest from Torch
in 1996. We are entitled to all revenue proceeds up to $9.00 per Bbl, with the
excess revenue over $9.00 per Bbl, if any, shared with the original owners from
whom Torch acquired its interest. We own amounts below $9.00 per Bbl with the
other working interest owners based on their respective ownership interests. For
2002, the effect of this agreement is that we were entitled to receive the
pricing upside above $9.00 per Bbl on approximately 73% of the gross Point
Pedernales production. As of December 31, 2002, we had $0.5 million accrued as
our obligation under this agreement. As of December 31, 2001, we had $0.2
million accrued as our obligation under this agreement. As of December 31, 2000,
we had $0.6 million accrued as our obligation under this agreement. Obligations
under this agreement are accounted for as an oil royalty.

27

RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains or incorporates by reference forward looking
statements within the meaning of Section 27A of the Securities Act of 1933, as
amended, Section 21E of the Securities Exchange Act of 1934 and the Private
Securities Litigation Reform Act of 1995. All statements other than statements
of historical facts included in this document, including without limitation,
statements in Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations regarding our financial position, estimated
quantities and net present values of reserves, business strategy, plans and
objectives of our management for future operations and covenant compliance, are
forward looking statements. We can give no assurances that the assumptions upon
which such forward-looking statements are based will prove to be correct.
Important factors that could cause actual results to differ materially from our
expectations are included throughout this document. The Cautionary Statements
expressly qualify all subsequent written and oral forward-looking statements
attributable to us or persons acting on our behalf.

VOLATILITY OF OIL AND GAS PRICES

Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond our control. These
factors include but are not limited to weather conditions in the United States,
the condition of the United States economy, the actions of the Organization of
Petroleum Exporting Countries ("OPEC'), governmental regulation, political
stability in the Middle East and elsewhere, the foreign supply of oil and gas,
the price of foreign oil imports and the availability of alternate fuel sources
and transportation interruption. Any substantial and extended decline in the
price of oil or gas would have an adverse effect on the carrying value of our
proved reserves, borrowing capacity, our ability to obtain additional capital,
and our revenues, profitability and cash flows from operations.

Volatile oil and gas prices make it difficult to estimate the value of
producing properties for acquisition and divestiture and often cause disruption
in the market for oil and gas producing properties, as buyers and sellers have
difficulty agreeing on such value. Price volatility also makes it difficult to
budget for and project the return on acquisitions and development and
exploitation projects.

PRICING OF HEAVY OIL PRODUCTION

A portion of our production is California heavy oil. The market price
for California heavy oil differs substantially from the established market
indices for oil and gas, principally due to the higher transportation and
refining costs associated with heavy oil. As a result, the price received for
heavy oil is generally lower than the price for medium and light oil, and the
production costs associated with heavy oil are relatively higher than for
lighter grades. The margin (sales price minus production costs) on heavy oil
sales is generally less than that of lighter oil, and the effect of material
price decreases will more adversely affect the profitability of heavy oil
production compared with lighter grades of oil. (See "Risk Management and
Hedging Policy" below for discussion of our crude oil sales contract which
expires in 2013).

RESERVE REPLACEMENT RISKS

Our future performance depends upon the ability to find, develop and
acquire additional oil and gas reserves that are economically recoverable.
Without successful exploration, exploitation or acquisition activities, our
reserves and revenues will decline. No assurances can be given that we will be
able to find and develop or acquire additional reserves at an acceptable cost.

The successful acquisition and development of oil and gas properties
requires an assessment of recoverable reserves, future oil and gas prices and
operating costs, potential environmental and other liabilities and other
factors. Such assessments are necessarily inexact and their accuracy inherently
uncertain. In addition, no assurances can be given that our exploitation and
development activities will result in any increase in reserves. Our operations
may be curtailed, delayed or canceled as a result of lack of adequate capital
and other factors, such as title problems, weather, compliance with governmental
regulations or price controls, mechanical difficulties or

28

shortages or delays in the delivery of equipment. In addition, the costs of
exploitation and development may materially exceed initial estimates.

SUBSTANTIAL CAPITAL REQUIREMENTS

We make, and will continue to make, substantial capital expenditures
for the exploitation, exploration, acquisition and production of oil and gas
reserves. Historically, these expenditures were financed with cash generated by
operations, proceeds from bank borrowings and the proceeds of debt and equity
issuances. We believe that we will have sufficient cash provided by operating
activities and borrowings under our bank credit facility to fund planned capital
expenditures. If revenues or our borrowing base decrease as a result of lower
oil and gas prices, operating difficulties or declines in reserves, we may have
limited ability to expend the capital necessary to undertake or complete future
drilling programs. There can be no assurance that additional debt or equity
financing or cash generated by operations will be available to meet these
requirements.

UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET CASH FLOWS

Estimates of economically recoverable oil and gas reserves and of
future net cash flows are based upon a number of variable factors and
assumptions, all of which are to some degree speculative and may vary
considerably from actual results. Therefore, actual production, revenues, taxes,
and development and operating expenditures may not occur as estimated. Future
results of operations will depend upon our ability to develop, produce and sell
our oil and gas reserves. The reserve data included herein are estimates only
and are subject to many uncertainties. Actual quantities of oil and gas may
differ considerably from the amounts set forth herein. In addition, different
reserve engineers may make different estimates of reserve quantities and cash
flows based upon the same available data.

OPERATING RISKS

Our operations are subject to risks inherent in the oil and gas
industry, such as blowouts, cratering, explosions, uncontrollable flows of oil,
gas or well fluids, fires, pollution, earthquakes and other environmental risks.
These risks could result in substantial losses due to injury and loss of life,
severe damage to and destruction of property and equipment, pollution and other
environmental damage and suspension of operations. Our offshore operations are
subject to a variety of operating risks peculiar to the marine environment, such
as hurricanes or other adverse weather conditions, to more extensive
governmental regulation, including regulations that may, in certain
circumstances, impose strict liability for pollution damage, and to interruption
or termination of operations by governmental authorities based on environmental
or other considerations. Our operations could result in liability for personal
injuries, property damage, oil spills, discharge of hazardous materials,
remediation and clean-up costs and other environmental damages. We could be
liable for environmental damages caused by previous property owners. As a
result, substantial liabilities to third parties or governmental entities may be
incurred, the payment of which could have a material adverse effect on our
financial condition and results of operations. We maintain insurance coverage
for our operations, including limited coverage for sudden environmental damages
and for existing contamination, but do not believe that insurance coverage for
environmental damages that occur over time or insurance coverage for the full
potential liability that could be caused by sudden environmental damages is
available at a reasonable cost, and we may be subject to liability or may lose
substantial portions of our properties in the event of certain environmental
damages.

FOREIGN INVESTMENTS

Our foreign investments involve risks typically associated with
investments in emerging markets such as uncertain political, economic, legal and
tax environments and expropriation and nationalization of assets. We attempt to
conduct our business and financial affairs so as to protect against political
and economic risks applicable to operations in the various countries where we
operate, but there can be no assurance that we will be successful in protecting
against such risks.

Our international assets and operations are subject to various
political, economic and other uncertainties, including, among other things, the
risks of war, expropriation, nationalization, renegotiation or nullification of
existing contracts, taxation policies, foreign exchange restrictions, changing
political conditions, international

29

monetary fluctuations, currency controls and foreign governmental regulations
that favor or require the awarding of drilling contracts to local contractors or
require foreign contractors to employ citizens of, or purchase supplies from, a
particular jurisdiction. In addition, if a dispute arises with foreign
operations, we may be subject to the exclusive jurisdiction of foreign courts or
may not be successful in subjecting foreign persons, especially foreign oil
ministries and national oil companies, to the jurisdiction of the United States.

Our private ownership of oil and gas reserves under oil and gas leases
in the United States differs distinctly from our ownership of foreign oil and
gas properties. In the foreign countries in which we do business, the state
generally retains ownership of the minerals and consequently retains control of
(and in many cases, participates in) the exploration and production of
hydrocarbon reserves. Accordingly, operations outside the United States, and
estimates of reserves attributable to properties located outside the United
States, may be materially affected by host governments through royalty payments,
export taxes and regulations, surcharges, value added taxes, production bonuses
and other charges.

RISK MANAGEMENT AND HEDGING POLICY

Our risk management policy is based on the view that oil prices revert
to a mean price over the long term. To the extent that future markets over a
forward 18 month period are significantly higher than long term norms, we will
hedge production volumes up to certain maximums set forth in our oil hedging
policy approved by our Board in March 2002. Maximum hedged volumes increase as
the price of oil increases. Variations from this policy require Board approval.
The risk management policy states that hedging activity that is speculative or
otherwise unrelated to our normal business activities is considered
inappropriate. We recognize the risks inherent in price management. In order to
minimize such risk, we have instituted a set of controls addressing approval
authority, trading limits and other control procedures. All hedging activity is
the responsibility of our Senior Vice President of Planning and Asset
Management. In addition, Internal Audit, which independently reports to the
Audit Committee, reviews our risk management activity.

We reduce our exposure to price volatility by hedging our production
through swaps, options and other commodity derivative instruments. In a typical
swap transaction, we will have the right to receive from the counterparty to the
hedge the excess of the fixed price specified in the hedge contract and a
floating price based on a market index, multiplied by the quantity hedged. If
the floating price exceeds the fixed price, we are required to pay the
counterparty the difference. We would be required to pay the counterparty the
difference between such prices regardless of whether our production was
sufficient to cover the quantities specified in the hedge. Since there is not an
established pricing index for hedges of California heavy crude oil production,
and the cash market for heavy oil production in California tends to vary widely
from index prices typically used in oil hedges, we have entered into a physical
sales contract to tie our California production to a traded NYMEX index. As
such, in February 2000, we entered into a 15-year contract, effective January 1,
2000, to sell substantially all of our current and future California crude oil
production to ConocoPhillips Corporation. The contract provides pricing based on
a fixed percentage of the NYMEX crude oil price for each type of crude oil that
we produce in California. Consequently, the actual price received by the Company
as a percentage of NYMEX will vary with our production mix. Based on our current
production mix, the price we receive for our California oil production is
expected to average approximately 74% of WTI. While the contract does not reduce
our exposure to price volatility, it does effectively eliminate the basis
differential risk between the NYMEX price and the field price of our California
oil production, thereby facilitating the ability to effectively hedge our
realized prices.

INSURANCE

The ability to secure certain insurance coverages at prices that we
consider reasonable may be impacted and other coverages or endorsements may not
be made available. No assurance can be given that we will be able to duplicate
our current insurance package when our policies come up for renewal.

30

COMPETITION/MARKETS FOR PRODUCTION

We operate in the highly competitive areas of oil and gas exploration,
exploitation, development and production. The availability of funds and
information relating to a property, the minimum projected return on investment,
the availability of alternate fuel sources and the intermediate transportation
of oil and gas are factors which affect our ability to compete in the
marketplace. Our competitors include major integrated oil companies and a
substantial number of independent energy companies, many of which possess
greater financial and other resources than we do.

Our heavy crude oil production in California requires special
processing treatment available only from a limited number of refineries.
Substantial damage to such a refinery or closures or reductions in capacity due
to financial or other factors could adversely affect the market for our heavy
crude oil production.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including adverse changes in commodity
prices and interest rates.

Commodity Price Risk. We produce and sell crude oil, natural gas and
natural gas liquids, therefore our operating results can be significantly
affected by fluctuations in commodity prices caused by changing market forces.
We reduce our exposure to price volatility by hedging our production through
swaps, put options, collars and other commodity derivative instruments. In a
typical swap transaction, if the floating price is less than the fixed price, we
will have the right to receive from the counterparty to the hedge the excess of
the fixed price specified in the hedge contract and a floating price based on a
market index, multiplied by the quantity hedged. If the floating price exceeds
the fixed price, we are required to pay the counterparty the difference. In a
typical put option contract, we purchase the right to receive from the
counterparty the difference, if any, between a fixed price specified in the
option less a floating market price. If the floating price is above the fixed
price, we are not entitled to a payment. A collar contract works similarly as a
put; however, we are required to pay the difference between the floating price
and ceiling strike price of the collar if the floating price exceeds the ceiling
price. Quantities covered by crude hedges are based on West Texas Intermediate
("WTI") barrels. Prices received for our production is expected to average 74%
of WTI, therefore, each WTI barrel effectively hedges 1.35 barrels of our
production. We use hedge accounting for these instruments, and settlements of
gains or losses on these contracts are reported as a component of oil and gas
revenues and operating cash flows in the period realized. These agreements
expose us to counterparty credit risk to the extent that the counterparty is
unable to meet their settlement commitments to us.

At December 31, 2002, we had entered into the following cash flow
hedges:

Crude Oil Hedges

Natural Gas Hedges

32

At December 31, 2002, the fair market value of these hedge positions
was a loss of $22.3 million. A 10% increase in the underlying commodity prices
would increase this loss by $22.1 million.

Subsequent to December 31, 2002, we entered into the following cash
flow hedges utilizing swap agreements:

Crude Oil Hedges

Natural Gas Hedges

The fair market value of our hedges was a loss of approximately $19
million at March 20, 2003.

Interest Rate Risk. We may enter into financial instruments such as
interest rate swaps to manage the impact of changes in interest rates. Our
exposure to changes in interest rates results primarily from our long-term debt
with both fixed and floating interest rates.

In late December 2001 and early 2002, we entered into three interest
rate swap agreements with notional amounts totaling $200 million to hedge the
fair value of our 9 1/2% Notes due 2008 and our 9 3/8% Notes due 2010. These
swaps were designated as fair value hedges and were reflected as an increase or
decrease of long-term debt with a corresponding increase in long-term assets or
liabilities.

In late August and early September 2002, we terminated our swap
transactions relating to these Notes. As a result of these terminations, we
received accrued interest of $2.2 million and the present value of the swap
option of $9.6 million on our 9 3/8% Notes and $0.5 million in accrued interest
and the present value of the swap option of $2.5 million on our 9 1/2% Notes.
The remaining gain of $9.6 million on our 9 3/8% Notes and $2.5 million on our 9
1/2% Notes continues to be reflected as an increase of long-term debt and is
being amortized as a reduction to interest expense over the life of the Notes.
Through December 31, 2002, we had amortized $0.3 million and $0.1 million,
respectively.

