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, 2000
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________________ to _____________________
Commission File Number 1-10537
NUEVO ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Delaware 76-0304436
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1021 Main, Suite 2100, Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 652-0706
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Common Stock, par value $.01 per share New York Stock Exchange
$2.875 Term Convertible Securities, Series A New York Stock Exchange
Preferred Stock Purchase Rights 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 March 22, 2001, was approximately $291,326,805.
As of March 22, 2001, the number of outstanding shares of the registrant's
common stock was 16,505,768.
Documents Incorporated by Reference:
Portions of the registrant's annual proxy statement, to be filed within 120 days
after December 31, 2000, are incorporated by reference into Part III.
NUEVO ENERGY COMPANY
ANNUAL REPORT ON FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
TABLE OF CONTENTS
Page
Number
------
PART I
Item 1. Business........................................................................... 2
Item 2. Properties......................................................................... 14
Item 3. Legal Proceedings.................................................................. 22
Item 4. Submission of Matters to a Vote of Security Holders................................ 23
PART II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters.................................................. 24
Item 6. Selected Financial Data............................................................ 26
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations.............................................. 27
Item 7a. Quantitative and Qualitative Disclosures About Market Risk......................... 39
Item 8. Financial Statements and Supplementary Data........................................ 40
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.............................................. 71
PART III
Item 10. Directors and Executive Officers of the Registrant................................. 71
Item 11. Executive Compensation............................................................. 71
Item 12. Security Ownership of Certain Beneficial Owners and Management..................... 71
Item 13. Certain Relationships and Related Transactions..................................... 71
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.................... 71
Signatures
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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"),
Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") and the
Private Securities Litigation Reform Act of 1995. All statements other than
statements of historical facts included in this document, including without
limitation, statements 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. The Company can give no
assurances that the assumptions upon which such forward looking statements are
based will prove to be correct. Important factors that could cause actual
results to differ materially from the Company's expectations ("Cautionary
Statements") are set forth throughout 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 ("Nuevo") was formed as a Delaware corporation on March
2, 1990, to acquire the businesses of certain public and private partnerships
(collectively "Predecessor Partnerships"). On July 9, 1990, the plan of
consolidation ("Plan of Consolidation") was approved by limited partners owning
a majority of units of limited partner interests in the Predecessor
Partnerships. Such Plan of Consolidation provided for the exchange of the net
assets of the Predecessor Partnerships for common stock of Nuevo ("Common
Stock"). The Common Stock began trading on the New York Stock Exchange on July
10, 1990, under the symbol "NEV." All references to the "Company" include Nuevo
and its majority and wholly-owned subsidiaries, unless otherwise indicated or
the context indicates otherwise.
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 strategy to differentiate itself
from its numerous peer group competitors and to generate long term shareholder
value consists of: (i) a management philosophy that frames all important
decisions in terms of anticipated impact on per share (rather than absolute)
growth of reserves, production, cash flow and net asset value; (ii) a contrarian
investment and financing orientation, in which the Company seeks to purchase
assets during periods of industry weakness and sell assets during periods of
industry strength; (iii) the outsourcing of non-strategic functions; and (iv)
the alignment of employee compensation structures with shareholder objectives.
Nuevo is also committed to an exemplary corporate governance structure, which
reinforces management's overarching view that Nuevo should be a conduit for
shareholders to achieve superior long-term capital gains. All of Nuevo's
directors, other than the chief executive officer, are independent directors.
Nuevo's directors and executive officers each have made substantial equity
investments in Nuevo, in order to align their interests with that of the
Company's stockholders.
The Company accumulates oil and gas reserves through the drilling of
exploratory wells on acreage owned by or leased to the Company, or through the
purchase of reserves from others. The Company maximizes production from these
reserves through the drilling of developmental wells and through other
exploitative techniques. The Company also owns and operates gas plants and
other facilities, which are ancillary to the primary business of producing oil
and natural gas. The Company also owns certain surface real estate parcels in
California that are candidates for sale and/or development in future years.
Oil and Gas Activities
Since its inception in 1990, Nuevo has expanded its operations through a
series of disciplined, low-cost acquisitions of oil and gas properties and the
subsequent exploitation and development of these properties. The Company has
complemented these efforts with divestitures of non-core assets and an
opportunistic exploration program, which provides exposure to high potential
prospects. The Company's primary strengths are its large inventory of
exploitation projects in its core areas of operation which the Company believes
will support future growth in reserves and production per share; its ability to
identify and acquire, at attractive prices, long-lived
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NUEVO ENERGY COMPANY
producing properties which have significant potential for further exploration,
exploitation and development; a capital structure supportive of a growing
investment program and future acquisitions; and a price risk management policy
designed to protect the Company's ability to generate self-sustaining cash flow
and to meet the interest coverage tests under the Company's bond indentures.
During the five years ended December 31, 2000, the Company invested $594.7
million in six acquisitions that added estimated net proved reserves of 196.6
MMBBLS of oil and 171.1 BCF of natural gas and replaced 329% of its production
at an average cost of $3.32 per BOE.
Domestic Operations
As of December 31, 2000, the Company's estimated net U.S. proved reserves
totaled 224.4 MMBOE or 91% of Nuevo's total proved reserve base. During 2000,
the Company's domestic production was 18.1 MMBOE, or 91% of total production.
The majority of the Company's domestic properties are located in the state
of California, where the Company operates from an office in Bakersfield. The
Company's properties in California are categorized as either Onshore or
Offshore.
Nuevo's California onshore district operations encompass an estimated net
proved reserve base of 143.4 MMBOE as of December 31, 2000, and produced 11.0
MMBOE in 2000. The Company's main California onshore properties include the
Company's interests in the Cymric, Midway-Sunset and Belridge oil fields in the
Western San Joaquin Basin in Kern County, California, the Buena Vista Hills
field in the Southern San Joaquin Basin in Kern County and the Coalinga gas
field in the North San Joaquin Valley. Certain of the Company's onshore
properties utilize thermal operations to maximize current production and the
ultimate recovery of reserves. The Company owns a 100% working interest (88%
net revenue) in its properties in the Cymric field and the entire working
interest and an average net revenue interest of approximately 98% in its
properties in the Midway-Sunset field. Production is from several zones in the
Cymric field, including the Tulare, Diatomite and Point of Rocks formations and
the Antelope Shale. The Midway-Sunset field produces from five zones with the
Potter Sand and the thermal Diatomite accounting for the majority of the total
production. The productive zones of the Belridge field above 2,000 feet in
which the Company owns royalty interest are operated by another independent
energy company. The remaining deeper zones of the Belridge field are operated
and owned by the Company in fee with 100% working and net revenue interests.
The Company operates and owns a 100% working interest (79% net revenue) in the
Buena Vista Hills field. Production from this field is from the Etchegoin Sands
and the Antelope Shale. The Coalinga gas field is operated by Nuevo and the
Company owns an average 61% working interest (52% net revenue). Production is
from the Gatchell formation. The Company also operates three fee properties in
the Brea Olinda oil field in northern Orange County with a 100% working and net
revenue interest. The Company has royalty interests in additional wells in the
Brea Olinda field. Brea Olinda production is from multiple-pay zones in the
Miocene and Pliocene sandstones at depths up to 6,500 feet.
Nuevo's California offshore district operations encompass an estimated net
proved reserve base of 79.1 MMBOE as of December 31, 2000, and resulted in
production of 6.4 MMBOE in 2000. Nuevo's offshore district properties include
the Company's interests in the Point Pedernales, Dos and East Dos Cuadras,
Huntington Beach, Santa Clara and Belmont oil fields in federal OCS leases,
offshore Santa Barbara and Ventura Counties and Long Beach. The Company
acquired a 12% working interest (10% net revenue) in the Point Pedernales field
in July 1994 and an additional 68% working interest (57% net revenue) in the
field as part of the acquisition of the California properties in 1996. The
Point Pedernales field is operated by the Company, and is located 3.5 miles
offshore Santa Barbara County, California, in federal waters. Production is
from the Monterey Shale at depths from 3,500-5,150 feet. The Dos Cuadras and
East Dos Cuadras fields are located offshore five and one-half miles from Santa
Barbara in the Santa Barbara Channel. The Company operates three platforms with
a 50% working interest (42% net revenue) and another platform with a 67.5%
working interest (56% net revenue).
The Company also has properties located in the onshore Gulf Coast region,
which are operated from the Company's headquarters in Houston. Nuevo's Houston
district operations encompass an estimated net proved reserve base of 1.8 MMBOE
as of December 31, 2000, and produced 0.7 MMBOE in 2000. Houston district
properties include the Company's interests in the Giddings field in Grimes and
Austin Counties, Texas; and in the North Frisco City field in Monroe County,
Alabama. The Company owns an interest in 12 producing wells in the
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NUEVO ENERGY COMPANY
Giddings field and has an average 46.9% working (35.2% net revenue) interest in
these wells. The North Frisco City field is operated by Nuevo. Nuevo owns
approximately a 22% working (17% net revenue) interest in this field.
The Company continues to create value through domestic 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 1,200
domestic exploitation projects on existing properties, at a West Texas
Intermediate ("WTI") crude price of $24.86 per Bbl. Capital expenditures for
domestic exploitation projects totaled $91.3 million in 2000 and are currently
budgeted at approximately $105.0 million in 2001. Examples of current or
planned projects include the continuation of horizontal drilling in the onshore
district and infill drilling in the Cymric field to further exploit the
Diatomite formation.
The Company also has a program targeting exploration opportunities in
California. 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's exploration program resulted
in 11 successful wells and two dry wells in 2000.
Capital expenditures for domestic exploration activity totaled $5.3 million
in 2000 and are budgeted at approximately $15.0 million in 2001.
International Operations
As of December 31, 2000, the Company's estimated international net proved
reserves totaled 23.2 MMBOE, or 9% of Nuevo's total proved reserve base. During
2000, the Company's international production was 1.8 MMBOE, or 9% of Nuevo's
total production.
Congo: The Company's international reserves and production consist of a
50% working interest (37.5% average net revenue) in the Yombo and Masseko oil
fields located in the Marine 1 Permit offshore the Republic of Congo in West
Africa ("Congo"). Estimated net proved reserves of the Yombo and Masseko oil
fields as of December 31, 2000 were 23.2 MMBbl, and production during 2000
totaled 1.8 MMBbl, all from the Yombo field. In 2000, revenues relating to
production from the Yombo field accounted for approximately 12% of the total oil
and gas revenues for the Company. The properties are located 27 miles offshore
in approximately 370 feet of water. The Company also owns a 50% interest in a
converted super tanker with storage capacity of over one million barrels of oil
for use as a floating production, storage and off loading vessel ("FPSO"). The
Company's production is converted on the FPSO to No. 6 fuel oil with less than
0.3% sulfur content.
