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, 1996

                                      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)

1331 Lamar, Suite 1650, Houston, Texas                        77010
(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:

      TITLE OF EACH CLASS                       NAME OF EACH EXCHANGE ON WHICH
                                                            REGISTERED
Common Stock, par value $.01 per share          New York Stock Exchange
12 1/2% Senior Subordinated Notes Due 2002      New York Stock Exchange
$2.875 Term Convertible Securities, Series A    New York Stock Exchange

       Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K [X].

The aggregate market value of the voting stock held by non-affiliates of the
registrant at February 27, 1997, was approximately $846,096,804.

As of February 27, 1997, the number of outstanding shares of the registrant's
common stock was 20,145,162.

Documents Incorporated by Reference:

Portions of the registrant's annual proxy statement, to be filed within 120 days
after December 31, 1996, are incorporated by reference into Part III.
<PAGE>

                          ANNUAL REPORT ON FORM 10-K
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996

                               TABLE OF CONTENTS

                                                                          Page
                                                                         Number
PART I                                                                   ------ 

   Item 1.    Business.................................................     3
   Item 2.    Properties...............................................    11
   Item 3.    Legal Proceedings........................................    15
   Item 4.    Submission of Matters to a Vote of Security Holders......    15

PART II

   Item 5.    Market for the Registrant's Common Equity and Related
                Stockholder Matters....................................    16
   Item 6.    Selected Financial Data..................................    17
   Item 7.    Management's Discussion and Analysis of Financial
              Condition and Results of Operations......................    18
   Item 8.    Financial Statements and Supplementary Data..............    26
   Item 9.    Changes in and Disagreements with Accountants on
                Accounting and Financial Disclosure....................    67

PART III

   Item 10.   Directors and Executive Officers of the Registrant.......    67
   Item 11.   Executive Compensation...................................    67
   Item 12.   Security Ownership of Certain Beneficial Owners and
                Management.............................................    67
   Item 13.   Certain Relationships and Related Transactions...........    67

PART IV

   Item 14.   Exhibits, Financial Statement Schedules and Reports
                on Form 8-K............................................    67

              Signatures
<PAGE>
                             NUEVO ENERGY COMPANY

                                    PART I

This document includes "forward looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended (the "Securities Act"),
and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"). All
statements other than statements of historical facts included in this document,
including without limitation, statements under "Management's Discussion and
Analysis of Financial Condition and Results of Operations" regarding the
Company's financial position, estimated quantities and net present values of
reserves, business strategy, plans and objectives of management of the Company
for future operations and covenant compliance, are forward-looking statements.
Although the Company believes that the assumptions upon which such
forward-looking statements are based are reasonable, it can give no assurances
that such assumptions will prove to have been correct. Important factors that
could cause actual results to differ materially from the Company's expectations
("Cautionary Statements") are disclosed below and elsewhere in this document.
All subsequent written and oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified by the
Cautionary Statements.

ITEM 1.  BUSINESS

GENERAL

      Nuevo Energy Company (the "Company" or "Nuevo") was formed as a Delaware
corporation on March 2, 1990, to acquire the businesses of certain public and
private partnerships (collectively "Predecessors" or "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 Predecessor Partnerships. Such Plan of
Consolidation provided for the exchange of the net assets of the Predecessor
Partnerships for common stock of the Company. The common stock began trading on
the New York Stock Exchange on July 10, 1990, under the symbol "NEV."

      Nuevo, headquartered in Houston, Texas, is primarily engaged in the
exploration for, and the acquisition, exploitation, development and production
of crude oil and natural gas. The Company's principal properties are located
domestically onshore and offshore California, in East Texas and the onshore Gulf
Coast region; and internationally offshore the Republic of Congo in West Africa.
The Company accumulates oil and gas assets through the drilling of exploration
and developmental wells on acreage (leasehold interests) owned by the Company or
through the purchase of properties from others. The Company also owns and
operates gas plants, pipeline facilities and other oil and gas related assets.

OIL AND GAS ACTIVITIES

      Since the Company's inception in 1990, it has grown and diversified its
operations through a series of disciplined, opportunistic acquisitions of oil
and gas properties and the subsequent exploitation and development of these
properties. The Company has complemented these efforts with an active and
growing exploration program which provides exposure to high-potential prospects.
The Company's primary strengths are its large inventory of exploitation and
exploration projects in its core areas of operation, its demonstrated ability to
implement and maintain a low cost structure, its ability to identify and
acquire, at attractive prices, producing properties which have significant
potential for further exploration, exploitation and development, and a capital
structure supportive of a growing investment 

                                       3
<PAGE>
program and future acquisitions. During the five years ended December 31, 1996,
the Company invested approximately $591.8 million in 26 acquisitions that added
estimated proved reserves of 185.4 MMBBLS of oil and 209.6 BCF of natural gas.
As a result of its activities, the Company's estimated proved equivalent
reserves have increased by approximately 678% since 1992.

      DOMESTIC

      In April 1996, the Company acquired certain upstream oil and gas
properties located onshore and offshore California ("Unocal Properties") from
Union Oil Company of California, ("Unocal") and certain California oil
properties ("Point Pedernales Properties" and, together with the Unocal
Properties, the "California Properties") from Torch Energy Advisors Incorporated
("Torch") and certain of its wholly-owned subsidiaries for a combined net
purchase price of $515.3 million, plus a contingent payment based on future
realized oil prices. The California Properties consist of 42 fields with
approximately 2,400 active wells, and estimated proved reserves as of December
31, 1996 of 177.7 MMBOE. During 1996, the California Properties constituted 66%
of the Company's total oil and natural gas production on a barrel of oil
equivalent basis. Since acquiring the California Properties, the Company has
spent approximately $35 million to commence over 110 exploitation and
development projects.

      In June 1996, the Company sold 177 producing wells and the majority of its
acreage in the Giddings field and East Texas Austin Chalk holdings for $27.3
million, representing estimated net proved reserves of 4.2 MMBOE as of December
31, 1995. The Company retained ownership of seven wells and surrounding acreage
in the Turkey Creek prospect area of the Austin Chalk trend located in Grimes
County, Texas.

      In July 1996, the Company completed the acquisition of a package of East
Texas oil and gas properties for a net purchase price of $9.3 million in cash.
The acquisition of these properties was effective as of December 1, 1995, and
the purchase price was reduced by the net cash flows from production between
such date and closing. In December 1996, the holders of the preferential rights
on these properties exercised such rights for a cash payment of $8.0 million
acquiring approximately half of the estimated proved reserves relating to this
acquisition.

      In addition to ongoing acquisition activities, the Company continues to
participate in several oil and gas development projects. The Company initiates
workovers, recompletions, development drilling, secondary and tertiary recovery
operations and other production enhancement techniques to maximize current
production and the ultimate recovery of reserves. The Company has identified in
excess of 1,300 exploitation projects on its existing properties which it
believes offer meaningful opportunities to grow reserves and increase
production, irrespective of exploration or acquisition successes. Examples of
current or planned projects include: (i) infill drilling, the initiation of a
new steamflood project, and multiple zone recompletions in the Midway-Sunset
field in central California, (ii) infill drilling and horizontal drilling in the
Cymric field in central California, (iii) recompletions and the initiation of a
waterflood project in the Brea Olinda field in the Los Angeles basin; (iv)
infill drilling and the commencement of construction of an adjacent gas
processing plant at the Point Pedernales field offshore California; and (v)
infill drilling in the Oak Hill field in East Texas. Capital expenditures for
domestic exploitation projects are estimated to be approximately $103.0 million
in 1997.

                                       4
<PAGE>
      The Company also has an active and growing exploration program targeting
high-potential reserve opportunities in California and the onshore Gulf Coast
region. The Company seeks to reduce the risks normally associated with
exploration through the use of advanced technologies, such as 3-D seismic
surveys and computer aided exploration ("CAEX") techniques, and by participating
with experienced industry partners. The Company has had recent exploratory
discoveries in: (i) the Frontier section of the North Riley Ridge area in
Western Wyoming; (ii) the Antelope Shale section in the Monument Junction area
of the Cymric field in central California; and (iii) the Sespe section in the
Big Mountain field in the Ventura Basin of California. Capital expenditures for
domestic exploration activities are expected to be $20.0 million in 1997.

      Effective January 1, 1993, the Company entered into an agreement whereby
it sold an interest in the Oak Hill field to Torchmark Corporation
("Torchmark"). The interest sold represented approximately 96 BCF of estimated
proved gas reserves and 287 MBBLS of estimated proved oil reserves at December
31, 1992. Torchmark paid a nominal amount of cash for the Oak Hill field
properties and conveyed to the Company a net profits production payment ("Oak
Hill Production Payment"). The Oak Hill Production Payment entitles the Company
to receive the net proceeds from production, limited to 90% of estimated proved
reserves at December 31, 1992, as well as an amount equal to 70% of the I.R.C.
ss.29 Tax Credits ("Section 29 Credits") generated by production from the Oak
Hill field properties. The Company has an option to repurchase the properties
for the fair market value of the reserves, which is based upon projected
discounted revenues from existing wells at the time of the repurchase. During
1996, 1995 and 1994, the Company recorded revenue of $.9 million, $1.1 million
and $1.3 million representing 70% of the Section 29 Credits generated by the Oak
Hill Production Payment, respectively.

      Substantially all of the future cash flows from the Oak Hill field
properties will be paid to the Company pursuant to the Oak Hill Production
Payment. Therefore, the conveyance was not reflected as a sale. The Company will
continue to reflect revenues and the proved reserves dedicated to the Oak Hill
Production Payment as if such working interests were owned by the Company.

      INTERNATIONAL

      In February 1995, the Company acquired a wholly-owned subsidiary of Amoco
Production Company ("APC")in the People's Republic of Congo ("Congo") adding
20.8 MMBBLS of oil to the Company's reserve base for a purchase price of $.6
million. At December 31, 1996, the Yombo field contained proved reserves of 20.2
MMBBLS. The properties purchased are located in the Yombo field which is 27
miles offshore from the Congo in 360 feet of water. As part of the acquisition,
the Company acquired 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"). The Company's production is converted to No. 6 fuel oil with
less than 0.3% sulphur content on the FPSO.

      During 1996, the Company completed a six-well development drilling program
which contributed approximately 2,600 gross barrels of oil per day as of
December 31, 1996. Also during 1996, the Company drilled a successful
exploration well to the Lower Sendji formation in the Yombo field. This well is
completed in half of the 236 feet of net pay and is producing over 3,200 gross
barrels of oil per day. The Company plans to drill developmental offsets to this
well in late 1997. In 1997, the Company plans to drill an exploration well to
evaluate the Lower Sendji and sub-salt sections underlying 

                                       5
<PAGE>
the Masseko field located several miles to the west of the Yombo field, as well
as to further delineate the Upper Sendji and Tchala zones which were discovered
but not developed by the previous operator. Other potential exploration features
of the concession are being evaluated for possible future drilling.
Additionally, the Company plans to initiate a waterflood project to enhance
production from existing Upper Sendji and Tchala zones in 1997. In 1997, the
Company plans to spend $12.0 million and $5.0 million for international
development and exploration, respectively.

      In 1996, revenues relating to production from the Yombo field represented
approximately 9% of the total oil and gas revenues for the Company.

      The Company's Congo investment involves 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 its foreign operations, the Company 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. The
Company attempts to conduct its business and financial affairs so as to protect
against political and economic risks applicable to operations in the various
countries where it operates, but there can be no assurance the Company will be
successful in so protecting itself. The Company's investment is insured through
political risk insurance provided by the Overseas Private Investment Corporation
("OPIC").

GAS PLANT, PIPELINES AND OTHER FACILITIES

      The Richfield Gas Storage project, in Morton County, Kansas, was acquired
in July 1993 for approximately $5.9 million. The storage facility has a working
gas capacity of 5 BCF. Three major pipelines are connected to the facility and
such pipelines provide access to multiple market areas.

      In December 1992, the Company purchased an 80% interest in Bright Star
Gathering, Inc. ("Bright Star") which owns a 90% partnership interest in a
150-mile gas gathering system in Leon County, Texas for an adjusted purchase
price of approximately $6.0 million. The system was constructed in 1985 and
currently is gathering approximately 3 MMCFD of casinghead gas from 80 wells.

      Effective April 1, 1992, the Company acquired a 95% interest in the NuStar
Joint Venture ("NuStar"), which owns a 66.7% interest in the Benedum natural gas
processing plant, a 50% undivided interest in the land on which such plant is
situated, a 100% interest in certain related assets and natural gas gathering
systems located in West Texas and rights to acquire certain other assets, all of
which are subject to certain obligations (the "Benedum Plant System"). The
purchase price for such interest was $21.6 million. In the second quarter of
1993, the installation of a new demethanizer unit was completed, increasing
daily gross processing capacity from 82 MMCFD to 95 MMCFD. Also, the operational
start-up of a bypass plant commenced in June 1993 and is currently processing 23
MMCFD.

      An additional pipeline at West Delta 152, located offshore Louisiana,
became operational in 1990. This pipeline was sold during the third quarter of
1996, for net proceeds of $3.0 million. The Company's 84-mile natural gas
pipeline in Illinois became operational in October 1990. Throughput averaged 13
MMCFD, 22 MMCFD and 19 MMCFD in 1996, 1995 and 1994, respectively.

                                       6
<PAGE>
INDUSTRY SEGMENT INFORMATION

      For industry segment data (including foreign operations), see Note 11 to
the Notes to Consolidated Financial Statements.

MARKETS

      The markets for hydrocarbons continue to be quite volatile. The Company's
financial condition, operating results, future growth and the carrying value of
its oil and gas properties are substantially dependent on prevailing prices of
oil and gas. The Company's ability to maintain or increase its 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 the control of the Company. 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 elsewhere in the U.S. or gas would have an adverse effect on
the Company's carrying value of its proved reserves, borrowing capacity, the
Company's ability to obtain additional capital, and its revenues, profitability
and cash flows from operations. A modest portion of the Company's production is
California heavy oil. The market 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.

      Sales to Rexene Corporation accounted for 18% and 19% of 1995 and 1994
revenues, respectively. In 1995, sales to Stinnes Interoil, Inc. accounted for
13% of total revenues. Management of the Company does not believe that the loss
of any single customer or contract would materially affect its business.

      Under the terms of a $30.0 million volumetric production payment, the
Company is committed to deliver 10.7 BCF of natural gas through December 1998.
(See Note 4 of the Notes to Consolidated Financial Statements). There are no
other significant delivery commitments and substantially all of the Company's
oil and gas production is sold at market responsive pricing through a marketing
affiliate of Torch. The Company from time to time may enter into crude oil and
natural gas price swaps or other similar hedge transactions to reduce its
exposure to price fluctuations.

REGULATION

      Oil and Gas Regulation

      The availability of a ready market for any oil and gas production depends
upon numerous factors beyond the Company's control. These factors include state
and Federal regulation of oil and gas production 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 

                                       7
<PAGE>
areas in which the Company may conduct operations. State and Federal regulations
generally are intended to prevent waste of oil and gas, protect rights to
produce oil and gas between owners in a common reservoir, control the amount of
oil and gas produced by assigning allowable rates of production and control
contamination of the environment. Pipelines and gas plants also are subject to
the jurisdiction of various Federal, state and local agencies.

      Environmental Regulation

      General. The Company's activities are subject to existing Federal, state
and local laws and regulations governing environmental quality and pollution
control. It is anticipated that, absent the occurrence of an extraordinary
event, compliance with existing Federal, state and local laws, rules and
regulations regulating the release of materials in the environment or otherwise
relating to the protection of the environment will not have a material effect
upon the operations, capital expenditures, earnings or the competitive position
of the Company.

      Activities of the Company 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.

      Waste Disposal. The Company currently owns or leases, and has in the past
owned or leased, numerous properties that have been used for production of oil
and gas for many years. Although the Company has 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 owned or
leased by the Company. In addition, many of these properties have been operated
by third parties over whom the Company 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 more strict. Under these new laws, the
Company could be required to remove or remediate previously disposed wastes
(including wastes disposed of or released by prior owners or operators) or
property contamination (including groundwater contamination) or to perform
remedial plugging operations to prevent future contamination.

      The Company may generate wastes, including hazardous wastes, that are
subject to the Federal Resource Conservation and Recovery Act and comparable
state statutes. The EPA has limited the disposal options for certain hazardous
wastes and is considering the adoption of stricter disposal standards for
nonhazardous wastes. Furthermore, certain wastes generated by the Company's 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, without regard to fault or the legality of the original
conduct, on certain classes of persons with respect to the release of a
"hazardous substance" into the environment. These persons 

                                       8
<PAGE>
include the current owner and operator of a facility and persons that disposed
of or arranged for the disposal of the hazardous substances found at 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 responsible classes of persons the costs of such action. In the
course of its operations, the Company may have generated and may generate wastes
that fall within CERCLA's definition of "hazardous substances." The Company may
also be an owner of facilities on which "hazardous substances" have been
released by previous owners or operators. The Company may be responsible under
CERCLA for all or part of the costs to clean up facilities at which such wastes
have been released. Neither the Company nor, to its knowledge, its Predecessors
has been named a potentially responsible person under CERCLA nor does the
Company know of any prior owners or operators of its properties that are named
as potentially responsible parties related to their ownership or operation of
such property.

      Air Emissions. The operations of the Company are subject to local, state
and Federal regulations for the control of emissions of air pollution.
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 the Company to forego construction, modification or
operation of certain air emission sources, although the Company believes that in
the latter cases it would have enough permitted or permittable capacity to
continue its operations without a material adverse effect on any particular
producing field.

      Oil Pollution Act. The Oil Pollution Act of 1990 ("OPA") and regulations
thereunder impose a variety of regulations on "responsible parties" related to
the prevention of oil spills and liability for damages resulting from such
spills in United States waters. A "responsible party" includes the owner or
operator of a facility or vessel, or the lessee or permittee of the area in
which a facility covered by OPA is located. OPA assigns joint and several
liability 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.

      OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. On August 25, 1993, an advance notice of intention to adopt a rule under
OPA was published that would require owners and operators of offshore oil and
gas facilities to establish $150 million in financial responsibility. Under the
proposed rule, financial responsibility could be established through insurance,
guaranty, indemnity, surety bond, letter of credit, qualification as a
self-insurer or a combination thereof. There is substantial uncertainty as to
whether insurance companies or underwriters will be willing to provide coverage
under OPA because the statute provides for direct lawsuits against insurers who
provide financial responsibility coverage, and most insurers have strongly
protested this requirement. The financial tests or other criteria that will be
used to judge self-insurance are also uncertain. The Company cannot predict the
final form of the financial responsibility rule that will be adopted but such
rule has the potential to result in the imposition of substantial additional
annual costs to the Company or otherwise materially adversely affect the
Company. The impact of the rule should not be any more adverse to the Company
than it will be to other similarly situated or less capitalized owners or
operators in the Gulf of Mexico.

                                       9
<PAGE>
      Management believes that the Company is in substantial compliance with
current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse impact on
the Company.

COMPETITION

      The Company operates 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 the Company for
the minimum projected return on investment and the availability of alternate
fuel sources are factors which affect the Company's ability to compete in the
marketplace. The Company's competitors include major integrated oil companies
and a substantial number of independent energy companies, many of which possess
greater financial and other resources than the Company.