In late August and early November 2002, we entered into two new
interest rate swap agreements with notional amounts totaling $50 million each,
to hedge a portion of the fair value of our 9 3/8% Notes due 2010. These swaps
were designated as fair value hedges and are reflected as an increase of
long-term debt of $2.2 million as of December 31, 2002, with a corresponding
increase in long-term assets. Under the terms of the first agreement, the
counterparty pays us a weighted average fixed annual rate of 9 3/8% on total
notional amounts of $50 million, and we pay the counterparty a variable annual
rate equal to the six-month LIBOR rate plus a weighted average rate of 4.71%.
Under the terms of the second agreement, the counterparty pays us a weighted
average fixed annual rate of 9 3/8% on total notional amounts of $50 million,
and we pay the counterparty a variable annual rate equal to the six-month LIBOR
rate plus a weighted average rate of 4.95%. At December 31, 2002, our interest
rate swaps had a fair value of $2.2 million.

33

The following table presents principal amounts and the related average
interest rates (exclusive of fair value hedges) by year of maturity for our debt
obligations at December 31, 2002:

34

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS AND SCHEDULES

35

INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders
Nuevo Energy Company:

We have audited the accompanying consolidated balance sheets of Nuevo Energy
Company and subsidiaries as of December 31, 2002 and 2001, and the related
consolidated statements of income, stockholders' equity, cash flows and
comprehensive income for each of the years in the three-year period ended
December 31, 2002. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. 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 Nuevo Energy Company
and subsidiaries as of December 31, 2002 and 2001, and the results of their
operations and their cash flows for each of the years in the three-year period
ended December 31, 2002, in conformity with accounting principles generally
accepted in the United States of America.

As also discussed in Note 2 to the consolidated financial statements, effective
January 1, 2000, the Company changed its method of accounting for its processed
fuel oil and natural gas liquids inventories. As discussed in Note 2, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments.

KPMG LLP

Houston, Texas
March 17, 2003

36

NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(IN THOUSANDS, EXCEPT PER SHARE DATA)

See accompanying notes.

37

NUEVO ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)

See accompanying notes.

38

NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

See accompanying notes.

39

NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)

See accompanying notes.

40

NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(IN THOUSANDS)

See accompanying notes.

41

NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

Nuevo Energy Company ("Nuevo") was formed as a Delaware corporation on
March 2, 1990, to acquire the businesses of certain public and private
partnerships (collectively "Predecessor Partnerships"). On July 9, 1990, the
plan of consolidation ("Plan of Consolidation") was approved by limited partners
owning a majority of units of limited partner interests in the partnerships
whereby the net assets of the Predecessor Partnerships, which were subject to
the Plan of Consolidation, were exchanged for Common Stock of Nuevo ("Common
Stock"). All references to the "Company" include Nuevo and its majority and
wholly-owned subsidiaries, unless otherwise indicated or the context indicates
otherwise.

We are engaged in the acquisition, exploitation, development,
exploration and production of crude oil and natural gas. Our principal oil and
gas properties are located domestically onshore and offshore California and West
Texas, and internationally offshore the Republic of Congo, West Africa.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

Our consolidated financial statements include the accounts of Nuevo and
our majority and wholly-owned subsidiaries. All significant intercompany
accounts and transactions have been eliminated in consolidation.

Oil and Gas Properties

We use the successful efforts method to account for our investments in
oil and gas properties. Under the successful efforts method, oil and gas lease
acquisition costs and intangible drilling costs associated with exploration
efforts that result in the discovery of proved reserves and costs associated
with development drilling, whether or not successful, are capitalized when
incurred. When a proved property is sold, ceases to produce or is abandoned, a
gain or loss is recognized. When an entire interest in an unproved property is
sold for cash or cash equivalent, a gain or loss is recognized, taking into
consideration any recorded impairment. When a partial interest in an unproved
property is sold, the amount received is treated as a reduction of the cost of
the interest retained.

Costs of successful wells, development dry holes and proved leases are
capitalized and depleted on a unit-of-production basis over the remaining proved
reserves. Capitalized drilling costs are depleted on a unit-of-production basis
over the lives of the remaining proved developed reserves. Total estimated costs
of $177.6 million for future dismantlement, abandonment and site remediation are
included when calculating depreciation and depletion using the
unit-of-production method. At December 31, 2002, we had recorded $81.4 million
as a component of accumulated depreciation, depletion and amortization related
to this future obligation. See "New Accounting Pronouncements" for a discussion
of the provisions of SFAS No. 143, which will be adopted effective January 1,
2003.

In October 2001, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 144, Accounting
for the Impairment or Disposal of Long-Lived Assets. This Statement requires
that long-lived assets that are to be disposed of by sale be measured at the
lower of book value or fair value less cost to sell. The standard also expanded
the scope of discontinued operations to include all components of an entity with
operations that can be distinguished from the rest of the entity and that will
be eliminated from the ongoing operations of the entity in a disposal
transaction. We adopted the provisions of this statement effective January 1,
2002 and have presented certain property dispositions as discontinued operations
in accordance with SFAS No. 144. (See Note 4).

In accordance with SFAS No. 144, we review our long-lived assets to be
held and used, including proved oil and gas properties accounted for using the
successful efforts method of accounting, on a depletable unit basis whenever
events or circumstances indicate that the carrying value of those assets may not
be recoverable. SFAS No. 144 requires an impairment loss to be recognized when
the carrying amount of an asset exceeds the sum of the undiscounted estimated
future net cash flows and we recognize an impairment loss equal to the
difference between the carrying value and the fair value of the asset. Fair
value is estimated to be the expected present value of future

42

net cash flows from proved reserves, utilizing a risk-free rate of return.
During 2001, we recorded an impairment totaling $103.5 million on our Santa
Clara, Huntington Beach, Pitas Point, Masseko (Congo) and Point Pedernales
fields and certain other oil and gas properties. We recorded no impairments in
2000 and only those required to be taken for the assets currently designated as
held for sale in 2002. Also, in accordance with SFAS No. 144, when the proved
properties are classified as held for sale, if the carrying amount of the assets
is less than their fair market value less our estimated costs to sell them, the
difference, if significant, is recognized as a loss in that period and the
associated results of operations are accounted for as discontinued.

Unproved leasehold costs are capitalized pending the results of
exploration efforts. Significant unproved leasehold costs are reviewed
periodically and a loss is recognized to the extent, if any, that the cost of
the property has been impaired. Exploration costs, including geological and
geophysical expenses, exploratory dry holes and delay rentals, are charged to
expense as incurred.

During 2002 and 2001, interest costs associated with non-producing
leases and exploration and development projects were capitalized only for the
period that activities were in progress to bring these projects to their
intended use. The capitalization rates were based on our weighted average cost
of funds used to finance expenditures. We capitalized $1.9 million and $2.5
million of interest costs in 2002 and 2001. There were no interest costs
capitalized in 2000.

Any reference to oil and gas reserve information in the Notes to the
Consolidated Financial Statements is unaudited.

Derivative Financial Instruments and Price Risk Management Activities

We use price risk management activities to manage non-trading market
risks. We use derivative financial instruments such as swaps, collars and put
options to hedge the impact market price risk exposures on our crude oil and
natural gas production and to mitigate our exposure to interest rate risk.

We adopted SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities, effective January 1, 2001. This statement requires all
derivative instruments to be carried on the balance sheet at fair value. In
accordance with the transition provisions of SFAS No. 133, we recorded a
cumulative-effect transition adjustment of $(16.0) million, net of related taxes
of $10.8 million, in accumulated other comprehensive income to recognize the
fair value of our derivatives designated as cash-flow hedging instruments at the
date of adoption.

Beginning on January 1, 2001, all of our derivative instruments are
recognized on the balance sheet at their fair value. We currently use swaps,
collars and put options to hedge our exposure to material changes in the future
price of crude oil and natural gas and interest rate swaps to hedge the fair
value of our long-term debt.

On the date we enter into a derivative contract, we designate the
derivative as either a hedge of the fair value of a recognized asset, liability
or firm commitment ("fair value" hedge), or as a hedge of the variability of
cash flows to be received or paid ("cash flow" hedge). Changes in the fair value
of a derivative that is highly effective as, and that is designated and
qualifies as, a fair value hedge, along with the change in fair value of the
hedged asset or liability that is attributable to the hedged risk (including
losses or gains on firm commitments), are recorded in current period earnings.
Changes in the fair value of a cash flow hedge are recorded in other
comprehensive income (loss) until the hedged transaction occurs. At December 31,
2002, we had both cash flow hedges and fair value hedges. (See Note 13.)

We formally document all relationships between hedging instruments and
hedged items, as well as its risk-management objective and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated as cash flow hedges to forecasted transactions.
We also formally assess, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged transactions. When it is
determined that a derivative is not highly effective as a hedge or that it has
ceased to be a highly effective hedge, we discontinue hedge accounting
prospectively.

When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value, and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately. In all other situations in which hedge accounting is discontinued,
the derivative will be carried at its fair value on the balance sheet, with
changes in its fair value recognized in earnings prospectively.

43

At December 31, 2002, we had recorded $11.5 million, net of related
taxes of $7.9 million, of cumulative hedging losses in other comprehensive
income, which will be reclassified to earnings within the next 12 months. The
amounts ultimately reclassified to earnings will vary due to changes in the fair
value of the open derivative contracts prior to settlement.

As a result of hedging transactions, oil and gas revenues were reduced
by $9.4 million, $47.6 million and $117.7 million in 2002, 2001 and 2000. The
portion of our derivative financial instruments that were ineffective or did not
qualify for hedge accounting totaled $4.7 million in 2002 and was recorded in
derivative gain/loss in the accompanying consolidated statements of income.

Goodwill and Other Intangible Assets

In June 2001, the FASB issued SFAS No. 142, Goodwill and Other
Intangible Assets. This Statement requires discontinuing amortization of
goodwill after 2001 and requires that goodwill be tested for impairment. The
impairment test requires allocating goodwill and all other assets and
liabilities to business levels referred to as reporting units. The fair value of
each reporting unit that has goodwill is determined and compared to the book
value of the reporting unit. If the fair value of the reporting unit is less
than the book value (including goodwill), then a second test is performed to
determine the amount of the impairment.

If the second test is necessary, the fair value of the reporting unit's
individual assets and liabilities is deducted from the fair value of the
reporting unit. This difference represents the implied fair value of goodwill,
which is compared to the book value of the reporting unit's goodwill. Any excess
of the book value of goodwill over the implied fair value of goodwill is the
amount of the impairment.

The goodwill impairment test is performed annually in the fourth
quarter, and also at interim dates upon the occurrence of significant events.
Significant events include: a significant adverse change in legal factors or
business climate; an adverse action or assessment by a regulator; a
more-likely-than-not expectation that a reporting unit or significant portion of
a reporting unit will be sold; significant adverse trends in current and future
oil and gas prices; nationalization of any of the Company's oil and gas
properties; or, significant increases in a reporting unit's carrying value
relative to its fair value.

We adopted the provisions of this statement on January 1, 2002. We
recorded $19.7 million of goodwill in connection with our acquisition of Athanor
Resources, Inc. (See Note 3). The goodwill is recorded in our domestic reporting
unit. The annual impairment test will be performed in the fourth quarter of each
year, or more often if required.

Comprehensive Income

Comprehensive income includes net income and all changes in other
comprehensive income. Changes in other comprehensive income include changes in
the fair value of derivatives designated as cash flow hedges.

Environmental Liabilities

Environmental expenditures that relate to current or future revenues
are expensed or capitalized as appropriate. Expenditures that relate to an
existing condition caused by past operations, and do not contribute to current
or future revenue generation, are expensed. Liabilities are recorded when
environmental assessments and/or clean-ups are probable, and the costs can be
reasonably estimated. Generally, the timing of these accruals coincides with our
commitment to a formal plan of action. As of December 31, 2002, we had accrued
approximately $5.6 million for future environmental expenditures.

Contingencies

We recognize liabilities for contingencies when we have an exposure
that, when fully analyzed, indicates it is both probable and that the amount can
be reasonably estimated. Funds spent to remedy these contingencies are charged
against a reserve, if one exists, or expensed.

44

Inventory

Our inventory is valued at the lower of cost or market, with cost being
determined on a first-in, first-out (FIFO) method. We had crude oil inventory in
the Congo of $3.0 million and $0.8 million at December 31, 2002 and 2001. Our
materials and supplies inventory totaled $4.3 million and $3.0 million at
December 31, 2002 and 2001.

Prior to December 31, 2000, we recorded inventory relating to
quantities of processed fuel oil and natural gas liquids in storage at current
market pricing. Also, fuel oil in inventory was stated at year end market prices
less transportation costs, and we recognized changes in the market value of
inventory from one period to the next as oil revenues. In December 2000, the
staff of the Securities and Exchange Commission announced that commodity
inventories should be carried at the lower of cost or market rather than at
market value. As a result, we changed our inventory valuation method to the
lower of cost or market in the fourth quarter of 2000, retroactive to the
beginning of the year and recorded a non-cash charge related to this cumulative
effect of accounting change, effective January 1, 2000, of $0.8 million, net of
related income tax benefit of $0.5 million, to value product inventory at the
lower of cost or market.

Gas Plant and Other Facilities

Gas plant and other facilities include the costs to acquire certain gas
plant and other facilities and to secure rights-of-way. Capitalized costs
associated with gas plant and other facilities are amortized primarily over the
estimated useful lives of the various components of the facilities utilizing the
straight-line method. The estimated useful lives of such assets range from three
to thirty years. We review these assets for impairment whenever events or
changes in circumstances indicate that their carrying amounts may not be
recoverable.

Recognition of Crude Oil and Natural Gas Revenue

Crude oil and natural gas revenue is recognized when title passes to
the purchaser. We use the entitlement method for recording sales of crude oil
and natural gas from producing wells. Under the entitlement method, revenue is
recorded based on our net revenue interest in production. Deliveries of crude
oil and natural gas in excess of our net revenue interests are recorded as
liabilities and under-deliveries are recorded as assets. Production imbalances
are recorded at the lower of the sales price in effect at the time of production
or the current market value. Substantially all such amounts are anticipated to
be settled with production in future periods. We did not have a material
imbalance position in terms of units or value at December 31, 2002 or 2001.