The Company's most significant international discovery in 1997 was the
Masseko M-4 well drilled on the Marine 1 Permit approximately six miles to the
northwest of the Yombo field. The Company drilled an exploration well to
evaluate the Lower Sendji and sub-salt sections underlying the Masseko
structure, as well as to further delineate the Upper Sendji and Tchala zones,
which were discovered but not developed by a previous operator. This well
tested at rates over 3,000 gross barrels per day from a newly discovered middle
Sendji section. Platform design and development plans are being formulated for
Masseko. Other potential exploration features are being evaluated for possible
future drilling. Additionally, the Company initiated a waterflood project in
the Yombo field to enhance production from existing Upper Sendji and Tchala
zones. Plans for 2001 include the continuation of horizontal drilling and the
waterflood project, as well as facility upgrades and pipeline replacements.
Ghana: In October 1997, Nuevo Ghana, Inc., ("Nuevo Ghana"), signed a
petroleum agreement with the Republic of Ghana in West Africa ("Ghana") and the
Ghana National Petroleum Corporation, ("GNPC") for petroleum rights covering 2.7
million acres offshore Ghana in the Accra-Keta prospect area. In November 2000,
the Company relinquished rights covering 800,000 acres under this agreement,
leaving rights covering 1.9 million acres. The Company is the operator of this
prospect and has a 50% participating interest. The exploration program for this
acreage has involved reprocessing existing seismic data, shooting additional
seismic and drilling an exploration well during the first phase of the
agreement.
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NUEVO ENERGY COMPANY
On February 16, 2000, the Company completed its acquisition and processing
of a 3-D seismic survey across the eastern portion of its Accra-Keta concession.
The Company's costs of the 3-D seismic survey acquisition and processing were
approximately $2.0 million. This survey extends from the outer shelf, across
the slope, and into the deepwater regions of the block. In October 2000, the
Company transferred a 25% participating interest in this permit to a large U.S.-
based independent oil and gas company. In January 2001, the Company added two
new partners, The Korean National Oil Corporation and SK Corporation, which
combined to acquire a 25% interest in the permit on a promoted basis. The
addition of these two new partners is subject to Ghanaian government approval.
Nuevo will continue to be the operator of the permit and will retain a 50%
participating interest. During January and February 2001, Nuevo drilled the NAK
#1 exploratory well in the Accra-Keta Permit. This well was located in
approximately 1,000 feet of water and was drilled to a total depth of 10,100
feet. The Company plugged and abandoned the NAK #1 well as a dry hole. Costs
to drill this well are expected to be approximately $12.5 million (approximately
$1.5 million net to Nuevo), and are expected to be incurred in the first quarter
of 2001. The Company plans to evaluate the NAK #1 well results during the
second quarter of 2001 in order to determine its future exploration plans in
this permit.
In February 2000, the Company relinquished its concession for petroleum
rights covering approximately 1.7 million acres in the East Cape Three Points
concession offshore Ghana. In September 1998, the Company plugged and abandoned
its first well in Ghana on the East Cape Three Points concession due to the lack
of commercial quantities of hydrocarbons. Dry hole costs and geological and
geophysical costs for this well (net to the Company) were $7.3 million and $1.6
million, respectively, in 1998.
Tunisia: In June 2000, the Company acquired interests in two exploration
permits in the Republic of Tunisia, North Africa, that added 1.3 million acres
to the Company's international portfolio. The first of these permits is the
171,000-acre (gross) Alyane Permit located offshore Tunisia in the Gulf of
Gabes. The Company will own a 100% participating interest and act as operator of
the block. The Convention and Joint Venture Agreement for the Alyane Permit call
for an initial term of four years, followed by two optional three-year terms.
Nuevo's work commitment requires shooting 3-D seismic and drilling one
exploratory well on the Alyane Permit in the initial term. The Company's
anticipated costs under this commitment are approximately $9.0 million. The
Company plans to explore the Alyane Permit aggressively and will acquire 3-D
seismic data in 2002 with the aim of drilling its first exploratory well in
2002. Nuevo anticipates formal government approval of the Convention and Joint
Venture Agreement in the second quarter of 2001.
Effective April 1, 2000, Nuevo acquired a 10.42% participating interest from
Bligh Tunisia Inc. in the 1.1-million-acre (gross) Anaguid Permit located
onshore southern Tunisia in the Ghadames Basin for approximately $1.5 million.
This permit is operated by Anadarko Petroleum Company. Under the current work
commitment, the partners must drill one exploration well on the Anaguid Permit
by December 2001. The Company's anticipated costs under this commitment are
approximately $1.3 million. In addition, the partners plan to reprocess all
existing seismic data and acquire new 2-D seismic data during 2001. Following
the expiration of the current work commitment term in December 2001, the final
renewal phase requires the drilling of one exploration well on the Anaguid
Permit during the 2 1/2-year term. Nuevo received government approval of this
acquisition in December 2000. The Company and its partners plan to drill a well
in the Anaguid Permit in late 2001, subject to rig availability.
In addition to acquiring its interests in the Anaguid and Alyane Permits,
Nuevo has, effective April 1, 2000, increased its existing 17.5% participating
interest in the 900,000-acre (gross) Fejaj Permit onshore Tunisia, North Africa,
by acquiring an additional 20% participating interest from Bligh Tunisia Inc.
Nuevo and its partners plan to re-enter and deepen the Chott Fejaj #3 well on
the Fejaj Permit to test a sub-salt prospect in 2001. The Company's anticipated
costs under this commitment are approximately $750,000. The current term of the
Fejaj Permit has been extended to April 2002. The Chott Fejaj #3 well was
drilled initially to the top of salt in December 1998, when it was temporarily
abandoned. Based on the Company's evaluation of the initial test results on this
well, the Company expensed $1.8 million of costs incurred as dry hole costs in
1998.
Canada: In May 2000, the Company acquired a 50% working interest (49.5% net
revenue) in 22,140 acres in Alberta, Canada. This project, Marten Hills, is a
heavy oil play that will require thermal operations in order to produce. Total
costs to acquire this interest were approximately $350,000. No significant
operating activity has occurred on this undeveloped acreage to date.
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NUEVO ENERGY COMPANY
General: Capital expenditures for 2000 international exploration and
development activity totaled $3.6 million and $4.7 million, respectively. The
Company's 2001 international exploration budget of approximately $9.0 million
includes the acquisition and processing of seismic data and the drilling of
three to four wells. International development plans for 2001 include the
continuation of the Company's waterflood program, facility upgrades and pipeline
replacements in the Congo and are currently budgeted at approximately $18.0
million.
The Company's international investments involve risks typically associated
with investments in emerging markets such as an uncertain political, economic,
legal and tax environment and expropriation and nationalization of assets. In
addition, if a dispute arises in 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 that the Company will
be successful in so protecting itself. A portion of the Company's investment in
the Congo is insured through political risk insurance provided by the Overseas
Private Investment Corporation ("OPIC"). See "Risk Factors".
Gas Plant and Other Facilities
The Company has owned and operated gas plants and other facilities, most of
which have been ancillary to the primary business of producing oil and natural
gas.
As of December 31, 2000, the Company owned two gas plants in California that
are strategic assets for the Company's oil and gas activities in California.
The Stearns Gas Plant is located in the Brea Olinda field and was processing 3.1
MMCFD at December 31, 2000. The HS&P Gas Plant is used to process gas production
from the Point Pedernales field. At December 31, 2000, the HS&P Gas Plant was
processing 1.3 MMCFD.
In December 1999, the Company sold the Santa Clara Valley Gas Plant, which is
located east of Ventura, California, in connection with the Company's sale of
its interest in the non-core properties onshore California.
In addition to the gas plants that process Company production, Nuevo has owned
certain non-core gas gathering, pipeline and storage assets. In December 1997,
the Company announced its intention to dispose of these non-core assets during
1998. The decision was made to dispose of these assets as they did not directly
contribute to the Company's core oil and gas operations. Such assets included:
the Company's 48.5% interest in the Richfield Gas Storage facility, which was
sold in February 1998 for proceeds of $2.1 million, an 80% interest in Bright
Star Gathering, Inc., which was sold in July 1998 for proceeds of $1.7 million,
and the Illini pipeline, which was sold in November 1999 for proceeds of $10.0
million. An agreement to sell the Illini Pipeline was reached in April 1998;
however, the approval of the sale was not received from the Illinois Commerce
Commission until November 1999. No gains or losses were recognized in
connection with these sales. The Company recorded a non-cash, pre-tax charge to
fourth quarter 1997 earnings of $23.9 million, reflecting the estimated loss on
the disposition of these assets. A positive revision to this charge was made in
the fourth quarter of 1998 in the amount of $3.7 million to reflect the
estimated current fair value of the Illini pipeline. The Company's results of
operations included the operating results from these assets through the
disposition date, as applicable. Such amounts were not significant relative to
total revenues and net operating results for the Company. These assets were not
depreciated subsequent to 1997.
On May 2, 1997, the Company sold its 95% interest in the NuStar Joint Venture,
which owned an interest in the Benedum natural gas processing plant, and an
interest in certain related assets and natural gas gathering systems located in
West Texas. The Company recognized a $2.3 million gain on this sale, which was
effective January 1, 1997.
Real Estate
In April 1996, along with its acquisition of certain California upstream oil
and gas properties from Union Oil Company of California ("Unocal") (see
"Acquisitions and Divestitures of Oil and Gas Properties"), the Company
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NUEVO ENERGY COMPANY
acquired tracts of land in Orange and Santa Barbara Counties in California, two
office buildings, one in Ventura County and one in Santa Barbara County, and
nearly 8,000 acres of agricultural property in the central valley of California.
As of December 31, 2000, there was $53.2 million of basis allocated to land. The
office buildings are included in other facilities at December 31, 2000.
Consistent with Nuevo's proactive asset management strategy, the Company
may, from time to time, sell certain of its surface real estate assets. The
Company expects to monetize a portion of its California real estate portfolio in
late 2001 or 2002. In 2000, the Company withdrew its entitlement application
for the Brea Highlands residential development from the City of Brea and
submitted the project, now named "Tonner Hills", to Orange County, which also
has jurisdiction over real estate development.
The agricultural land, primarily in Kings County, Fresno County and Kern
County, has surface leases for grazing or farming use, which are compatible with
the production of oil.
Acquisitions and Divestitures of Oil and Gas Properties
Consistent with its contrarian acquisition and divestiture strategy, Nuevo
has, from time to time, been an active participant in the market for oil and gas
properties. The Company attempts to purchase high growth assets which, for any
of a variety of reasons, are out of favor in the marketplace and hence available
for acquisition at attractive prices. From time to time, the Company also seeks
to divest itself of lower growth assets at times when those assets are valued
highly by the marketplace. Examples of this contrarian strategy are listed
below:
In May 2000, the Company sold its working interest in the Las Cienegas field
in California for proceeds of approximately $4.6 million. The Company
reclassified these assets to assets held for sale during the third quarter of
1999, at which time it discontinued depleting and depreciating these assets. No
impairment charge was recorded upon reclassification to assets held for sale.