PERSONNEL

      At December 31, 1996, the Company employed 53 full time employees who
represent the executive officers and key operating, exploration, financial and
accounting management. The Company outsources the administrative and operational
functions to Torch, which maintains a large technical, operating, accounting and
administrative staff. Pursuant to an agreement with Torch (the "Torch
Agreement"), Torch administers certain business activities of the Company for a
monthly fee based on a fixed percentage of operating cash flow and total assets
(as defined). (See Note 5 to the Notes to Consolidated Financial Statements).
The combined personnel of Torch and the Company consists of 787 employees at
December 31, 1996.

                                       10
<PAGE>
ITEM 2.  PROPERTIES

RESERVES, PRODUCTIVE WELLS, ACREAGE AND PRODUCTION

      The Company holds interests in oil and gas wells located in the United
States and West Africa. The Company's principal developed properties are located
in California, Texas, Nevada, Mississippi, the Gulf of Mexico and offshore West
Africa; and undeveloped acreage is located primarily in California, Texas,
Mississippi and Alabama. Proved oil and gas reserves at December 31, 1996
increased approximately 212% since December 31, 1995 primarily as a result of
development drilling activities and acquisitions of producing properties. (See
Note 14 to the Notes to Consolidated Financial Statements). The Company has not
filed any different oil or gas reserve information with any foreign government
or other Federal authority or agency.

      The following table sets forth certain information, as of December 31,
1996, which relates to the Company's principal oil and gas properties:
<TABLE>
<CAPTION>
                                  NET PROVED RESERVES
                                   DECEMBER 31, 1996             1996 PRODUCTION
                               --------------------------    ------------------------
                       GROSS     OIL       GAS                 OIL     GAS
                       WELLS   (MBBLS)   (MMCF)      MBOE    (MBBLS)  (MMCF)    MBOE
                       -----   -------   -------   -------   ------   ------   ------
<S>                      <C>    <C>          <C>    <C>       <C>      <C>      <C>  
U.S. PROPERTIES
California Fields
   Cymric ..........     398    28,698       434    28,770    1,855       40    1,862
   Midway-Sunset ...     439    28,806      --      28,806    1,674     --      1,674
   Brea Olinda .....     232    22,303     5,656    23,246      517      118      537
   Point Pedernales       15    17,158    11,796    19,124    2,215     --      2,215
   Belridge ........     405     4,232       958     4,392      254      263      298
   Dos Cuadros .....     135     9,983     7,054    11,159      491      382      555
   Coalinga ........      92       298    15,894     2,947       56    4,023      727
   Huntington Beach       21     7,975     1,185     8,173      353       51      362
   Santa Clara .....      47    11,568     9,707    13,186      698      565      792
   Belmont .........      11     2,517       478     2,597      246       32      251
   South Mountain ..     101     4,876     2,034     5,215      141      137      164
   Other ...........     534    23,665    38,463    30,076    2,049    6,933    3,205
                       -----   -------   -------   -------   ------   ------   ------
   Total California
   fields(1) .......   2,430   162,079    93,659   177,691   10,549   12,544   12,642

Other U.S. Fields
   Oak Hill, Tx ....     240       408   260,902    43,892       25    9,619    1,628
   Chappell Hill, Tx     199       754    16,244     3,461       76    1,704      360
   Weeks Island, La        9       439     1,207       640      391      329      446
   N.Frisco City, Al       8     1,263     1,745     1,554      340      398      406
   Giddings, Tx ....       5        48    12,198     2,081      160    7,531    1,415
   Other ...........      61       848     8,675     2,292      383    2,650      823
                       -----   -------   -------   -------   ------   ------   ------
     Total other
     U.S. fields ...     522     3,760   300,971    53,920    1,375   22,231    5,078
                       -----   -------   -------   -------   ------   ------   ------
Total U.S. .........
Properties .........   2,952   165,839   394,630   231,611   11,924   34,775   17,720

FOREIGN PROPERTIES
   Yombo, W. Africa       25    20,214      --      20,214    1,420     --      1,420
                       -----   -------   -------   -------   ------   ------   ------
Total Properties ...   2,977   186,053   394,630   251,825   13,344   34,775   19,140
                       =====   =======   =======   =======   ======   ======   ======
</TABLE>
(1)   Represents production from the date of acquisition of the California
      Properties (April 9, 1996).

                                       11
<PAGE>
ACREAGE

      The following table sets forth the acres of developed and undeveloped oil
and gas properties in which the Company held an interest as of December 31,
1996. Undeveloped acreage is considered to be those 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 in the following table refers to
the number of acres in which a working interest is owned directly by the
Company. The number of net acres is the sum of the fractional ownership of
working interests owned directly by the Company in the gross acres expressed as
a whole number and percentages thereof. A "net acre" is deemed to exist when the
sum of fractional ownership of working interests in gross acres equals one.

                                                 GROSS         NET
                                              ---------    ---------
             Developed Acreage                  297,688      153,403
             Undeveloped Acreage                255,056      127,722
                                              ---------    ---------
                   Total                        552,744      281,125
                                              =========    =========

      The following table sets forth the Company's undeveloped acreage at
December 31, 1996:

                                                      GROSS                NET
                                                     -------             -------
California .............................             123,578              93,521
Texas ..................................              47,928               9,816
Nevada .................................              19,108               2,395
Mississippi ............................              14,746               3,966
Yombo ..................................              26,375              11,539
Other ..................................              23,321               6,485
                                                     -------             -------
      Total ............................             255,056             127,722
                                                     =======             =======

PRODUCTIVE WELLS

      The following table sets forth the Company's gross and net interests in
productive oil and gas wells as of December 31, 1996. Productive wells are
producing wells and wells capable of production.

                                                       GROSS                NET
                                                       -----               -----
Oil Wells ..............................               2,628               2,317
Gas Wells ..............................                 349                 110
                                                       -----               -----
Total ..................................               2,977               2,427
                                                       =====               =====

PRODUCTION

      The Company's principal production volumes during the year ended December
31, 1996 were from the states of California, Texas, Alabama, Louisiana, and from
the Gulf of Mexico and West Africa.

                                       12
<PAGE>
      Data relating to production volumes, average sales prices, average unit
production costs and oil and gas reserve information appears in Note 14 to the
Notes to Consolidated Financial Statements.

DRILLING ACTIVITY AND PRESENT ACTIVITIES

      During the three year period ended December 31, 1996, the Company's
principal drilling activities occurred in the continental United States and
offshore in state and federal waters, and offshore in the Republic of Congo.

      Between the date of acquisition, April 9, 1996, and the end of 1996, the
Company drilled 71 wells in the Cymric field in central California, which
contains 11% of the Company's total estimated proved equivalent reserves at
December 31, 1996, and anticipates drilling approximately 100 wells during 1997.
In the Midway-Sunset field in central California, which contains 11% of the
total estimated proved equivalent reserves at December 31, 1996, the Company
drilled 35 wells during 1996, and plans to drill approximately 70 wells in 1997.

      In the Oak Hill field in Rusk County, Texas, the Company drilled 18 wells
in 1996. The Company received Texas Railroad Commission approval for 80 acre
spacing in March 1995, providing a total of 189 additional drilling locations,
72 of which are included in the Company's proved reserve volumes. The Company
commenced a two rig drilling program in July 1996, and plans to continue
drilling through 1997.

      In 1996, the Company sold 177 producing wells and the majority of its
undeveloped acreage in the Giddings field and East Texas Austin Chalk formation
for $27.3 million. The Company retained ownership of several wells and
surrounding acreage in the Turkey Creek prospect area of the Austin Chalk trend.
The Company drilled 3 wells in 1996 and plans to drill 4 wells in this area
during 1997. Two of the three wells drilled tested at gross rates of over 20
MMCFD.

      During 1996, the Company completed a six-well development drilling program
in the Congo which contributed approximately 2,600 gross barrels of oil per day
as of December 31, 1996. Also during 1996, the Company drilled a successful
exploration well to the Lower Sendji formation in the Yombo field. This well is
completed in half of the 236 feet of net pay and is producing over 3,200 gross
barrels of oil per day. In 1997, the Company plans to drill an exploration well
to evaluate the Lower Sendji and sub-salt sections underlying the Masseko field
located several miles to the west of the Yombo field, as well as to further
delineate the Upper Sendji and Tchala zones which were discovered but not
developed by the previous operator. Other potential exploration features of the
concession are being evaluated for possible future drilling. Additionally, the
Company plans in 1997 to initiate a waterflood project to enhance production
from existing Upper Sendji and Tchala zones.

      The Company's exploration program resulted in 6 successful wells out of 13
drilled in 1996. The Company's most significant discoveries in 1996 were in: (i)
the Lower Sendji section of the Yombo field, (ii) an Antelope Shale section
beneath the Cymric field in central California; and (iii) a Frontier sand
formation at North Riley Ridge in Western Wyoming. In 1995, the Company's
exploration program resulted in 7 successful wells out of 16 drilled.
Discoveries include Brownsville Dome in Hinds County, Mississippi and East Mud
Lake in Cameron Parish, Louisiana. In 1994, the Company's exploration program
resulted in 10 successful wells in Conecuh County, 

                                       13
<PAGE>
Alabama; Iberia Parish, Louisiana; and Glasscock, Harvard and Pecos Counties,
Texas.

      In 1992, the Company discovered the North Frisco City field in Monroe
County, Alabama through its exploration efforts. In 1995, the Company
successfully implemented a water injection project in the North Frisco City
field which has increased oil and gas recoveries and will extend the life of the
field.


      The Company had 30 gross (19 net) wells awaiting completion at December
31, 1996. The following table sets forth the results of drilling activity by the
Company, net to its interest, for the last three calendar years. Gross wells, as
it applies to wells in the following tables, refers to the number of wells in
which a working interest is owned directly by the Company. The number of net
wells is the sum of the fractional ownership of working interests owned directly
by the Company in gross wells expressed as whole numbers and percentages
thereof.

                               EXPLORATORY WELLS

                             GROSS                              NET
                   -------------------------     ------------------------------
                                DRY                             DRY
                   PRODUCTIVE  HOLES   TOTAL     PRODUCTIVE    HOLES     TOTAL
                   ----------  -----   -----     ----------   -------    ------
1994 .............     10       9       19          1.84       2.74       4.58
1995 .............      7       9       16          1.32       1.97       3.29
1996 .............      6       7       13          3.40       2.09       5.49


                               DEVELOPMENT WELLS

                             GROSS                              NET
                   ----------------------------   ------------------------------
                                   DRY                           DRY
                   PRODUCTIVE     HOLES   TOTAL   PRODUCTIVE    HOLES     TOTAL
                   ----------     -----   -----   ----------    -----     ------
1994 ............       99          -       99       40.45        --       40.45
1995 ............       53          -       53       15.30        --       15.30
1996 ............      149          1      150      125.24        1.00    126.24

                                       14
<PAGE>
GAS PLANT, PIPELINES AND OTHER FACILITIES

      As of December 31, 1996 the Company owned interests in the following gas
plant and pipeline facilities:
                                                             1996
                                                CAPACITY  THROUGHPUT  OWNERSHIP
FACILITY        STATE           OPERATOR          MMCFD      MMCFD    INTEREST
--------       --------      ----------------   --------  ----------  ----------
Illini         Illinois      Illini Carrier,         50       13.0       100%
 Carrier                     L.P.
                             
Bright Star    Texas         Bright Star Gathering   30        3.0        72%
                             Incorporated
                             
Benedum Gas    Texas         Torch Operating        125       63.2         *
  Plant                      Company
                             
Stearns Gas    California    Torch Operating          6        3.0       100%
  Plant                      Company
                             
Santa Clara    California    Torch Operating         18        7.0       100%
  Plant                      Company
                          
      The Richfield Gas Storage facility is located in Morton County, Kansas and
is operated by Associated Natural Gas, Inc. The storage facility has a working
gas capacity of 5 BCF with firm gas storage agreements for 3.5 BCF in place at
December 31, 1996. The Company owns a 48.5% interest in the facility.
------------
*     The Company owns 63% of the Benedum Plant System, however, the Benedum
      bypass plant, which became operational in 1993, is owned 95% by the
      Company.

ITEM 3.  LEGAL PROCEEDINGS

       Neither the Company nor its subsidiaries are parties to any material
pending legal proceedings.

      The Company has been named as a defendant in certain lawsuits incidental
to its business. Management does not believe that the outcome of such litigation
will have a material adverse impact on the Company's operating results or
financial condition. However, these actions and claims in the aggregate seek
substantial damages against the Company and are subject to the inherent
uncertainties in any litigation. The Company is defending itself vigorously in
all such matters.

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

       There were no matters submitted to a vote of security holders during the
fourth quarter of 1996.

                                       15
<PAGE>
                                    PART II

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

       The principal market on which the Company's common stock is traded is the
New York Stock Exchange (Symbol: NEV). There were approximately 1,570
stockholders of record and approximately 8,556 additional beneficial owners as
of February 27, 1997. The Company has not paid dividends on its common stock and
does not anticipate the payment of cash dividends in the immediate future as it
contemplates the use of cash flows for expansion of its operations. In addition,
certain restrictions contained in the Company's financing arrangements restrict
the payment of dividends (See Management's Discussion and Analysis of Financial
Condition and Results of Operations Capital Resources and Liquidity and Note 6
to the Notes to Consolidated Financial Statements). The high and low recorded
prices of the Company's common stock during 1995 and 1996 are presented in the
following table:

                                                          MARKET PRICE
                                                         ----------------
                                                         HIGH       LOW
  Quarter Ended:                                        -------    ------

       March 31, 1995.......................            $20.00     $16.00
       June 30, 1995........................            $23.63     $18.63
       September 30, 1995...................            $24.88     $20.13
       December 31, 1995....................            $23.63     $20.38

       March 31, 1996.......................            $28.75     $20.38
       June 30, 1996........................            $32.75     $26.88
       September 30, 1996...................            $43.00     $30.75
       December 31, 1996....................            $53.75     $41.50

PRIVATE PLACEMENTS OF SECURITIES

    On April 9, 1996, the Company acquired the Point Pedernales Properties from
Torch for an adjusted net purchase price of $35.7 million. The Company paid the
purchase price of the Point Pedernales Properties by issuing to Torch 1,275,000
shares (the "Shares") of the Company's Common Stock valued at $28.00 per share,
the price to the public in the Company's public offering of common stock that
closed on that same date. On April 9, 1996, the Company also issued to John B.
Hall and EnCap Investments, Inc. warrants ("Warrants") to purchase 120,000 and
30,000 shares of Common Stock, respectively. The Warrants were issued as
brokers' fees for services rendered in connection with the Company's acquisition
of the California Properties. The Warrants have an initial exercise price of
$28.00 per share and are exercisable for a period of five years. The Warrants
also contain a cashless exercise feature.

    The Company believes that since (i) the Shares and Warrants were offered
without public solicitation to only three persons who were intimately involved
in negotiating the acquisition of the California Properties and (ii) the Shares
and the Warrants were issued pursuant to direct negotiations with such persons,
the issuance of the Shares and the Warrants and the issuance of the shares of
Common Stock issuable upon conversion of the Warrants qualified and will qualify
for the exemption from the registration provisions of the Securities Act
provided by Section 4(2) thereof.

                                       16
<PAGE>
ITEM 6.  SELECTED FINANCIAL DATA

       The following selected financial data with respect to the Company should
be read in conjunction with the consolidated financial statements and
supplementary information included in Item 8 (amounts in thousands, except per
share data).

                                   AT AND FOR THE YEARS ENDED DECEMBER 31,
                          ------------------------------------------------------
                             1996      1995        1994         1993     1992
                          --------   --------   ---------    --------   --------
Oil and gas revues ....   $282,656   $103,216   $  79,968    $ 67,184   $ 41,331
Gas plant revenues ....     34,802     27,183      28,798      24,680     15,883
Pipeline and other
  revenues ............      6,774      7,222      10,309      14,697      3,574

Interest and other
  income ..............      1,614      1,106         245       1,271        664
                          --------   --------   ---------    --------   --------
Total Revenues ........   $325,846   $138,727   $ 119,320    $107,832   $ 61,452

Total expenses
  (including income
  taxes and minority
  interest)(2) ........    291,150    129,717     136,923      98,899     57,770
                          --------   --------   ---------    --------   --------
Net income (loss)(1)(3)   $ 34,696   $  9,010   $ (17,603)   $  8,933   $  3,682
                          ========   ========   =========    ========   ========
Earnings (loss)
  attributable to
  common stockholder(2)   $ 33,757   $  7,538   $ (19,353)   $  7,183   $  2,647

Earnings (loss) per
  common and common
  equivalent share(1) .   $   1.92   $    .66   $   (1.76)   $    .70   $    .30

Earnings (loss) per
  common and common
  equivalent share,
  assuming full
  dilution ............   $   1.83   $    .66   $   (1.76)   $    .70   $    .30

Total Assets ..........   $863,803   $306,544   $ 307,220    $287,591   $238,891

Long-term debt, net of
  current matuturities    $287,038   $113,032   $ 118,219    $ 87,049   $ 88,742
------------
(1)   No common stock dividends have been declared since the formation of the
      Company. See Note 6 to the Notes to Consolidated Financial Statements
      concerning restrictions on the payment of common stock dividends.

(2)   Includes $34.6 million related to the excess of capitalized costs over
      future net revenues in 1994. (See Note 2 to the Notes to Consolidated
      Financial Statements).

(3)   The year ended December 31, 1996 includes activity of the California
      Properties from the date of acquisition (April 9, 1996.)

                                       17
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS

OVERVIEW

      Nuevo is an independent energy company engaged in the acquisition,
development and exploration of oil and gas properties. Since its inception, the
Company has grown through a series of disciplined, opportunistic acquisitions of
oil and gas properties and the subsequent exploitation and development of these
properties. The Company has complemented these efforts with an active and
growing exploration program which provides exposure to high potential prospects.
The Company's primary strengths are its large inventory of exploitation and
exploration projects in its core areas of operation, its demonstrated ability to
implement and maintain a low cost structure, its ability to identify and
acquire, at attractive prices, producing properties which have significant
potential for further exploration, exploitation and development, and a capital
structure supportive of a growing investment program and future acquisitions.