Income Taxes

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

Statements of Cash Flows

For cash flow presentation purposes, we consider all highly liquid
money market instruments with an original maturity of three months or less to be
cash equivalents. Interest paid in cash, including amounts capitalized, for
2002, 2001 and 2000 was $35.4 million, $38.3 million and $32.1 million. Net
amounts paid (refunded) in cash for income taxes for 2002, 2001 and 2000 were
$(1.5) million, $0.4 million and $(0.5) million.

Use of Estimates

In order to prepare these financial statements in conformity with
accounting principles generally accepted in the United States of America, our
management has made a number of estimates and assumptions relating to the
reporting of assets and liabilities and the disclosure of contingent assets and
liabilities, as well as reserve information, which affects the depletion
calculation. Actual results could differ from those estimates.

45

Stock-Based Compensation

We account for stock compensation plans under the intrinsic value
method of Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock
Issued to Employees. No compensation expense is recognized for stock options
that had an exercise price equal to their market value of the underlying common
stock on the date of grant. As allowed by SFAS No. 123, Accounting for
Stock-Based Compensation, we have continued to apply APB Opinion No. 25 for
purposes of determining net income. In December 2002, the FASB issued SFAS No.
148, Accounting for Stock-Based Compensation - Transition and Disclosure - an
amendment of FASB Statement No. 123 to provide alternative methods of transition
for a voluntary change to the fair value based method of accounting for
stock-based employee compensation. Additionally, the statement amends the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based employee compensation and the effect of the method used on reported
results. Had compensation expense for stock-based compensation been determined
based on the fair value at the date of grant, our net income and earnings per
share would have been as follows:

The weighted-average fair value of options granted during 2002, 2001 and 2000
was $8.20, $6.23 and $10.87. The fair value of each option grant is estimated on
the date of grant using the Black-Scholes option-pricing model with the
following weighted-average assumptions: expected stock price volatility of
44.5%, 54.5% and 112.0% in 2002, 2001 and 2000; risk free interest of 4%, 4% and
5% in 2002, 2001 and 2000; and average expected option lives of eight years in
2002 and three years in 2001 and 2000.

Functional Currency

Our functional currency for all operations is the U.S. dollar.

Reclassifications

Certain reclassifications of prior period amounts have been made to
conform to the current presentation. The unaudited quarterly data footnote (Note
16) also reflects reclassifications to conform with current presentation. These
reclassifications had no effect on net income or earnings per share.

46

New Accounting Pronouncements

Accounting for Asset Retirement Obligations. In August 2001, the FASB
issued SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement
requires companies to record a liability relating to the eventual retirement and
removal of assets used in their business. The liability is discounted to its
present value, with a corresponding increase to the related asset value. Over
the life of the asset, the liability will be accreted to its future value and
eventually extinguished when the asset is taken out of service. The provisions
of this Statement are effective for fiscal years beginning after June 15, 2002.
We will adopt the provisions of SFAS No. 143 effective January 1, 2003. In
connection with the initial application of SFAS No. 143, it is expected that we
will record a cumulative effect of change in accounting principle, net of taxes,
of approximately $10 million to $15 million as an increase to net income, which
will be reflected in our results of operations for 2003. In addition, it is
expected we will record an asset retirement obligation of approximately $75
million to $80 million.

Accounting for Costs Associated with Exit or Disposal Activities. In
July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal Activities. This statement requires the recognition of costs
associated with exit or disposal activities when they are incurred rather than
at the date of a commitment to an exit or disposal plan. The provisions of this
Statement are effective for exit or disposal activities initiated after December
31, 2002.

Guarantor's Accounting and Disclosure Requirements. In November 2002,
the FASB issued Interpretation No. 45 (FIN 45), Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of the
Indebtedness of Others, which clarifies the requirements of SFAS No. 5,
Accounting for Contingencies, relating to a guarantor's accounting for and
disclosures of certain guarantees issued. FIN 45 requires enhanced disclosures
for certain guarantees. It also will require certain guarantees that are issued
or modified after December 31, 2002, including certain third-party guarantees,
to be initially recorded on the balance sheet at fair value. For guarantees
issued on or before December 3, 2002, liabilities are recorded when and if
payments become probable and estimable. The financial statement recognition
provisions are effective prospectively, and we cannot reasonably estimate the
impact of FIN 45 until guarantees are issued or modified in future periods, at
which time their results will be initially reported in the financial statements.

3. MERGER WITH ATHANOR RESOURCES, INC.

Effective September 18, 2002, pursuant to an agreement and plan of
merger, Nuevo Texas, Inc. one of our wholly owned subsidiaries, acquired Athanor
Resources, Inc. (Athanor). In connection with the acquisition, we issued
approximately 2.0 million shares of common stock for all of the common and
preferred stock of Athanor. The results of Athanor's operations have been
included in our consolidated financial statements effective September 18, 2002.

The merger was accounted for using the purchase method of accounting.
The purchase price totaling approximately $101.4 million included the
combination of $61.3 million of available cash and additional borrowings, the
issuance of approximately $20.1 million of our common stock (approximately 2.0
million shares) to Athanor stockholders, and the fair value of the net
liabilities assumed of approximately $20.0 million. The following table
summarizes the estimated fair value of the assets acquired and liabilities
assumed at the date of acquisition.

The allocation of the purchase price resulted in approximately $19.7
million allocated to goodwill which is not expected to be deductible for tax
purposes. This goodwill is attributable to a premium paid for Athanor because
the acquisition gives us a new core area with increasing growth opportunities,
diversifies our asset base

47

with higher margin properties and was financed with a component of equity. Other
accrued merger costs of $1.6 million included capitalizable third party
transaction costs.

The merger included certain non-cash investing and financing activities
not reflected in the Consolidated Statement of Cash Flows as follows:

Subsequent to the acquisition, the long-term debt of $20.0 million was
repaid.

The following unaudited pro forma condensed income statement
information has been prepared to give effect to the merger as if the transaction
had occurred at the beginning of the periods presented. The historical results
of operations have been adjusted to reflect the difference between Athanor's
historical depletion, depreciation and amortization and such expense calculated
based on the value allocated to the assets acquired in the merger. The
information presented is not necessarily indicative of the results of future
operations of the merged companies.

4. ACQUISITIONS AND DIVESTITURES

Discontinued Operations

Eastern Properties. In 2002, we sold a majority of our oil and gas
properties located in Texas, Alabama and Louisiana for approximately $9.0
million. We recognized a $0.9 million loss on the sale of these properties.
Historical results of operations from these properties and the loss on sale are
classified as discontinued operations in our consolidated statements of income.
Revenues associated with the sold properties were $3.2 million in 2002, $8.3
million in 2001 and $14.6 million in 2000. Pre-tax income associated with the
sold properties totaled $1.0 million in 2002, $4.6 million in 2001 and $6.8
million in 2000.

Brea-Olinda. In December 2002, our Board approved the sale of our
Brea-Olinda property located in California. We transferred our remaining basis
in the properties to assets held for sale and recognized a $30.5 million loss in
connection with writing down these assets to their estimated fair value less our
costs to sell them. Historical results of operations from this property and the
loss from the write down are classified as discontinued operations in our
statements of income. Revenues associated with these properties were $16.4
million in 2002, $18.0 million in 2001 and $20.4 million in 2000. Pre-tax income
associated with these properties were $8.0 million in 2002, $7.7 million in 2001
and $14.0 million in 2000. We consummated the sale of the Brea-Olinda oil and
gas properties in February 2003.

Continuing Operations

California Real Estate. In December 2002, our Board approved the sale
of certain real estate properties located in California. We transferred the
remaining basis in this real estate to assets held for sale and recognized a
$1.3 million loss in connection with writing down the basis of these properties
to their estimated fair value less our costs to sell them.

48

Power Plant Project. In late 2001, we made the decision not to pursue
our power plant project in Kern County, California due to the inability to
secure the required permits. We transferred our remaining equipment to assets
held for sale and recognized a $3.5 million loss in connection with writing down
the equipment to their estimated fair value less our costs to sell the assets.

Anaguid Permit. In July 2001, we acquired an additional interest in the
Anaguid Permit, a 1.1 million-acre permit located onshore southern Tunisia in
the Ghadames Basin. Our working interest increased to 22.5%. We relinquished the
Anaguid Permit in 2002 and wrote off $2.2 million as exploration costs.

Accra-Keta Permit. In June 2001, we relinquished our 1.9 million-acre
Accra-Keta Permit offshore the Republic of Ghana. The Permit was relinquished
prior to the commencement of the second phase of the work program. We were the
operator of this Permit and held a 50% working interest. An impairment of $1.0
million was recorded in 2001 in connection with this relinquishment.

Kern County Properties. In January 2001, we acquired approximately
2,900 acres of producing properties in Kern County, California for approximately
$28.5 million. The acreage is southeast of our interest in the Cymric field, of
which more than half is natural gas and provides significant development
potential.

Las Cienegas Field. In May 2000, we sold our working interest in the
Las Cienegas field in California for approximately $4.6 million. In connection
with this sale, we unwound hedges of 2,800 BOPD for the period from May 2000
through December 2000 and recorded an adjusted net gain on sale of approximately
$0.9 million.

5. RESTRUCTURING, SEVERANCE AND OUTSOURCING

During 2002, we terminated our California field operations and human
resources outsourcing agreements. We brought the human resources function
in-house and we now employ the field employees working on our California
properties. Our exploration and production operations were reorganized to create
a smaller, more focused exploitation program and we eliminated our California
exploration program along with approximately 20 technical positions in late
2001. The following table rolls forward our liability recorded for restructuring
and severance obligations related to this termination:

In 2002, we terminated all remaining outsourcing contracts with Torch
Energy Advisors Incorporated and their affiliates. Since 1999, they had provided
the following services: oil and gas administration (accounting, information
technology and land administration), human resources, corporate administration
(legal, graphics, support, and corporate insurance), crude oil marketing,
natural gas marketing, land leasing and field operations. Under the Master
Services Agreement, which contained the overall terms and conditions governing
each individual service agreement, we paid Torch $5.9 million, $8.4 million and
$13.7 million in 2002, 2001 and 2000. The fees charged for field operations were
$7.5 million, $22.3 million and $21.8 million in 2002, 2001 and 2000 and the
marketing fees were $0.9 million, $1.9 million and $1.8 million in 2002, 2001
and 2000. We will incur no such fees in 2003.

49

6. INCOME TAXES
Income tax expense (benefit) is summarized as follows:

We recorded income tax expense (benefit) of $(9.4) million, $4.9
million and $8.4 million in 2002, 2001 and 2000 related to discontinued
operations. We recorded a tax benefit of $0.5 million related to a cumulative
effect of a change in accounting principle in 2000 (see Note 2). A deferred tax
benefit related to the exercise of employee stock options of approximately $0.5
million, $0.8 million and $0.5 million was allocated directly to additional
paid-in capital in 2002, 2001 and 2000.

Total income tax expense (benefit) differs from the amount computed by
applying the federal income tax rate to income (loss) before income taxes and
cumulative effect. The reasons for these differences are as follows:

The tax effects of temporary differences that result in significant
portions of the deferred income tax assets and liabilities and a description of
the financial statement items creating these differences are as follows:

At December 31, 2002, we had a net operating loss carryforward for
regular tax purposes of approximately $211.0 million, which will begin expiring
in 2018. Alternative minimum tax credit carryforwards of $0.2 million do not
expire and may be applied to reduce regular income tax to an amount not less
than the alternative minimum tax payable in any one year. For all periods
presented we concluded that based upon available estimates and tax planning
strategies, it was more likely than not that substantially all of the recorded
deferred tax assets would be realized.

50

7. ACCOUNTS RECEIVABLE

Our accounts receivable consisted of the following at December 31:

8. LONG-TERM DEBT

Our long-term debt consisted of the following:

9 3/8% Notes due 2010

On September 26, 2000, we issued $150.0 million of 9 3/8% Senior
Subordinated Notes due October 1, 2010. Interest accrues at 9 3/8% per annum and
is payable semi-annually in arrears on April 1 and October 1. The Notes are
redeemable, in whole or in part, at our option, on or after October 1, 2005,
under certain conditions. We are not required to make mandatory redemption or
sinking fund payments with respect to these Notes. The indenture contains
covenants that, among other things, limit our ability to incur additional
indebtedness, limit restricted payments, limit issuances and sales of capital
stock by restricted subsidiaries, limit dispositions of proceeds from asset
sales, limit dividends and other payment restrictions affecting restricted
subsidiaries, and restrict mergers, consolidations or sales of assets. If one of
our subsidiaries guarantees other subordinated indebtedness of ours, the
subsidiary must also guarantee these Notes. Currently, none of our subsidiaries
guarantee subordinated indebtedness of ours. The Notes are unsecured general
obligations, and are subordinated in right of payment to all existing and future
senior indebtedness. In the event of a defined change in control, we will be
required to make an offer to repurchase all outstanding 9 3/8% Notes at 101% of
the principal amount, plus accrued and unpaid interest to the date of
redemption.

9 1/2% Notes due 2008

In July 1999, we authorized a new issuance of $260.0 million of 9 1/2%
Senior Subordinated Notes due June 1, 2008. In August 1999, we exchanged $157.5
million of our 9 1/2% Notes due 2006 and $99.9 million of our 8 7/8% Senior
Subordinated Notes due 2008. In connection with the exchange offers, we
solicited consents to proposed amendments to the indentures under which the
exchanged notes were issued. The exchange was accounted for as a debt
modification and the consideration we paid to the holders of the exchanged 9
1/2% Notes due 2006 was $4.7 million and was accounted for as deferred financing
costs.

Interest on these Notes accrues at the rate of 9 1/2% per annum and is
payable semi-annually in arrears on June 1 and December 1. These Notes are
redeemable, in whole or in part, at our option, on or after June 1, 2003, under
certain conditions. We are not required to make mandatory redemption or sinking
fund payments on these Notes. The indenture contains covenants that, among other
things, limit the Company's ability to incur additional indebtedness, limit
restricted payments, limit issuances and sales of capital stock by restricted
subsidiaries, limit dispositions of proceeds from asset sales, limit dividends
and other payment restrictions affecting restricted

51

subsidiaries, and restrict mergers, consolidations or sales of assets. The
9 1/2% Notes are not currently guaranteed by our subsidiaries but are required
to be guaranteed by any subsidiary that guarantees pari passu or subordinated
indebtedness. Currently, none of our subsidiaries guarantees our subordinated
indebtedness. The 9 1/2% Notes are unsecured general obligations, and are
subordinated in right of payment to all of our existing and future senior
indebtedness. In the event of a defined change in control, we will be required
to make an offer to repurchase all outstanding Notes at 101% of the principal
amount, plus accrued and unpaid interest to the date of redemption.