On December 31, 1999, the Company completed the sale of its interests in 13
onshore fields and a gas processing plant located in Ventura County, California
for an adjusted sales price of $29.6 million. The effective date of the sale
was September 1, 1999. A portion of the proceeds, $4.5 million, was deposited
in escrow to address possible remediation issues. The funds will remain in
escrow until the Los Angeles Regional Water Quality Control Board approves
completion of the remediation work. All or any portion of the funds not used
in remediation shall be delivered to the Company. The remainder of the proceeds
from the sale were used to repay a portion of the Company's outstanding bank
debt.
In June 1999, the Company acquired oil and gas properties located onshore
and offshore California for $61.4 million from Texaco Inc ("Texaco"). To
purchase these assets, the Company used funds from a $100.0 million interest-
bearing escrow account that provided "like-kind exchange" tax treatment for the
purchase of domestic oil and gas producing properties. The escrow account was
created with proceeds from the Company's January 1999 sale of its East Texas
natural gas assets. Following the Texaco transaction, the $41.0 million
remaining in the escrow account, which included $2.4 million of interest income,
was used to repay a portion of outstanding bank debt in early July 1999. The
acquired properties had estimated net proved reserves at June 30, 1999, of 33.7
MMBOE and represent either additional interests in the Company's existing
properties or are located near its existing properties. The acquisition
included interests in Cymric, East Coalinga, Dos Cuadras, Buena Vista Hills and
other fields the Company operates.
On January 6, 1999, the Company completed the sale of its East Texas
natural gas assets to an affiliate of Samson Resources Company for an adjusted
sales price of approximately $191.0 million (see Note 4 to the Notes to
Consolidated Financial Statements). The Company realized an $80.2 million
adjusted pre-tax gain on the sale of these assets. A $5.2 million gain on
settled hedge transactions was also realized in connection with the closing of
this sale in 1999. The effective date of the sale was July 1, 1998. The
Company reclassified these assets to assets held for sale and discontinued
depleting these assets during the third quarter of 1998. Estimated net proved
reserves associated with these properties totaled approximately 329.0 BCF of
natural gas equivalent at January 1, 1999.
7
NUEVO ENERGY COMPANY
In April 1998, the Company acquired an additional working interest in the
Marine 1 Permit in the Congo for $7.8 million. This acquisition increased the
Company's net working interest in the Congo from 43.75% to 50.0%.
In July 1996, the Company completed the acquisition of certain East Texas oil
and gas properties, which added 31.2 BCF to the Company's reserve base, for a
net purchase price of $9.3 million in cash. The package consisted of interests
in 11 fields. In December 1996, the holders of the preferential rights on these
properties exercised such rights for a cash payment of $8.0 million, acquiring
properties constituting approximately half of the estimated proved reserves
related to this acquisition.
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 April 1996, the Company acquired certain upstream oil and gas properties
located onshore and offshore California ("Unocal Properties") from Unocal and
certain California oil properties ("Point Pedernales Properties" and, together
with the Unocal Properties, the "California Properties") from Torch Energy
Advisors Incorporated and certain of its wholly-owned subsidiaries ("Torch") for
a combined net purchase price of $525.9 million, plus a contingent payment based
on future realized oil prices.
Subsidiaries
The Company's domestic oil and gas operations are organized under Nuevo
Energy Company. The Company's oil and gas operations in the Congo are organized
under The Nuevo Congo Company and Nuevo Congo Ltd., both wholly-owned
subsidiaries of Nuevo. From time to time, the Company may set up a new wholly-
owned subsidiary for its international oil and gas operations. As of December
31, 2000, the Company did not have any significant operating activities under
any other subsidiary.
Industry Segment Information
For industry segment data (including foreign operations), see Note 10 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
("OPEC"), governmental regulation, political stability in the Middle East and
elsewhere, the foreign supply of oil and gas, the price of foreign oil imports
and the availability of alternate fuel sources. Any substantial and extended
decline in the price of oil 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. (See Note 14 to the Notes to Consolidated Financial
Statements.)
The price of natural gas and the threat of electrical disruptions are
factors that create volatility in the Company's California oil and gas
operations. Because of the recent developments in these commodities, Nuevo has
made significant changes in its natural gas disposition and electricity
production in California. Regarding natural gas, Nuevo has a net long position
in California - producing more natural gas than consumed in thermal crude
production. Moreover, as gas prices escalated in late 2000, Nuevo began to
exploit this gas position by diverting gas
8
NUEVO ENERGY COMPANY
consumed in uneconomic cyclic steaming operations to gas sales. In January and
February 2001, Nuevo sold an average of 19 MMcfd, or 44% of its total daily gas
production, which resulted in an increase in gas sales of 33%. This strategy
will remain as long as gas prices support sales over thermal oil production.
In California, Nuevo generates a total of 22.5 Megawatts ("MW") of power at
various sites. Two turbines came on-line at the Company's Brea Olinda field
using gas previously flared. Three turbines in Kern County produce 12 MW of
power and cogenerate 15% of Nuevo's total steam needs in thermal operation. By
self-generating power consumption in Kern County, Nuevo has reduced it exposure
to rising electricity prices. With the exception of the Point Pedernales field,
for which the Company has contracted for firm electric power service, Nuevo's
facilities receive power under interruptible service contracts. Considering the
fact that California is short of electricity and some Nuevo facilities receive
interruptible service, the Company could experience periodic power
interruptions. In addition, the State of California could change existing rules
or impose new rules or regulations with respect to power that could impact the
Company's operating costs.
Production of California San Joaquin Valley heavy oil (defined herein as
those fields which produce primarily 15(degrees) API quality crude oil or
heavier through thermal operations) constituted 51% of the Company's total 2000
crude output.
In addition, properties which produce primarily other grades of relatively
heavy oil (generally, 20o API or heavier, but produced through non-thermal
operations) constituted 32% of the Company's total 2000 crude output.
The market price for California heavy oil differs from the established market
indices for oil elsewhere in the U.S., due principally to the higher
transportation and refining costs associated with heavy oil.
In February 2000, the Company entered into a 15-year contract, effective
January 1, 2000, to sell all of its current and future California crude oil
production to Tosco Corporation. The contract provides pricing based on a fixed
percentage of the NYMEX crude oil price for each type of crude oil that Nuevo
produces in California. While the contract does not reduce the Company's
exposure to price volatility, it does effectively eliminate the basis
differential risk between the NYMEX price and the field price of the Company's
California oil production. In doing so, the contract makes it substantially
easier for the Company to hedge its realized prices. The Tosco contract permits
the Company, under certain circumstances, to separately market up to ten percent
of its California crude production. The Company exercised this right and,
effective January 1, 2001, began selling 5,000 BOPD of its San Joaquin Valley
oil production to a third party under a one-year contract containing NYMEX
pricing.
The Company's Yombo Field production in its Marine 1 Permit offshore the
Congo produces a relatively heavy crude oil (16-20(degrees) API gravity) which
is processed into a low-sulfur, No. 6 fuel oil product for sale to worldwide
markets. Production from this property constituted 9% of the Company's total
2000 output. The market for residual fuel oil differs from the markets for WTI
and other benchmark crudes due to its primary use as an industrial or utility
fuel versus the higher value transportation fuel component, which is produced
from refining most grades of crude oil.
Sales to Tosco Corporation accounted for 84%, 79% and 60% of 2000, 1999 and
1998 oil and gas revenues, respectively. Sales to Torch Energy Marketing
accounted for 11%, 12% and 10% of 2000, 1999 and 1998 oil and gas revenues,
respectively. The loss of any single significant customer or contract could
have a material adverse short-term effect on the Company; however, management of
the Company does not believe that the loss of any single significant customer or
contract would materially affect its business in the long-term.
9
NUEVO ENERGY COMPANY
Regulation
Oil and Gas Regulation
The availability of a ready market for 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 and transportation, as well as
regulations governing environmental quality and pollution control, state limits
on allowable rates of production by a well or proration unit, the amount of oil
and gas available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
For example, a productive gas well may be "shut-in" because of an over-supply of
gas or lack of an available gas pipeline in the areas in which 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.
The Company's sales of natural gas are affected by the availability, terms
and costs of transportation. The rates, terms and conditions applicable to the
interstate transportation of gas by pipelines are regulated by the Federal
Energy Regulatory Commission ("FERC") under the Natural Gas Acts, as well as
under Section 311 of the Natural Gas Policy Act. Since 1985, the FERC has
implemented regulations intended to increase competition within the gas industry
by making gas transportation more accessible to gas buyers and sellers on an
open-access, non-discriminatory basis.
The Company's sales of oil are also affected by the availability, terms and
costs of transportation. The rates, terms, and conditions applicable to the
interstate transportation of oil by pipelines are regulated by the FERC under
the Interstate Commerce Act. In this connection, FERC has implemented a
simplified and generally applicable ratemaking methodology for interstate oil
pipelines to fulfill the requirements of Title VIII of the Energy Policy Act of
1992 comprised of an indexing system to establish ceilings on interstate oil
pipeline rates. The FERC has announced several important transportation-related
policy statements and rule changes, including a statement of policy and final
rule issued February 25, 2000 concerning alternatives to its traditional cost-
of-service rate-making methodology to establish the rates interstate pipelines
may charge for their services. The final rule revises FERC's pricing policy and
current regulatory framework to improve the efficiency of the market and further
enhance competition in natural gas markets.
With respect to transportation of natural gas on or across the Outer
Continental Shelf ("OCS"), the FERC requires, as a part of its regulation under
the Outer Continental Shelf Lands Act ("OCSLA"), that all pipelines provide open
and non-discriminatory access to both owner and non-owner shippers. Although to
date the FERC has imposed light-handed regulation on offshore facilities that
meet its traditional test of gathering status, it has the authority to exercise
jurisdiction under the OCSLA over gathering facilities, if necessary, to permit
non-discriminatory access to service. For those facilities transporting natural
gas across the OCS that are not considered to be gathering facilities, the
rates, terms and conditions applicable to this transportation are regulated by
FERC under the NGA and NGPA, as well as the OCSLA. With respect to the
transportation of oil and condensate on or across the OCS, the FERC requires, as
part of its regulation under the OCSLA, that all pipelines provide open and non-
discriminatory access to both owner and non-owner shippers. Accordingly, the
FERC has the authority to exercise jurisdiction under the OCSLA, if necessary,
to permit non-discriminatory access to service.
In the event the Company conducts operations on federal, state or Indian
oil and gas leases, such operations must comply with numerous regulatory
restrictions, including various nondiscrimination statutes, royalty and related
valuation requirements, and certain of such operations must be conducted
pursuant to certain on-site security regulations and other appropriate permits
issued by the Bureau of Land Management ("BLM") or Minerals Management Service
("MMS") or other appropriate federal or state agencies.