      The Company's results of operations have been significantly affected by
its success in acquiring oil and gas properties and its ability to maintain or
increase production through its exploitation activities. Fluctuations in oil and
gas prices have also significantly affected the Company's results. Principally
through acquisitions and exploitation, the Company has achieved significant
increases in its oil and gas production. The following table reflects the
Company's oil and gas production and its average oil and gas prices (inclusive
of crude oil and natural gas price swaps) for the periods presented:

                                                    YEAR ENDED DECEMBER 31,
                                          --------------------------------------
                                             1996          1995          1994
                                          -----------   ----------    ----------
Production:
  Oil (MBBLS) ........................        13,051         3,947         2,365
  Natural gas (MMCF) .................        34,775        28,913        23,327
  Natural Gas Liquids (MBBLS) ........           293          --            --

Average sales price:
  Oil and condensate (per barrel) ....    $    15.93    $    14.68    $    14.89
  Natural gas (per MCF) ..............    $     2.12    $     1.56    $     1.90
                                                                      
Average unit production cost                                          
  per equivalent barrel (6 MCF                                        
  equal 1 barrel) ....................    $     5.01    $     3.38    $     2.42
                                                                      
Average unit depletion rate per                                       
 equivalent barrel (6 MCF equal                                       
 1 barrel):                                                           
   Domestic ..........................    $     4.05    $     4.98    $     5.60
   Congo .............................    $      .75    $      .75    $     --

                                       18
<PAGE>
      The Company utilizes the full cost method to account for its investment in
oil and gas properties. Under the full cost method of accounting, all costs of
acquisition, exploration and development of oil and natural gas reserves
(including such costs as leasehold acquisition costs, geological expenditures,
dry hole costs and tangible and intangible development costs and directly
associated internal costs) are capitalized into a "full cost pool" as incurred
on a country-by-country basis. Oil and gas properties, the estimated future
expenditures to develop proved reserves, and estimated future abandonment, site
remediation and dismantlement costs are depleted and charged to operations using
the unit-of-production method based on the ratio of current production to total
proved recoverable oil and natural gas reserves as estimated by independent
engineering consultants. Costs directly associated with the acquisition and
evaluation of unproved properties are excluded from the amortization computation
until it is determined whether or not proved reserves can be assigned to the
properties or whether impairment has occurred. Domestic depletion expense per
equivalent barrel of production was $4.05 in 1996, $4.98 in 1995 and $5.60 in
1994. Depletion expense for the Congo was $0.75 per equivalent barrel of
production in 1996 and in 1995. Dispositions of oil and gas properties are
recorded as adjustments to capitalized costs, with no gain or loss recognized
unless such adjustments would significantly alter the relationship between
capitalized costs and proved reserves of oil and natural gas. To the extent that
capitalized costs of oil and gas properties, net of accumulated depreciation,
depletion and amortization and related deferred income taxes, exceed the tax
affected discounted future net revenues of proved oil and natural gas reserves,
on a country-by-country basis, such excess capitalized costs would be charged to
operations. Late in 1994, natural gas prices declined significantly. This trend
continued through the third quarter of 1995. Due to this decline, the Company
recorded a write down in 1994 for the excess of capitalized costs over
discounted future net revenues of $33 million for U.S. operations and $1.6
million for foreign operations. No such write down in book value was required in
1996 or 1995.

FINANCING ACTIVITIES

      The Company has $292.4 million in outstanding indebtedness at December 31,
1996 which is scheduled to mature as follows: (amounts in thousands)

            1997..........................$   5,408
            1998..........................    3,716
            1999..........................    3,716
            2000..........................   11,462
            2001..........................   51,250
            Thereafter....................  216,894
                                          ---------
                                          $ 292,446
                                          =========

      On December 23, 1996, the Company and its wholly-owned subsidiary, Nuevo
Financing I, a statutory business trust formed under the laws of the state of
Delaware, (the "Trust"), closed the offering of 2,300,000 Term Convertible
Securities, Series A, ("TECONS") on behalf of the Trust. The price to the public
of the TECONS was $50.00 per TECONS. Distributions on the TECONS began to
accumulate from December 23, 1996 and will be 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 .8421 shares of Common Stock for each TECONS, subject to adjustment.
(See Note 7 to Notes to Consolidated Financial Statements).

                                       19
<PAGE>
      Also on December 23, 1996, the Company and United Investors Management
Company, ("United"), and The 1818 Fund, L.P. ("The 1818 Fund"), closed the
offering of 2,138,605 shares of Common Stock (the "Shares"). United sold
1,275,000 Shares and The 1818 Fund sold 863,605 Shares. The price to the public
of the Shares was $47.50 per share. All of the Shares sold by United were
outstanding and 112 of the Shares sold by The 1818 Fund were outstanding prior
to the offering. The remaining 863,493 of the Shares sold by The 1818 Fund were
issued upon conversion of the remaining 11,220 shares of 7% Cumulative
Convertible Preferred Stock, ("7% Preferred Stock") of the Company. As a result
of this conversion by The 1818 Fund of its shares of 7% Preferred Stock, there
are no longer any shares of the 7% Preferred Stock outstanding. The Company did
not receive any proceeds from the sale of the Shares. (See Note 6 to Notes to
Consolidated Financial Statements).

      In April 1996, the Company financed the acquisition of the Unocal
Properties with the proceeds from the sale to the public of 5,109,200 shares of
Common Stock (the "Common Stock Offering") and a principal amount of $160.0
million, 9 1/2% Senior Subordinated Notes due 2006 of the Company, and by
borrowings under a revolving credit facility (the "Credit Facility") dated as of
April 1, 1996 with a syndicate of banks which provides the Company with a line
of credit of up to $385.0 million. (See Note 8 to Notes to Consolidated
Financial Statements). Such proceeds were also used to retire the borrowings
under an existing credit facility in the amount of $27.0 million. The purchase
of the Point Pedernales Properties was financed by the issuance to Torch of
1,275,000 shares of the Company's Common Stock valued at the public offering
price of $28.00 per share in the Common Stock Offering. In connection with the
acquisition of the Unocal Properties, the Company also entered into a bridge
commitment with a bank group led by NationsBank of Texas, N.A. The facility was
not drawn down; however, $1.7 million in fees associated with the bridge
commitment were expensed in the second quarter of 1996, when the commitment
expired.

      During the third quarter of 1995, the Company consummated the sale of
2,225,000 shares of common stock at an offering price of $24.25 per share. Of
the shares sold, 760,399 were newly-issued by the Company upon the conversion of
approximately 40% of the Company's 7% Preferred Stock by The 1818 Fund. The
remaining 1,464,601 shares were sold by Energy Assets International Corporation,
a wholly-owned subsidiary of Torch. The Company did not receive any proceeds
from the sale of the shares.

      In February 1995, in connection with the purchase of the stock of the
Amoco Congo Petroleum Company, the Company negotiated with OPIC and an agent
bank for a non-recourse credit facility in the amount of $25.0 million. The
initial drawdown on the facility was $8.8 million to finance a portion of the
purchase price. The remaining funds under the credit facility will be used to
finance 75% of a development drilling program in the Congo. A portion of the
remaining outstanding commitment, $6.0 million, was drawn down in January 1996
to fund the first phase of the development drilling program in the Congo. The
interest rate associated with such credit facility is the London Interbank
Offered Rate plus 20 basis points and a guaranty fee of 2.75% of the outstanding
loan balance, all of which is payable quarterly. At December 31, 1996, the
interest rate was 6.09%, plus the 2.75% guaranty fee. The loan agreement
requires a sixteen-quarter repayment period.

      In April 1994, the Company entered into a four-year commitment for a $30.0
million volumetric production payment for the development of certain infill
drilling locations in the Oak Hill field. The proceeds from this agreement
financed the capital expenditures for well drilling, fracturing and completing
and for surface facility installations. Each advance under the production
payment obligates the 

                                       20
<PAGE>
Company to deliver a fixed volume of natural gas, based upon prevailing market
conditions at the time of the advance. During 1994, the Company received $18.4
million covering expenditures on nineteen wells. No such proceeds were received
in 1996 or 1995. (See Note 4 to the Notes to Consolidated Financial Statements).

      On July 24, 1992, the Company closed the sale of $75.0 million aggregate
principal amount of 12 1/2% Senior Subordinated Notes (the "Notes") due June 15,
2002. The Notes are callable in June 1997 at 104% of face value. The Company
currently anticipates borrowing under its Credit Facility to redeem the Notes.
However, the Company's final decision and ability will depend upon numerous
factors at the time of redemption, including commodity prices and the conditions
of the capital markets. The indenture contains covenants that, among other
things, limit the Company's ability to incur additional indebtedness; pay common
stock dividends; purchase capital stock; make certain other distributions;
secure loans and investments; sell assets; enter into transactions with related
persons; and merge, consolidate or transfer substantially all of its assets. The
Notes are unsecured general obligations of the Company and are subordinated in
right of payment to all existing and future senior indebtedness of the Company.
(See Note 8 to the Notes to Consolidated Financial Statements).

      On May 28, 1992, the Company sold $25.0 million of its 7% Preferred Stock,
to The 1818 Fund. (See Note 6 of the Notes to Consolidated Financial
Statements). As a result of the conversion by The 1818 Fund of its shares of 7%
Preferred Stock, there are no longer any shares outstanding.

      At present, there is no plan to pay dividends on common stock. The Company
maintains a policy of reinvesting its discretionary cash flows for the expansion
of its business and operations.

OTHER MATTERS

GAS BALANCING POSITIONS

      It is customary in the industry for various working interest partners to
sell more or less than their entitled share of natural gas. The settlement or
disposition of gas balancing positions is not anticipated to adversely impact
the financial condition of the Company in the near term.

RESULTS OF OPERATIONS

      REVENUES

      Oil and gas revenues for 1996 of $282.7 million were 174% higher than 1995
oil and gas revenues of $103.2 million, due to the acquisition of the California
Properties, as well as higher oil and gas prices. The California Properties
accounted for 66% of total oil and gas revenues in 1996.

      The Company has experienced significant oil and gas revenue growth in
recent years. Oil and gas revenues for 1995 were 29% higher than 1994 oil and
gas revenues of $80.0 million. In 1995, the Congo acquisition accounted for
$17.7 million of the increase in revenues over 1994. In 1996, oil and gas
revenues were decreased by $2.5 million due to the effects of oil and gas
hedges. In 1995, oil and gas revenues were reduced by $.1 million in relation to
a gas price hedge, while the effect of hedging in 1994 was to increase revenues
by $.3 million. The Company's acquisitions of producing properties and
development drilling programs are primarily 

                                       21
<PAGE>
responsible for the increased revenues during 1996, 1995 and 1994. During the
three year period, the volatility of oil and gas prices directly impacted
revenues.

      Gas plant revenues in 1996 of $34.8 million were 28% higher than 1995
revenues of $27.2 million, primarily due to increased natural gas liquids
prices. Gas plant revenues in 1995 were 6% lower than 1994 revenues of $28.8
million. The decrease from 1995 to 1994 was primarily due to decreased volumes
and price declines in natural gas liquids. Pipeline and other revenues for 1996
were $6.8 million, or 6% lower than 1995 revenues of $7.2 million, due primarily
to the sale of the West Delta 152 pipeline during July 1996. Pipeline and other
revenues for 1995 were 30% less than 1994 pipeline revenues of $10.3 million.
The decrease is primarily attributable to reduced throughput in the West Delta
152 pipeline and decreased throughput in the Bright Star gathering system
associated with reduced volumes resulting from producers in the Alabama Ferry
Field employing gas lift recovery in their reservoir maintenance operations.

      EXPENSES

      Lease operating expenses for 1996 totaled $95.9 million, as compared to
$29.6 million and $15.2 million for 1995 and 1994, respectively. The annual
increases of 224% in 1996 and 95% in 1995 are reflective of higher production
and costs associated with the California Properties and Congo acquisitions.

      Gas plant expenses of $29.3 million for 1996 were 29% higher than expenses
of $22.7 million in 1995, primarily due to increased liquids settlements under
percent of proceeds contracts resulting from higher natural gas and natural gas
liquids prices. Gas plant expenses for 1995 were 12% lower than 1994 expenses of
$25.8 million in 1994. This decrease was primarily due to decreased volumes and
the effect of decreased gas prices on plant volume recovery gas. Pipeline and
other operating expenses for 1996 were $6.1 million, or 30% higher than 1995
expenses of $4.7 million, which is attributable to increased tariffs on the
Illini pipeline due to additional transportation contracts. Pipeline and other
operating expenses for 1995 were 31% lower than 1994 pipeline expenses of $6.8
million, due to decreased throughput at the Bright Star gathering system.

      Depreciation, depletion and amortization of $77.3 million in 1996 reflects
an increase of 84% from the 1995 amount of $41.9 million. Such increase reflects
increased production volumes in 1996, due to the acquisition of the California
Properties in 1996, partially offset by a lower depletion rate per barrel of oil
equivalent. In 1995, depreciation, depletion and amortization was 9% higher than
the 1994 amount of $38.6 million primarily due to increased production volumes
in 1995, partially offset by a decreased depletion rate per barrel of oil
equivalent due to the write-down related to the excess of capitalized costs over
future net revenues in December 1994.

      Late in 1994 and continuing into 1995, natural gas prices declined
significantly. As a result of this decline, the capitalized costs of the Company
were in excess of the discounted future net revenues. A provision for impairment
of oil and gas properties of $34.6 million was recorded in 1994. No such
provision was required in 1996 or 1995.

      General and administrative expenses totaled $22.2 million, $10.2 million,
and $10.7 million in 1996, 1995, and 1994, respectively. The 118% increase in
1996 as compared to 1995 is due to the increase in management fees resulting
from significant growth in the assets of the Company, as well as additional
general and administrative costs associated with the acquisition of the
California Properties. 

                                       22
<PAGE>
The 5% decrease in 1995 as compared to 1994 was primarily due to decreased
management fees resulting from a revision to the Torch Agreement which was
implemented on January 1, 1995 as well as reduced legal fees.

      Interest expense increased 135% to $36.2 million in 1996 from $15.4
million in 1995. Such increase is due primarily to increased borrowings under
the Credit Facility as well as the issuance of $160.0 million, 9 1/2% Senior
Subordinated Notes due 2006 in order to finance the acquisition of the
California Properties. In 1995, interest expense increased 22% from $12.6
million in 1994 due to increased borrowings under existing debt facilities along
with interest incurred under the OPIC facility.

      Income tax expense of $23.4 million was recognized in 1996 compared to
income tax expense of $5.2 million in 1995 and an income tax benefit of $9.7
million in 1994. The Company's effective income tax rate increased from 36.6% in
1995 to 40.5% in 1996 primarily due to increased state income taxes associated
with business activity in the state of California.

      NET INCOME (LOSS)

      Net income of $34.7 million was generated in 1996, as compared to net
income of $9.0 million in 1995 and a net loss of $17.6 million in 1994. Net
income after deducting dividends paid on the 7% Preferred Stock was $33.8
million in 1996 as compared to net income of $7.5 million in 1995 and a net loss
of $19.4 million in 1994.

CAPITAL RESOURCES AND LIQUIDITY

      Since the formation of the Company, management's strategy has been to
purchase and develop producing oil and gas properties, participate in gas
processing, gas gathering and pipeline investments and to participate
selectively in exploration activities. The funding of these activities was
provided by operating cash flows, debt and bank financing, private and public
placements of equity, property divestitures and joint ventures with industry
participants. Net cash provided by operating activities was $130.1 million,
$40.1 million, and $63.8 million in 1996, 1995 and 1994, respectively. The
Company invested $520.3 million, $42.6 million, and $108.2 million in oil and
gas properties in 1996, 1995 and 1994, respectively. Additionally, the Company
spent $17.7 million, $1.0 million and $3.4 million on gas plant, pipelines and
other facilities in 1996, 1995 and 1994, respectively. Included in the $520.3
million spent on investments in oil and gas properties in 1996 is approximately
$477.6 million relating to acquisition costs. Also included in the oil and gas
capital expenditures for 1996 is approximately $35.0 million for development
drilling activity in California. In the Company's 1997 capital budget,
approximately $115.0 million is allocated to exploitation projects and the
remaining $25.0 million is directed to exploration. The exploitation spending is
anticipated to consist of $83 million in California, $20 million in East Texas
and the Gulf Coast region, and $12 million internationally. The exploration
spending is planned to be allocated $12 million in East Texas and the Gulf Coast
region, $8 million in California, and $5 million internationally.

      The Company believes its working capital, cash flow from operations and
available financing sources are sufficient to meet its obligations as they
become due and to finance its exploration and development programs. The Company
has an unused commitment under the Credit Facility of $249.0 million at December
31, 1996. Current maturities of long-term debt are $5.4 million, $3.7 million,
$3.7 million, $11.5 million, and $51.3 million for 1997, 1998, 1999, 2000 and
2001, respectively.

                                       23
<PAGE>
OUTLOOK

      The Company anticipates investing approximately $140.0 million during
1997, primarily for development drilling activities. The Company believes its
working capital, cash provided by operating activities, property divestitures,
project financing resources and the Credit Facility are sufficient to meet these
capital commitments.

      Estimates of future net cash flows from proved reserves of oil, gas,
condensate and natural gas liquids were made in accordance with Statement of
Accounting Standard No. 69, "Disclosures about Oil and Gas Producing
Activities." (See Note 14 to Notes to Consolidated Financial Statements). The
estimates are based on prices at year-end of $18.31 BBL for oil and $3.71 MCF
for gas. Significant changes can occur in these estimates based on prices
currently in effect. The results of these disclosures should not be construed to
represent the fair market value of the Company's oil and gas properties.

      The Company periodically uses derivative financial instruments to manage
oil and gas price risk. At December 31, 1996, the Company has entered into
contracts to hedge 2% of its 1997 estimated oil production, and 60% of its 1997
estimated gas production.

      Inflation has not had a material impact on the Company and is not expected
to have a material impact on the Company in the future.

NEW ACCOUNTING PRONOUNCEMENTS

      Statement of Financial Accounting Standard No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of,"
issued by the Financial Accounting Standards Board ("FASB") in March 1995, was
implemented by the Company in the first quarter of 1996. This standard addresses
the accounting for the recognition and measurement of impairment losses for
long-lived assets, certain identifiable intangibles and goodwill related to
those assets to be held and used. This standard also addresses the accounting
for long-lived assets and certain identifiable intangibles to be disposed of.

      The adoption of Accounting Standard 121 did not have a significant impact
on consolidated results of operations or the financial position of the Company.

      The Company follows the intrinsic value method for stock options granted
to employees. In October 1995, the FASB issued Statement of Financial Accounting
Standard No. 123, "Accounting for Stock-Based Compensation." The Company did not
adopt the fair value method for stock-based compensation plans, but has provided
the proforma effects on net income and earnings per share that would have been
recognized if the fair value method was used. (See Note 6 to Notes to
Consolidated Financial Statements).

CONTINGENCIES

      The Company has been named as a defendant in certain lawsuits incidental
to its business. Management does not believe that the outcome of such litigation
will have a material adverse impact on the Company's operating results or
financial condition. However, these actions and claims in the aggregate seek
substantial 

                                       24
<PAGE>
damages against the Company and are subject to the inherent uncertainties in any
litigation. The Company is defending itself vigorously in all such matters.

      In connection with their respective acquisitions of two subsidiaries
owning interests in the Yombo field offshore West Africa (each a "Congo
subsidiary"), the Company 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. Pursuant to the agreement, the Company and CMS may be liable to
the seller for the recapture of Dual Consolidated Losses utilized by the seller
in years prior to the acquisitions if certain triggering events occur, including
(i) a disposition by either the Company or CMS of its respective Congo
subsidiary, (ii) either Congo subsidiary's sale of its interest in the Yombo
field, (iii) the acquisition of the Company or CMS by another consolidated group
or (iv) the failure of the Company or CMS's Congo subsidiary 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 Company and CMS have agreed among
themselves 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.
The Company's potential direct liability could be as much as $54.0 million if a
triggering event with respect to the Company occurs, and the Company believes
that CMS's liability (for which the Company would be jointly liable with an
indemnification right against CMS) could be as much as $72.0 million. The
Company does not expect a triggering event to occur with respect to it or CMS
and does not believe the agreement will have a material adverse effect upon the
Company.