9 1/2% Notes due 2006

In April 1996, we issued $160.0 million of 9 1/2% Notes and in 1999, we
exchanged $157.5 million of these Notes for 9 1/2% Notes due 2008 and have
repurchased some of the Notes in the open market. In August 1999, we exchanged
$157.5 million of these notes for our 9 1/2% Notes due 2008. In October 1999, we
purchased $0.1 million of the remaining Notes. No significant costs were
incurred in connection with the early retirement of the $0.1 million Notes.
Interest on these Notes accrues at the rate of 9 1/2% per annum and is payable
semi-annually in arrears on April 15 and October 15 and were redeemable, in
whole or in part, at our option, on or after April 15, 2001, under certain
conditions. These Notes have not been redeemed, in whole, or in part at December
31, 2002. We are not required to make mandatory redemption or sinking fund
payments with respect to these Notes and they are unsecured general obligations,
and are subordinated in right of payment to all existing and future senior
indebtedness.

Interest Rate Swaps

We entered into interest rate swaps in 2001 and 2002. (See Note 13).

Bank Credit Facility

Our Third Amended and Restated Credit Agreement, dated June 7, 2000, as
amended, provides for secured revolving credit availability of up to $250
million and issuance of letters of credit from a bank group led by Bank of
America, N.A., Bank One, NA, and Bank of Montreal until its expiration on June
7, 2005. At year-end 2002, we had $28.7 million under the Credit Facility and
one letter of credit outstanding in the amount of $0.8 million.

Availability under the Credit Facility is determined pursuant to a
semi-annual borrowing base determination which establishes the maximum
borrowings that may be outstanding under the credit facility. The borrowing base
is determined by a 60% vote of participant banks (two-thirds in the event of an
increase in the borrowing base), each of which bases its judgement on: (i) the
present value of our oil and gas reserves based on their own assumptions
regarding future prices, production, costs, risk factors and discount rates, and
(ii) projected cash flow coverage ratios calculated under varying scenarios. If
amounts outstanding under the credit facility exceed the borrowing base, as
redetermined from time to time, we would be required to repay such excess over a
defined period of time. We have a $175.0 million borrowing base under our Credit
Facility with $146.3 million available at December 31, 2002 and had drawn $28.7
million under the agreement.

Amounts outstanding under the credit facility bear interest at a rate
equal to LIBOR plus an amount which varies according to our Indebtedness to
Capitalization ratio (as defined in the Credit Agreement). The weighted average
interest rate was 3.6% in 2002 and 6.2% in 2001.

Our Credit Agreement has covenants which limit certain restricted
payments and investments, guarantees and indebtedness, prepayments of
subordinated and certain other indebtedness, mergers and consolidations, on
certain types of acquisitions and on the issuance of certain securities by
subsidiaries, liens, sales of properties, transactions with affiliates,
derivative contracts and debt in subsidiaries. We are also required to maintain
certain financial ratios and conditions, including without limitation an EBITDAX
(earnings before interest, taxes, depreciation, depletion, amortization and
exploration expenses) to fixed charge coverage ratio and a funded debt to
capitalization ratio. At December 31, 2002, we were in compliance with all
covenants of the Credit Agreement.

52

The amount of scheduled debt maturities during the next five years and
thereafter is as follows (amounts in thousands):

2003............................................................ $ --
2004............................................................ --
2005............................................................ 28,700
2006............................................................ 2,367
2007............................................................ --
Thereafter...................................................... 407,210
===========
Total debt maturities....................................... $ 438,277
===========

Based upon the quoted market price, the fair value of the 9 3/8% Notes
was estimated to be $149.4 million and $146.8 million at December 31, 2002 and
2001; the fair value of the 9 1/2% Notes due 2010 was estimated to be $264.0
million and $245.6 million at December 31, 2002 and 2001, and the fair value of
the 9 1/2% Notes due 2008 was estimated to be $2.4 million and $2.4 million at
December 31, 2002 and 2001. The carrying amount of the credit facility
approximates its fair value at December 31, 2002.

9. STOCKHOLDERS' EQUITY

Common and Preferred Stock

Our Certificate of Incorporation authorizes the issuance of up to 50
million shares of Common Stock and 10 million shares of Preferred Stock, the
terms, preferences, rights and restrictions of which are established by our
Board of Directors. All shares of Common Stock have equal voting rights of one
vote per share on all matters to be voted upon by stockholders. Cumulative
voting for the election of directors is not permitted. Certain restrictions
contained in our loan agreements limit the amount of dividends that may be
declared. Under the terms of the most restrictive covenant in our indenture for
the 9 1/2% Senior Subordinated Notes due 2008 described in Note 8, we and our
restricted subsidiaries had $20.5 million available for the payment of dividends
and share repurchases at December 31, 2002. We have not paid dividends on our
Common Stock and do not anticipate the payment of cash dividends in the
immediate future.

EPS Computation

SFAS No. 128, Earnings per Share, requires a reconciliation of the
numerator (income) and denominator (shares) of the basic EPS computation to the
numerator and denominator of the diluted EPS computation. In 2001, the weighted
average shares held by benefit trust of 145,000 are not included in the
calculation of diluted loss per share due to their anti-dilutive effect. In
2001, stock options were excluded from the calculation of diluted loss per share
due to their anti-dilutive effect. We had 2.1 million and 2.4 million stock
options in 2002 and 2000 which were not included in the calculation of diluted
earnings per share because the option exercise price exceeded the average market
price. We also have 2.3 million Term Convertible Securities, Series A ("TECONS')
that were not included in the calculation of diluted earnings (loss) per share
in 2002, 2001 or 2000 due to their anti-dilutive effect. The reconciliation is
as follows:

53

Treasury Stock Repurchases

Our Board of Directors has authorized the open market repurchase of up
to 5.6 million shares of common stock. Repurchases may be made at times and at
prices deemed appropriate by management and consistent with the authorization of
our Board. There were no shares repurchased during 2002. As of December 31,
2002, we had 3.9 million shares of treasury stock.

Shareholder Rights Plan

In 1997, we adopted a Shareholder Rights Plan to protect our
shareholders from coercive or unfair takeover tactics. Under the Shareholder
Rights Plan, each outstanding share and each share of subsequently issued common
stock has attached to it one Right. Generally, in the event a person or group
("Acquiring Person") acquires or announces an intention to acquire beneficial
ownership of 15% or more of the outstanding shares of common stock without our
prior consent, or we are acquired in a merger or other business combination, or
50% or more of our assets or earning power is sold, each holder of a Right will
have the right to receive, upon exercise of the Right, that number of shares of
common stock of the acquiring company, which at the time of such transaction
will have a market price of two times the exercise price of the Right. We may
redeem the Right for $.01 at any time before a person or group becomes an
Acquiring Person without prior approval. The Rights will expire on March 21,
2007, subject to earlier redemption by us.

In 2000, we amended the Shareholder Rights Plan to provide that if we
receive and consummate a transaction pursuant to a qualifying offer, the
provisions of the Shareholder Rights Plan are not triggered. In general, a
qualifying offer is an all cash, fully-funded tender offer for all outstanding
common shares by a person who, at the commencement of the offer, beneficially
owns less than five percent of the outstanding common shares. A qualifying offer
must remain open for at least 120 days, must be conditioned on the person
commencing the qualifying offer acquiring at least 75% of the outstanding common
shares and the per share consideration must exceed the greater of (1) 135% of
the highest closing price of the common shares during the one-year period prior
to the commencement of the qualifying offer or (2) 150% of the average closing
price of the common shares during the 20 day period prior to the commencement of
the qualifying offer.

Executive Compensation Plan

In 1997, we adopted a plan to encourage senior executives to personally
invest in our stock, and to regularly review executives' ownership versus
targeted ownership objectives. These incentives include a deferred compensation
plan (the "Plan") that gives key executives the ability to defer all or a
portion of their salaries and bonuses and invest in our common stock or make
other investments at the employee's discretion. Stock is held in a benefit trust
and stock acquired at a discount prior to the 2001 amendment to the Plan is
restricted for a two-year period. The Plan was amended in 2001 to remove the
discount on investments in our common stock and to provide additional investment
alternatives. Target levels of ownership are based on multiples of base salary
and are administered by the Compensation Committee of the Board of Directors.
Upon withdrawal from the Plan, the obligation to the employee is settled with
the invested assets. The Plan applies to certain highly compensated employees
and all executives at a level of Vice-President and above. The stock held in the
benefit trust (70,595 shares, 122,995 shares and 174,904 shares at December 31,
2002, 2001 and 2000) was accounted for as a liability at market value, with any
changes in market value charged or credited to general and administrative
expense until July 2002. Using this approach, we recorded a net benefit of $0.2
million and $0.1 million in 2001 and 2000 related to deferred compensation. In
July 2002, the Plan was further amended to remove the right to receive
withdrawals in cash resulting in a reclassification of the $1.1 million
liability into shareholders' equity. The deferred compensation obligation is now
classified in shareholders' equity and changes in the fair value of the
obligation are not recognized.

Director Compensation

Non-employee directors may elect to receive all or part of an annual
cash retainer of $30,000 in restricted shares of our Common Stock at a 33%
increase in value. The election must be made in increments of 25% ($7,500).
Therefore, for each $7,500 of compensation for which the election is exercised,
the director would receive $9,975 in restricted stock. Beginning in 2003, each
non-employee director also receives a semi-annual grant of 2,125 restricted
shares of our common stock. All restricted shares are subject to a three-year
restricted period. Directors

54

have the option of deferring delivery of restricted shares beyond the three-year
period. Directors also receive $1,000 for each committee meeting attended while
committee chairmen receive $1,500. Directors may elect to receive restricted
shares for committee meetings at a 33% discount.

Stock Incentive Plans

In 1990, we established the 1990 Stock Option Plan; in 1993, the Board
of Directors adopted the Nuevo Energy Company 1993 Stock Incentive Plan; and in
1999, the Board of Directors adopted the Nuevo Energy Company 1999 Stock
Incentive Plan (collectively, the "Stock Incentive Plans"). In 2001, the Board
of Directors adopted the 2001 Stock Incentive Plan as well as individual
incentive plans to induce our Senior Vice President and Chief Financial Officer
and our Senior Vice President, Planning and Asset Management to accept
employment with us. The purpose of the Stock Incentive Plans is to provide our
directors and key employees with performance incentives and to provide a means
of encouraging these individuals to own our stock.

In November 2002, the Compensation Committee of the Board of Directors
approved an increase of 250,000 shares under the 2001 Stock Incentive Plan,
increasing the total maximum number of shares subject to options under the Stock
Incentive Plans to 5,250,000 shares. Options are granted under the Stock
Incentive Plans on the basis of the optionee's contribution to us. No option may
exceed a term of more than ten years. Options granted under the Stock Incentive
Plans may be either incentive stock options or options that do not qualify as
incentive stock options. Our Compensation Committee is authorized to designate
the recipients of options, the dates of grants, the number of shares subject to
options, the option price, the terms of payment upon exercise of the options,
and the time during which the options may be exercised. Options for officers
vest over a term of one to three years, as specified by the Compensation
Committee. Officers who have met their targeted stock ownership requirement
receive accelerated vesting on all options issued prior to October 15, 2001.

The following table details the summary of activity in the stock option
plans during the three years ended 2002:

We had options exercisable of 2,053,416 (weighted average exercise
price of $17.89), 2,728,494 (weighted average exercise price of $21.80) and
2,361,979 (weighted average exercise price of $23.04) at December 31, 2002, 2001
and 2000. Detail of stock options outstanding and options exercisable at
December 31, 2002 follows:

55

10. COMPANY-OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED SECURITIES OF
NUEVO FINANCING I

On December 23, 1996, the Company and Nuevo Financing I, a statutory
business trust formed under the laws of the state of Delaware, (the "Trust"),
closed the offering of 2.3 million TECONS on behalf of the Trust. The price to
the public was $50.00 per TECONS. Distributions began to accumulate from
December 23, 1996, and are payable quarterly on March 15, June 15, September 15,
and December 15, at an annual rate of $2.875 per TECONS. Each TECONS is
convertible at any time prior to the close of business on December 15, 2026, at
the option of the holder into shares of common stock at the rate of 0.8421
shares of common stock for each TECONS, subject to adjustment. The sole asset of
the Trust as the obligor on the TECONS is $115.0 million aggregate principal
amount of 5.75% Convertible Subordinated Debentures ("Debentures") of the
Company due December 15, 2026. The Debentures were issued by us to the Trust to
facilitate the offering of the TECONS. The TECONS must be redeemed for $50.00
per TECON plus accrued and unpaid dividends on December 15, 2026.

11. SEGMENTS

Our operations consist of the acquisition, exploitation, exploration,
development and production of crude oil and natural gas. Our reportable segments
are domestic, foreign and other. Financial information by reportable segment is
presented below:

- ----------
(1) Other includes corporate income and expenses.

(2) Net of geological and geophysical, delay rentals, non-cash items and
other exploration costs.

Credit Risks due to Certain Concentrations

In 2002, 2001 and 2000, we had one customer that accounted for 73%, 63%
and 84% of oil and gas revenues. In 2001 and 2000, we had another customer that
accounted for 23% and 11% of oil and gas revenues.

We entered into a 15-year contract, effective January 1, 2000, to sell
all of our current and future California crude oil production to Tosco
Corporation (now ConocoPhillips). The contract provides pricing based on a fixed
percentage of the NYMEX crude oil price for each type of crude oil that we
produce in California. Effective January 1, 2003, we renegotiated this contract
relative to our Point Arguello production, effectively

56

increasing our price on 10% of our 2003 crude output by 14.5% on the NYMEX
price. While the contract does not reduce our exposure to price volatility, it
does effectively eliminate the risk of widening basis differential between the
NYMEX price and the field price of our California oil production. In doing so,
the contract makes it substantially easier for us to hedge our realized prices.
The ConocoPhillips contract permits, under certain circumstances, to separately
market up to ten percent of our California crude production. We exercised this
right in 2001 and 2002 and sold 5,000 BOPD of our San Joaquin Valley oil
production to a third party under a one-year contract containing NYMEX pricing.
A new contract was entered into for a two-year period on January 1, 2003.