The Company's OCS leases in federal waters are administered by the MMS and
require compliance with detailed MMS regulations and orders. The MMS has
promulgated regulations implementing restrictions on various production-related
activities, including restricting the flaring or venting of natural gas. Under
certain circumstances,
10
NUEVO ENERGY COMPANY
the MMS may require any Company operations on federal leases to be suspended or
terminated. Any such suspension or termination could materially and adversely
affect the Company's financial condition and operations. On March 15, 2000, the
MMS issued a final rule effective June 1, 2000, that amends its regulations
governing the calculation of royalties and the valuation of crude oil produced
from federal leases. Among other matters, this rule amends the valuation
procedure for the sale of federal royalty oil by eliminating posted prices as a
measure of value and relying instead on arm's length sales prices and spot
market prices as market value indicators. Because the Company generally sells
its production to third parties and therefore pays royalties on production from
federal leases, it is not anticipated that this final rule will have any
substantial impact on the Company.
The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or
indirect ownership of any interest in federal onshore oil and gas leases by a
foreign citizen of a country that denies "similar or like privileges" to
citizens of the United States. Such restrictions on citizens of a "non-
reciprocal" country include ownership or holding or controlling stock in a
corporation that holds a federal onshore oil and gas lease. If this restriction
is violated, the corporation's lease can be canceled in a proceeding instituted
by the United States Attorney General. Although the regulations of the BLM
(which administers the Mineral Act) provide for agency designations of non-
reciprocal countries, there are presently no such designations in effect. The
Company owns interest in numerous federal onshore oil and gas leases. It is
possible that holders of equity interests in the Company may be citizens of
foreign countries, which at some time in the future might be determined to be
non-reciprocal under the Mineral Act.
The Company's pipelines used to gather and transport its oil and gas are
subject to regulation by the Department of Transportation ("DOT") under the
Hazardous Liquids Pipeline Safety Act of 1979, as amended ("HLPSA") relating to
the design, installation, testing, construction, operation, replacement and
management of pipeline facilities. The HLPSA requires the Company and other
pipeline operators to comply with regulations issued pursuant to HLPSA designed
to permit access to and allowing copying of records and to make certain reports
and provide information as required by the Secretary of Transportation.
The Pipeline Safety Act of 1992 (The "Pipeline Safety Act") amends the
HLPSA in several important respects. It requires the Research and Special
Programs Administration ("RSPA") of DOT to consider environmental impacts, as
well as its traditional public safety mandate, when developing pipeline safety
regulations. In addition, the Pipeline Safety Act mandates the establishment by
DOT of pipeline operator qualification rules requiring minimum training
requirements for operators, and requires that pipeline operators provide maps
and records to RSPA. It also authorizes RSPA to require certain pipeline
modifications as well as operational and maintenance changes. The Company
believes its pipelines are in substantial compliance with all HLPSA and the
Pipeline Safety Act. Nonetheless, significant expenses would be incurred if new
or additional safety measures are required.
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 governing 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"), the DOT and the FERC. 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.
With respect to the Company's offshore oil and gas operations in California,
the Company has significant exit cost liabilities. These liabilities include
costs for dismantlement, rehabilitation and abandonment. As of December 31,
2000, the Company's net liability for these exit costs was approximately $82.1
million. The Company is not indemnified for any part of these exit costs.
11
NUEVO ENERGY COMPANY
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 nonhazadous
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 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 Predecessor
Partnerships 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 certain duties and liabilities on "responsible parties"
related to the prevention of oil spills and 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.
The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. Certain amendments to the OPA that were enacted in 1996 require owners
and operators of offshore facilities that have a worst case oil spill potential
of more than 1,000 barrels to demonstrate financial responsibility in amounts
ranging from $10 million in specified state waters and $35 million in federal
OCS waters, with higher amounts, up to $150 million based upon worst case oil-
spill discharge
12
NUEVO ENERGY COMPANY
volume calculations. The Company believes that it currently has established
adequate proof of financial responsibility for its offshore facilities.
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 that 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. The Company competes
with these competitors to acquire producing properties, exploration leases,
licenses, concessions and marketing agreements.
Personnel
At December 31, 2000, the Company employed 67 full time employees who
represent the executive officers and key operating, exploration, financial and
accounting management. The Company outsources certain administrative and
operational functions to third-party service providers, which maintain large
technical, operating, accounting and/or administrative staff to provide services
to Nuevo and other clients. (See Note 5 to the Notes to Consolidated Financial
Statements).
In a move designed to further streamline operations, improve performance
and reduce costs, Nuevo brought in-house key operations and environmental safety
and regulatory compliance functions. Effective January 1, 2001, Nuevo hired
approximately 43 professionals in California for positions in drilling,
production engineering and supervision, operations and facilities management,
environmental safety and regulatory compliance and procurement. Under this new
organizational structure, Nuevo currently outsources only direct field
operations and certain administrative functions. All other operating and
management functions related to Nuevo's oil and gas operations are now performed
by Nuevo employees. As a result of this hiring process, Nuevo now has
approximately 110 employees located in its offices in Houston, Texas, and
Bakersfield and Orcutt, California.
13
NUEVO ENERGY COMPANY
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, Alabama, and offshore Congo, West Africa; undeveloped acreage
is located primarily in California, Texas, Congo, Ghana and Tunisia. Estimated
proved oil and gas reserves at December 31, 2000 decreased approximately 14%
since December 31, 1999, primarily as a result of price revisions relating to
extremely high natural gas prices which adversely affect thermal oil producing
property reserves. The estimates are based on realized prices at year-end 2000,
of $19.51 per Bbl and $13.94 per Mcf, and are adjusted for the effects of
contractual agreements with Unocal and Amoco in connection with the California
and Congo property acquisitions. (See Notes 13 and 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, 2000,
which relates to the Company's principal oil and gas properties:
Net Proved Reserves (SEC)
December 31, 2000 2000 Production
----------------------------- --------------------------
Gross Oil* Gas Oil* Gas PV-10**
Wells (Mbbls) (Mmcf) MBOE (Mbbls) (Mmcf) MBOE (000's)
----- -------- -------- ------- ------- ------- ------ ------------
U.S. PROPERTIES
California Fields
Cymric........................ 458 50,531 7,436 51,771 4,982 746 5,107 $ 140,591
Brea Olinda................... 220 32,747 22,361 36,474 790 209 825 157,535
Santa Clara................... 23 18,579 36,763 24,707 742 510 827 224,625
Midway-Sunset................. 364 18,561 -- 18,561 2,497 -- 2,497 48,055
Dos Cuadras................... 95 14,593 12,121 16,613 759 573 854 114,252
Belridge...................... 329 15,899 1,205 16,100 859 220 896 43,154
Point Pedernales.............. 12 14,334 4,620 15,104 1,867 412 1,935 77,563
Pitas Point................... 9 -- 23,352 3,891 -- 3,863 644 223,222
Buena Vista................... 194 2,640 23,208 6,508 180 1,547 438 106,415
Other......................... 439 28,375 26,524 32,795 2,673 4,452 3,415 321,648
----- ------- ------- ------- ------ ------ ------ ----------
Total California Fields...... 2,143 196,259 157,590 222,524 15,349 12,532 17,438 1,457,060
----- ------- ------- ------- ------ ------ ------ ----------
Other U.S. Fields
Other U.S. Fields............. 42 433 8,387 1,831 242 2,683 689 53,543
----- ------- ------- ------- ------ ------ ------ ----------
Total U.S. Properties........ 2,185 196,692 165,977 224,355 15,591 15,215 18,127 1,510,603
----- ------- ------- ------- ------ ------ ------ ----------
FOREIGN PROPERTIES
Yombo, Congo.................. 31 14,921 -- 14,921 1,843 -- 1,843 105,922
Masseko, Congo................ -- 8,281 -- 8,281 -- -- -- 32,689
----- ------- ------- ------- ------ ------ ------ ----------
Total Foreign Properties 31 23,202 -- 23,202 1,843 -- 1,843 138,611
----- ------- ------- ------- ------ ------ ------ ----------
Unocal contingent payment...... -- -- -- -- -- -- -- (52,609)
----- ------- ------- ------- ------ ------ ------ ----------
TOTAL PROPERTIES 2,216 219,894 165,977 247,557 17,434 15,215 19,970 $1,596,605
===== ======= ======= ======= ====== ====== ====== ==========
---------------
* includes natural gas liquids
** pre-tax
In addition to the information presented in the above table, the Company had
entered into swap arrangements on a portion of its future crude production as of
December 31, 2000 (see Note 12 to the Notes to Consolidated Financial
Statements). The effects of these hedges would decrease the PV-10 by
approximately $39.3 million.
14
NUEVO ENERGY COMPANY
The summary of SEC reserves, which is presented on the previous page, is
computed based on realized prices at December 31, 2000, held constant over time
(see Note 14 to the Notes to Consolidated Financial Statements). Oil and gas
prices at December 31, 2000, were high compared to historical levels.
Management believes that the following reserve information, which reflects
fluctuating commodity pricing based on market information available at year-end,
is more consistent with management's belief that the current oil and gas prices
will revert to long-term historical averages. The following table sets forth
this alternative reserve information as of December 31, 2000 (based on forward
NYMEX price strips at December 31, 2000, beginning with $24.86 per Bbl and $6.19
per Mcf in 2001, and ending with $18.73 per Bbl and $3.58 per Mcf in 2015).
Because the prices used in the following table are lower than the year-end
prices Nuevo received for its production, the following does not represent
information attributable to "proved reserves" as defined by the SEC.
Estimated Market Case
December 31, 2000
------------------------------------------------
Oil* Gas PV-10**
(Mbbls) (Mmcf) MBOE (000's)
------------- -------------- --------------- ---------------
U.S. PROPERTIES
California Fields
Cymric...................................... 88,888 7,436 90,127 $ 338,959
Brea Olinda................................. 32,583 22,361 36,310 91,135
Midway-Sunset............................... 30,117 -- 30,117 116,798
Santa Clara................................. 16,543 32,108 21,894 59,063
Belridge.................................... 18,021 1,143 18,212 99,880
Dos Cuadras................................. 12,164 9,408 13,732 37,617
Point Pedernales............................ 12,691 3,864 13,335 30,525
Other....................................... 24,383 64,142 35,074 175,681
------- ------- ------- ----------
Total California Fields.................... 235,390 140,462 258,801 949,658
------- ------- ------- ----------
Other U.S. Fields
Other U.S. Fields........................... 417 8,077 1,763 24,068
------- ------- ------- ----------
Total U.S. Properties...................... 235,807 148,539 260,564 973,726
------- ------- ------- ----------
FOREIGN PROPERTIES
Yombo, Congo................................ 14,869 -- 14,869 70,874
Masseko, Congo.............................. 8,123 -- 8,123 22,342
------- ------- ------- ----------
Total Foreign Properties 22,992 -- 22,992 93,216
------- ------- ------- ----------
Unocal contingent payment.................... -- -- -- (16,068)
------- ------- ------- ----------
TOTAL PROPERTIES 258,799 148,539 283,556 $1,050,874
======= ======= ======= ==========
---------------
* includes natural gas liquids
** pre-tax
In addition to the information presented in the above table, the Company had
entered into swap arrangements on a portion of its future crude production as of
December 31, 2000 (see Note 12 to the Notes to Consolidated Financial
Statements). The effects of these hedges would decrease the PV-10 by
approximately $19.6 million.