                                       25
<PAGE>
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                    INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
                                                                         PAGE
                                                                        NUMBER
                                                                        ------
  Independent Auditors' Report.......................................     27

  Financial Statements:

  Consolidated Balance Sheets as of December 31, 1996
    and 1995.........................................................     28

  Consolidated Statements of Operations for the Years Ended
    December 31, 1996, 1995 and 1994.................................     30

  Consolidated Statements of Changes in Stockholders'
    Equity for the Years Ended December 31, 1996, 1995 and 1994......     31

  Consolidated Statements of Cash Flows for the Years Ended
    December 31, 1996, 1995 and 1994.................................     32

  Notes to Consolidated Financial Statements.........................     34

                                       26
<PAGE>
                           INDEPENDENT AUDITORS' REPORT

The Board of Directors
Nuevo Energy Company:

We have audited the accompanying consolidated balance sheets of Nuevo Energy
Company as of December 31, 1996 and 1995, and the related consolidated
statements of operations, changes in stockholders' equity and cash flows for
each of the years in the three-year period ended December 31, 1996. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Nuevo Energy Company
as of December 31, 1996 and 1995, and the results of its operations and its cash
flows for each of the years in the three-year period ended December 31, 1996, in
conformity with generally accepted accounting principles.

                                                         KPMG PEAT MARWICK LLP

Houston, Texas
February 21, 1997

                                       27
<PAGE>
                              NUEVO ENERGY COMPANY

                           CONSOLIDATED BALANCE SHEETS

                             (AMOUNTS IN THOUSANDS)

                                     ASSETS

                                                      DECEMBER 31,  DECEMBER 31,
                                                          1996         1995
                                                      -----------    ----------
      CURRENT ASSETS:

      Cash and cash equivalents........               $    13,636    $    5,765
      Accounts receivable..............                    37,595        21,195
      Product inventory................                     2,731         2,187
      Due from affiliates..............                     5,609           ---
      Prepaid expenses and other.......                     4,067           573
                                                      -----------    ----------
         Total current assets..........                    63,638        29,720
                                                      -----------    ----------
      PROPERTY AND EQUIPMENT, AT COST:

      Land ............................                    49,696           ---
      Buildings and improvements.......                     5,304           ---
      Oil and gas properties (full cost
        method) ($44,661 and $12,414
        of unproved properties are excluded
        from amortization in 1996 and 1995,
        respectively)..................                 1,031,057       460,800
      Pipeline and other facilities....                    46,887        50,970
      Gas plant facilities.............                    41,694        25,661
                                                      -----------    ----------
                                                        1,174,638       537,431
      Accumulated depreciation,
         depletion and amortization....                  (392,977)     (269,989)
                                                      -----------    ----------
                                                          781,661       267,442

      OTHER ASSETS.....................                    18,504         9,382
                                                      -----------    ----------
                                                      $   863,803    $  306,544
                                                      ===========    ==========

                   See Notes to Consolidated Financial Statements.

                                       28
<PAGE>
                     CONSOLIDATED BALANCE SHEETS (CONTINUED)

                             (AMOUNTS IN THOUSANDS)

                      LIABILITIES AND STOCKHOLDERS' EQUITY

                                                     DECEMBER 31,   DECEMBER 31,
                                                         1996          1995
                                                       --------      --------
CURRENT LIABILITIES:

Accounts payable ....................................  $ 18,720      $  4,591
Accrued interest ....................................     4,736           972
Accrued liabilities .................................    10,482         2,930
Gas balancing liabilities ...........................       754           479
Due to affiliates ...................................      --           1,314
Current maturities of long-term debt ................     5,408         3,677
                                                       --------      --------
Total current liabilities ...........................    40,100        13,963
                                                       --------      --------
OTHER LONG-TERM LIABILITIES .........................     3,864         1,949
                                                                   
DEFERRED REVENUE ....................................     4,828         8,932
                                                                   
LONG-TERM DEBT, NET OF CURRENT MATURITIES ...........   287,038       113,032
                                                                   
DEFERRED TAXES ......................................    35,153        12,926
                                                                   
MINORITY INTEREST ...................................       704         1,134
                                                                   
COMPANY-OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE               
 PREFERRED SECURITIES OF NUEVO FINANCING I ..........   115,000          --
                                                                   
CONTINGENCIES                                                      
                                                                   
STOCKHOLDERS' EQUITY:                                              
                                                                   
 Preferred stock, $1.00 par value, $1,000 per                      
   share liquidation preference, 10,000,000                        
   shares authorized; 7% Cumulative Convertible                    
   Preferred Stock, Series A and B, none issued                    
   and outstanding at December 31, 1996, and                       
   12,619 and 2,500 shares issued and                              
   outstanding at December 31, 1995 .................      --              15
                                                                   
                                                                   
 Common stock, $.01 par value, 50,000,000 shares                   
   authorized, 19,852,478 and 11,716,919 shares                    
   issued and outstanding at December 31, 1996                     
   and 1995, respectively ...........................       199           117
                                                                   
Additional paid-in capital ..........................   340,126       151,442
Retained earnings ...................................    36,791         3,034
                                                       --------      --------
    Total stockholders' equity ......................   377,116       154,608
                                                       --------      --------
                                                       $863,803      $306,544
                                                       ========      ========
                                                                    
                    See Notes to Consolidated Financial Statements.

                                       29
<PAGE>
                      CONSOLIDATED STATEMENTS OF OPERATIONS

                  (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)

                                                     YEAR ENDED DECEMBER 31,
                                              ---------------------------------
                                                1996         1995       1994
                                              ---------    --------   ---------
REVENUES:
  Oil and gas revenues ....................   $ 282,656    $103,216   $  79,968
  Gas plant revenues ......................      34,802      27,183      28,798
  Pipeline and other revenues .............       6,774       7,222      10,309
  Interest and other income ...............       1,614       1,106         245
                                              ---------    --------   ---------
                                                325,846     138,727     119,320
                                              ---------    --------   ---------
COSTS AND EXPENSES:
  Lease operating expenses ................      95,859      29,634      15,160
  Gas plant operating expenses ............      29,311      22,667      25,794
  Pipeline and other operating
    costs .................................       6,105       4,726       6,767
  General and administrative
    expenses ..............................      22,218      10,165      10,656
  Depreciation, depletion and
    amortization ..........................      77,253      41,866      38,568
  Provision for impairment of
    oil and gas properties ................        --          --        34,632
  Interest expense ........................      36,174      15,389      12,560
  Other expense ...........................       1,069          45       2,387
                                              ---------    --------   ---------
                                                267,989     124,492     146,524
                                              ---------    --------   ---------
Income (loss) before income taxes
  and minority interest ...................      57,857      14,235     (27,204)

Income tax expense (benefit) ..............      23,432       5,209      (9,653)

Minority interest in (loss) earnings
   of subsidiary ..........................        (271)         16          52
                                              ---------    --------   ---------
Net income (loss) .........................      34,696       9,010     (17,603)
Dividends on preferred stock ..............         939       1,472       1,750
                                              ---------    --------   ---------
Earnings (loss) attributable to
 common stockholders ......................   $  33,757    $  7,538   $ (19,353)
                                              =========    ========   =========
Earnings (loss) per share .................   $    1.92    $    .66   $   (1.76)
                                              =========    ========   =========
Earnings per share assuming full
  dilution ................................   $    1.83    $    .66   $   (1.76)
                                              =========    ========   =========
Weighted average common and common
 equivalent shares outstanding ............      17,560      11,355      10,972
                                              =========    ========   =========
Weighted average common and common
  equivalent shares outstanding
  assuming full dilution ..................      18,959      11,437      10,972
                                              =========    ========   =========

                      See Notes to Consolidated Financial Statements.

                                       30
<PAGE>
                       CONSOLIDATED STATEMENTS OF CHANGES

                             IN STOCKHOLDERS' EQUITY

                             (AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
                                                                                                                            TOTAL 
                                                    COMMON STOCK       PREFERRED STOCK      ADDITIONAL     RETAINED         STOCK-
                                                  -----------------    ----------------       PAID-IN      EARNINGS        HOLDERS'
                                                  SHARES     AMOUNT    SHARES    AMOUNT       CAPITAL      DEFICIT)         EQUITY
                                                  ------      ----      ---       ----       --------      --------       ---------
<S>                                               <C>         <C>        <C>      <C>        <C>           <C>            <C>      
January 1, 1994 ...........................       10,758      $108       25       $ 25       $148,155      $ 14,849       $ 163,137
                                                  ------      ----      ---       ----       --------      --------       ---------
Exercise of stock options
 and related tax benefit ...................          10       --       --         --             154          --               154
Preferred stock dividends ..................        --         --       --         --            --          (1,750)         (1,750)
Net loss ...................................        --         --       --         --            --         (17,603)        (17,603)
                                                  ------      ----      ---       ----       --------      --------       ---------
  December 31, 1994 ........................      10,768      $108       25       $ 25       $148,309      $ (4,504)      $ 143,938
                                                  ------      ----      ---       ----       --------      --------       ---------
Exercise of stock options
 and related tax benefit ...................         189         1      --         --           3,123          --             3,124
Conversion of preferred
  stock ....................................         760         8      (10)       (10)            10          --                 8
Preferred stock dividends ..................        --         --       --         --            --          (1,472)         (1,472)
Net income .................................        --         --       --         --            --           9,010           9,010
                                                  ------      ----      ---       ----       --------      --------       ---------
December 31, 1995 ..........................      11,717      $117       15       $ 15       $151,442      $  3,034       $ 154,608
                                                  ======      ====      ===       ====       ========      ========       =========
Issuance of Common Stock ...................       6,384        64      --         --         172,147          --           172,211
Exercise of stock options
 and related tax benefit ...................         587         6      --         --          14,718          --            14,724
Issuance of non-employee
  stock options ............................        --         --       --         --             244          --               244
Issuance of warrants .......................        --         --       --         --           1,575          --             1,575
Conversion of preferred
  stock ....................................       1,164        12      (15)       (15)          --            --                (3)
Preferred stock dividends ..................        --         --       --         --            --            (939)           (939)
Net income .................................        --         --       --         --            --          34,696          34,696
                                                  ------      ----      ---       ----       --------      --------       ---------
December 31, 1996 ..........................      19,852      $199      --         --        $340,126      $ 36,791       $ 377,116
                                                  ======      ====      ===       ====       ========      ========       =========
</TABLE>
                        See Notes to Consolidated Financial Statements.

                                       31
<PAGE>
                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                             (AMOUNTS IN THOUSANDS)

                                                   YEAR ENDED DECEMBER 31,
                                             ----------------------------------
                                               1996         1995         1994
                                             ---------    --------    ---------
CASH FLOWS FROM OPERATING
   ACTIVITIES:
Net income (loss) ........................   $  34,696    $  9,010    $ (17,603)
Adjustments to reconcile net income
(loss) to net cash provided
by operating activities:
  Depreciation, depletion and
  amortization and impairment
  provision ..............................      77,253      41,866       73,200
  Amortization of debt
   financing costs .......................       1,370         365          394
  Amortization of deferred revenue .......      (4,104)     (5,955)      (3,463)
  Deferred taxes .........................      21,932       5,193       (8,737)
  Minority interest ......................        (271)         16           52
                                             ---------    --------    ---------
                          ................     130,876      50,495       43,843
Changes in assets and liabilities,
  net of acquisition effects:
  Accounts receivable ....................     (15,477)     (2,493)       1,922
  Gas imbalances .........................        (198)        225         (269)
  Accounts payable .......................      14,688       1,283          589
  Accrued liabilities ....................      11,316      (3,852)       2,364
  Due (to) from affiliates ...............      (6,923)     (4,198)      (1,231)
  Deferred revenue .......................        --          --         18,350
  Other ..................................      (4,224)     (1,352)      (1,801)
                                             ---------    --------    ---------
NET CASH FLOWS PROVIDED BY
 OPERATING ACTIVITIES ....................     130,058      40,108       63,767
                                             ---------    --------    ---------
CASH FLOWS FROM INVESTING
  ACTIVITIES:
Additions to land ........................     (49,696)       --           --
Additions to buildings and
  improvements ...........................      (5,304)       --           --
Additions to oil and gas
  properties .............................    (520,322)    (41,942)    (108,238)
Proceeds from sales of oil and gas
  properties .............................      43,900       5,257        9,080
Additions to gas plant, pipelines
  and other facilities ...................     (17,717)     (1,022)      (3,397)
Acquisition of Amoco Congo Production
  Company, net of cash acquired ..........        --          (639)        --
Other ....................................        --         2,850       (2,857)
                                             ---------    --------    ---------
NET CASH FLOWS USED IN
 INVESTING ACTIVITIES ....................    (549,139)    (35,496)    (105,412)
                                             ---------    --------    ---------

                     See Notes to Consolidated Financial Statements.

                                       32
<PAGE>
                CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

                             (AMOUNTS IN THOUSANDS)

                                                   YEAR ENDED DECEMBER 31,
                                          -------------------------------------
                                             1996           1995         1994
                                          ---------      --------      --------
CASH FLOWS FROM FINANCING
  ACTIVITIES:
Proceeds from borrowings ............       408,000        17,813        33,000
Deferred financing costs ............       (10,920)         --            --
Net proceeds from issuance of
 common stock .......................       138,327          --            --
Payments of long-term debt ..........      (232,359)      (20,847)       (1,475)
Preferred stock dividends ...........          (939)       (1,472)       (1,750)
Proceeds from exercise of stock
  options ...........................        10,003         2,462           154
Proceeds from issuance of
  Company-obligated mandatorily
  redeemable convertible
  preferred securities of
  Nuevo Financing I .................       115,000          --            --
Cash distribution to minority
 interest ...........................          (160)         (250)         --
                                          ---------      --------      --------
NET CASH FLOWS PROVIDED BY
 (USED IN) FINANCING ACTIVITIES .....       426,952        (2,294)       29,929
                                          ---------      --------      --------
Net increase (decrease) in cash
  and cash equivalents ..............         7,871         2,318       (11,716)
Cash and cash equivalents at
  beginning of year .................         5,765         3,447        15,163
                                          ---------      --------      --------
CASH AND CASH EQUIVALENTS AT
END OF YEAR .........................     $  13,636      $  5,765      $  3,447
                                          =========      ========      ========

                 See Notes to Consolidated Financial Statements.

                                       33
<PAGE>
                              NUEVO ENERGY COMPANY
             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

                              NUEVO ENERGY COMPANY

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

   1. ORGANIZATION

      Nuevo Energy Company (the "Company" or "Nuevo") was formed as a Delaware
      corporation on March 2, 1990, to acquire the businesses of certain public
      and private partnerships (collectively "Predecessors" or "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 such Plan of
      Consolidation, were exchanged for common stock of the Company. The common
      stock began trading on the New York Stock Exchange on July 10, 1990, under
      the symbol "NEV."

   2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

      PRINCIPLES OF CONSOLIDATION

      The consolidated financial statements include the accounts of Nuevo and
      its wholly-owned subsidiaries. NuStar Joint Venture and its 66.7%
      investment in the Benedum Plant System, of which the Company owns a 95%
      interest, has been pro rata consolidated. The Company's 48.5% general
      partner interest in Richfield Gas Storage Partnership also has been pro
      rata consolidated. The consolidated financial statements also include
      Bright Star Gathering, Inc., which is 80% owned by the Company; minority
      interests have been deducted from results of operations and stockholders'
      equity in the appropriate period. All significant intercompany accounts
      and transactions have been eliminated in consolidation.

      OIL AND GAS PROPERTIES

      The Company utilizes the full cost method to account for its investment in
      oil and gas properties. Under the full cost method of accounting, all
      costs of acquisition, exploration and development of oil and natural gas
      reserves (including such costs as leasehold acquisition costs, geological
      expenditures, dry hole costs and tangible and intangible development costs
      and directly associated internal costs) are capitalized into a "full cost
      pool" as incurred on a country-by-country basis. Oil and gas properties,
      the estimated future expenditures to develop proved reserves, and
      estimated future abandonment, site remediation and dismantlement costs are
      depleted and charged to operations using the unit-of-production method
      based on the ratio of current production to total proved recoverable oil
      and natural gas reserves as estimated by independent engineering
      consultants. Costs directly associated with the acquisition and evaluation
      of unproved properties are excluded from the amortization computation
      until it is determined whether or not proved reserves can be assigned to
      the properties or whether impairment has occurred. Domestic depletion
      expense per equivalent barrel of production was $4.05 in 1996, $4.98 in
      1995 and $5.60 in 1994. Depletion expense for the Congo was $0.75 per
      equivalent barrel of production in 1996 and 1995. Dispositions of oil and
      gas properties are recorded as adjustments to capitalized costs, with no
      gain or loss recognized unless such adjustments would significantly alter
      the relationship between capitalized costs and proved reserves of oil and
      natural gas. To the extent that capitalized costs of oil and gas
      properties, net of accumulated depreciation, depletion and 

                                       34
<PAGE>
      amortization and related deferred income taxes, exceed the tax affected
      discounted future net revenues of proved oil and natural gas reserves, on
      a country-by-country basis, such excess capitalized costs would be charged
      to operations. Late in 1994, natural gas prices declined significantly.
      This trend continued through the third quarter of 1995. Due to this
      decline, the Company recorded a write down in 1994 for the excess of
      capitalized costs over discounted future net revenues of $33 million for
      U.S. operations and $1.6 million for foreign operations. No such write
      down in book value was required in 1996 or 1995.

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

      GAS PLANT, PIPELINES AND OTHER FACILITIES

      Gas plant, pipelines and other facilities include the costs to acquire
      certain gas plant, pipelines and other facilities and to secure
      rights-of-way. Capitalized costs associated with gas plant, pipelines 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.

      NEW ACCOUNTING STANDARDS

      Statement of Financial Accounting Standard No. 121, "Accounting for the
      Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
      of," issued by the Financial Accounting Standards Board ("FASB") in March
      1995, was implemented by the Company in the first quarter of 1996. This
      standard addresses the accounting for the recognition and measurement of
      impairment losses for long-lived assets, certain identifiable intangibles
      and goodwill related to those assets to be held and used. This standard
      also addresses the accounting for long-lived assets and certain
      identifiable intangibles to be disposed of.

      The adoption of Accounting Standard 121 did not have a significant impact
      on consolidated results of operations or the financial position of the
      Company.

      The Company follows the intrinsic value method for stock options granted
      to employees. In October 1995, the FASB issued Statement of Financial
      Accounting Standard No. 123, "Accounting for Stock-Based Compensation."
      The Company did not adopt the fair value method for stock-based
      compensation plans, but has provided the proforma effects on net income
      and earnings per share that would have been recognized if the fair value
      method was used.