Our revenues are derived principally from uncollateralized sales to
customers in the oil and gas industry, therefore, customers may be similarly
affected by changes in economic and other conditions within the industry. We
have not experienced significant credit losses in such sales. Sales of oil and
gas to ConocoPhillips are similarly uncollateralized.

12. COMMITMENTS AND CONTINGENCIES

On December 18, 2002, a lawsuit was filed by Hills for Everyone, a
non-profit corporation, against Orange County and Nuevo Energy Company
challenging the adequacy of the Environment Impact Report for the Company's
Tonner Hills project. The suit seeks to compel Orange County to set aside its
decision to adopt the Environment Impact Report and seeks additional
environmental analysis and mitigation measures. The Company is contesting the
litigation and both the County and the Company are continuing to take the
necessary regulatory steps to move the project toward development.

On September 14, 2001, during an annual inspection, we discovered
fractures in the heat affected zone of certain flanges on our pipeline that
connects the Point Pedernales field with onshore processing facilities. We
voluntarily elected to shut-in production in the field while repairs were being
made. The daily net production from this field was approximately 5,000 barrels
of crude oil and 1.2 MMcf of natural gas, representing approximately 11% of our
daily production. We replaced the damaged flanges, as well as others which had
not shown signs of damage. We resumed production in January 2002. During the
third quarter 2002 we reached a final agreement with our underwriters with
respect to our business interruption claim. Accordingly, we recognized $3.0
million of business interruption recoveries during the third quarter 2002 which
is classified in other revenue and received payment on this claim by year-end
2002. Certain other costs related to repair are expected to be covered by
insurance based on a tentative agreement we have with our underwriters. We
expect payment with respect to the repair claims in the next nine months once
the claims are fully adjusted.

On June 15, 2001, we experienced a failure of a carbon dioxide
treatment vessel at the Rincon Onshore Separation Facility ("ROSF") located in
Ventura County, California. There were no injuries associated with this event.
Crude oil and natural gas produced from three fields offshore California are
transported onshore by pipeline to the ROSF plant where crude oil and water are
separated and treated, and carbon dioxide is removed from the natural gas
stream. The daily net production associated with these fields was 3,000 barrels
of crude oil and 2.4 MMcf of natural gas in 2001, representing approximately 6%
of our daily production. In early July 2001, crude oil production resumed and
full gas sales resumed by mid August 2001. The cost of repair, less a $50,000
deductible, is expected to be covered by insurance. We expect to settle the
insurance claims within the next six months.

On September 22, 2000, we were named as a defendant in the lawsuit
Thomas Wachtell et al. versus Nuevo Energy Company in the Superior Court of Los
Angeles County, California. We settled this lawsuit in June 2002 for, among
other matters, making a payment to plaintiffs of $3.4 million, and receiving
from plaintiffs certain interests in properties and extinguishing certain
contract rights of plaintiffs. We established a reserve for this contingency in
2001 and the settlement payment did not have a material impact on our results of
operations or financial position.

On April 5, 2000, we filed a lawsuit against ExxonMobil Corporation in
the United States District Court for the Central District of California, Western
Division. We and ExxonMobil each owned a 50% interest in the Sacate field,
offshore Santa Barbara County, California. We believed that we had been denied a
reasonable opportunity to exercise our rights under the unit operating
agreement. We alleged that ExxonMobil's actions breached the unit operating
agreement and the covenant of good faith and fair dealing. We settled this
lawsuit in June 2002. Under the terms of the settlement agreement, we received
$16.5 million from ExxonMobil and conveyed to them our interest in the Santa
Ynez Unit, our non-consent interest in the adjacent Pescado field and
relinquished our right to participate in the Sacate field and recorded a $15.3
million gain related to the sale of this unproved property.

57

In September 1997, there was a spill of crude oil into the Santa
Barbara Channel from a pipeline that connects our Point Pedernales field with
shore-based processing facilities. The volume of the spill was estimated to be
163 Bbls of oil. Repairs were completed by the end of 1997, and production
recommenced in December 1997. The costs of the clean up and the cost to repair
the pipeline either have been or are expected to be covered by our insurance,
less a deductible of $0.1 million. As of December 31, 2002, we had received
insurance reimbursements of $4.2 million, with a remaining insurance receivable
of $0.5 million. Costs related to the settlement of claims for natural resource
damage asserted by certain federal and state agencies are also expected to be
covered by insurance.

Our international investments involve risks typically associated with
investments in emerging markets such as an uncertain political, economic, legal
and tax environment and expropriation and nationalization of assets. In
addition, if a dispute arises in our foreign operations, we may be subject to
the exclusive jurisdiction of foreign courts or may not be successful in
subjecting foreign persons to the jurisdiction of the United States. We attempt
to conduct our business and financial affairs to protect against political and
economic risks applicable to operations in the various countries where we
operate, but there can be no assurance that we will be successful in so
protecting ourselves. A portion of our investment in the Congo is insured
through political risk insurance provided by Overseas Private Investment Company
("OPIC"). The political risk insurance through OPIC covers up to $25.0 million
relating to expropriation and political violence, which is the maximum coverage
available through OPIC. We have no deductible for this insurance.

In connection with our February 1995 acquisitions of two subsidiaries
owning interests in the Yombo field offshore Congo, we and a wholly-owned
subsidiary of CMS NOMECO Oil & Gas Co. ("CMS") agreed with the seller of the
subsidiaries not to claim certain tax losses ("dual consolidated losses")
incurred by such subsidiaries prior to the acquisitions. Under the tax law in
the Congo, as it existed when this acquisition took place, if an entity is
acquired in its entirety and that entity has certain tax attributes, for example
tax loss carryforwards from operations in the Republic of Congo, the subsequent
owners of that entity can continue to utilize those losses without restriction.
Pursuant to the agreement, we and CMS may be liable to the seller for the
recapture of dual consolidated losses (net operating losses of any domestic
corporation that are subject to an income tax of a foreign country without
regard to the source of its income or on a residence basis) utilized by the
seller in years prior to the acquisitions if certain triggering events occur,
including: (i) a disposition by either us or CMS of its respective Congo
subsidiary, (ii) either Congo subsidiary's sale of its interest in the Yombo
field, (iii) the acquisition of us or CMS by another consolidated group or (iv)
the failure of CMS's Congo subsidiary or us to continue as a member of its
respective consolidated group.

A triggering event will not occur, however, if a subsequent purchaser
enters into certain agreements specified in the consolidated return regulations
intended to ensure that such dual consolidated losses will not be claimed. The
only time limit associated with the occurrence of a triggering event relates to
the utilization of a dual consolidated loss in a foreign jurisdiction. A dual
consolidated loss that is utilized to offset income in a foreign jurisdiction is
only subject to recapture for 15 years following the year in which the dual
consolidated loss was incurred for U.S. income tax purposes. We and CMS have
agreed among ourselves that the party responsible for the triggering event shall
indemnify the other for any liability to the seller as a result of such
triggering event. Our potential direct liability could be as much as $35.4
million if a triggering event with respect to us occurs. Additionally, we
believe that CMS's liability (for which we would be jointly liable with an
indemnification right against CMS) could be as much as $53.1 million. CMS sold
their interest in the Yombo field in 2002 to a U.S. subsidiary of Perenco, S.A.
(Perenco), which is awaiting approval from the government of Congo. The sale was
not a triggering event as both CMS and Perenco filed a request for a Closing
Agreement with the Internal Revenue Service in accordance with the U.S.
consolidated tax return regulations prior to the sale. Further, we do not expect
a triggering event to occur with respect to Nuevo, CMS or Perenco, and do not
believe the agreement will have a material adverse effect upon us.

During 1997, a new government was established in the Congo. Although
the political situation in the Congo has not to date had a material adverse
effect on our operations in the Congo, no assurances can be made that continued
political unrest in West Africa will not have a material adverse effect on us or
our operations in the Congo in the future.

In 1996, the Congo government requested that the convention governing
the Marine I Exploitation Permit be converted to a Production Sharing Agreement
("PSA"). We are under no obligation to convert to a PSA, and our existing
convention is valid and protected by law. Our position is that any conversion to
a PSA would have no detrimental impact to us, otherwise, we will not agree to
any such conversion. Discussions with the government

58

have been ongoing intermittently since early 1997. To date, no final agreement
has been reached concerning conversion to a PSA.

We have been named as a defendant in certain other lawsuits incidental
to our business. These actions and claims in the aggregate seek damages against
us and are subject to the inherent uncertainties in any litigation. We are
defending ourselves vigorously in all such matters. We have reserved an amount
that we deem adequate to cover any potential losses related to these matters to
the extent the losses are deemed probable and estimable. This amount is reviewed
periodically and changes may be made, as appropriate. Any additional costs
related to these potential losses are not expected to be material to our
operating results, financial condition or liquidity.

Operating Leases

We have operating leases in the normal course of business, which
include those for office space and operating facilities and office and operating
equipment, with varying terms from 2002 to 2009. Total rental expense under the
agreements was $2.2 million in 2002, $4.1 million in 2001 and $2.7 million in
2000. The rental expense for operating equipment is recorded in lease operating
expense and other rental expense is recorded in general and administrative
expense. At December 31, 2002, our total commitments under operating leases were
approximately $8.9 million.

Minimum annual rental commitments at December 31, 2002, were as
follows:

13. FINANCIAL INSTRUMENTS

We have entered into commodity swaps, collars, put options and interest
rate swaps. The commodity swaps, collars and put options are designated as cash
flow hedges and the interest rate swaps are designated as fair value hedges in
accordance with SFAS 133. Quantities covered by crude hedges are based on West
Texas Intermediate ("WTI") barrels. Our production is expected to average 74% of
WTI, therefore, each WTI barrel hedges 1.35 barrels of our production.

Derivative Instruments Designated as Cash Flow Hedges

At December 31, 2002, we had entered into the following cash flow
hedges:

Crude Oil Hedges

59

Natural Gas Hedges

Natural Gas Hedges

At December 31, 2002, the fair market value of these hedge positions is
a loss of $22.3 million. All of these agreements expose us to counterparty
credit risk to the extent that the counterparty is unable to meet its settlement
commitments.

Derivative Instruments Designated as Fair Value Hedges

In late December 2001 and early 2002, we entered into three interest
rate swap agreements with notional amounts totaling $200 million to hedge the
fair value of our 9 1/2% Notes due 2008 and our 9 3/8% Notes due 2010. These
swaps were designated as fair value hedges and were reflected as an increase or
decrease of long-term debt with a corresponding increase in long-term assets or
liabilities.

In late August and early September 2002, we terminated our swap
transactions relating to these Notes. As a result of these terminations, we
received accrued interest of $2.2 million and the present value of the swap
option of $9.6 million on our 9 3/8% Notes and $0.5 million in accrued interest
and the present value of the swap option of $2.5 million on our 9 1/2% Notes.
The gain of $9.6 million on our 9 3/8% Notes and $2.5 million on our 9 1/2%
Notes is reflected as an increase of long-term debt and will be amortized as a
reduction to interest expense over the life of the Notes. As of December 31,
2002, we amortized $0.4 million as a reduction of interest expense.

In late August and early November 2002, we entered into two interest
rate swap agreements with notional amounts totaling $50 million each, to hedge a
portion of the fair value of our 9 3/8% Notes due 2010. These swaps are
designated as fair value hedges and are reflected as an increase of long-term
debt of $2.2 million as of December 31, 2002, with a corresponding increase in
long-term assets. Under the terms of the first agreement, the counterparty pays
us a weighted average fixed annual rate of 9 3/8% on total notional amounts of
$50 million, and we pay the counterparty a variable annual rate equal to the
six-month LIBOR rate plus a weighted average rate of 4.71%. Under the terms of
the second agreement, the counterparty pays us a weighted average fixed annual
rate of 9 3/8% on total notional amounts of $50 million, and we pay the
counterparty a variable annual rate equal to the six-month LIBOR rate plus a
weighted average rate of 4.95%.

Fair Values of Financial Instruments

Fair value for cash, short-term investments, receivables and payables
approximates carrying value. The following table details the carrying values and
approximate fair values of our other investments, derivative financial
instruments and long-term debt at December 31, 2002 and 2001.

60

The fair value of our long-term debt and TECONS were determined based
upon interest rates currently available to us for borrowing with similar terms
at December 31, 2002 and 2001.

Other - Enron Exposure and Call Spreads

In December 2001, Enron Corp. ("Enron") and certain of its affiliates
filed voluntary petitions for reorganization under Chapter 11 of the United
States Bankruptcy Code. As a result, we recorded a $7.6 million charge in the
fourth quarter of 2001: $1.2 million related to the November and December 2001
crude oil price swaps, $0.9 million related to the Enron call spread (see
below), and $5.5 million related to the fair value of open hedges of second,
third and fourth quarter 2002 crude oil production. Once a deterioration in
creditworthiness creates uncertainty as to whether the future cash flows from
the hedging instrument will be highly effective in offsetting the hedged risk,
the derivative instrument is no longer considered highly effective and no longer
qualifies for hedge accounting treatment. At such time, the fair value of the
derivative asset or liability is adjusted to its new fair value, with the change
in value being charged to current earnings. The net gain or loss of the
derivative instruments previously reported in other comprehensive income remains
in accumulated other comprehensive income and is reclassified into earnings
during the period in which the originally designated hedge items affect
earnings. The $2.2 million deferred gain in Other Comprehensive Income at
December 31, 2001 was reclassified into earnings in 2002.

In 2001 and 2000, we entered into call spreads with the anticipation of
using the proceeds to offset the Unocal Contingent payment. (See Note 14).
Subsequent to entering into the call spreads, the market fell and as a result,
offsetting call spreads were purchased to economically nullify the trade. All of
our existing call spreads had been offset through the purchase of a mirror
spread, however, the call spread with Enron was cancelled. (See above
discussion). The remaining mirror call spread is not designated as a hedging
instrument and is marked-to-market with changes in fair value recognized
currently as derivative gain/loss. At December 31, 2002, $2.8 million is
reflected in long-term liabilities.