15
NUEVO ENERGY COMPANY
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, 2000.
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
the Company's fractional ownership of working interests in gross acres equals
one.
Gross Net
------------- --------------
Developed Acreage 206,321 122,435
Undeveloped Acreage 4,416,134 1,739,944
--------- ---------
Total 4,622,455 1,862,379
========= =========
The following table sets forth the Company's undeveloped acreage as of
December 31, 2000:
Gross Net
------------- --------------
California 245,029 121,195
Texas 24,023 7,379
Alberta, Canada 22,140 11,070
Congo, West Africa:
Marine 1 Permit 38,000 19,000
Ghana, West Africa:
Accra-Keta 1,900,000 950,000
Tunisia, North Africa 2,171,000 623,120
Other 15,942 8,180
--------- ---------
Total 4,416,134 1,739,944
========= =========
Productive Wells
The following table sets forth the Company's gross and net interests in
productive oil and gas wells as of December 31, 2000. Productive wells are
producing wells and wells capable of production.
Gross Net
---------- ----------
Oil Wells 2,072 1,705
Gas Wells 144 80
----- -----
Total 2,216 1,785
===== =====
Production
The Company's principal production volumes for the year ended December 31,
2000, were from California and offshore Congo.
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, 2000, the Company's principal
drilling activities occurred in the continental United States and offshore in
state and federal waters, and offshore the Congo in West Africa.
16
NUEVO ENERGY COMPANY
The Company believes that its demonstrated ability to reduce operating costs
to levels well below those of the larger oil and gas companies from which
acquisitions have been made allows it to compete successfully in an industry
characterized by fluctuating commodity prices.
As of December 31, 2000, the Company had drilled 360 wells in the Cymric
field in central California, which contained 21% of the Company's total
estimated net proved equivalent reserves at December 31, 2000, and anticipates
drilling approximately 30 wells in the Cymric field during 2001. In the Midway-
Sunset field in central California, which contained 7% of the total estimated
net proved equivalent reserves at December 31, 2000, the Company drilled 40
wells during 2000, and plans to defer future development in this field until
2002. In the Belridge field in central California, which contained 7% of the
total estimated net proved equivalent reserves at December 31, 2000, the Company
drilled 20 wells during 2000, and plans to drill approximately 9 wells in 2001.
In 1999, the Company initiated a waterflood project in the Yombo field
offshore Congo to enhance production from existing Upper Sendji and Tchala
zones. The Company continued its development drilling program in the Yombo
field during 2000 and repaired a pipeline from one of its platforms. Plans for
2001 include the drilling of three to four development wells, expansion of the
waterflood program and replacing pipelines from the two platforms.
The Company's most significant discovery in 2000 was the 701 well on its Star
Fee lease in the Cymric Field in California, which was acquired from Texaco in
1999. The Star Fee 701 deep well tested at a rate of over 900 BOPD and 1.2
million cubic feet of gas per day, and has already produced over 216 equivalent
barrels since August 2000. The Company owns a 100% working and net revenue
interest in this well, which is currently producing at rates over 660 BOPD. As
a result of this success, additional exploratory wells have been scheduled for
drilling in 2001 to further test the deep geologic model. The Company's most
significant discoveries in 1998 were: (i) four successful wells at Four Isle
Dome in Louisiana, which helped increase net production from 0.6 MMCFPD and 35
BOPD at the beginning of 1998 to 7.9 MMCFPD and 170 BOPD at the end of 1998;
(ii) two successful wells at Weeks Island, Louisiana, which each resulted in
completions producing in excess of 700 BOPD (the Company's interest in Weeks
Island was sold in 1999); and (iii) successful extension to the south and east
at the Monument Junction reservoir in the Cymric Field in California.
The Company had two gross (two net) wells in progress at December 31, 2000.
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
------------- ------------ ------------ ------------- ------------ -------------
1998 8 6 14 4.09 3.58 7.67
1999 -- 4 4 -- 2.33 2.33
2000 11 2 13 11 1.45 12.45
Development Wells
--------------------------------------------------------------------------------------------------
Gross Net
-------------------------------------------- -----------------------------------------------
Dry Dry
Productive Holes Total Productive Holes Total
------------- ------------ ------------ ------------- ------------ -------------
1998 155 -- 155 134.43 -- 134.43
1999 44 1 45 40.21 0.33 40.54
2000 175 3 178 173.25 2.68 175.93
17
NUEVO ENERGY COMPANY
Exit Cost Liabilities
With respect to the Company's offshore oil and gas operations in California,
the Company has significant exit cost liabilities. These liabilities include
costs for dismantlement, rehabilitation and abandonment. As of December 31,
2000, the Company's net liability for these exit costs was approximately $82.1
million. The Company is not indemnified for any part of these exit costs.
Gas Plant, Pipelines and Other Facilities
As of December 31, 2000, the Company owned interests in the following gas
plant facilities:
2000
Capacity Throughput Ownership
Facility State Operator MMCFD MMCFD Interest
-------------------- ------------ --------------------- ---------------- ---------------- ----------------
Stearns Gas Plant California Nuevo Energy Company 5 3.2 100%
HS&P Gas Plant California Nuevo Energy Company 13 3.1 80%
Risk Factors
Volatility of Oil and Gas Prices
Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond the control of the
Company. These factors include weather conditions in the United States, the
condition of the United States economy, the actions of OPEC, governmental
regulation, political stability in the Middle East and elsewhere, the foreign
supply of oil and gas, the price of foreign oil imports and the availability of
alternate fuel sources. Any substantial and extended decline in the price of
oil 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.
Volatile oil and gas prices make it difficult to estimate the value of
producing properties for acquisition and divestiture and often cause disruption
in the market for oil and gas producing properties, as buyers and sellers have
difficulty agreeing on such value. Price volatility also makes it difficult to
budget for and project the return on acquisitions and development and
exploitation projects.
Pricing of Heavy Oil Production
A portion of the Company's production is California heavy oil. The market
price for California heavy oil differs substantially from the established market
indices for oil and gas, due principally to the higher transportation and
refining costs associated with heavy oil. As a result, the price received for
heavy oil is generally lower than the price for medium and light oil, and the
production costs associated with heavy oil are relatively higher than for
lighter grades. The margin (sales price minus production costs) on heavy oil
sales is generally less than for lighter oil, and the effect of material price
decreases will more adversely affect the profitability of heavy oil production
compared with lighter grades of oil. (See "Hedging" below for discussion of 15-
year crude oil contract).
Reserve Replacement Risks
The Company's future performance depends upon its ability to find, develop
and acquire additional oil and gas reserves that are economically recoverable.
Without successful exploration, exploitation or acquisition activities, the
Company's reserves and revenues will decline. No assurances can be given that
the Company will be able to find and develop or acquire additional reserves at
an acceptable cost.
18
NUEVO ENERGY COMPANY
The successful acquisition and development of oil and gas properties requires
an assessment of recoverable reserves, future oil and gas prices and operating
costs, potential environmental and other liabilities and other factors. Such
assessments are necessarily inexact and their accuracy inherently uncertain. In
addition, no assurances can be given that the Company's exploitation and
development activities will result in any increase in reserves. The Company's
operations may be curtailed, delayed or canceled as a result of lack of adequate
capital and other factors, such as title problems, weather, compliance with
governmental regulations or price controls, mechanical difficulties or shortages
or delays in the delivery of equipment. In addition, the costs of exploitation
and development may materially exceed initial estimates.
Substantial Capital Requirements
The Company makes, and will continue to make, substantial capital
expenditures for the exploitation, exploration, acquisition and production of
oil and gas reserves. Historically, the Company has financed these expenditures
primarily with cash generated by operations, proceeds from bank borrowings and
the proceeds of debt and equity issuances. The Company believes that it will
have sufficient cash provided by operating activities and borrowings under its
bank credit facility to fund planned capital expenditures. If revenues or the
Company's borrowing base decreases as a result of lower oil and gas prices,
operating difficulties or declines in reserves, the Company may have limited
ability to expend the capital necessary to undertake or complete future drilling
programs. There can be no assurance that additional debt or equity financing or
cash generated by operations will be available to meet these requirements.
Uncertainty of Estimates of Reserves and Future Net Cash Flows
Estimates of economically recoverable oil and gas reserves and of future net
cash flows are based upon a number of variable factors and assumptions, all of
which are to some degree speculative and may vary considerably from actual
results. Therefore, actual production, revenues, taxes, and development and
operating expenditures may not occur as estimated. Future results of operations
of the Company will depend upon its ability to develop, produce and sell its oil
and gas reserves. The reserve data included herein are estimates only and are
subject to many uncertainties. Actual quantities of oil and gas may differ
considerably from the amounts set forth herein. In addition, different reserve
engineers may make different estimates of reserve quantities and cash flows
based upon the same available data.
Operating Risks
Nuevo's operations are subject to risks inherent in the oil and gas industry,
such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or
well fluids, fires, pollution, earthquakes and other environmental risks. These
risks could result in substantial losses to the Company due to injury and loss
of life, severe damage to and destruction of property and equipment, pollution
and other environmental damage and suspension of operations. Moreover, offshore
operations are subject to a variety of operating risks peculiar to the marine
environment, such as hurricanes or other adverse weather conditions, to more
extensive governmental regulation, including regulations that may, in certain
circumstances, impose strict liability for pollution damage, and to interruption
or termination of operations by governmental authorities based on environmental
or other considerations. The Company's operations could result in liability for
personal injuries, property damage, oil spills, discharge of hazardous
materials, remediation and clean-up costs and other environmental damages. The
Company could be liable for environmental damages caused by previous property
owners. As a result, substantial liabilities to third parties or governmental
entities may be incurred, the payment of which could have a material adverse
effect on the Company's financial condition and results of operations. The
Company maintains insurance coverage for its operations, including limited
coverage for sudden environmental damages and for existing contamination, but
does not believe that insurance coverage for environmental damages that occur
over time is available at a reasonable cost. Moreover, the Company does not
believe that insurance coverage for the full potential liability that could be
caused by sudden environmental damages is available at a reasonable cost.
Accordingly, the Company may be subject to liability or may lose substantial
portions of its properties in the event of certain environmental damages.
19
NUEVO ENERGY COMPANY
California Natural Gas and Electricity Markets
The price of natural gas and the threat of electrical disruptions are
factors that create volatility in the Company's California oil and gas
operations. Because of the recent developments in these commodities, Nuevo has
made significant changes in its natural gas disposition and electricity
production in California. Regarding natural gas, Nuevo has a net long position
in California - producing more natural gas than consumed in thermal crude
production. Moreover, as gas prices escalated in late 2000, Nuevo began to
exploit this gas position by diverting gas consumed in uneconomic cyclic
steaming operations to gas sales. In January and February 2001, Nuevo sold an
average of 19 MMcfd, or 44% of its total daily gas production, which resulted in
an increase in gas sales of 33%. This strategy will remain as long as gas
prices support sales over thermal oil production.