      GAS BALANCING POSITIONS

      The Company uses the entitlement method for recording sales of natural
      gas. Under the entitlement method of accounting, revenue is recorded based
      on the Company's net revenue interest in production. Deliveries of natural
      gas in excess of the Company's 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. At December 31, 1996 the
      Company's liability due to gas sales in excess of its entitled share was
      approximately $.8 million, and the receivable for gas sales less than the
      Company's entitled share was approximately $1.2 million. 

                                       35
<PAGE>
      Substantially all such amounts are anticipated to be settled with
      production in future periods.

      DERIVATIVE FINANCIAL INSTRUMENTS

      Commodity derivatives utilized as hedges include futures and swap
      contracts. In order to qualify as a hedge, price movements in the
      underlying commodity derivative must be sufficiently correlated with the
      hedged commodity. Settlement of gains and losses on price swap contracts
      are realized monthly, generally based upon the difference between the
      contract price and the average closing New York Mercantile Exchange
      ("NYMEX") price and are reported as a component of oil and gas revenues
      and operating cash flows in the period realized. Gains or losses
      attributable to the termination of a swap contract are deferred on the
      balance sheet and recognized in revenue when the hedged crude oil and
      natural gas is sold. There were no such deferred gains or losses at
      December 31, 1996, 1995 or 1994.

      Gains and losses on other derivative financial instruments that qualify as
      a hedge of firmly committed or anticipated purchases and sales of oil and
      gas commodities are deferred on the balance sheet and recognized in income
      and operating cash flows when the related hedged transaction occurs. Gains
      or losses on derivative financial instruments that do not qualify as a
      hedge are recognized in income currently.

      Oil and gas revenues were decreased by $2.5 million in 1996, decreased by
      $.1 million in 1995 and increased by $.3 million in 1994 as a result of
      such hedging activity.

      EARNINGS (LOSS) PER SHARE AND STOCK - BASED COMPENSATION

      Earnings (loss) per share calculations are based on the weighted average
      number of common shares and common share equivalents and earnings (loss)
      attributable to common stockholders. Common share equivalents include
      dilutive common stock options, warrants and the Company-obligated
      mandatorily redeemable convertible preferred securities of Nuevo Financing
      I, ("TECONS"). The assumed conversion of the 7% Cumulative Convertible
      Preferred Stock, ("7% Preferred Stock"), was anti-dilutive in 1995 and
      1994.

      INCOME TAXES

      Deferred 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, the Company considers all highly
      liquid debt instruments purchased with an original maturity of three
      months or less to be cash equivalents. Interest paid in cash for 1996,
      1995 and 1994 was $30.6 million, $14.4 million and $11.4 million,
      respectively. Income taxes paid 

                                       36
<PAGE>
      (refunded) in cash for 1996, 1995 and 1994 were $1,500,000, ($909,000) and
      $6,600, respectively. (See also Note 6 for certain non-cash financing
      activities related to the acquisition of oil and gas properties.)


      PRODUCT INVENTORY

      Inventory relating to quantities of crude oil and natural gas liquids in
      storage as of the balance sheet date is carried at current market pricing.
      The Company recognizes revenue for Congo crude oil sales when the sale is
      completed and risk of loss transfers to a third party purchaser. Crude oil
      in inventory is stated at year end market prices less transportation
      costs; the Company recognizes changes in the market value of inventory
      from one period to the next as oil revenues.

      USE OF ESTIMATES

      Management of the Company 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 and the computation of the full cost
      ceiling limitation to prepare these financial statements in conformity
      with generally accepted accounting principles. Actual results could differ
      from those estimates.

      RECLASSIFICATIONS

      Certain reclassifications of prior period statements have been made to
      conform with current reporting practices.

   3. ACQUISITIONS

      During the last three years, the Company has made the following
      acquisitions (the "Acquisitions"):

      In April 1996, the Company consummated the acquisition of (i) certain
      upstream oil and gas properties located onshore and offshore California
      ("Unocal Properties") of Union Oil Company of California ("Unocal") for an
      adjusted purchase price of $480.5 million in cash and (ii) certain
      California oil properties ("Point Pedernales Properties," and together
      with the Unocal Properties, the "California Properties") from Torch Energy
      Advisors Incorporated ("Torch") and certain of its wholly-owned
      subsidiaries for a net adjusted purchase price of $35.7 million in common
      stock of the Company. The acquisition of the California Properties was
      effective as of October 1, 1995, and the purchase price was reduced by the
      net cash flows from production between such date and closing. The
      acquisition was recorded using the purchase method effective April 1, 1996
      for accounting purposes. See the Company's current report on Form 8-K
      filed with the Securities and Exchange Commission ("SEC") on April 23,
      1996, as well as Form 8-K/A filed with the SEC on November 26, 1996.

      The following table presents the unaudited pro forma results of operations
      as if the acquisition of the California Properties had occurred as of the
      beginning of the years ended December 31, 1996 and 1995. These pro forma
      results are based on assumptions and estimates and are not necessarily
      indicative of the Company's results of operations had the transaction
      occurred as of the beginning of the 

                                       37
<PAGE>
      years ended December 31, 1996 and 1995 or in the future (amounts in
      thousands except per share data).

                                                             1996         1995
                                                          ---------    ---------
      Revenues..........................................  $ 381,682    $ 354,726
      Net Income........................................  $  40,935    $  23,921
      Earnings available to common stockholders.........  $  39,996    $  22,449
      Earnings per common and common equivalent share...  $    2.07    $    1.27
      Earnings per common and common equivalent share
         assuming full dilution.........................  $    1.98    $    1.27

      In July 1996, the Company completed the acquisition of a package of East
      Texas oil and gas properties for a net purchase price of $9.3 million in
      cash. The acquisition of these properties was effective as of December 1,
      1995, and the purchase price was reduced by the net cash flows from
      production between such date and closing. In December 1996, the holders of
      the preferential rights on these properties exercised such rights for a
      cash payment of $8.0 million, acquiring approximately half of the
      estimated proved reserves relating to this acquisition.

      A subsidiary of Nuevo, the Nuevo Congo Company ("NCC"), along with a third
      party, acquired all of the capital stock of Amoco Congo Production Company
      ("ACPC"), and Amoco Congo Exploration Company (collectively, the "Congo
      Companies") in February 1995, for a cash purchase price of $10.8 million.
      The primary asset acquired by the Company is an 18.75% interest in the
      Yombo field in the People's Republic of Congo. Through an interpurchaser
      agreement, Nuevo and the third party have agreed to share the combined net
      operating revenues and expenses of the Congo Companies evenly.

      NCC is a U.S. corporation with foreign branch operations in the Congo. The
      functional currency of NCC is the U.S. Dollar and its income is taxed in
      the United States. The Company's Congo investment involves risks typically
      associated with investments in emerging markets such as an uncertain
      political, economic, legal and tax environment, and expropriation and
      nationalization of assets. The Company's investment is insured through
      political risk insurance provided by the Overseas Private Investment
      Corporation ("OPIC").

      Cash consideration of approximately $10.8 million was paid to Amoco using
      Company funds and loan proceeds prior to purchase price adjustments. The
      purchase price was based on an economic effective date of December 1,
      1993. The fair value of the net assets acquired follows:

                  Working capital, primarily cash     $    11,536
                  Oil and gas property                        639
                                                      -----------
                  Total purchase price, including
                    acquisition costs                 $    12,175
                                                      ===========

      The Company completed ten oil and gas property acquisitions during 1994
      with an aggregate gross purchase price of $33.7 million. The acquisitions
      added approximately 4,515 MBBLS of proved oil reserves and 44.0 BCF of
      proved gas reserves. The acquired properties are located primarily in
      Texas, Louisiana and offshore California.

                                       38
<PAGE>
   4. PRODUCTION PAYMENTS

      In April 1994, the Company entered into a four-year commitment for a $30.0
      million volumetric production payment for the development of certain
      infill drilling locations in the Oak Hill field. The proceeds from this
      agreement financed the capital expenditures for well drilling, fracturing
      and completing and for surface facility installations. Each advance under
      the production payment obligates the Company to deliver a fixed volume of
      natural gas, based upon prevailing market conditions at the time of the
      advance. During 1994, the Company received $18.4 million, committing the
      Company to deliver 10.7 BCF of natural gas through December 1998. The cash
      advances are reflected as deferred revenues on the Company's consolidated
      balance sheets and are amortized into revenue as the natural gas volumes
      are delivered. No such advances were received in 1996 or 1995.

      Effective January 1, 1993 the Company sold an interest in the Oak Hill
      field to Torchmark Corporation ("Torchmark"). The interest sold represents
      approximately 96 BCF of estimated proved gas reserves and 287 MBBLS of
      estimated proved oil reserves at December 31, 1992. Torchmark paid a
      nominal amount of cash for the Oak Hill field properties and conveyed to
      the Company a net profits production payment ("Oak Hill Production
      Payment"). The Oak Hill Production Payment entitles the Company to receive
      the net proceeds from production, limited to 90% of estimated reserves at
      December 31, 1992, as well as an amount equal to 70% of the I.R.C. ss.29
      Tax Credits ("Section 29 Credits") generated by production from the Oak
      Hill field properties. The Company has an option to repurchase the
      properties for the fair market value of the reserves based upon projected
      discounted revenues from existing wells at the time of the repurchase.
      During 1996, 1995 and 1994, the Company recorded revenues of $.9 million,
      $1.1 million and $1.3 million, respectively, representing 70% of the
      Section 29 Credits generated by the Oak Hill Production Payment.

      Substantially all of the future cash flows from the Oak Hill field
      properties will be paid to the Company pursuant to the Oak Hill Production
      Payment. Therefore, the conveyance was not reflected as a sale. The
      Company will continue to reflect revenues and the proved reserves
      dedicated to the Oak Hill Production Payment as owned by the Company.

   5. RELATED PARTY TRANSACTIONS

      On July 9, 1990 the Company entered into an agreement with Torch (the
      "Torch Agreement") whereby Torch administers certain business activities
      of the Company for a monthly fee. Torch is primarily in the business of
      providing management and advisory services relating to oil and gas assets
      for institutional and public investors and maintains a large technical,
      operating, accounting and administrative staff. The Torch Agreement
      requires Torch to administer the business activities of the Company for a
      monthly fee equal to the sum of one-twelfth of 2% on the first $250
      million of assets and one-twelfth of 1% on assets in excess of $250
      million, excluding certain gas plant facilities and cash, plus 2% of
      monthly operating cash flows (as defined) during the period in which the
      services are rendered. In addition, the Torch Agreement contains a
      provision whereby 20% of the overhead fees on Torch operated properties
      are credited against the monthly fee paid to Torch, as well as a provision
      whereby the monthly fee is credited for one-twelfth of $900,000. The Torch
      Agreement was amended 

                                       39
<PAGE>
      effective January 1, 1996, with an initial term of three years,
      automatically renewable for successive one-year periods, unless terminated
      earlier. If the Company terminates the amended Torch Agreement prior to
      the end of its first, second, or third year, it will be required to pay
      Torch a break-up fee of $30.0 million, $25.0 million and $20.0 million,
      respectively unless such termination is caused by the bankruptcy,
      insolvency or dissolution of Torch, breach of the agreement by Torch or a
      change in control of Torch. For the years ended December 31, 1996, 1995
      and 1994, fees paid to Torch amounted to $10.2 million, $5.9 million and
      $6.4 million, respectively. Additionally, in the ordinary course of
      business, the Company incurs intercompany balances resulting from the
      payment of costs and expenses by affiliated entities on behalf of the
      Company.

      J. P. Bryan, Chairman of the Board for the Company, is also Chairman of
      the Board for Torch and holds a 22% interest in Torch on a fully diluted
      basis as of December 31, 1996.

      A subsidiary of Torch markets oil and natural gas production and natural
      gas liquids from certain oil and gas properties and gas plants in which
      the Company owns an interest. In 1996, 1995 and 1994 such charges were
      $2.8 million, $.8 million and $.4 million, respectively.

      Costs of the evaluation of potential property acquisitions are incurred by
      Torch on behalf of the Company. The Company was charged $.6 million, $1.0
      million and $.9 million, for these costs in 1996, 1995 and 1994,
      respectively.

      In consideration of the services rendered by Torch in connection with the
      origination of the acquisition of the Unocal Properties, the Company
      agreed to pay Torch $10.0 million in twelve equal monthly installments
      after the closing of the acquisition. Additionally, 30,000 warrants were
      issued to a director of the Company, as a broker's fee related to the
      acquisition of the Unocal Properties.

      Torch operates certain oil and gas interests owned by the Company. The
      Company is charged, on the same basis as other third parties, for all
      customary expenses and cost reimbursements associated with these
      activities. Operator's overhead charged for these activities for the years
      ended December 31, 1996, 1995 and 1994 was $8.8 million, $2.0 million and
      $1.8 million, respectively.

      In January 1995, the Company loaned International Testing Services, Inc.
      ("International Testing"), the sum of $500,000 payable with interest. This
      obligation has a maturity date of May 1997. The president and a director
      of International Testing is also a director of the Company.

      In 1994, Nuevo paid a transaction fee of approximately $.1 million in
      relation to an acquisition of an entity that is affiliated with a member
      of the Board of Directors.

   6. STOCKHOLDERS' EQUITY

      COMMON AND PREFERRED STOCK

      The Certificate of Incorporation of the Company authorizes the issuance of
      up to 50,000,000 shares of common stock and 10,000,000 shares of preferred
      stock, the terms, preferences, rights and restrictions of which will be
      established by the Board of Directors of the Company. All shares of common
      stock have equal voting 

                                       40
<PAGE>
      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 the Company's loan agreements
      limit the amount of dividends which may be declared. Under the terms of
      the 12 1/2% Senior Subordinated Notes described in Note 8, $232.6 million
      of Nuevo's consolidated stockholders' equity was available for the payment
      of dividends at December 31, 1996. Under the terms of the 9 1/2% Senior
      Subordinated Notes described in Note 8, $84.7 million of Nuevo's
      consolidated stockholders' equity was available for the payment of
      dividends at December 31, 1996. There is no present plan to pay dividends
      on common stock as the Company intends to reinvest its cash flows for the
      expansion of its business and operations.

      On December 23, 1996, the Company and United Investors Management Company
      ("United") and The 1818 Fund, L.P. ("The 1818 Fund") closed the offering
      of 2,138,605 shares of Common Stock (the "Shares"). United sold 1,275,000
      Shares and The 1818 Fund sold 863,605 shares. The price to the public of
      the Shares was $47.50 per share. All of the Shares sold by United were
      outstanding and 112 of the Shares sold by The 1818 Fund were outstanding
      prior to the offering. The remaining 863,493 of the Shares sold by The
      1818 Fund were issued upon conversion of the remaining 11,220 shares 7%
      Preferred Stock of the Company. The Company did not receive any proceeds
      from the issuance of these shares. As a result of this conversion by The
      1818 Fund of its shares of 7% Preferred Stock, there are no longer any
      shares of the 7% Preferred Stock outstanding.

      During April 1996, the Company partially financed the acquisition of the
      Unocal Properties with the proceeds from the sale to the public of
      5,109,200 shares of common stock (the "Common Stock Offering"). The
      purchase of the Point Pedernales Properties was financed by the issuance
      to Torch of 1,275,000 shares of the Company's Common Stock valued at the
      public offering price of $28.00 per share in the Common Stock Offering.

      During the third quarter of 1995, the Company consummated the sale of
      2,225,000 shares of common stock at an offering price of $24.25 per share.
      Of the shares sold, 760,399 were newly-issued by the Company upon the
      conversion of approximately 40% of the Company's 7% Preferred Stock. The
      remaining 1,464,601 shares were sold by Energy Assets International
      Corporation, a wholly-owned subsidiary of Torch. The Company did not
      receive any proceeds from the sale of the shares.

      STOCK INCENTIVE PLAN

      In 1990, the Company established its 1990 Stock Option Plan (the "Stock
      Option Plan"), with respect to its common stock. On March 30, 1993, the
      Board of Directors adopted the Nuevo Energy Company 1993 Stock Incentive
      Plan ("Stock Incentive Plan"), which was approved by the stockholders on
      May 12, 1993. The purpose of the Stock Option Plan and the Stock Incentive
      Plan is to provide directors and key employees of the Company and its
      subsidiaries, and the officers and key employees of Torch (in their
      capacity as managers under the Torch Agreement) performance incentives,
      and to provide a means of encouraging stock ownership in the Company by
      such persons.

      The maximum number of shares subject to options under the Stock Incentive
      Plan is 2,500,000 shares. Options are granted under the Stock Incentive
      Plan on the basis of the optionee's contribution to the Company. No option
      may exceed a term 

                                       41
<PAGE>
      of more than ten years. Options granted under the Stock Incentive Plan may
      be either incentive stock options or options that do not qualify as
      incentive stock options. The Company's compensation committee is
      authorized to designate the recipients of options, the dates of grants,
      the number of shares subject to options, the option price (which may not
      be less than the fair market value of the shares at the time the option is
      granted), the terms of payment upon exercise of the options, and the time
      during which the options may be exercised. Options granted are
      exercisable, in full, six months following the date of grant.

      A summary of activity in the stock option plans during 1994, 1995 and 1996
      is set forth below:

                                                                       WEIGHTED-
                                                                        AVERAGE
                                                        OPTIONS        EXERCISE
                                                        (000'S)          PRICE
                                                       ----------       ------
Outstanding at December 31, 1993 ..............           763,400       $15.42
                                                       ----------       ------
            Granted ...........................           881,000       $18.20
            Exercised .........................           (10,500)      $15.42
                                                       ----------       ------

Outstanding at December 31, 1994 ..............         1,633,900       $16.92
                                                       ----------       ------
            Granted ...........................           394,750       $20.07
            Exercised .........................          (188,288)      $13.11
            Canceled ..........................            (4,525)      $21.75
                                                       ----------       ------

Outstanding at December 31, 1995 ..............         1,835,837       $17.97
            Granted ...........................           518,100       $38.10
            Exercised .........................          (587,799)      $17.03
                                                       ----------       ------

Outstanding at December 31, 1996 ..............         1,766,138       $24.24
                                                       ==========       ======


      The Company had 1,505,538 options and 1,548,987 options exercisable at
      December 31, 1996 and 1995, respectively. Detail of stock options
      outstanding and options exercisable at December 31, 1996 follows:

                                      Outstanding               Exercisable
                          --------------------------------  --------------------
                                    Weighted-
                                     Average   Weighted-              Weighted-
                                    Remaining   Average                Average 
       Range of Exercise              Life     Exercise               Exercise 
             Prices         Number   (Years)     Price       Number     Price  
       -------------------------------------------------------------------------
       $11.00 to $16.88     449,050    7.05      $15.93      449,050    $15.93
       $17.63 to $20.88     733,063    7.64      $19.71      733,063    $19.71
       $21.75 to $30.63     323,425    8.58      $26.97      323,425    $26.97
       $32.00 to $49.88     260,600    9.93      $47.88          --     $47.88
                          ---------                        ---------    
                          1,766,138                        1,505,538
                          =========                        =========

      The weighted-average fair value of options granted during 1996 and 1995
      was $11.52 and $6.21, respectively. 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: 1996 and 1995
      expected stock price 

                                       42
<PAGE>
      volatility of 33.6%, and 34.6%, respectively; risk free interest rate of
      6%, and average expected option lives of 3 years. Had compensation expense
      for stock-based compensation been determined based on the fair value at
      the date of grant, the Company's net income and earnings per share would
      have been reduced to the pro forma amounts indicated below:

                                                          1996            1995
                                                      -----------      ---------
      Net Income
           As reported ........................       $   33,757       $   7,538
           Pro forma ..........................       $   31,507       $   5,860

      Primary earnings per share
           As reported ........................       $     1.92       $     .66
           Pro forma ..........................       $     1.79       $     .52

      Fully diluted earnings per share
           As reported ........................       $     1.83       $     .66
           Pro forma ..........................       $     1.71       $     .52


      7. 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 2,300,000 Term Convertible Securities,
      Series A, ("TECONS") on behalf of the Trust (the "TECONS Offering"). The
      price to the public of the TECONS was $50.00 per TECONS. Distributions on
      the TECONS began to accumulate from December 23, 1996 and will be 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 .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 due December 15, 2026 of the
      Company.