14. CONTINGENT PAYMENT AND PRICE SHARING AGREEMENTS

In connection with the acquisition from Unocal in 1996 of the
properties located in California, we are obligated to make a contingent payment
for the years 1998 through 2004 if oil prices exceed thresholds set forth in the
agreement with Unocal. Contingent payments are accounted for as a purchase price
adjustment to oil and gas properties. The contingent payment will equal 50% of
the difference between the actual average annual price received on a
field-by-field basis (capped by a maximum price) and a minimum price, less ad
valorem and production taxes, and certain other permitted deductions, multiplied
by the actual number of barrels of oil sold that are produced from the
properties acquired from Unocal during the respective year. The minimum price of
$17.75 per Bbl under the agreement (determined based on the near month delivery
of WTI crude oil on the NYMEX) is escalated at 3% per year and the maximum price
of $21.75 per Bbl on the NYMEX is escalated at 3% per year. Minimum and maximum
prices are reduced to reflect the field level price by subtracting a fixed
differential established for each field. The reduction was established at
approximately the differential between actual sales prices and NYMEX prices in
effect in 1995 ($4.34 per Bbl weighted average for all the properties acquired
from Unocal). We accumulate credits to offset the contingent payment when prices
are $0.50 per Bbl or more below the minimum price. On March 15, 2002, we paid
$10.8 million to Unocal attributable to calendar year 2001 and recorded the
payment in oil and gas properties. In March 2003, we advised Unocal that we had
failed to take deductions to the purchase price that we believe are permitted by
the agreement. Application of these deductions resulted in no payment due for
either calendar year 2001 or 2002 and resulted in a credit being available to
use against future obligations. Unocal disputes this position. Discussions are
taking place between the companies in an effort to resolve this issue for both
years. While the final outcome of this matter is not presently determinable, its
resolution is not expected to have a significant impact to our operating
results, financial condition or liquidity.

In connection with the acquisition of the Congo properties in 1995, we
entered into a price sharing agreement with the seller. Under the terms of the
agreement, if the average price received for the oil production during the year
is greater than the benchmark price established by the agreement, we are
obligated to pay the seller 50% of the difference between the benchmark price
and the actual price received, for all the production associated with this
acquisition. The benchmark price was $15.96 million in 2002, $15.78 per Bbl for
2001 and $15.19 per Bbl for 2000. The benchmark price increases each year, based
on the increase in the Consumer Price Index. For 2002, the effect of this
agreement was that we only owned upside above $15.96 per Bbl on approximately
66% of our Congo production. We were obligated to pay the seller $4.1 million in
2002, $3.4 million in 2001 and $5.4 million in 2000 under this price sharing
agreement. Because there is no termination date associated with this agreement,
it is accounted for as an oil royalty.

61

We acquired a 12% working interest in the Point Pedernales oil field
from Unocal in 1994 and the remainder of its 80.3 % working interest from Torch
in 1996. We are entitled to all revenue proceeds up to $9.00 per Bbl, with the
excess revenue over $9.00 per Bbl, if any, we share with the original owners
from whom Torch acquired its interest. We own amounts below $9.00 per Bbl with
the other working interest owners based on their respective ownership interests.
For 2002, the effect of this agreement is we were entitled to receive the
pricing upside above $9.00 per Bbl on approximately 73% of the gross Point
Pedernales production. As of December 31, 2002, we had $0.5 million accrued as
our obligation under this agreement. As of December 31, 2001, we had $0.2
million accrued as our obligation under this agreement. As of December 31, 2000,
we had $0.6 million accrued as our obligation under this agreement. Obligations
under this agreement are accounted for as an oil royalty.

15. SUPPLEMENTAL INFORMATION (UNAUDITED)

Oil and Gas Producing Activities

Included herein is information with respect to oil and gas acquisition,
exploration, development and production activities, which is based on estimates
of year-end oil and gas reserve quantities and estimates of future development
costs and production schedules. Reserve quantities and future production as of
December 31, 2002, and for previous years, are based primarily on reserve
reports prepared by the independent petroleum engineering firm of Ryder Scott
Company. These estimates are inherently imprecise and subject to substantial
revision.

Estimates of future net cash flows from proved reserves of gas, oil,
condensate and natural gas liquids ("NGL") were made in accordance with SFAS No.
69, Disclosures about Oil and Gas Producing Activities. The estimates are based
on the NYMEX cash price at year-end 2002, of $31.20 per Bbl and $4.79 per MMbtu
adjusted for basis differences, and are adjusted for the effects of contractual
agreements with Unocal and Amoco in connection with the California and Congo
property acquisitions (see Note 14).

Estimated future cash inflows are reduced by estimated future
development and production costs based on year-end cost levels, assuming
continuation of existing economic conditions, and by estimated future income tax
expense. Tax expense is calculated by applying the existing statutory tax rates,
including any known future changes, to the pre-tax net cash flows, less
depreciation of the tax basis of the properties and depletion allowances
applicable to the gas, oil, condensate and NGL production. Because the
disclosure requirements are standardized, significant changes can occur in these
estimates based upon oil and gas prices currently in effect. The results of
these disclosures should not be construed to represent the fair market value of
our oil and gas properties. A market value determination would include many
additional factors including: (i) anticipated future increases or decreases in
oil and gas prices and production and development costs; (ii) an allowance for
return on investment; (iii) the value of additional reserves, not considered
proved at the present, which may be recovered as a result of further exploration
and development activities; and (iv) other business risks.

62

Costs incurred

The following table sets forth the costs incurred in property
acquisition and development activities:

(1) Includes capitalized interest directly related to development
activities of $1.9 million in 2002 and $2.5 million in 2001. There was
no capitalized interest in 2000.

63

Capitalized costs

The following table sets forth the capitalized costs relating to oil
and gas activities and the associated accumulated depreciation, depletion and
amortization:

64

Results of operations for producing activities

- ----------
* Results of operations represent results from continuing operations.

65

Our estimated total proved and proved developed reserves of oil and gas
are as follows:

- ----------
(1) Includes estimated NGL reserves.

(2) Reserves and production from discontinued operations are included in
this table.

66

Discounted future net cash flows

The standardized measure of discounted future net cash flows and
changes therein are shown below:

67

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

68

16. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

- ---------
(1) The sum of the individual quarterly net income (loss) per common share may
not agree with year-to-date net income (loss) per common share as each
quarterly computation is based on the weighted average number of common
shares outstanding during that period.

(2) Results for the 2001 quarters were revised due to a change in accounting
for processed fuel oil and natural gas liquids inventories (See Note 2).

(3) Fourth quarter 2001 results include $103.5 million of impairments.

(4) Fourth quarter 2002 results include a $17.8 million after-tax write down of
assets held for sale in discontinued operations.

69

INDEPENDENT AUDITORS' REPORT ON CONSOLIDATED FINANCIAL
STATEMENT SCHEDULE

To the Board of Directors and Stockholders
Nuevo Energy Company:

Under date of March 17, 2003, we reported on the consolidated balance sheets of
Nuevo Energy Company as of December 31, 2002 and 2001, and the related
consolidated statements of income, stockholders' equity, cash flows and
comprehensive income for each of the years in the three-year period ended
December 31, 2002. In connection with our audits of the aforementioned
consolidated financial statements, we also audited the related consolidated
financial statement schedule. This consolidated financial statement schedule is
the responsibility of the Company's management. Our responsibility is to express
an opinion on the consolidated financial statement schedule based on our audits.

In our opinion, the consolidated financial statement schedule, when considered
in relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respects, the information set forth therein.

KPMG LLP

Houston, Texas
March 17, 2003

70

SCHEDULE II

NUEVO ENERGY COMPANY
VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS)

71

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

A change in independent auditors from Arthur Andersen LLP to KPMG LLP
was reported in our Current Report on Form 8-K dated July 22, 2002.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required by this item will be included in our
definitive proxy statement, which will be filed not later than 120 days after
December 31, 2002, and is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item will be included in our
definitive proxy statement, which will be filed not later than 120 days after
December 31, 2002, and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by Item 403 of Regulation S-K will be included
in our definitive proxy statement, which will be filed not later than 120 days
after December 31, 2002, and is incorporated herein by reference.

EQUITY COMPENSATION PLAN INFORMATION

The following table sets forth information about the Common Stock that
may be issued under all of the Company's existing equity compensation plans as
of December 31, 2002:

Equity compensation plans approved by our shareholders include the 1990
Option Plan, the 1993 Stock Incentive Plan, and the 1999 Stock Incentive Plan.

The equity compensation plans that have not been approved by our
shareholders are the 2001 Stock Incentive Plan, the Janet F. Clark Stock Option
Plan and the George B. Nilsen Stock Option Plan.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this item will be included in a definitive
proxy statement, which will be filed not later than 120 days after December 31,
2002, and is incorporated herein by reference.

72

ITEM 14. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

The term "disclosure controls and procedures" is defined in Rule
13a-14(c) of the Securities Exchange Act of 1934, or the Exchange Act. This term
refers to the controls and procedures of a company that are designed to ensure
that information required to be disclosed by a company in the reports that it
files under the Exchange Act is recorded, processed, summarized and reported
within required time periods. Our Chief Executive Officer and our Chief
Financial Officer have evaluated the effectiveness of our disclosure controls
and procedures as of a date within 90 days before the filing of the annual
report, and they have concluded that as of that date, our disclosure controls
and procedures were effective at ensuring that required information will be
disclosed on a timely basis in our reports filed under the Exchange Act.

CHANGE IN INTERNAL CONTROLS

We maintain a system of internal controls that are designed to provide
reasonable assurance that our books and records accurately reflect our
transactions and that our established policies and procedures are followed.
There were no significant changes to our internal controls or in other factors
that could significantly affect our internal controls subsequent to the date of
their evaluation by our Chief Executive Officer and our Chief Financial Officer,
including any corrective actions with regard to significant deficiencies and
material weaknesses.

73

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) THE FOLLOWING DOCUMENTS ARE FILED AS PART OF THIS REPORT:

1. Financial Statements.

Our consolidated financial statements are included in Part II,
Item 8 of this report:

Independent Auditors Report................................................... 36
Consolidated Statements of Income ............................................ 37
Consolidated Balance Sheets .................................................. 38
Consolidated Statements of Cash Flows ........................................ 39
Consolidated Statements of Stockholder's Equity .............................. 40
Consolidated Statements of Comprehensive Income............................... 41
Notes to the Consolidated Financial Statements ............................... 42

2. Financial statement schedules and supplementary information
required to be submitted.

Schedule II - Valuation and qualifying accounts .............................. 71
Schedules other than that listed above are omitted because they are not applicable.

3. Exhibit List.................................................................. 75

(b) REPORTS ON FORM 8-K:

o We filed a current report on Form 8-K on November 15, 2002 filing
2001 re-audited financial statements.

74

NUEVO ENERGY COMPANY

EXHIBIT LIST
DECEMBER 31, 2002

Each exhibit identified below is filed as a part of this report.
Exhibits not incorporated by reference to a prior filing are designated by an
asterisk; all exhibits not so designated are incorporated herein by reference to
a prior filing as indicated. Exhibits designated with a "+" constitute a
management contract or compensatory plan or arrangement required to be filed as
an exhibit to this report pursuant to Item 14 (c) of Form 10-K.

(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation
or Succession.

2.1 Agreement and Plan of Merger dated September 18, 2002
by and among Athanor Resources, Inc., Athanor B.V.,
Nuevo Energy Company, Nuevo Texas Inc., Yorktown
Energy Partners III, L.P., Yorktown Energy IV, L.P.,
Yorktown Partners LLC, SAFIC S.A., Charles de
Mestral, J. Ross Craft, Montana Oil and Gas, Ltd.,
David A. Badley, James S. Scott, Glenn Reed, Doug
Allison and Mohamed Yaich (Exhibit 2.1 to our Form
8-K dated September 19, 2002).

(3) Articles of Incorporation and bylaws.

3.1 Certificate of Incorporation of Nuevo Energy Company
(Exhibit 3.1 to our 1999 Second Quarter Form 10-Q).

3.2 Certificate of Amendment to the Certificate of
Incorporation of Nuevo Energy Company (Exhibit 3.2 to
our 1999 Second Quarter Form 10-Q).

3.3 Bylaws of Nuevo Energy Company (Exhibit 3.3 to our
1999 Second Quarter Form 10-Q).

3.4 Amendment to section 3.1 of the Bylaws of Nuevo
Energy Company (Exhibit 3.4 to our 1999 Second
Quarter Form 10-Q).

(4) Instruments defining the rights of security holders, including
indentures.

4.1 Specimen Stock Certificate (Exhibit 4.1 to our Form
S-4 (No. 33-33873) filed under the Securities Act of
1933).

4.2 Indenture dated April 1, 1996 among Nuevo Energy
Company as Issuer, various Subsidiaries as the
Guarantors, and State Street Bank and Trust Company
as the Trustee - 9 1/2% Senior Subordinated Notes due
2006. (Incorporated by reference from Form S-3 (No.
333-1504).

4.3 Form of Amended and Restated Declaration of Trust
dated December 23, 1996, among the Company, as
Sponsor, Wilmington Trust Company, as Institutional
Trustee and Delaware Trustee, and Michael D. Watford,
Robert L. Gerry, III and Robert M. King, as Regular
Trustees. (Exhibit 4.1 to our Form 8-K filed on
December 23, 1996).

4.4 Form of Subordinated Indenture dated as of November
25, 1996, between the Company and Wilmington Trust
Company, as Indenture Trustee. (Exhibit 4.2 to Form
8-K filed on December 23, 1996).

4.5 Form of First Supplemental Indenture dated December
23, 1996, between the Company and Wilmington Trust
Company, as Indenture Trustee. (Exhibit 4.3 to Form
8-K filed on December 23, 1996).

4.6 Form of Preferred Securities Guarantee Agreement
dated as of December 23, 1996, between the Company
and Wilmington Trust Company, as Guarantee Trustee.
(Exhibit 4.4 to Form 8-K filed on December 23, 1996).

4.7 Form of Certificate representing TECONS. (Exhibit 4.5
to Form 8-K filed on December 23, 1996).

75

4.8 Shareholder Rights Plan, dated March 5, 1997, between
Nuevo Energy Company and American Stock Transfer &
Trust Company, as Rights Agent (Exhibit 1 to our Form
8-A filed on April 1, 1997).

4.9 Release and Termination of Subsidiary Guarantees with
respect to the 9 1/2% Senior Subordinated Notes due
2006. (Exhibit 4.11 to our 1997 Form 10-K)

4.10 Second Supplemental Indenture to the Indenture dated
April 1, 1996, dated August 9, 1999 between Nuevo
Energy Company and State Street Bank and Trust
Company - 9 1/2% Senior Subordinated Notes due 2006
(Exhibit 4.10 to our Form S-4 (No. 333-90235) filed
on November 3, 1999).