In California, Nuevo generates a total of 22.5 Megawatts ("MW") of power at
various sites. Two turbines came on-line at the Company's Brea Olinda field
using gas previously flared. Three turbines in Kern County produce 12 MW of
power and cogenerate 15% of Nuevo's total steam needs in thermal operation. By
self-generating power consumption in Kern County, Nuevo has reduced it exposure
to rising electricity prices. With the exception of the Point Pedernales field,
for which the Company has contracted for firm electric power service, Nuevo's
facilities receive power under interruptible service contracts. Considering the
fact that California is short of electricity and some Nuevo facilities receive
interruptible service, the Company could experience periodic power
interruptions. In addition, the State of California could change existing rules
or impose new rules or regulations with respect to power that could impact the
Company's operating costs.
Foreign Investments
The Company's foreign investments involve risks typically associated with
investments in emerging markets such as uncertain political, economic, legal and
tax environments and expropriation and nationalization of assets. 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 protecting against such risks.
The Company's international assets and operations are subject to various
political, economic and other uncertainties, including, among other things, the
risks of war, expropriation, nationalization, renegotiation or nullification of
existing contracts, taxation policies, foreign exchange restrictions, changing
political conditions, international monetary fluctuations, currency controls and
foreign governmental regulations that favor or require the awarding of drilling
contracts to local contractors or require foreign contractors to employ citizens
of, or purchase supplies from, a particular jurisdiction. In addition, if a
dispute arises with foreign operations, the Company may be subject to the
exclusive jurisdiction of foreign courts or may not be successful in subjecting
foreign persons, especially foreign oil ministries and national oil companies,
to the jurisdiction of the United States.
The Company's private ownership of oil and gas reserves under oil and gas
leases in the United States differs distinctly from its ownership of foreign oil
and gas properties. In the foreign countries in which the Company does
business, the state generally retains ownership of the minerals and consequently
retains control of (and in many cases, participates in) the exploration and
production of hydrocarbon reserves. Accordingly, operations outside the United
States, and estimates of reserves attributable to properties located outside the
United States, may be materially affected by host governments through royalty
payments, export taxes and regulations, surcharges, value added taxes,
production bonuses and other charges.
Hedging
During 1999, the Company formalized its policies regarding the management of
price risk to ensure the Company's ability to optimally manage its portfolio of
investment opportunities. In a typical swap transaction, the Company will have
the right to receive from the counterparty to the hedge the excess of the fixed
price specified in the hedge contract and a floating price based on a market
index, multiplied by the quantity hedged. If the floating price exceeds the
fixed price, the Company is required to pay the counterparty the difference.
The Company would be required to pay the counterparty the difference between
such prices regardless of whether the Company's
20
NUEVO ENERGY COMPANY
production was sufficient to cover the quantities specified in the hedge. In
addition, the index used to calculate the floating price in a hedge is
frequently not the same as the prices actually received for the production
hedged. The difference (referred to as basis differential) may be material, and
may reduce the benefit or increase the detriment caused by a particular hedge.
There is not an established pricing index for hedges of California heavy crude
oil production, and the cash market for heavy oil production in California tends
to vary widely from index prices typically used in oil hedges. Consequently,
prior to 2000, hedging California heavy crude oil was particularly subject to
the risks associated with volatile basis differentials. In February 2000, the
Company entered into a 15-year contract, effective January 1, 2000, to sell
substantially all of its current and future California crude oil production to
Tosco Corporation. The contract provides pricing based on a fixed percentage of
the NYMEX crude oil price for each type of crude oil that Nuevo produces in
California. Therefore, the actual price received as a percentage of NYMEX will
vary with the Company's production mix. Based on the Company's current
production mix, the price received by Nuevo for its California oil production is
expected to average approximately 72% of WTI. While the contract does not reduce
the Company's exposure to price volatility, it does effectively eliminate the
basis differential risk between the NYMEX price and the field price of the
Company's California oil production, thereby facilitating Nuevo's ability to
hedge its realized prices.
As a result of hedging transactions, oil and gas revenues were reduced by
$117.7 million and $44.9 million in 2000 and 1999, respectively, and increased
by $0.6 million in 1998. For 2001, the Company has entered into swap
arrangements on 26,000 BOPD for the first quarter at an average WTI price of
$19.52, for the second quarter on 25,000 BOPD at an average WTI price of $19.54,
for the third quarter on 20,000 BOPD at an average WTI price of $21.22, and for
the fourth quarter on 15,500 BOPD at an average WTI price of $22.95 per barrel.
Subsequent to December 31, 2000, the Company entered into swaps on an additional
1,200 BOPD for the second quarter, bringing the total to 26,200 BOPD at an
average price of $19.84 per barrel. On a physical volume basis, these hedges
cover 47% of the Company's estimated 2001 oil production. At December 31, 2000,
the market value of the swaps in place for 2001 was a loss of $35.1 million. For
2002, the Company has entered into swap arrangements on 12,500 BOPD for the
first quarter at an average WTI price of $25.91 per barrel. For the remainder
of 2002, the Company purchased put options with a WTI strike price of $22.00 per
barrel, on 19,000 BOPD for the second quarter, and on 14,000 BOPD for both the
third and fourth quarters. At December 31, 2000, the market value of the 2002
hedge positions is a gain of $8.3 million. See Item 7a. "Quantitative and
Qualitative Disclosures About Market Risk".
Risk Management Policy
The Board of Directors adopted a risk management policy, which was
implemented by management and is periodically assessed by the Governance
Committee of the Board. The Company's policy is designed to meet the following
goals: (i) to assure the Company can generate sufficient operating cash flow to
replace reserves that are produced and (ii) to assure compliance with
restrictive debt covenants that would otherwise limit the Company's ability to
incur additional debt. It is also the Company's policy that significant capital
investments whose rates of return are sensitive to future oil and gas prices be
protected from exposure to extreme price volatility.
The Company's risk management policy is based on the view that oil prices
revert to a mean price over the long term. To the extent that future markets
over a forward 18 month period are significantly higher than long term norms,
the Company will hedge as much of its production as is necessary to meet its
policy goals for that period. Variations from this policy require Board
approval. The risk management policy states that hedging activity that is
speculative or otherwise unrelated to the Company's normal business activities
is considered inappropriate. The Company recognizes the risks inherent in price
management. In order to minimize such risk, the Company has instituted a set of
controls addressing approval authority, trading limits and other control
procedures. All hedging activity is the responsibility of the Chief Financial
Officer. In addition, Internal Audit, which independently reports to the Audit
Committee, reviews the Company's price management activity.
Competition/Markets for Production
The Company operates in the highly competitive areas of oil and gas
exploration, exploitation, development and production. The availability of
funds and information relating to a property, the standards established by the
Company for the minimum projected return on investment, the availability of
alternate fuel sources and the intermediate transportation of oil and gas are
factors which affect the Company's ability to compete
21
NUEVO ENERGY COMPANY
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.
The Company's heavy crude oil production in California requires special
treatment available only from a limited number of refineries. Substantial
damage to such a refinery or closures or reduction in capacity due to financial
or other factors could adversely affect the market for the Company's heavy crude
oil production.
Environmental and Other Regulation
The Company's operations are subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. These laws and regulations require the acquisition
of a permit before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands and other
protected areas, and impose substantial liabilities for pollution which might
result from the Company's operations. Moreover, the recent trend toward
stricter standards in environmental legislation and regulation is likely to
continue. For instance, legislation has been proposed in Congress from time to
time that would reclassify certain oil and gas exploration and production wastes
as "hazardous wastes" which would make the reclassified wastes subject to much
more stringent handling, disposal and cleanup requirements. If such legislation
were to be enacted, it could have a significant impact on the operating costs of
the Company, as well as the oil and gas industry in general. Initiatives to
further regulate the disposal of oil and gas wastes are also pending in certain
states, and these various initiatives could have a similar impact on the
Company. The Company could incur substantial costs to comply with environmental
laws and regulations.
The OPA imposes a variety of regulations on "responsible parties" related to
the prevention of oil spills. The implementation of new, or the modification of
existing, environmental laws or regulations, including regulations promulgated
pursuant to the OPA, could have a material adverse impact on the Company.
ITEM 3. LEGAL PROCEEDINGS
The Company had been named as a defendant in Gloria Garcia Lopez and Husband,
Hector S. Lopez, Individually, and as successors to Galo Land & Cattle Company
v. Mobil Producing Texas & New Mexico, et al. in the 79th Judicial District
Court of Brooks County, Texas. On June 9, 2000, the parties entered into a
memorandum of settlement agreement, pursuant to which the lawsuit was dismissed,
the defendants paid the plaintiffs $12.0 million and the lease agreement was
amended. Nuevo's working interest in these properties is 20%, and its share of
the settlement payment was approximately $2.4 million.
On September 22, 2000, the Company was named as a defendant in the lawsuit
Thomas Wachtell et al. versus Nuevo Energy Company in the Superior Court of Los
Angeles County, California. The plaintiffs, who own certain interests in the
Point Pedernales properties, have asserted numerous causes of action including
breach of contract, fraud and conspiracy in connection with the plaintiff's
allegation that: (i) royalties have not been properly paid to them for
production from the Point Pedernales field, (ii) payments have not been made to
them related to production from the Sacate field, and, (iii) the Company has
failed to recognize the plaintiff's interests in the Tranquillon Ridge project.
The plaintiffs have not specified damages. The Company has not yet been
required to file an answer, but believes the allegations are without merit and
intends to vigorously contest these claims. Management does not believe that
the outcome of this matter will have a material adverse impact on the Company's
operating results, financial condition or liquidity.
On April 5, 2000, the Company filed a lawsuit against ExxonMobil Corporation
in the United States District Court for the Central District of California,
Western Division. The Company and ExxonMobil each own a 50% interest in the
Sacate Field, offshore Santa Barbara County, California, which can only be
accessed from an existing ExxonMobil platform. The Company has alleged that by
grossly inflating the fee that ExxonMobil insists the Company must pay to use an
existing ExxonMobil platform and production infrastructure, ExxonMobil failed to
submit a proposal for the development of the Sacate field consistent with the
Unit Operating Agreement. The Company therefore believes that it has been denied
a reasonable opportunity to exercise its rights under the Unit
22
NUEVO ENERGY COMPANY
Operating Agreement. ExxonMobil contends that Nuevo had not consented to the
operation and therefore cannot receive its share of production from Sacate until
ExxonMobil has first recovered certain costs and fees. As a result, Nuevo has
neither received revenues, incurred operating expenses, nor booked any proved
reserves related to Sacate. The Company has alleged that ExxonMobil's actions
breach the Unit Operating Agreement and the covenant of good faith and fair
dealing. The Company is seeking damages and a declaratory judgment as to the
payment that must be made to access ExxonMobil's platform and facilities. The
Company's capitalized costs associated with Sacate are insignificant.