      8.  LONG-TERM DEBT

      Long-term debt is comprised of the following at December 31, 1996 and
      1995:

                                                      1996             1995
                                                    ---------        ---------
      12 1/2% Senior Subordinated Notes,
        net of discount (a) .....................   $  74,288        $  74,191
      
      9 1/2% Senior Subordinated Notes (b) ......     160,000             --
      
      OPIC credit facility (at 6.09% and
        6.14% at December 31, 1996, and
        1995, respectively, plus a
        guaranty fee of 2.75%) (c) ..............      11,309            8,262
      
      Bank credit facility (at 6.125% at
        December 31, 1996) (d) ..................      40,000             --
      
      Bank credit facility (at 7.68% at
        December 31, 1995 (e) ...................        --             24,600
      
      NuStar Credit Agreement (f) ...............       5,872            7,747
      
      Other .....................................         977            1,909
                                                    ---------        ---------
        Total debt ..............................     292,446          116,709
      Less current maturities ...................      (5,408)          (3,677)
                                                    ---------        ---------
      
      Long-term debt ............................   $ 287,038        $ 113,032
                                                    =========        =========
                                       43
<PAGE>
  (a) On July 24, 1992, the Company closed the sale of $75,000,000 aggregate
      principal amount of 12 1/2% Senior Subordinated Notes due June 15, 2002
      (the "Notes"). The Notes are callable in June 1997 at 104% of face value.
      The Notes were sold at 98.583% of face value. The Notes are redeemable, in
      whole or in part, at the option of the Company, on or after June 15, 1997,
      under certain conditions. The Company currently anticipates borrowing
      under its Credit Facility to redeem the Notes. However, the Company's
      final decision will depend upon numerous factors at the time of
      redemption, including commodity prices and conditions in the capital
      markets. The Company is required to make mandatory sinking fund payments
      of $11,250,000, plus accrued and unpaid interest, on June 15, 2000 and
      June 15, 2001, calculated to retire prior to maturity 30% of the aggregate
      principal amount of the Notes originally issued. The indenture contains
      covenants that, among other things, limit the Company's ability to incur
      certain additional indebtedness; pay common stock dividends; purchase
      capital stock; make certain other distributions; secure loans and
      investments; sell assets; enter into transactions with related persons;
      and merge, consolidate or transfer substantially all of its assets. The
      Notes are unsecured general obligations of the Company and are
      subordinated in right of payment to all existing and future senior
      indebtedness of the Company. The Company also may be required, subject to
      certain conditions, to offer to purchase certain of the Notes at 100% of
      the principal amount plus accrued and unpaid interest, if its defined
      Adjusted Consolidated Net Tangible Assets decreases to less than 125% of
      indebtedness, other than subordinated indebtedness of the Company, and
      non-recourse indebtedness. In the event of a defined change of control,
      the Company will be required, subject to certain conditions, to offer to
      purchase all outstanding Notes at a price equal to 101% of the principal
      amount plus accrued and unpaid interest. The Notes are listed on the New
      York Stock Exchange.

  (b) In April 1996, the Company financed a portion of the purchase price of the
      Unocal Properties with the proceeds from the sale to the public of a
      principal amount of $160.0 million, 9 1/2% Senior Subordinated Notes due
      April 15, 2006 (the "9 1/2% Notes"). Interest on the 9 1/2% Notes will
      accrue at the rate of 9 1/2% per annum and will be payable semi-annually
      in arrears on April 15 and October 15. The 9 1/2% Notes are redeemable, in
      whole or in part, at the option of the Company, on or after April 15,
      2001, under certain conditions. The Company is not required to make
      mandatory redemption or sinking fund payments with respect to the 9 1/2%
      Notes. The indenture contains covenants that, among other things, limit
      the Company's ability to incur additional indebtedness, limits restricted
      payments, limit issuances and sales of capital stock by restricted
      subsidiaries, limit dispositions of proceeds of asset sales, limit
      dividends and other payment restrictions affecting restricted
      subsidiaries, and restricts mergers, consolidations or sales of assets.
      The 9 1/2% Notes are unsecured general obligations of the Company, and are
      subordinated in right of payment to all existing and future senior
      indebtedness of the Company. In the event of a defined change in control,
      the Company will be required to make an offer to 

                                       44
<PAGE>
      repurchase all outstanding 9 1/2% Notes at 101% of the principal amount
      thereof plus accrued and unpaid interest to the date of redemption.

  (c) In February 1995, in connection with the purchase of the stock of ACPC,
      the Company negotiated with the OPIC and an agent bank for a non-recourse
      credit facility in the amount of $25.0 million. The security for such
      facility is the assets and stock of NCC. The initial drawdown on the
      facility was $8.8 million to finance a portion of the purchase price. The
      remaining funds under the credit facility will be used to finance 75% of a
      development drilling program in the Congo. A portion of the remaining
      outstanding commitment, $6.0 million, was drawn down in January 1996 to
      fund the first phase of the development drilling program in the Congo. The
      interest rate associated with such credit facility is the London Interbank
      Offered Rate ("LIBOR") plus 20 basis points and a guaranty fee of 2.75% of
      the outstanding loan balance, payable quarterly. At December 31, 1996, the
      interest rate was 6.09%, plus the guarantee fee of 2.75%. The loan
      agreement requires a sixteen-quarter repayment period.

  (d) In April 1996, the Company negotiated a commitment from a bank group led
      by NationsBank of Texas, N.A. to extend to the Company a $385.0 million
      credit facility (the "Credit Facility") maturing on May 17, 2001. The
      maximum borrowings that may be outstanding under the Credit Facility may
      not exceed a borrowing base ("Borrowing Base") based on the present value
      of the Company's oil and gas reserves based on assumptions regarding
      prices, production and costs approved by the bank group. The Borrowing
      Base was $289.0 million at December 31, 1996, and will be reset annually.
      Sales of assets in excess of $10.0 million will trigger a requirement to
      re-calculate the Borrowing Base. If amounts outstanding under the Credit
      Facility exceed the Borrowing Base, as redetermined from time to time, the
      Company will be required to repay such excess, and may be required to sell
      assets to make such repayments. Amounts outstanding under the Credit
      Facility will bear interest at a rate equal to the LIBOR plus a number of
      basis points which increases as the senior indebtedness of the Company as
      a percent of the Borrowing Base increases. At December 31, 1996, the
      Company's interest rate under the Credit Facility is LIBOR plus .5%, or
      6.125%. The Credit Facility has customary covenants including, but not
      limited to, covenants with respect to the following matters: (i)
      limitation on restricted payments and investments; (ii) limitation on
      guarantees and indebtedness; (iii) limitation on prepayments of
      subordinated indebtedness; (iv) limitation on prepayments of additional
      indebtedness; (v) limitation on mergers and issuances of securities; (vi)
      limitation on liens; (vii) limitation on sales of property; (viii)
      limitation on transactions with affiliates; (ix) limitation on derivative
      contracts; (x) limitation on acquisitions, new businesses and margin
      stock; (xi) limitation with respect to certain prohibited types of
      contracts and multi-employer ERISA plans; and (xii) limitation with
      respect to unrestricted subsidiaries. The Company is also required to
      maintain certain financial ratios and conditions, including without
      limitation an EBITDA to fixed charge coverage ratio, a net worth
      requirement and a funded debt to capitalization ratio. The proceeds were
      used to finance a portion of the purchase price of the Unocal Properties
      as well as retire the borrowings under an existing credit facility in the
      amount of $27.0 million.

  (e) In 1994, the Company entered into an agreement with two banks for a $40.0
      million credit facility. The Company used the proceeds of this credit
      facility to fund capital expenditures and for general corporate purposes.
      This credit facility 

                                       45
<PAGE>
      was refinanced by the Credit Facility in connection with the acquisition
      of the Unocal Properties.

  (f) In 1992, NuStar entered into a credit agreement with a group of lenders
      whereby NuStar borrowed $12.0 million in order to finance the acquisition
      of certain operating assets. Under the terms of the agreement, 80% of the
      operating cash flows (as defined) of NuStar are dedicated to the repayment
      of principal and interest on a quarterly basis. The indebtedness bears
      interest at a fixed rate of 8.5% per annum. The credit agreement provides
      that dedicated payments of operating cash flows will be increased to 100%
      if certain scheduled principal reductions are not achieved during the term
      of the credit agreement. Currently, 100% of NuStar's cash flows are being
      utilized to service such debt. Additionally, quarterly payments totaling
      7.5% of operating cash flows (as defined) are to be made to the lenders
      until the principal indebtedness is repaid. Upon full repayment of
      principal, 50% of future operating cash flows will be dedicated to the
      lenders until a 13% rate of return is achieved, at which time payments of
      5% of operating cash flows are required until a 17.5% rate of return is
      achieved. Based on NuStar's estimate of future operating cash flows,
      interest expense has been recorded in 1996, 1995 and 1994 using a 13%
      effective interest rate. The venturers in NuStar are obligated to make
      additional payments if certain gross operating margins are not exceeded
      for two consecutive quarters. One such payment was required in the second
      quarter of 1994 in the amount of $349,945. No such payments were required
      in 1996 or 1995. The debt is secured by a full security interest in
      NuStar's interest in the Benedum Plant System.

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

       1997..................................       $  5,408
       1998..................................          3,716
       1999.................................           3,716
       2000..................................         11,462
       2001..................................         51,250
       Thereafter ...........................        216,894
                                                    --------
      Total debt.............................       $292,446
                                                    ========

      Based upon the quoted market price, the fair value of the 12 1/2% Senior
      Subordinated Notes is estimated to be $80.4 million and $81.8 million at
      December 31, 1996 and 1995, respectively. The fair value of the 9 1/2%
      Senior Subordinated Notes is estimated to be $167.4 million at December
      31, 1996. For the NuStar credit agreement, OPIC credit facility and other
      debt, for which no quoted prices are available, management believes the
      carrying value of the debt materially represents the fair value of the
      debt at December 31, 1996 and 1995.

                                       46
<PAGE>
9.    GUARANTOR FINANCIAL STATEMENTS

      Consolidating financial statements of the Company and the Guarantor
      Subsidiaries, (Rubicon Venture, Inc.; Nuevo Liquids, Inc.; Nuevo Financing
      I; Bright Star Gathering, Inc.; Sierra Power Corporation, L.C.; and
      Richfield Natural Gas Inc.) as guarantors of the Company's 12 1/2% Senior
      Subordinated Notes due 2002, and the Company's 9 1/2% Senior Subordinated
      Notes due 2006, for the years ended December 31, 1996 and 1995 are as
      follows:

                      CONDENSED CONSOLIDATING BALANCE SHEET

                             As of December 31, 1996

                             (Amounts in Thousands)
                                                             
                                     GUARANTOR    NUEVO          
                                        SUB-      CONGO     ELIMINA-    CONSOLI-
                             NUEVO    SIDIARIES  COMPANY     TIONS        DATED
                           --------   --------   -------   ---------    --------
Total current assets ..... $ 66,435   $102,591   $10,174   $(115,562)   $ 63,638

Net property, plant and
  equipment ..............  724,695     32,339    24,627        --       781,661

Total other assets .......   15,993      8,068       172      (5,729)     18,504
                           --------   --------   -------   ---------    --------

      Total Assets ....... $807,123   $142,998   $34,973   $(121,291)   $863,803
                           ========   ========   =======   =========    ========
Total current liabilities  $ 19,624   $  9,545   $10,931        --      $ 40,100

Long-term debt ...........  389,887      5,107     7,605    (115,561)    287,038

Deferred taxes ...........   28,654      3,478     3,021        --        35,153

Other long-term
 liabilities .............    7,139      2,257      --          --         9,396

Mandatorily redeemable
convertible preferred
securities of Nuevo
Financing I ..............     --      115,000      --          --       115,000

Total stockholders equity   361,819      7,611    13,416      (5,730)    377,116
                           --------   --------   -------   ---------    --------
    Total liabilities
      and stockholders'
      equity ............. $807,123   $142,998   $34,973   $(121,291)   $863,803
                           ========   ========   =======   =========    ========

                                       47
<PAGE>
                    CONDENSED CONSOLIDATING INCOME STATEMENT

                      For the Year Ended December 31, 1996

                             (Amounts in Thousands)

                                      GUARANTOR      NUEVO CONGO
                          NUEVO      SUBSIDIARIES     COMPANY      CONSOLIDATED
                         --------      -------        -------        --------
Revenues .............   $265,033      $40,136        $20,677        $325,846
                                                                   
Expenses .............    216,995       37,890         12,833         267,718
                         --------      -------        -------        --------
Net Earnings Before                                                
Income Taxes .........     48,038        2,246          7,844          58,128
                                                                   
Income Taxes .........     19,456          799          3,177          23,432
                         --------      -------        -------        --------
Net Earnings .........     28,582        1,447          4,667          34,696
                                                                   
Dividends on                                                       
Preferred                                                          
Stock ................        939         --             --               939
                         --------      -------        -------        --------
Net Earnings Available                                             
to Common                                                          
Stockholders .........   $ 27,643      $ 1,447        $ 4,667        $ 33,757
                         ========      =======        =======        ========

                                       48
<PAGE>
                 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

                      For the Year Ended December 31, 1996

                             (Amounts in Thousands)

<TABLE>
<CAPTION>
                                                                   NUEVO
                                                    GUARANTOR      CONGO              
                                        NUEVO      SUBSIDIARIES   COMPANY   CONSOLIDATED
                                        ---------    ---------    --------    ---------
<S>                                     <C>          <C>          <C>         <C>      
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income ..........................   $  28,582    $   1,447    $  4,667    $  34,696
Non-cash adjustments ................      89,538        2,400       4,242       96,180

Change in assets and
  liabilities .......................     125,134     (132,817)      6,865         (818)
                                        ---------    ---------    --------    ---------
NET CASH PROVIDED BY
  OPERATING ACTIVITIES ..............     243,254     (128,970)     15,774      130,058
                                        ---------    ---------    --------    ---------
CASH FLOWS FROM INVESTING
  ACTIVITIES:
Additions to oil and gas
  properties ........................    (520,378)      19,530     (19,474)    (520,322)
Proceeds from sale of
  properties ........................      43,928          (28)       --         43,900
Additions to
other properties
and other ...........................     (72,657)         (60)       --        (72,717)
                                        ---------    ---------    --------    ---------
NET CASH (USED IN) PROVIDED
  BY INVESTING ACTIVITIES ...........    (549,107)      19,442     (19,474)    (549,139)
                                        ---------    ---------    --------    ---------
CASH FLOWS FROM FINANCING
  ACTIVITIES:
Proceeds from borrowings ............     402,000         --         6,000      408,000
Proceeds from issuance of
  mandatorily redeemable
  convertible preferred
  securities of Nuevo
  Financing I .......................        --        115,000        --        115,000
Payments of long-term debt ..........    (226,606)      (2,800)     (2,953)    (232,359) 
Other ...............................     136,471         (160)       --        136,311
                                        ---------    ---------    --------    ---------
NET CASH PROVIDED BY
  FINANCING ACTIVITIES ..............     311,865      112,040       3,047      426,952
                                        ---------    ---------    --------    ---------
Net increase (decrease) in
  cash & cash equivalents ...........       6,012        2,512        (653)       7,871

Cash and cash equivalents
  at beginning of period ............         690        2,722       2,353        5,765
                                        ---------    ---------    --------    ---------
Cash and cash equivalents
  at end of period ..................   $   6,702    $   5,234    $  1,700    $  13,636
                                        =========    =========    ========    =========
</TABLE>
                                       49
<PAGE>
                      CONDENSED CONSOLIDATING BALANCE SHEET

                             As of December 31, 1995

                             (Amounts in Thousands)
<TABLE>
<CAPTION>
                                                                                         NUEVO
                                                                      GUARANTOR          CONGO                              CONSOLI-
                                                        NUEVO        SUBSIDIARIES       COMPANY         ELIMINATIONS          DATED
                                                       --------         -------         --------          --------          --------
<S>                                                    <C>              <C>             <C>               <C>               <C>     
Total current assets .........................         $ 52,549         $ 2,586         $  8,097          $(33,512)         $ 29,720
Net property, plant and
  equipment ..................................          213,267          48,052            6,123              --             267,442
Total other assets ...........................            6,033           5,785             (263)           (2,173)            9,382
                                                       --------         -------         --------          --------          --------
      Total Assets ...........................         $271,849         $56,423         $ 13,957          $(35,685)         $306,544
                                                       ========         =======         ========          ========          ========
Total current liabilities ....................         $  5,456         $42,715         $   (696)         $(33,512)         $ 13,963
Long-term debt ...............................           98,835           8,138            6,059              --             113,032
Deferred taxes ...............................            7,837           2,745            2,344              --              12,926
Other long-term
 liabilities .................................            9,520           2,495             --                --              12,015

Total stockholders' equity ...................          150,201             330            6,250            (2,173)          154,608
                                                       --------         -------         --------          --------          --------
      Total liabilities
       and stockholders'
       equity ................................         $271,849         $56,423         $ 13,957          $(35,685)         $306,544
                                                       ========         =======         ========          ========          ========
</TABLE>
                                       50
<PAGE>
                    CONDENSED CONSOLIDATING INCOME STATEMENT

                      For the Year Ended December 31, 1995

                             (Amounts in Thousands)

                                               GUARANTOR   NUEVO CONGO  CONSOLI-
                                     NUEVO    SUBSIDIARIES  COMPANY      DATED
                                    -------     -------     -------     --------
Revenues ......................     $83,849     $37,362     $17,516     $138,727

Expenses ......................      76,846      36,568      11,094      124,508
                                    -------     -------     -------     --------
Net Earnings Before
Income Taxes ..................       7,003         794       6,422       14,219

Income Taxes ..................       2,569         296       2,344        5,209
                                    -------     -------     -------     --------
Net Earnings ..................       4,434         498       4,078        9,010

Dividends on Preferred Stock ..       1,472        --          --          1,472
                                    -------     -------     -------     --------
Net Earnings Available
 to Common
 Stockholders .................     $ 2,962     $   498     $ 4,078     $  7,538
                                    =======     =======     =======     ========