4.11 Indenture dated as of August 20, 1999, between Nuevo
Energy Company and State Street Bank Trust Company,
as Trustee (Exhibit 4.11 to our Form S-4 (No.
333-90235) filed on November 3, 1999).

4.12 Registration Agreement dated August 20, 1999, between
Nuevo Energy Company, Banc of America Securities LLC
and Salomon Smith Barney Inc. (Exhibit 4.12 to our
Form S-4 (No. 333-90235) filed on November 3, 1999).

4.13 Indenture dated September 26, 2000, between Nuevo
Energy Company and State Street Bank and Trust
Company as the Trustee - 9 3/8% Senior subordinated
Notes due 2010 (Exhibit 4.12 to our 2000 Third
Quarter Form 10-Q).

4.14 Registration Agreement dated September 26, 2000,
between Nuevo Energy Company and Banc of America
Securities LLC, Banc One Capital Markets, Inc. and
J.P. Morgan & Co. (Exhibit 4.13 to our 2000 Third
Quarter Form 10-Q).

(10) Material Contracts.

10.1 Third Restated Credit Agreement dated June 7, 2000,
between Nuevo Energy Company (Borrower) and Bank of
America N.A. (Administrative Agent), Bank One, NA
(Syndication Agent), Bank of Montreal (Documentation
Agent) and certain lenders (Exhibit 10.1 to our 2000
Second Quarter Form 10-Q).

10.2 1990 Stock Option Plan, as amended (Exhibit 10.8 to
our Form S-1 dated July 13, 1992).

10.3 1993 Stock Incentive Plan, as amended (Exhibit 4.2 to
our Form S-8 (No. 333-21063) filed on February 4,
1997.)

10.4 1999 Stock Incentive Plan (Exhibit 99.1 to our Form
S-8 (No. 333-87899) filed on September 28, 1999).

10.5 Nuevo Energy Company Deferred Compensation Plan
(Exhibit 99 to our Form S-8 (No. 333-51217) filed on
April 28, 1998).

10.6 Stock Purchase Agreement, dated as of June 30, 1994,
among Amoco Production Company ("APC"), Walter
International Inc. ("Walter"), Walter Congo Holdings,
Inc. ("Walter Holdings"), Walter International Congo,
Inc. (before the merger "Walter Congo" and after the
merger "Old Walter Congo"), Nuevo, Nuevo Holding and
The Nuevo Congo Company (before the merger, "Nuevo
Congo" and after the merger, "Old Nuevo Congo").
(Exhibit 2.1 to Form 8-K dated March 10, 1995).

10.7 Amendment to Stock Purchase Agreement dated as of
September 19, 1994, among APC, Walter Congo, Nuevo
Congo, Walter Holdings, Nuevo Holding, Walter and
Nuevo. (Exhibit 2.2 to Form 8-K dated March 10,
1995).

76

10.8 Second Amendment to Stock Purchase Agreement dated as
of October 15, 1994, among APC, Walter Congo, Nuevo
Congo, Walter Holdings, Nuevo Holding, Walter and
Nuevo. (Exhibit 2.3 to Form 8-K dated March 10,
1995).

10.9 Third Amendment to Stock Purchase Agreement dated as
of December 2, 1994, among APC, Walter Congo, Nuevo
Congo, Walter Holdings, Nuevo Holding, Walter and
Nuevo. (Exhibit 2.4 to Form 8-K dated March 10,
1995.)

10.10 Fourth Amendment to Stock Purchase Agreement dated as
of February 23, 1995, among APC, Walter Congo, Nuevo
Congo, Walter Holdings, Nuevo Holding, Walter and
Nuevo. (Exhibit 2.5 to Form 8-K dated March 10,
1995).

10.11 Tax Agreement dated as of February 23, 1995, executed
by APC, Amoco Congo Exploration Company ("ACEC"),
Amoco Congo Production Company ("ACPC"), Walter,
Walter Holdings, Walter Congo, Nuevo, Nuevo Holding
and Nuevo Congo. (Exhibit 2.6 to Form 8-K dated March
10, 1995).

10.12 Agreement and Plan of Merger executed by Nuevo Congo,
Nuevo Holding and APC dated February 24, 1995.
(Exhibit 2.7 to Form 8-K dated March 10, 1995).

10.13 Finance Agreement dated as of December 28, 1994,
among Nuevo Holding, Nuevo Congo and The Overseas
Private Investment Corporation ("OPIC"). (Exhibit 2.8
to Form 8-K dated March 10, 1995).

10.14 Subordination Agreement dated December 28, 1994,
among Nuevo Congo, Nuevo Holding, Walter Congo,
Walter Holdings and APC. (Exhibit 2.9 to Form 8-K
dated March 10, 1995).

10.15 Guaranty covering the obligations of Nuevo Congo and
Walter Congo under the Stock Purchase Agreement dated
February 24, 1995, executed by Walter and Nuevo.
(Exhibit 2.10 to Form 8-K dated March 10, 1995).

10.16 Inter-Purchaser Agreement dated as of December 28,
1994, among Walter, Old Walter Congo, Walter
Holdings, Nuevo, Old Nuevo Congo and Nuevo Holding.
(Exhibit 2.11 to Form 8-K dated March 10, 1995).

10.17 Latent ORRI Contract dated February 25, 1995, among
Walter, Walter Holdings, Walter Congo, Nuevo, Nuevo
Holding and Nuevo Congo. (Exhibit 2.12 to Form 8-K
dated March 10, 1995).

10.18 Latent Working Interest Contract dated February 25,
1995, among Walter, Walter Holdings, Walter Congo,
Nuevo, Nuevo Holding and Nuevo Congo. (Exhibit 2.13
to Form 8-K dated March 10, 1995).

10.19 Asset Purchase Agreement dated as of February 16,
1996 between Nuevo Energy Company, the Purchaser, and
Union Oil Company of California as Seller. (Exhibit
2.1 to Form S-3 (No. 333-1504).

10.20 Asset Purchase Agreement dated as of April 4, 1997,
by and among Torch California Company and Express
Acquisition Company, as Sellers, and Nuevo Energy
Company, as Purchaser. (Exhibit 2.2 to Form S-3 (No.
333-1504)).

10.21 Purchase and sale agreement dated October 16, 1998
between Nuevo Energy Company (Seller) and Samson Lone
Star Limited Partnership (Buyer). (Exhibit 10.28 to
our 1998 Form 10-K).

10.22 Master Services Agreement among the Company and Torch
Energy Advisors Incorporated, Torch Operating
Company, Torch Energy Marketing, Inc., and Novistar,
Inc. dated January 1, 1999. (Exhibit 10.29 to our
1998 Form 10-K).

77

10.23 Employment Agreement with Bruce Murchison dated June
1, 1999. (Exhibit 10.27 to our 1999 Third Quarter
Form 10-Q).

10.24 Employment Agreement with John P. McGinnis dated July
15, 1999. (Exhibit 10.28 to our 1999 Third Quarter
Form 10-Q).

10.25 Crude Oil Purchase Agreement dated February 4, 2000
between Nuevo Energy Company and Tosco Corporation.
(Exhibit 10.1 to Form 8-K dated March 23, 2000).

10.26 Severance Protection Agreement dated March 25, 2001.
(Exhibit 10.31 to our 2000 Form 10-K).

10.27 Amendment to 1999 Stock Incentive Plan (Exhibit 99.1
to our Form S-8, filed on October 21, 2001).

10.28 2001 Stock Incentive Plan (Exhibit 99.1 to our Form
S-8, filed on October 21, 2001).

10.29 Employment Agreement with James L. Payne dated
October 15, 2001. (Exhibit 10.1 to our 2001 Third
Quarter Form 10-Q).

10.30 Janet F. Clark Stock Option Plan (Exhibit 10.35 to
our 2001 Form 10-K).

10.31 George B. Nilsen Stock Option Plan (Exhibit 10.36 to
our 2001 Form 10-K).

10.32 Registration Rights Agreement dated September 18,
2002 by and among Nuevo Energy Company, Yorktown
Energy Partners III, L.P., Yorktown Energy IV, L.P.,
Yorktown Partners LLC, SAFIC S.A., Charles de
Mestral, J. Ross Craft, Montana Oil and Gas, Ltd.,
David A. Badley, James S. Scott, Glenn Reed, Doug
Allison and Mohamed Yaich (Exhibit 10.1 to our Form
8-K dated September 19, 2002).

10.33 Amendment to the 2001 Stock Incentive Plan (Exhibit
99.1 to our Form S-8 dated November 1, 2002).

+10.34 First Amendment to Employment Agreement with James L.
Payne dated September 11, 2002.

+10.35 Key Executive Terminated Without Cause Agreement.

*21 Subsidiaries of the Registrant

(23) Consents of experts and counsel

*23.1 Consent of KPMG LLP

(99) Additional Exhibits

*99.1 Certification of Chief Executive Officer of Nuevo
Energy Company

*99.2 Certification of Chief Financial Officer of Nuevo
Energy Company

78

GLOSSARY OF OIL AND GAS TERMS

TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS

o Bbl -- One stock tank barrel, or 42 US gallons liquid volume,
of crude oil or other liquid hydrocarbons.

o Bcf -- One billion cubic feet of natural gas.

o Bcfe -- One billion cubic feet of natural gas equivalent.

o BOE -- One barrel of oil equivalent, converting gas to oil at
the ratio of 6 Mcf of gas to 1 Bbl of oil.

o BOPD -- One barrel of oil per day.

o MBbl -- One thousand Bbls.

o Mcf -- One thousand cubic feet of natural gas.

o MMBbl -- One million Bbls of oil or other liquid hydrocarbons.

o MMcf -- One million cubic feet of natural gas.

o MBOE -- One thousand BOE.

o MMBOE -- One million BOE.

TERMS USED TO DESCRIBE THE COMPANY'S INTERESTS IN WELLS AND ACREAGE

o Gross oil and gas wells or acres -- The Company's gross wells
or gross acres represent the total number of wells or acres in
which the Company owns a working interest.

o Net oil and gas wells or acres -- Determined by multiplying
"gross" oil and natural gas wells or acres by the working
interest that the Company owns in such wells or acres
represented by the underlying properties.

TERMS USED TO ASSIGN A PRESENT VALUE TO THE COMPANY'S RESERVES

o Standard measure of proved reserves -- The present value,
discounted at 10%, of the pre-tax future net cash flows
attributable to estimated net proved reserves. The Company
calculates this amount by assuming that it will sell the oil
and gas production attributable to the proved reserves
estimated in its independent engineer's reserve report for the
prices it received for the production on the date of the
report, unless it had a contractual arrangement specific to a
property to sell the production for a different price. The
Company also assumes that the cost to produce the reserves
will remain constant at the costs prevailing on the date of
the report. The assumed costs are subtracted from the assumed
revenues resulting in a stream of future net cash flows.
Estimated future income taxes using rates in effect on the
date of the report are deducted from the net cash flow stream.
The after-tax cash flows are discounted at 10% to result in
the standardized measure of the Company's proved reserves. The
standardized measure of the Company's proved reserves is
disclosed in the Company's audited financial statements in
Note 15.

o Pre-tax discounted present value -- The discounted present
value of proved reserves is identical to the standardized
measure, except that estimated future income taxes are not
deducted in calculating future net cash flows. The Company
discloses the discounted present value without deducting
estimated income taxes to provide what it believes is a better
basis for comparison of its reserves to the producers who may
have different tax rates.

79

TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES

o Proved reserves -- The estimated quantities of crude oil,
natural gas and natural gas liquids which, upon analysis of
geological and engineering data, appear with reasonable
certainty to be recoverable in the future from known oil and
natural gas reservoirs under existing economic and operating
conditions.

The SEC definition of proved oil and gas reserves, per Article
4-10(a)(2) of Regulation S-X, is as follows:

Proved oil and gas reserves. Proved oil and gas reserves are
the estimated quantities of crude oil, natural gas, and
natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date
the estimate is made. Prices include consideration of changes
in existing prices provided only by contractual arrangements,
but not on escalations based upon future conditions.

(a) Reservoirs are considered proved if economic producibility
is supported by either actual production or conclusive
formation test. The area of a reservoir considered proved
includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any; and (B) the
immediately adjoining portions not yet drilled, but which can
be reasonably judged as economically productive on the basis
of available geological and engineering data. In the absence
of information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of
the reservoir.

(b) Reserves which can be produced economically through
application of improved recovery, techniques (such as fluid
injection) are included in the "proved" classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was
based.

(c) Estimates of proved reserves do not include the following:
(1) oil that may become available from known reservoirs, but
is classified separately as "indicated additional reserves";
(2) crude oil, natural gas, and natural gas liquids, the
recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or
economic factors; (3) crude oil, natural gas, and natural gas
liquids, that may occur in undrilled prospects; and (4) crude
oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such
sources.

o Proved developed reserves -- Proved reserves that can be
expected to be recovered through existing wells with existing
equipment and operating methods.

o Proved undeveloped reserves -- Proved reserves that are
expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is
required.

TERMS WHICH DESCRIBE THE COST TO ACQUIRE THE COMPANY'S RESERVES

o Finding costs -- The Company's finding costs compare the
amount the Company spent to acquire, explore and develop its
oil and gas properties, explore for oil and gas and to drill
and complete wells during a period, with the increases in
reserves during the period. This amount is calculated by
dividing the net change in the Company's evaluated oil and
property costs during a period by the change in proved
reserves plus production over the same period. The Company's
finding costs as of December 31 of any year represent the
average finding costs over the three-year period ending
December 31 of that year.

TERMS WHICH DESCRIBE THE PRODUCTIVE LIFE OF A PROPERTY OR GROUP OF PROPERTIES

o Reserve life index -- A measure of the productive life of an
oil and gas property or a group of oil and gas properties,
expressed in years. Reserve life index for the years ended
December 31, 2002, 2001 or 2000 equal the estimated net proved
reserves attributable to a property or group of properties
divided by production from the property or group of properties
for the four fiscal quarters preceding the date as of which
the proved reserves were estimated.