The Company has been named as defendant in certain other 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 2000.
23
NUEVO ENERGY COMPANY
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). On March 22, 2001, Nuevo had 16,505,768
shares of common stock outstanding and had reserved 1,936,830 shares of common
stock for issuance upon conversion of the TECONS and 225,534 shares for issuance
pursuant to employee stock options. There were approximately 1,076 stockholders
of record and approximately 2,472 additional beneficial owners as of March 22,
2001. 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 2000 and 1999 are presented
in the following table:
Market Price
------------------------------------------
High Low
--------------- ---------------
Quarter Ended:
March 31, 2000....................................... $26.00 $15.50
June 30, 2000........................................ $22.06 $16.81
September 30, 2000................................... $20.25 $14.31
December 31, 2000.................................... $21.00 $14.63
March 31, 1999....................................... $16.38 $ 6.13
June 30, 1999........................................ $18.19 $11.63
September 30, 1999................................... $18.13 $13.50
December 31, 1999.................................... $19.50 $13.63
Treasury Stock Repurchases
Since December 1997, the Board of Directors of the Company authorized the
open market repurchase of up to 4,616,600 shares of outstanding Common Stock at
times and at prices deemed appropriate by management. During 2000, the Company
repurchased 1,482,000 shares of its Common Stock in open market transactions at
an average purchase price, including commissions, of $16.67 per share. During
1999, the Company repurchased 1,999,100 shares of its Common Stock in open
market transactions at an average purchase price, including commissions, of
$16.50 per share. No Common Stock was repurchased during 1998. As of March 22,
2001, the Company had repurchased 3,608,900 shares, on a cumulative basis, at an
average purchase price of $16.56 per share, including commissions, under the
current share repurchase program.
Shareholder Rights Plan
In March 1997, the Company adopted a Shareholder Rights Plan to protect the
Company's shareholders from coercive or unfair takeover tactics. Under the
Shareholder Rights Plan, each outstanding share and each share of subsequently
issued Common Stock has attached to it one Right. Generally, in the event a
person or group ("Acquiring Person") acquires or announces an intention to
acquire beneficial ownership of 15% or more of the outstanding shares of Common
Stock without the prior consent of the Company, or the Company is acquired in a
merger or other business combination, or 50% or more of its assets or earning
power is sold, each holder of a Right will have the right to receive, upon
exercise of the Right, that number of shares of common stock of the acquiring
company, which at the time of such transaction will have a market price of two
times the exercise price of the Right. The Company may redeem the Right for
$.01 at any time before a person or group becomes an Acquiring Person
24
NUEVO ENERGY COMPANY
without prior approval. The Rights will expire on March 21, 2007, subject to
earlier redemption by the Board of Directors of the Company.
On January 10, 2000, the Company amended the Shareholder Rights Plan to
provide that if the Company receives and consummates a transaction pursuant to a
qualifying offer, the provisions of the Shareholder Rights Plan are not
triggered. In general, a qualifying offer is an all cash, fully-funded tender
offer for all outstanding Common shares by a person who, at the commencement of
the offer, beneficially owns less than five percent of the outstanding Common
shares. A qualifying offer must remain open for at least 120 days, must be
conditioned on the person commencing the qualifying offer acquiring at least 75%
of the outstanding Common shares and the per share consideration must exceed the
greater of: (1) 135% of the highest closing price of the Common shares during
the one-year period prior to the commencement of the qualifying offer or (2)
150% of the average closing price of the Common shares during the 20 day period
prior to the commencement of the qualifying offer.
Executive Compensation Plan
During July 1997, the Board of Directors of the Company adopted a plan to
encourage senior executives to personally invest in the stock of the Company,
and to regularly review executives' ownership versus targeted ownership
objectives. These incentives include a deferred compensation plan (the "Plan")
that gives key executives the ability to defer all or a portion of their
salaries and bonuses and invest in Common Stock of the Company at a discount to
market prices or make other investments at the employee's discretion. Stock
acquired at a discount will be held in a benefit trust and will be restricted
for a two-year period. The Plan does not permit investment in a diversified
equity portfolio until and unless targeted levels of Common Stock ownership in
the Company are achieved and maintained. Target levels of ownership are based
on multiples of base salary and are administered by the Compensation Committee
of the Board of Directors. The Plan applies to certain highly compensated
employees and all executives at a level of Vice-President and above.
25
NUEVO ENERGY COMPANY
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).
As of and for the Years ended December 31,
----------------------------------------------------------------------------------
2000 1999 1998 1997 1996
-------- -------- -------- -------- --------
Oil and gas revenues.............. $331,655 $242,274 $242,675 $331,973 $279,859
Gas plant revenues................ -- -- -- 14,826 34,802
Pipeline and other revenues....... -- -- -- 5,772 6,774
Gain on sale of assets, net....... 657 85,294 5,768 1,372 6,008
Interest and other income......... 4,293 4,667 4,260 3,335 1,614
-------- -------- -------- -------- --------
Total revenues.................. 336,605 332,235 252,703 357,278 329,057
Total costs and expenses before
extraordinary item and
cumulative effect (including
income taxes and minority
interest)/(2)/................... 324,174 300,793 346,975 367,954 294,779
Cumulative effect of a change in
accounting principle............. 796 -- -- -- --
Extraordinary loss on early
extinguishment of debt........... -- -- -- 3,024 --
-------- -------- -------- -------- --------
Net income (loss)/(1)(3)/......... $ 11,635 $ 31,442 $(94,272) $(13,700) $ 34,278
======== ======== ======== ======== ========
Net income (loss) attributable to
Common Stockholders.............. $ 11,635 $ 31,442 $(94,272) $(13,700) $ 33,339
Earnings (loss) per Common Share
- Basic.......................... $0.67 $ 1.62 $ (4.77) $(0.69) $1.99
Earnings (loss) per Common Share
- Diluted........................ $0.64 $ 1.61 $ (4.77) $(0.69) $1.84
Total Assets...................... $848,024 $760,030 $817,685 $804,286 $817,643
Long-term debt, net of current
maturities....................... $409,727 $340,750 $419,150 $305,940 $287,038
Company-obligated Mandatorily
Redeemable Convertible Preferred
Securities of Nuevo Financing I.. $115,000 $115,000 $115,000 $115,000 $115,000
---------------
(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) Results for the years ended 1998 and 1997 include impairments of oil and gas
properties of $68.9 million and $30.0 million, respectively, and (revision to)
provision for impairment on assets held for sale of ($3.7) million and $23.9
million, respectively.
(3) The year ended December 31, 1996, includes activity of the California
Properties from the date of acquisition (April 9, 1996).
26
NUEVO ENERGY COMPANY
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Overview
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 strategy to differentiate itself
from its numerous peer group competitors and to generate long term shareholder
value consists of: (i) a management philosophy that frames all important
decisions in terms of anticipated impact on per share (rather than absolute)
growth of reserves, production, cash flow and net asset value; (ii) a contrarian
investment and financing orientation, in which the Company seeks to purchase
assets during periods of industry weakness and sell assets during periods of
industry strength; (iii) the outsourcing of non-strategic functions; and (iv)
the alignment of employee compensation structures with shareholder objectives.
Nuevo is also committed to an exemplary corporate governance structure, which
reinforces management's overarching view that Nuevo should be a conduit for
shareholders to achieve superior long-term capital gains. All of Nuevo's
directors, other than the chief executive officer, are independent directors.
Nuevo's directors and executive officers each have made substantial equity
investments in Nuevo, in order to align their interests with that of the
Company's stockholders.
Nuevo is an independent energy company. Since its inception in 1990, Nuevo
has expanded its operations through a series of disciplined, low-cost
acquisitions of oil and gas properties and the subsequent exploitation and
development of these properties. The Company has complemented these efforts
with divestitures of non-core assets and an opportunistic exploration program,
which provides exposure to high-potential prospects. The Company's primary
strengths are its large inventory of exploitation projects in its core areas of
operation, which the Company believes will support future growth in reserves and
production per share; its ability to identify and acquire, at attractive prices,
long-lived producing properties, which have significant potential for further
exploration, exploitation and development; a capital structure supportive of a
growing investment program and future acquisitions; and a price risk management
policy designed to protect the Company's ability to generate self-sustaining
cash flow and to meet the interest coverage tests under the Company's bond
indentures.
The Company's results of operations have been significantly affected by
fluctuations in oil and gas prices. The Company's success in acquiring oil and
gas properties and its ability to maintain or increase production through its
exploitation activities have also significantly affected the Company's results.
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),
by oil and gas segment and in total, for the periods presented:
Year Ended December 31,
---------------------------------------------
Production: 2000 1999 1998
------ ------ ------
Oil (MBBLS):
Domestic................................. 15,413 15,685 17,122
Foreign.................................. 1,843 1,835 1,461
------ ------ ------
Total.................................... 17,256 17,520 18,583
====== ====== ======
Natural gas (MMCF):
Domestic................................. 15,215 17,620 32,521
Natural gas liquids (MBBLS):
Domestic................................. 178 207 223
27
NUEVO ENERGY COMPANY
Year Ended December 31,
----------------------------------------------
Average sales price: 2000 1999 1998
------ ------ ------
Oil (per barrel):
Domestic................................. $21.73 $13.59 $ 9.11
Foreign.................................. $22.19 $16.69 $10.82
Total - exclusive of hedges.............. $21.88 $13.82 $ 9.26
Total - hedge effect..................... $(7.13) $(2.61) $(0.01)
------ ------ ------
Total - net of hedge effect.............. $14.75 $11.21 $ 9.25
====== ====== ======
Natural gas (per MCF):
Domestic/Total - exclusive of hedges..... $ 4.78 $ 2.27 $ 1.98
Domestic/Total - hedge effect............ $ --- $ --- $ 0.02
------ ------ ------
Domestic/Total - net of hedge effect..... $ 4.78 $ 2.27 $ 2.00
====== ====== ======
AVERAGE UNIT PRODUCTION COST PER EQUIVALENT
BARREL (6 MCF EQUALS 1 BARREL):
Domestic................................. $ 7.88 $ 6.07 $ 5.39
Foreign.................................. $ 7.39 $ 7.01 $ 8.14
Total.................................... $ 7.84 $ 6.15 $ 5.56
The Company utilizes the successful efforts method of accounting for its
investments in oil and gas properties. Under the successful efforts method of
accounting, oil and gas lease acquisition costs and intangible drilling costs
associated with exploration efforts that result in the discovery of proved
reserves and costs associated with development drilling, whether or not
successful, are capitalized when incurred. When a proved property is sold,
ceases to produce or is abandoned, a gain or loss is recognized. When an entire
interest in an unproved property is sold for cash or cash equivalent, a gain or
loss is recognized, taking into consideration any recorded impairment. When a
partial interest in an unproved property is sold, the amount received is treated
as a reduction of the cost of the interest retained.