                                       51
<PAGE>
                 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

                      For the Year Ended December 31, 1995

                             (Amounts in Thousands)
<TABLE>
<CAPTION>
                                                   GUARANTOR      NUEVO CONGO     CONSOLI-
                                          NUEVO   SUBSIDIARIES     COMPANY         DATED
                                        --------    -------        -------        --------
<S>                                     <C>         <C>            <C>            <C>     
CASH FLOWS FROM OPERATING ACTIVITIES:                                             
Net income ..........................   $  4,434    $   498        $ 4,078        $  9,010
Non-cash adjustments ................     32,878      5,309          3,298          41,485
                                                                                  
Change in assets and                                                              
   liabilities ......................     (7,294)     3,115         (6,208)        (10,387)
                                        --------    -------        -------        --------
NET CASH PROVIDED BY                                                              
   OPERATING ACTIVITIES .............     30,018      8,922          1,168          40,108
                                        --------    -------        -------        --------
CASH FLOWS FROM INVESTING                                                         
   ACTIVITIES:                                                                    
Additions to oil and gas                                                          
   properties .......................    (29,759)    (5,745)        (6,438)        (41,942)
Proceeds from sale of                                                             
   properties .......................      5,257       --             --             5,257
Acquisition of Amoco                                                              
   Congo Production                                                                  
   Company ..........................       --         --             (639)           (639)
Additions to other                                                                             
properties and other ................      2,596       (768)          --             1,828
                                        --------    -------        -------        --------
NET CASH USED IN                                                                  
   INVESTING ACTIVITIES .............    (21,906)    (6,513)        (7,077)        (35,496)
                                        --------    -------        -------        --------
CASH FLOWS FROM FINANCING                                                         
    ACTIVITIES:                                                                   
Proceeds from borrowings ............      9,000       --            8,813          17,813
Payments of long-term debt ..........    (17,413)    (2,883)          (551)        (20,847)
Other ...............................        990       (250)          --               740
                                        --------    -------        -------        --------
NET CASH (USED IN)PROVIDED                                                                          
   BY FINANCING ACTIVITIES ..........     (7,423)    (3,133)         8,262          (2,294)
                                        --------    -------        -------        --------
Net increase (decrease) in                                                        
   cash & cash equivalents ..........        689       (724)         2,353           2,318
                                                                                  
Cash and cash equivalents                                                         
   at beginning of period ...........          1      3,446           --             3,447
                                        --------    -------        -------        --------
Cash and cash equivalents                                                         
   at end of period .................   $    690    $ 2,722        $ 2,353        $  5,765
                                        ========    =======        =======        ========
</TABLE>
                                       52
<PAGE>
10.   INCOME TAXES

      Income tax expense (benefit) is summarized as follows:

                                              YEAR ENDED DECEMBER 31,
                                    -----------------------------------------
                                     1996             1995             1994
                                    ------         ---------         --------
      Current
      Federal.....................  $ 1,200        $      16         $   (916)
      State.......................      300              --              --
                                    -------        ---------         --------
                                      1,500               16             (916)
                                    -------        ---------         --------
      Deferred
        Federal...................   17,425            4,613           (8,568)
        State.....................    4,507              580             (169)
                                    -------        ---------         --------
                                     21,932            5,193           (8,737)
                                    -------        ---------         --------
      Total income tax ...........  $23,432        $   5,209         $ (9,653)
                                    =======        =========         ========

      A deferred tax benefit related to the exercise of employee stock options
      of approximately $4.7 million and $.7 million was allocated directly to
      additional paid-in capital in 1996 and 1995, respectively. Such deferred
      tax benefit was immaterial in 1994. The Company recorded deferred taxes of
      $5.0 million in 1996 in connection with the acquisition of oil and gas
      properties due primarily to the impact of California unitary state taxes
      and the carry over tax basis for the properties acquired from Torch.

      Total income tax differs from the amount computed by applying the Federal
      income tax rate to income (loss) before income taxes and minority
      interest. The reasons for these differences are as follows:

                                                     YEAR ENDED DECEMBER 31,
                                                  ----------------------------
                                                  1996       1995        1994
                                                  ----       ----        -----
Statutory Federal income tax rate ...........     35.0%      35.0%       (35.0%)

Increase in tax rate resulting from:
  State income taxes, net of Federal
    benefit .................................      5.4%       2.6%         (.4%)
  Nondeductible travel and
    entertainment and other .................       .1%      (1.0%)        (.1%)
                                                  ----       ----        -----
                                                  40.5%      36.6%       (35.5%)
                                                  ====       ====        =====

                                       53
<PAGE>
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,
                                          ------------------------
                                            1996            1995
                                          ---------      ---------
      Net operating loss
         carryforwards................    $   6,372      $   7,402
      Alternative minimum tax credit
         carryforwards................        1,437            237
      Other ..........................          ---             66
                                          ---------      ---------
             Total deferred income
             tax assets...............    $   7,809      $   7,705
                                          ---------      ---------
      Plant, property and
       equipment......................    $ (37,190)     $ (19,266)
      State income taxes..............       (5,772)        (1,365)
                                          ---------      ---------
             Total deferred income tax
             liabilities..............    $ (42,962)       (20,631)
                                          ---------      ---------
      Net deferred income tax
         liability....................    $ (35,153)     $ (12,926)
                                          =========      ==========

At December 31, 1996, the Company had a net operating loss carryforward for
regular tax of approximately $18.2 million which will expire in future years
beginning in 2005. The alternative minimum tax credit carryforward of $1.4
million does 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.
Management believes that it is more likely than not that the deferred income tax
assets, comprised primarily of the net operating loss carryforward, will be
realized in future years through the reversal of taxable temporary differences
and the annual election to capitalize intangible drilling costs during the
carryforward period.

                                       54
<PAGE>
   11.      INDUSTRY SEGMENT INFORMATION

   Nuevo's operations are concentrated primarily in two segments:
         - Exploration and production of oil and natural gas
         - Gas plant, pipelines and other facilities

                                       AT AND FOR THE YEARS ENDED DECEMBER 31,
                                       --------------------------------------
 (Amounts in thousands)                  1996            1995        1994
                                       ---------      ---------    ----------
Sales to unaffiliated customers:
      Oil and gas - domestic...     $    261,988      $  85,844    $   79,968
      Oil and gas - foreign....           20,668         17,372           --
      Gas plant, pipelines and
       other facilities........           41,576         34,405        39,107
                                       ---------      ---------    ----------
          Total sales..........          324,232        137,621       119,075
      Other revenues...........            1,614          1,106           245
                                       ---------      ---------    ----------
          Total revenues.......        $ 325,846      $ 138,727    $  119,320
                                       =========      =========    ==========
Operating profit (loss) before
  income taxes:
      Oil and gas - domestic (1)    $    105,269      $  28,175    $   (4,842)
      Oil and gas - foreign....            8,660          7,114           --
      Gas plant, pipelines and
       other facilities........            1,742          3,585         3,101
                                       ---------      ---------    ----------
                                         115,671         38,874        (1,741)
      Unallocated corporate expenses      21,369          9,266        12,955
      Interest expense.........           36,174         15,389        12,560
                                      ----------      ---------    ----------
      Income (loss) before
       income taxes............       $   58,128      $  14,219    $  (27,256)
                                      ==========      =========    ==========
Identifiable assets:
      Oil and gas - domestic(2)       $  728,174      $ 214,391    $  225,222
      Oil and gas - foreign....           34,128         11,962           --
      Gas plant, pipelines and
       other facilities........           66,329         61,446        63,542
                                      ----------      ---------    ----------
                                         828,631        287,799       288,764
Corporate assets and investments          35,172         18,745        18,456
                                      ----------      ---------    ----------
          Total................       $  863,803      $ 306,544    $  307,220
                                      ==========      =========    ==========
Capital expenditures:
      Oil and gas - domestic(2)       $  565,650      $  35,504   $   108,238
      Oil and gas - foreign....           19,607          7,077           --
      Gas plant, pipelines and
       other facilities........            2,717          1,022         2,706
                                      ----------      ---------    ----------
      Total....................       $  587,974      $  43,603    $  110,944
                                      ==========      =========    ==========
Depreciation, depletion and
 amortization:
      Oil and gas - domestic...       $   71,803      $  37,339    $   35,018
      Oil and gas - foreign....            1,065            954          --
      Provision for impairment of
       oil and gas properties..              --             --         34,632
      Gas plant, pipelines and
       other facilities........            3,812          3,411         3,393
                                      ----------       --------    ----------
                                      $   76,680      $  41,704    $   73,043
                                      ==========      =========    ==========

                                       55
<PAGE>
      (1)   Oil and gas operations for 1994 include a charge for $34.6 million
            to record the excess of capitalized costs over discounted future net
            revenues. See Note 2.

      (2)   Identifiable assets and capital expenditures for 1996 include $15.0
            million in costs associated with gas plant facilities in California,
            which process immaterial amounts of third party gas, and whose
            revenues from the sale of these liquids are included in oil and gas
            revenues.

       In 1996, the Company had one customer that accounted for 52% of its
       revenues. In 1995, the Company had two customers that accounted for 31%
       of total revenues. In 1994, one customer accounted for 19% of total
       revenues.


   12. CONTINGENCIES

       The Company has been named as a defendant in certain lawsuits incidental
       to its business. Management does not believe that the outcome of such
       litigation will have a material adverse impact on the Company's operating
       results or financial condition. However, these actions and claims in the
       aggregate seek substantial damages against the Company and are subject to
       the inherent uncertainties in any litigation. The Company is defending
       itself vigorously in all such matters.

       In connection with their respective acquisitions of two subsidiaries
       owning interests in the Yombo field offshore West Africa (each a "Congo
       subsidiary"), the Company 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. Pursuant to the agreement, the
       Company and CMS may be liable to the seller for the recapture of dual
       consolidated losses utilized by the seller in years prior to the
       acquisitions if certain triggering events occur, including (i) a
       disposition by either the Company or CMS of its respective Congo
       subsidiary, (ii) either Congo subsidiary's sale of its interest in the
       Yombo field, (iii) the acquisition of the Company or CMS by another
       consolidated group or (iv) the failure of the Company or CMS's Congo
       subsidiary 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 Company and CMS have agreed among themselves 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. The
       Company's potential direct liability could be as much as $54.0 million if
       a triggering event with respect to the Company occurs, and the Company
       believes that CMS's liability (for which the Company would be jointly
       liable with an indemnification right against CMS) could be as much as
       $72.0 million. The Company does not expect a triggering event to occur
       with respect to it or CMS and does not believe the agreement will have a
       material adverse effect upon the Company.

   13. FINANCIAL INSTRUMENTS

       The Company periodically uses derivative financial instruments to manage
       oil and natural gas price risk. For 1997, the Company is a party to
       several commodity 

                                       56
<PAGE>
      price swap agreements, hedging an aggregate of 23,360 MMCF of gas, at
      prices ranging from $1.88 to $2.20. The Company has also purchased futures
      contracts at an average price of $21.15 on 270,000 barrels for 1997, on
      which the Company has a unrecognized deferred loss of $.4 million at
      December 31, 1996. These energy swap agreements expose the Company to
      counterparty credit risk to the extent the counterparty is unable to meet
      its monthly settlement commitment to the Company. Futures contracts are
      guaranteed settlement by the NYMEX and have nominal credit risk. Futures
      contracts are executed through brokers and require daily margin
      settlement.

       DETERMINATION OF 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 the Company's other investments,
       derivative financial instruments and long-term debt at December 31, 1996
       and 1995.

                               DECEMBER 31, 1996         DECEMBER 31, 1995
                            ----------------------     ----------------------
(Amounts in thousands)       CARRYING    APPROXIMATE   CARRYING   APPROXIMATE
                              VALUE      FAIR VALUE      VALUE     FAIR VALUE
                            ---------     --------     --------    ---------
Other investments ......     $  1,673     $  2,558     $  3,005     $  3,714
Derivative Assets:
  Futures contracts ....        1,000          599         --           --
Long-term debt .........      287,038      300,526      113,032      120,641
  (See Note 8)
TECONS .................      115,000      123,349         --           --

   14.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, 1996 are based primarily on reserve
      reports prepared by the independent petroleum engineering firms of Ryder
      Scott Company and Poco Oil Company. Reserve quantities and future
      production for previous years are based primarily upon reserve reports
      prepared by the independent petroleum engineering firms of Miller and
      Lents, Ltd., S.A. Holditch and Associates, Inc., Ryder Scott Company,
      D.O.R. Engineering Inc., and Poco Oil 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
      Statement of Financial Accounting Standard No. 69, "Disclosures about Oil
      and Gas Producing Activities." The estimates are based on prices at
      year-end, of $18.31 BBL for oil and $3.71 MCF for gas. 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

                                       57
<PAGE>
      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 the Company's 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.

      Costs incurred (amounts in thousands) -

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

                                               YEAR ENDED DECEMBER 31,
                                        -----------------------------------
                                           1996         1995        1994
                                        ----------    ---------   ---------
      DOMESTIC
      Property acquisition:
        Proved properties(2).........   $  452,603     $    ---   $  29,226
        Unproved properties..........       40,000          ---       1,550
      Exploration(1).................        9,889        9,387       7,128
      Development....................       63,158       26,117      70,334
                                        ----------    ---------   ---------

                                        $  565,650    $  35,504   $ 108,238
                                        ==========    =========   =========
      FOREIGN
      Property acquisition:
      Proved properties..............   $      ---    $     639   $     ---
      Exploration....................        8,844          ---         ---
      Development....................       10,763        6,438         ---
                                        ----------    ---------   ---------

                                        $   19,607    $   7,077    $    ---
                                        ==========    =========    ========
      TOTAL
      Property acquisition:
        Proved properties............   $  452,603     $    639   $  29,226
        Unproved properties..........       40,000          ---       1,550
      Exploration....................       18,733        9,387       7,128
      Development....................       73,921       32,555      70,334
                                        ----------    ---------   ---------
                                        $  585,257    $  42,581   $ 108,238
                                        ==========    =========   =========
      ------------
      (1) Includes capitalized internal costs directly related to exploration
      activities of $2.6 million, $1.0 million and $2.7 million in 1996, 1995
      and 1994, respectively.

      (2) The acquisition of domestic proved properties for 1996 includes $15.0
      million in costs associated with gas plant facilities in California.

                                       58
<PAGE>
      CAPITALIZED COSTS (amounts in thousands) -

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

                                              YEAR ENDED DECEMBER 31,
                                        -----------------------------------
                                           1996          1995        1994
                                        ----------    ---------   ---------
      DOMESTIC
      Proved properties..............   $  959,712    $ 441,309   $ 404,935
      Unproved properties............       44,661       12,414      13,284
                                        ----------    ---------   ---------
      Total capitalized costs........    1,004,373      453,723     418,219

      Accumulated depreciation,
       depletion and amortization....     (373,297)    (252,648)   (209,999)
                                        ----------     --------   ---------
      Net capitalized costs..........   $  631,076    $ 201,075   $ 208,220
                                        ==========    =========   =========
      FOREIGN
      Proved properties..............   $   26,684    $   7,077   $     ---
                                        ----------    ---------   ---------
      Total capitalized costs........       26,684        7,077         ---

      Accumulated depreciation,
       depletion and amortization....       (2,019)        (954)        ---
                                        ----------    ---------   ---------

      Net capitalized costs..........   $   24,665    $   6,123   $     ---
                                        ==========    =========   =========
      TOTAL
      Proved properties..............   $  986,396    $ 448,386   $ 404,935
      Unproved properties............       44,661       12,414      13,284
                                        ----------    ---------   ---------
      Total capitalized costs........    1,031,057      460,800     418,219

      Accumulated depreciation,
       depletion and amortization....     (375,316)    (253,602)   (209,999)
                                        ----------    ---------   ---------
      Net capitalized costs..........   $  655,741    $ 207,198   $ 208,220
                                        ==========    =========   =========

                                       59
<PAGE>
      RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES (amounts in thousands)

                                               YEAR ENDED DECEMBER 31,
                                        -----------------------------------
                                           1996         1995         1994
                                        ----------    ---------   ---------
      DOMESTIC
      Revenues from oil and gas
       producing activities..........   $  261,988    $  85,844   $  79,968
      Production costs...............      (84,916)     (20,330)    (15,160)
      Depreciation, depletion
       and amortization..............      (71,803)     (37,339)    (35,018)
      Provision for impairment of
       oil and gas properties........          ---          ---     (34,632)
      Income tax benefit
       (provision)...................      (42,634)     (10,312)      1,719
                                        ----------     --------   ---------
      Results of operations from
        producing activities
       (excluding corporate
       overhead and interest costs)..   $   62,635    $  17,863   $  (3,123)
                                        ==========     ========   ==========

      FOREIGN
      Revenues from oil and gas
       producing activities..........   $   20,668     $ 17,372   $     ---
      Production costs...............      (10,943)      (9,304)        ---
      Depreciation, depletion
       and amortization..............       (1,065)        (954)        ---
      Provision for impairment of
       oil and gas properties........          ---          ---         ---
      Income tax benefit
       (provision)...................       (3,507)      (2,603)        ---
                                        ----------    ---------   ---------
      Results of operations from
        producing activities
       (excluding corporate
       overhead and interest costs)..   $    5,153    $   4,511   $     ---
                                        ==========    =========   =========
      TOTAL
      Revenues from oil and gas
       producing activities..........   $  282,656    $ 103,216   $  79,968
      Production costs...............      (95,859)     (29,634)    (15,160)
      Depreciation, depletion
       and amortization..............      (72,868)     (38,293)    (35,018)
      Provision for impairment of
       oil and gas properties........          ---          ---     (34,632)
      Income tax benefit
       (provision)...................      (46,141)     (12,915)      1,719
                                           -------    ---------   ---------
      Results of operations from
        producing activities
       (excluding corporate
       overhead and interest costs)..   $   67,788    $  22,374   $  (3,123)
                                        ==========    =========   ==========

                                       60
<PAGE>
      PER UNIT SALES PRICES AND COSTS:

                                             YEAR ENDED DECEMBER 31,
                                        --------------------------------
                                         1996           1995       1994
                                        ------        --------    ------
      DOMESTIC
      Average sales price:
        Oil (per barrel).............   $16.10        $  15.18    $14.89
        Gas (per MCF) ...............   $ 2.12        $   1.56    $ 1.90

      Average production cost
        per equivalent barrel........   $ 4.79        $   2.71    $ 2.42

      FOREIGN
      Average sales price:
        Oil (per barrel).............   $14.56        $  13.66    $   --
        Gas (per MCF) ...............   $  --         $    --     $   --

      Average production cost
        per equivalent barrel........   $ 7.71        $   7.31    $   --

      TOTAL
      Average sales price:
        Oil (per barrel).............   $15.93        $  14.68    $14.89
        Gas (per MCF) ...............   $ 2.12        $   1.56    $ 1.90

      Average production cost
        per equivalent barrel........   $ 5.01        $   3.38    $ 2.42