80

TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF THE COMPANY'S OIL AND GAS
PROPERTIES

o Royalty interest -- A real property interest entitling the
owner to receive a specified portion of the gross proceeds of
the sale of oil and natural gas production or, if the
conveyance creating the interest provides, a specific portion
of oil and natural gas produced, without any deduction for the
costs to explore for, develop or produce the oil and natural
gas. A royalty interest owner has no right to consent to or
approve the operation and development of the property, while
the owners of the working interests have the exclusive right
to exploit the mineral on the land.

o Working interest -- A real property interest entitling the
owner to receive a specified percentage of the proceeds of the
sale of oil and natural gas production or a percentage of the
production, but requiring the owner of the working interest to
bear the cost to explore for, develop and produce such oil and
natural gas. A working interest owner who owns a portion of
the working interest may participate either as operator or by
voting his percentage interest to approve or disapprove the
appointment of an operator and drilling and other major
activities in connection with the development and operation of
a property.

o Net revenue interest -- A real property interest entitling the
owner to receive a specified percentage of the proceeds of the
sale of oil and natural gas production or a percentage of the
production, net of royalty interests and costs to explore for,
develop and produce such oil and natural gas.

TERMS USED TO DESCRIBE SEISMIC OPERATIONS

o Seismic data -- Oil and gas companies use seismic data as
their principal source of information to locate oil and gas
deposits, both to aid in exploration for new deposits and to
manage or enhance production from known reservoirs. To gather
seismic data, an energy source is used to send sound waves
into the subsurface strata. These waves are reflected back to
the surface by underground formations, where they are detected
by geophones which digitize and record the reflected waves.
Computers are then used to process the raw data to develop an
image of underground formations.

o 2-D seismic data -- 2-D seismic survey data has been the
standard acquisition technique used to image geologic
formations over a broad area. 2-D seismic data is collected by
a single line of energy sources which reflect seismic waves to
a single line of geophones. When processed, 2-D seismic data
produces an image of a single vertical plane of sub-surface
data.

o 3-D seismic -- 3-D seismic data is collected using a grid of
energy sources, which are generally spread over several miles.
A 3-D survey produces a three dimensional image of the
subsurface geology by collecting seismic data along parallel
lines and creating a cube of information that can be divided
into various planes, thus improving visualization.
Consequently, 3-D seismic data is a more reliable indicator of
potential oil and natural gas reservoirs in the area evaluated
than 2-D seismic data.

THE COMPANY'S MISCELLANEOUS DEFINITIONS

o Infill drilling - Infill drilling is the drilling of an
additional well or additional wells in excess of those
provided for by a spacing order in order to more adequately
drain a reservoir.

o No. 6 fuel oil (Bunker) - No. 6 fuel oil is a heavy residual
fuel oil used by ships, industry, and for large-scale heating
installations.

o Upstream oil and gas properties - Upstream is a term used in
describing operations performed before those at a point of
reference. Production is an upstream operation and marketing
is a downstream operation when the refinery is used as a point
of reference. On a gas pipeline, gathering activities are
considered to have ended when gas reaches a central point for
delivery into a single line, and facilities used before this
point of reference are upstream facilities used in gathering,
whereas facilities employed after commingling at the central
point and employed to make ultimate delivery of the gas are
downstream facilities.

81

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

NUEVO ENERGY COMPANY
(Registrant)

Date: March 31, 2003 By: /s/ James L. Payne
--------------------- -----------------------------
James L. Payne
Chairman, President and
Chief Executive Officer

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

By: /s/ James L. Payne Date: March 31, 2003
----------------------------------- --------------------------
James L. Payne
Chairman, President and
Chief Executive Officer
(Principal Executive Officer)

By: /s/ Janet F. Clark Date: March 31, 2003
----------------------------------- --------------------------
Janet F. Clark
Senior Vice President and
Chief Financial Officer
(Principal Financial and
Accounting Officer)

By: /s/ Isaac Arnold, Jr. Date: March 31, 2003
----------------------------------- --------------------------
Isaac Arnold, Jr.
Director

By: /s/ Charles M. Elson Date: March 31, 2003
----------------------------------- --------------------------
Charles M. Elson
Director

By: /s/ Robert L Gerry III Date: March 31, 2003
----------------------------------- --------------------------
Robert L. Gerry III
Director

By: /s/ J. Frank Haasbeek Date: March 31, 2003
----------------------------------- --------------------------
J. Frank Haasbeek
Director

By: /s/ James T. Jongebloed Date: March 31, 2003
----------------------------------- --------------------------
James T. Jongebloed
Director

By: /s/ Gary R. Petersen Date: March 31, 2003
----------------------------------- --------------------------
Gary R. Petersen
Director

By: /s/ Sheryl K. Pressler Date: March 31, 2003
----------------------------------- --------------------------
Sheryl K. Pressler
Director

82

INDEX TO EXHIBITS

4.8 Shareholder Rights Plan, dated March 5, 1997, between
Nuevo Energy Company and American Stock Transfer &
Trust Company, as Rights Agent (Exhibit 1 to our Form
8-A filed on April 1, 1997).

4.9 Release and Termination of Subsidiary Guarantees with
respect to the 9 1/2% Senior Subordinated Notes due
2006. (Exhibit 4.11 to our 1997 Form 10-K)

4.10 Second Supplemental Indenture to the Indenture dated
April 1, 1996, dated August 9, 1999 between Nuevo
Energy Company and State Street Bank and Trust
Company - 9 1/2% Senior Subordinated Notes due 2006
(Exhibit 4.10 to our Form S-4 (No. 333-90235) filed
on November 3, 1999).

4.11 Indenture dated as of August 20, 1999, between Nuevo
Energy Company and State Street Bank Trust Company,
as Trustee (Exhibit 4.11 to our Form S-4 (No.
333-90235) filed on November 3, 1999).

4.12 Registration Agreement dated August 20, 1999, between
Nuevo Energy Company, Banc of America Securities LLC
and Salomon Smith Barney Inc. (Exhibit 4.12 to our
Form S-4 (No. 333-90235) filed on November 3, 1999).

4.13 Indenture dated September 26, 2000, between Nuevo
Energy Company and State Street Bank and Trust
Company as the Trustee - 9 3/8% Senior subordinated
Notes due 2010 (Exhibit 4.12 to our 2000 Third
Quarter Form 10-Q).

4.14 Registration Agreement dated September 26, 2000,
between Nuevo Energy Company and Banc of America
Securities LLC, Banc One Capital Markets, Inc. and
J.P. Morgan & Co. (Exhibit 4.13 to our 2000 Third
Quarter Form 10-Q).

(10) Material Contracts.

10.1 Third Restated Credit Agreement dated June 7, 2000,
between Nuevo Energy Company (Borrower) and Bank of
America N.A. (Administrative Agent), Bank One, NA
(Syndication Agent), Bank of Montreal (Documentation
Agent) and certain lenders (Exhibit 10.1 to our 2000
Second Quarter Form 10-Q).

10.2 1990 Stock Option Plan, as amended (Exhibit 10.8 to
our Form S-1 dated July 13, 1992).

10.3 1993 Stock Incentive Plan, as amended (Exhibit 4.2 to
our Form S-8 (No. 333-21063) filed on February 4,
1997.)

10.4 1999 Stock Incentive Plan (Exhibit 99.1 to our Form
S-8 (No. 333-87899) filed on September 28, 1999).

10.5 Nuevo Energy Company Deferred Compensation Plan
(Exhibit 99 to our Form S-8 (No. 333-51217) filed on
April 28, 1998).

10.6 Stock Purchase Agreement, dated as of June 30, 1994,
among Amoco Production Company ("APC"), Walter
International Inc. ("Walter"), Walter Congo Holdings,
Inc. ("Walter Holdings"), Walter International Congo,
Inc. (before the merger "Walter Congo" and after the
merger "Old Walter Congo"), Nuevo, Nuevo Holding and
The Nuevo Congo Company (before the merger, "Nuevo
Congo" and after the merger, "Old Nuevo Congo").
(Exhibit 2.1 to Form 8-K dated March 10, 1995).

10.7 Amendment to Stock Purchase Agreement dated as of
September 19, 1994, among APC, Walter Congo, Nuevo
Congo, Walter Holdings, Nuevo Holding, Walter and
Nuevo. (Exhibit 2.2 to Form 8-K dated March 10,
1995).

10.8 Second Amendment to Stock Purchase Agreement dated as
of October 15, 1994, among APC, Walter Congo, Nuevo
Congo, Walter Holdings, Nuevo Holding, Walter and
Nuevo. (Exhibit 2.3 to Form 8-K dated March 10,
1995).

10.9 Third Amendment to Stock Purchase Agreement dated as
of December 2, 1994, among APC, Walter Congo, Nuevo
Congo, Walter Holdings, Nuevo Holding, Walter and
Nuevo. (Exhibit 2.4 to Form 8-K dated March 10,
1995.)

10.10 Fourth Amendment to Stock Purchase Agreement dated as
of February 23, 1995, among APC, Walter Congo, Nuevo
Congo, Walter Holdings, Nuevo Holding, Walter and
Nuevo. (Exhibit 2.5 to Form 8-K dated March 10,
1995).

10.11 Tax Agreement dated as of February 23, 1995, executed
by APC, Amoco Congo Exploration Company ("ACEC"),
Amoco Congo Production Company ("ACPC"), Walter,
Walter Holdings, Walter Congo, Nuevo, Nuevo Holding
and Nuevo Congo. (Exhibit 2.6 to Form 8-K dated March
10, 1995).

10.12 Agreement and Plan of Merger executed by Nuevo Congo,
Nuevo Holding and APC dated February 24, 1995.
(Exhibit 2.7 to Form 8-K dated March 10, 1995).

10.13 Finance Agreement dated as of December 28, 1994,
among Nuevo Holding, Nuevo Congo and The Overseas
Private Investment Corporation ("OPIC"). (Exhibit 2.8
to Form 8-K dated March 10, 1995).

10.14 Subordination Agreement dated December 28, 1994,
among Nuevo Congo, Nuevo Holding, Walter Congo,
Walter Holdings and APC. (Exhibit 2.9 to Form 8-K
dated March 10, 1995).

10.15 Guaranty covering the obligations of Nuevo Congo and
Walter Congo under the Stock Purchase Agreement dated
February 24, 1995, executed by Walter and Nuevo.
(Exhibit 2.10 to Form 8-K dated March 10, 1995).

10.16 Inter-Purchaser Agreement dated as of December 28,
1994, among Walter, Old Walter Congo, Walter
Holdings, Nuevo, Old Nuevo Congo and Nuevo Holding.
(Exhibit 2.11 to Form 8-K dated March 10, 1995).

10.17 Latent ORRI Contract dated February 25, 1995, among
Walter, Walter Holdings, Walter Congo, Nuevo, Nuevo
Holding and Nuevo Congo. (Exhibit 2.12 to Form 8-K
dated March 10, 1995).

10.18 Latent Working Interest Contract dated February 25,
1995, among Walter, Walter Holdings, Walter Congo,
Nuevo, Nuevo Holding and Nuevo Congo. (Exhibit 2.13
to Form 8-K dated March 10, 1995).

10.19 Asset Purchase Agreement dated as of February 16,
1996 between Nuevo Energy Company, the Purchaser, and
Union Oil Company of California as Seller. (Exhibit
2.1 to Form S-3 (No. 333-1504).

10.20 Asset Purchase Agreement dated as of April 4, 1997,
by and among Torch California Company and Express
Acquisition Company, as Sellers, and Nuevo Energy
Company, as Purchaser. (Exhibit 2.2 to Form S-3 (No.
333-1504)).

10.21 Purchase and sale agreement dated October 16, 1998
between Nuevo Energy Company (Seller) and Samson Lone
Star Limited Partnership (Buyer). (Exhibit 10.28 to
our 1998 Form 10-K).

10.22 Master Services Agreement among the Company and Torch
Energy Advisors Incorporated, Torch Operating
Company, Torch Energy Marketing, Inc., and Novistar,
Inc. dated January 1, 1999. (Exhibit 10.29 to our
1998 Form 10-K).

10.23 Employment Agreement with Bruce Murchison dated June
1, 1999. (Exhibit 10.27 to our 1999 Third Quarter
Form 10-Q).

10.24 Employment Agreement with John P. McGinnis dated July
15, 1999. (Exhibit 10.28 to our 1999 Third Quarter
Form 10-Q).

10.25 Crude Oil Purchase Agreement dated February 4, 2000
between Nuevo Energy Company and Tosco Corporation.
(Exhibit 10.1 to Form 8-K dated March 23, 2000).

10.26 Severance Protection Agreement dated March 25, 2001.
(Exhibit 10.31 to our 2000 Form 10-K).

10.27 Amendment to 1999 Stock Incentive Plan (Exhibit 99.1
to our Form S-8, filed on October 21, 2001).

10.28 2001 Stock Incentive Plan (Exhibit 99.1 to our Form
S-8, filed on October 21, 2001).

10.29 Employment Agreement with James L. Payne dated
October 15, 2001. (Exhibit 10.1 to our 2001 Third
Quarter Form 10-Q).

10.30 Janet F. Clark Stock Option Plan (Exhibit 10.35 to
our 2001 Form 10-K).

10.31 George B. Nilsen Stock Option Plan (Exhibit 10.36 to
our 2001 Form 10-K).

10.32 Registration Rights Agreement dated September 18,
2002 by and among Nuevo Energy Company, Yorktown
Energy Partners III, L.P., Yorktown Energy IV, L.P.,
Yorktown Partners LLC, SAFIC S.A., Charles de
Mestral, J. Ross Craft, Montana Oil and Gas, Ltd.,
David A. Badley, James S. Scott, Glenn Reed, Doug
Allison and Mohamed Yaich (Exhibit 10.1 to our Form
8-K dated September 19, 2002).

10.33 Amendment to the 2001 Stock Incentive Plan (Exhibit
99.1 to our Form S-8 dated November 1, 2002).

+10.34 First Amendment to Employment Agreement with James L.
Payne dated September 11, 2002.

+10.35 Key Executive Terminated Without Cause Agreement.

*21 Subsidiaries of the Registrant

(23) Consents of experts and counsel

*23.1 Consent of KPMG LLP

(99) Additional Exhibits

*99.1 Certification of Chief Executive Officer of Nuevo
Energy Company

*99.2 Certification of Chief Financial Officer of Nuevo
Energy Company

+ Management contract or compensatory plan or arrangement required to be filed.

* Not incorporated by reference.