                                       61
<PAGE>
      The Company's estimated total proved and proved developed reserves of oil
      and gas are as follows:
<TABLE>
<CAPTION>
                                                                                YEAR ENDED DECEMBER 31,
                                                  ---------------------------------------------------------------------------------
           DESCRIPTION                                     1996*                       1995*                         1994*
           -----------                            -----------------------       ----------------------       ----------------------
                                                    Oil           Gas            Oil            Gas           Oil            Gas
                                                   (MBBL)         (MMCF)        (MBBL)        (MMCF)         (MBBL)         (MMCF)
                                                  --------       --------       -------       --------       -------       --------
<S>                                                  <C>          <C>            <C>           <C>             <C>          <C>    
DOMESTIC
Proved reserves at beginning
  of year ..................................         9,700        301,311        10,852        261,115         5,961        237,758
Revisions of previous estimates ............         5,581         (1,388)         (472)        18,419         1,719        (10,894)
Extensions and discoveries .................         3,615         18,291         2,456         58,463         1,044         19,275
Production .................................       (11,924)       (34,775)       (2,675)       (28,913)       (2,365)       (23,327)
Sales of reserves in-place .................        (2,506)       (30,588)         (461)        (7,773)          (22)        (5,730)
Purchase of reserves in-place ..............       161,373        141,779          --             --           4,515         44,033
                                                  --------       --------       -------       --------       -------       --------
Proved reserves at end of year .............       165,839        394,630         9,700        301,311        10,852        261,115
                                                  ========       ========       =======       ========       =======       ========
Proved developed reserves -
  Beginning of year ........................         8,289        142,012         8,692        164,183         4,133        119,478
                                                  ========       ========       =======       ========       =======       ========
  End of year ..............................       122,088        236,013         8,289        142,012         8,692        164,183
                                                  ========       ========       =======       ========       =======       ========
FOREIGN
Proved reserves at beginning
  of year ..................................        20,826           --            --             --            --             --
Revisions of previous estimates ............          (107)          --           4,096           --            --             --
Extensions and discoveries .................           915           --            --             --            --             --
Production .................................        (1,420)          --          (1,272)          --            --             --
Sales of reserves in-place .................          --             --            --             --            --             --
Purchase of reserves in-place ..............          --             --          18,002           --            --             --
                                                  --------       --------       -------       --------       -------       --------
Proved reserves at end of year .............        20,214           --          20,826
                                                  ========       ========       =======       ========       =======       ========
Proved developed reserves - ................
  Beginning of year ........................        14,787           --            --             --            --             --
                                                  ========       ========       =======       ========       =======       ========
  End of year ..............................        16,727           --          14,787           --            --             --
                                                  ========       ========       =======       ========       =======       ========
TOTAL
Proved reserves at beginning
  of year ..................................        30,526        301,311        10,852        261,115         5,961        237,758
Revisions of previous estimates ............         5,474         (1,388)        3,624         18,419         1,719        (10,894)
Extensions and discoveries .................         4,530         18,291         2,456         58,463         1,044         19,275
Production .................................       (13,344)       (34,775)       (3,947)       (28,913)       (2,365)       (23,327)
Sales of reserves in-place .................        (2,506)       (30,588)         (461)        (7,773)          (22)        (5,730)
Purchase of reserves in-place ..............       161,373        141,779        18,002           --           4,515         44,033
                                                  --------       --------       -------       --------       -------       --------
Proved reserves at end of year .............       186,053        394,630        30,526        301,311        10,852        261,115
                                                  ========       ========       =======       ========       =======       ========
Proved developed reserves -
  Beginning of year ........................        23,076        142,012         8,692        164,183         4,133        119,478
                                                  ========       ========       =======       ========       =======       ========
  End of year ..............................       138,815        236,013        23,076        142,012         8,692        164,183
                                                  ========       ========       =======       ========       =======       ========
</TABLE>
Notes:

(*)   Proved reserves in 1996, 1995, and 1994 include those dedicated to the Oak
      Hill Production Payment. (See Note 4).

                                       62
<PAGE>
DISCOUNTED FUTURE NET CASH FLOWS (amounts in thousands)

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

                                             YEAR ENDED DECEMBER 31,
                                      -------------------------------------
                                         1996          1995         1994
                                      ----------   -----------  -----------
DOMESTIC
Future cash inflows.................  $4,476,523   $  850,521   $   561,092
Future production costs.............  (1,739,219)    (311,452)     (189,907)
Future development costs(1).........    (309,365)     (81,102)      (78,111)
                                      ----------   -----------  -----------
Future net inflows before
  income tax........................   2,427,939      457,967       293,074
Future income taxes.................    (736,788)     (96,829)      (31,416)
                                      ----------   -----------  -----------

Future net cash flows...............   1,691,151      361,138       261,658
10% discount factor.................    (702,996)    (124,218)      (78,453)
                                      ----------   ----------   -----------
Standardized measure of
  discounted future net
  cash flows........................  $  988,155   $  236,920   $   183,205
                                      ==========   ==========   ===========
FOREIGN
Future cash inflows.................  $  414,383   $  364,444   $       ---
Future production costs.............    (248,222)    (192,934)          ---
Future development costs............      (2,625)      (6,278)          ---
                                      ----------   -----------  -----------
Future net inflows before
  income tax........................     163,536      165,232           ---
Future income taxes.................     (55,083)     (57,869)          ---
                                      ----------   -----------  -----------

Future net cash flows...............     108,453      107,363           ---
10% discount factor.................     (33,659)     (33,197)          ---
                                      ----------   ----------   -----------
Standardized measure of
  discounted future net
  cash flows........................  $   74,794   $   74,166   $       ---
                                      ==========   ==========    ==========
TOTAL
Future cash inflows.................  $4,890,906   $1,214,965   $   561,092
Future production costs.............  (1,987,441)    (504,386)     (189,907)
Future development costs............    (311,990)     (87,380)      (78,111)
                                      ----------   -----------  -----------
Future net inflows before
  income tax........................   2,591,475      623,199       293,074
Future income taxes.................    (791,871)    (154,698)      (31,416)
                                      ----------   -----------  -----------
Future net cash flows...............   1,799,604      468,501       261,658
10% discount factor.................    (736,655)    (157,415)      (78,453)
                                      ----------   ----------   -----------
Standardized measure of
  discounted future net
  cash flows........................  $1,062,949   $  311,086    $  183,205
                                      ==========   ==========    ==========
------------
(1) Includes $10.7 million of environmental and site-remediation liabilities.

                                       63
<PAGE>
The following are the principal sources of change in the standardized measure of
discounted future net cash flows:

                                             YEAR ENDED DECEMBER 31,
                                       ------------------------------------
                                         1996         1995         1994
                                       ---------   -----------   ----------
DOMESTIC
Standardized measure -
  beginning of year..................  $ 236,920    $ 183,205    $  166,430
Sales, net of production costs.......   (177,072)     (65,514)      (64,808)
Purchases of reserves in-place.......    605,210          ---        41,482
Net change in prices and
  production costs...................    505,108       58,184       (69,755)
Extensions, discoveries and improved
  recovery, net of future production
  and development costs..............     38,572       51,265        20,602
Changes in estimated future
  development costs..................    (29,124)       7,273        (8,361)
Development costs incurred during
  the period ........................     39,275        7,633        32,388
Revisions of quantity estimates......     79,185       14,030          (282)
Accretion of discount................     26,207       18,321        17,604
Net change in income taxes...........   (238,071)     (25,151)        9,606
Sales of reserves in-place...........    (41,969)      (4,691)       (2,581)
Changes in production rates and
 other...............................    (56,086)      (7,635)       40,880
                                       ---------   -----------   ----------
Standardized measure -
  end of year........................  $ 988,155   $  236,920    $  183,205
                                       =========   ==========    ==========
FOREIGN
Standardized measure -
  beginning of year..................  $  74,166   $      ---    $      ---
Sales, net of production costs.......     (9,725)      (8,068)          ---
Purchases of reserves in-place.......        ---       64,524           ---
Net change in prices and
  production costs...................     (1,557)      35,476           ---
Extensions, discoveries and improved
  recovery, net of future production
  and development costs..............      4,930          ---           ---
Changes in estimated future
  development costs..................     (2,386)       2,253           ---
Development costs incurred during
  the period ........................      6,278          ---           ---
Revisions of quantity estimates......       (598)      24,483           ---
Accretion of discount................     11,288          ---           ---
Net change in income taxes...........      6,304      (38,713)          ---
Sales of reserves in-place...........        ---          ---           ---
Changes in production rates and
 other...............................    (13,906)      (5,789)          ---
                                       ----------  -----------      -------
Standardized measure -
  end of year........................  $  74,794    $  74,166    $      ---
                                       =========   ==========    ==========

                                       64
<PAGE>
TOTAL
Standardized measure -
  beginning of year..................  $ 311,086    $ 183,205    $  166,430
Sales, net of production costs.......   (186,797)     (73,582)      (64,808)
Purchases of reserves in-place.......    605,210       64,524        41,482
Net change in prices and
  production costs...................    503,551       93,660       (69,755)
Extensions, discoveries and improved
  recovery, net of future production
  and development costs..............     43,502       51,265        20,602
Changes in estimated future
  development costs..................    (31,510)       9,526        (8,361)
Development costs incurred during
  the period ........................     45,553        7,633        32,388
Revisions of quantity estimates......     78,587       38,513          (282)
Accretion of discount................     37,495       18,321        17,604
Net change in income taxes...........   (231,767)     (63,864)        9,606
Sales of reserves in-place...........    (41,969)      (4,691)       (2,581)
Changes in production rates and
 other...............................    (69,992)     (13,424)       40,880
                                      ----------   ----------    ----------
Standardized measure -
  end of year........................ $1,062,949   $  311,086    $  183,205
                                      ==========   ==========    ==========

                                       65
<PAGE>
Selected quarterly financial data (amounts in thousands, except per share data)
(unaudited):

                                                 QUARTER ENDED
                                   ---------------------------------------------
                                  March 31, June 30, September 30,  December 31,
                                    1996       1996       1996          1996
                                   -------    -------    -------     --------
    Revenues(1) ...............    $34,425    $93,515    $90,911     $106,995
                                                                       
    Operating Earnings(1)  ....    $12,778    $30,418    $29,115     $ 43,089
                                                                     
    Net income(1) .............    $ 4,201    $ 7,188    $ 8,008     $ 15,299
                                                                       
    Earnings available to common                                               
     stockholders(1) ..........    $ 3,936    $ 6,924    $ 7,771     $ 15,126
                                                                       
    Earnings per common                                                        
     equivalent share(1) ......    $   .32    $   .38    $   .40     $    .75

    Fully diluted earnings per
     common equivalent share (1)   $   .32    $   .37    $   .39     $    .73
-----------                                                                   
(1) The quarters ended June 30, September 30, and December 31, 1996 are
inclusive of activity subsequent to the acquisition of the California
Properties.

                                                QUARTER ENDED
                              -------------------------------------------------
                              March 31,     June 30,  September 30, December 31,
                                1995          1995        1995         1995
                               -------      -------      -------      -------
Revenues ...................   $35,085      $36,155      $32,415      $35,072

Operating Earnings .........   $ 9,861      $10,162      $ 9,007      $ 9,860

Net income .................   $ 2,183      $ 2,540      $ 1,659      $ 2,628

Earnings
 attributable
 to common
 stockholders ..............   $ 1,745      $ 2,103      $ 1,326      $ 2,364

Earnings per
  common equivalent
  share ....................   $   .16      $   .19      $   .12      $   .20

                                       66
<PAGE>
                                NUEVO ENERGY COMPANY

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

None.

                                      PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

   The information required by this item will be included in a definitive proxy
   statement, pursuant to Regulation 14A, to be filed not later than 120 days
   after December 31, 1996. Such information is incorporated herein by
   reference.

ITEM 11.  EXECUTIVE COMPENSATION

   The information required by this item will be included in a definitive proxy
   statement, pursuant to Regulation 14A, to be filed not later than 120 days
   after December 31, 1996. Such information is incorporated herein by
   reference.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

   The information required by this item will be included in a definitive proxy
   statement, pursuant to Regulation 14A, to be filed not later than 120 days
   after December 31, 1996. Such information is incorporated herein by
   reference.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   The information required by this item will be included in a definitive proxy
   statement, pursuant to Regulation 14A, to be filed not later than 120 days
   after December 31, 1996. Such information is incorporated herein by
   reference.

                                       PART IV

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

   (a)      1. and 2.   Financial Statements:

                  See index to Consolidated Financial Statements and
                  Supplemental Information in Item 8, which information is
                  incorporated herein by reference.

3. Exhibits

   (3)      Articles of Incorporation and by-laws.

            3.1 Certificate of Incorporation of Nuevo Energy Company
            (incorporated by reference to Exhibit 3.1 to Registration Statement
            on Form S-4 (No. 33-33873) filed under the Securities Act of 1933).

                                       67
<PAGE>

            3.2 By-laws of Nuevo Energy Company (incorporated by reference to
            Exhibit 3.2 to Registration Statement on Form S-4 (No. 33-33873)
            filed under the Securities Act of 1933).


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

            4.1 Specimen Stock Certificate (incorporated by reference to Exhibit
            4.1 to Registration Statement on Form S-4 (No. 33-33873) filed under
            the Securities Act of 1933).

            4.2 1990 Stock Option Plan of the Company, as amended (incorporated
            by reference from Exhibit 10.8 to Form S-1 dated July 13, 1992).

            4.3 Indenture dated July 24, 1992 among Nuevo Energy Company as
            Issuer, various Subsidiaries, as the Guarantors, and Ameritrust
            Texas National Association as the Trustee - 12 1/2% Senior
            Subordinated Notes due 2002. (Incorporated by reference from Form
            S-1 dated July 13, 1992).

            4.4 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).

            4.5 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. (Incorporated by reference from Exhibit 4.1 to Form 8-K
            filed on December 23, 1996).

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

            4.7 Form of First Supplemental Indenture dated December 23, 1996,
            between the Company and Wilmington Trust Company, as Indenture
            Trustee. (Incorporated by reference from exhibit 4.3 to Form 8-K
            filed on December 23, 1996).

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

            4.9 Form of Certificate representing TECONS. (Incorporated by
            reference from Exhibit 4.5 to Form 8-K filed on December 23, 1996)

            4.10 1993 Stock Incentive Plan, as amended (incorporated by
            reference to Exhibit 4.2 to Form S-8 (No. 333-21063) filed on
            February 4, 1997).

                                       68
<PAGE>
   (10)     Material Contracts.

            10.1 Joint Venture Agreement dated effective as of April 1, 1992,
            between Torch Energy Advisors Incorporated and JM Gas Company d/b/a/
            TriStar Gas Company (incorporated by reference from Exhibit 10.13 to
            Form S-1 dated July 13, 1992).

            10.2 Assignment of Interest and Assumption of Liabilities in NuStar
            Joint Venture, dated May 20, 1992, between Torch Energy Advisors
            Incorporated and Nuevo Liquids Inc. (incorporated by reference from
            Exhibit 10.14 to Form S-1 dated July 13, 1992).

            10.3 Purchase and sale agreement dated April 14, 1994 between Nuevo
            Energy Company, (Seller); and Beauregard Corporation (Buyer).
            (Incorporated by reference from Exhibit 10.1 to form 10-Q for the
            quarter ended June 30, 1994).

            10.4 First Additional Production Payment dated July 1, 1994, under
            the Purchase and Sale Agreement dated April 14, 1994 between Nuevo
            Energy Company as Seller, and Beauregard Corporation as Buyer.
            (Incorporated by reference from Exhibit 10.21 to Form 10-K for the
            year ended December 31, 1994.)

            10.5 Second Additional Production Payment dated December 15, 1994,
            under the Purchase and Sale Agreement dated as of April 14, 1994
            between Nuevo Energy Company, as Seller, and Beauregard Corporation
            as Buyer. (Incorporated by reference from Exhibit 10.22 to Form 10-K
            for the year ended December 31, 1994.)

            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"). (Incorporated by reference from 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. (Incorporated by reference from 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. (Incorporated by
            reference from 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. (Incorporated by
            reference from 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. (Incorporated by
            reference from Exhibit (2.5) to Form 8-K dated March 10, 1995).

                                       69
<PAGE>
            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. (Incorporated by reference from
            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. (Incorporated by reference
            from 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"). (Incorporated by reference from 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.
            (Incorporated by reference from 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. (Incorporated by reference from
            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. (Incorporated by reference from (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.
            (Incorporated by reference from 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. (Incorporated by reference form Exhibit (2.13) to
            Form 8-K dated March 10, 1995).

            10.19 Loan agreement dated April 1, 1996 between Nuevo Energy
            Company (Borrower) and certain subsidiaries and NationsBank of
            Texas, N.A. (Administrative Agent), Morgan Guaranty Trust Company of
            New York (Documentation Agent) and certain lenders. (Incorporated by
            reference from Exhibit 10.1 to Form S-3 (No. 333-1504).

            10.20 Warrant Certificate No. W-001 dated April 9, 1996 between
            Nuevo Energy Company and John Hall authorizing the purchase of
            120,000 shares of Nuevo Common Stock.

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

                                       70
<PAGE>
            10.22 Administrative Services Agreement among the Company and Torch
            Energy Advisors Incorporated as amended through January 1, 1996.

            10.23 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 (incorporated by
            reference from Exhibit 2.2 to Form S-3 (No. 333-1504)).


(22)  Subsidiaries of the Registrant

(23)  Consents of experts and counsel:

23.1  Consent of KPMG Peat Marwick LLP

(b)   Reports on Form 8-K:

      1. Report filed on Form 8-K on December 23, 1996 regarding the sale of
      2,300,000 shares of $2.875 Term Convertible Securities, Series A (TECONS).

                                       71
<PAGE>
                                   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 5, 1997                   By:/S/ MICHAEL D. WATFORD
                                                 Michael D. Watford
                                                 President, Chief Executive
                                                 Officer and Chief Operating
                                                 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/ J. P. BRYAN                     Date:   MARCH 5, 1997
          J.P. Bryan
          Chairman of the Board of 
          Directors

   By:/s/ ROBERT L. GERRY, III            Date:  MARCH 5, 1997
          Robert L. Gerry, III
          Director and Vice Chairman

   By:/s/ ROBERT M. KING                  Date:  MARCH 5, 1997
          Robert M. King
          Senior Vice President,
          Chief Financial Officer 
          (Principal Financial Officer)

   By:/s/ SANDRA KRAEMER                  Date:  MARCH 5, 1997
          Sandra Kraemer
          Controller (Principal 
          Accounting Officer)

   By:/s/ GARY R. PETERSEN                Date:  MARCH 5, 1997
          Gary R. Petersen
          Director

   By:/s/ THOMAS D. BARROW                Date:  MARCH 5, 1997
          Thomas D. Barrow
          Director

   By:/s/ JOHN B. CONNALLY, III           Date:  MARCH 5, 1997
          John B. Connally, III
          Director

   By:
          Isaac Arnold, Jr.
          Director

   By:/s/ JAMES T. HACKETT                Date:  MARCH 5, 1997
          James T. Hackett
          Director

   By:/s/ ROBERT H. ALLEN                 Date:  MARCH 5, 1997
          Robert H. Allen
          Director

   By:/s/ MICHAEL D. WATFORD              Date:  MARCH 5, 1997
          Michael D. Watford
          President, Chief 
          Executive Officer
         and Chief Operating Officer

   By:/s/ MICHAEL LONG                    Date:  MARCH 5, 1997
          Michael Long
          Director

                                       72