Unproved leasehold costs are capitalized, pending the results of exploration
efforts. Significant unproved leasehold costs are reviewed periodically and a
loss is recognized to the extent, if any, that the cost of the property has been
impaired. An impairment of unproved leasehold costs of $8.1 million was
recognized as of December 31, 1998. No such impairment was recognized for the
years ended December 31, 2000 or 1999. Exploration costs, including geological
and geophysical expenses, exploratory dry holes and delay rentals, are charged
to expense as incurred.
Costs of successful wells, development dry holes and proved leases are
capitalized and depleted on a unit-of-production basis over the life of the
remaining proved reserves. Capitalized drilling costs are depleted on a unit-
of-production basis over the life of the remaining proved developed reserves.
Estimated costs (net of salvage value) of dismantlement, abandonment and site
remediation are computed by the Company and an independent consultant and are
included when calculating depreciation and depletion using the unit-of-
production method.
In accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of", the Company reviews its
long-lived assets to be held and used, including proved oil and gas properties
accounted for using the successful efforts method of accounting, on a depletable
unit basis whenever events or circumstances indicate that the carrying value of
those assets may not be recoverable. SFAS No. 121 requires an impairment loss be
recognized when the carrying amount of an asset exceeds the sum of the
undiscounted estimated future cash flows. In this circumstance, the Company
recognizes an impairment loss equal to the difference between the carrying value
and the fair value of the asset. Fair value is estimated to be the present value
of expected future net cash flows from proved reserves, utilizing a risk-
adjusted rate of return.
28
NUEVO ENERGY COMPANY
During 1998, the Company recorded a fair value impairment totaling $60.8
million on its East Coalinga, Las Cienegas, Beta, Point Pedernales and South
Mountain fields and certain other insignificant oil and gas properties due to
the significant, sustained decline in domestic oil prices during the year from
an average Company realized price of $14.86 per barrel for 1997 to an average
realized price of $9.25 per barrel in 1998. No such impairment was recognized
during 2000 or 1999.
Any reference to oil and gas reserve information in the Notes to Consolidated
Financial Statements is unaudited.
Financing Activities
The Company had $409.7 million in outstanding indebtedness at December 31,
2000, which is scheduled to mature as follows (amounts in thousands):
2001.......................................................... $ --
2002.......................................................... --
2003.......................................................... --
2004.......................................................... --
2005.......................................................... --
Thereafter.................................................... 409,727
--------
$409,727
========
On September 26, 2000, the Company issued $150.0 million of 9-3/8% Senior
Subordinated Notes due September 15, 2010 ("9-3/8% Notes"). Interest on the
9-3/8% Notes accrues at the rate of 9-3/8% per annum and is payable semi-
annually in arrears on April 1 and October 1. The 9-3/8% Notes are redeemable,
in whole or in part, at the option of the Company, on or after October 1, 2005,
under certain conditions. The Company is not required to make mandatory
redemption or sinking fund payments with respect to the 9-3/8% Notes. The
indenture contains covenants that, among other things, limit the Company's
ability to incur additional indebtedness, limit restricted payments, limit
issuances and sales of capital stock by restricted subsidiaries, limit
dispositions of proceeds from asset sales, limit dividends and other payment
restrictions affecting restricted subsidiaries, and restrict mergers,
consolidations or sales of assets. If a subsidiary of the Company guarantees
other subordinated indebtedness of the Company, the subsidiary must also
guarantee the 9-3/8% Notes. Currently, none of the Company's subsidiaries
guarantees subordinated indebtedness of the Company. The 9-3/8% 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 repurchase all outstanding 9-3/8% Notes at 101% of the principal amount
thereof, plus accrued and unpaid interest to the date of redemption.
In July 1999, the Company authorized a new issuance of $260.0 million of
9-1/2% Senior Subordinated Notes due June 1, 2008 ("9-1/2% Notes"). The Company
offered to exchange the new notes for its outstanding $160.0 million of 9-1/2%
Senior Subordinated Notes due 2006 ("Old 9-1/2% Notes") and $100.0 million of
8-7/8% Senior Subordinated Notes due 2008 ("8-7/8 % Notes"). In August 1999, the
Company received tenders to exchange $157.5 million of its Old 9-1/2% Notes and
$99.85 million of the 8-7/8% Notes. In connection with the exchange offers, the
Company solicited consents to proposed amendments to the indentures under which
the old notes were issued. These amendments streamline the Company's covenant
structure and provide the Company with additional flexibility to pursue its
operating strategy. The exchange was accounted for as a debt modification. As
such, the consideration that the Company paid to the holders of the Old 9-1/2%
Notes who tendered in the exchange offer (equal to 3% of the outstanding
principal amount of the Old 9-1/2% Notes exchanged) was accounted for as
deferred financing costs. Also in connection with this exchange offer, the
Company incurred a total of $3.1 million in third-party fees during the third
and fourth quarters of 1999, which are included in other expense.
Interest on the 9-1/2% Notes accrues at the rate of 9-1/2% per annum and
is payable semi-annually in arrears on June 1 and December 1. The 9-1/2% Notes
are redeemable, in whole or in part, at the option of the Company, on or after
June 1, 2003, 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,
29
NUEVO ENERGY COMPANY
limit the Company's ability to incur additional indebtedness, limit restricted
payments, limit issuances and sales of capital stock by restricted subsidiaries,
limit dispositions of proceeds from asset sales, limit dividends and other
payment restrictions affecting restricted subsidiaries, and restrict mergers,
consolidations or sales of assets. The 9-1/2% Notes are not currently guaranteed
by Nuevo's subsidiaries but are required to be guaranteed by any subsidiary that
guarantees indebtedness ranking equal as to right of payment to the 9-1/2% Notes
or subordinated indebtedness. Currently, none of the Company's subsidiaries
guarantees subordinated indebtedness of the Company. 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 repurchase all outstanding 9-1/2% Notes at 101% of the principal amount
thereof, plus accrued and unpaid interest to the date of redemption.
Nuevo's Third Amended and Restated Credit Agreement, (the "Credit
Agreement"), dated June 7, 2000, provides for secured revolving credit
availability of up to $410.0 million (subject to a semi-annual borrowing base
determination) from a bank group led by Bank of America, N.A., Bank One, NA, and
Bank of Montreal until its expiration on June 7, 2005.
The borrowing base is subject to a semi-annual borrowing base determination
within 60 days following March 1 and August 15 of each year. The borrowing base
determination establishes the maximum borrowings that may be outstanding under
the credit facility, and is determined by a 60% vote of the banks (two-thirds in
the event of an increase in the borrowing base), each of which bases its
judgement on (i) the present value of the Company's oil and gas reserves based
on its own assumptions regarding future prices, production, costs, risk factors
and discount rates, and (ii) on projected cash flow coverage ratios calculated
under varying scenarios. If amounts outstanding under the credit facility
exceed the borrowing base, as redetermined from time to time, the Company would
be required to repay such excess over a defined period of time. As of December
31, 2000, the Company's borrowing base was $225.0 million. There were no
outstanding borrowings under this facility at December 31, 2000.
Amounts outstanding under the credit facility bear interest at a rate equal
to the London Interbank Offered Rate ("LIBOR") plus an amount which increases as
borrowing base utilization increases.
The Credit Agreement has customary covenants including, but not limited to,
covenants with respect to the following matters: (i) limitations on certain
restricted payments and investments; (ii) limitations on guarantees and
indebtedness; (iii) limitations on prepayments of subordinated and certain other
indebtedness; (iv) limitations on mergers and consolidations, on certain types
of acquisitions and on the issuance of certain securities by subsidiaries; (v)
limitations on liens; (vi) limitations on sales of properties; (vii) limitations
on transactions with affiliates; (viii) limitations on derivative contracts; and
(ix) limitations on debt in subsidiaries. The Company is also required to
maintain certain financial ratios and conditions, including without limitation
an EBITDAX (earnings before interest, taxes, depreciation, depletion,
amortization and exploration expenses) to fixed charge coverage ratio and a
funded debt to capitalization ratio. As a result of reduced revenues in 1998
due to falling oil prices, the Company obtained amendments for relief from the
EBITDAX fixed charge coverage test through March 31, 2000. The Company was in
compliance with this test and all other covenants of the Credit Agreement at
December 31, 2000, and does not anticipate any issues of non-compliance arising
in the foreseeable future.
In February 1995, in connection with the purchase of the stock of the Amoco
Congo Petroleum Company, the Company negotiated with the Overseas Private
Investment Corporation ("OPIC") and an agent bank for a non-recourse credit
facility in the amount of $25.0 million. The credit facility expired in June
1999. The initial drawdown on the facility was $8.8 million to finance a
portion of the purchase price. 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. This loan agreement required a
sixteen-quarter repayment period and was fully re-paid in April 2000.
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.
30
NUEVO ENERGY COMPANY
Results of Operations
Revenues
The Company has experienced significant oil and gas revenue volatility in
recent years. Beginning in late 1997 and continuing through early 1999, oil
prices were very low compared with historical prices. Oil prices improved
significantly during 1999 and 2000. During this three-year period, the
volatility of oil and gas prices directly impacted revenues. For the purpose
of reducing exposure to decreases in oil and gas prices, the Company utilizes
derivative financial instruments in accordance with its price risk management
policy, which was adopted in 1999. As a result of such hedging transactions,
oil and gas revenues were reduced by $117.7 million and $44.9 million in 2000
and 1999, respectively, and increased by $0.6 million in 1998.
Oil and gas revenues for 2000 were 37% higher than 1999 oil and gas
revenues primarily due to a 32% increase in average realized oil prices and a
111% increase in average realized gas prices from 1999 to 2000. Partially
offsetting these increases in realized prices, the Company's gas production
decreased 14% from 1999 to 2000, and oil production decreased 2% from 1999 to
2000. The production decreases were primarily a result of asset sales. Oil and
gas revenues for 1999 were relatively flat as compared to 1998, however the
factors driving oil and gas revenues for each period were different. The 15%
decrease in oil and gas production from 1998 to 1999 was almost entirely offset
by higher commodity prices received in 1999. Oil volumes decreased 6% from 1998
to 1999 primarily as a result of reduced capital spending during 1999. This
decrease was partially offset by the production from the California properties
acquired from Texaco in June 1999. Gas volumes decreased 46% from 1998 to 1999
principally due to the January 1999 sale of the East Texas natural gas assets,
and to a lesser extent, natural field declines in California. Offsetting these
production declines, oil and gas price realizations increased 21% and 14%,
respectively, from 1998 to 1999.
The net gain on sale of assets for 2000 was $657,000, primarily
representing a $923,000 gain on the sale of the Company's working interest in
the Las Cienegas field in California, which was partially offset by a $266,000
net loss on the sale of several individually insignificant non-core assets. The
net gain on sale of assets for 1999 was $85.3 million, which is comprised of:
(i) an $80.2 million gain on the sale of the Company's East Texas natural gas
assets in January 1999, (ii) a $5.4 million gain on the sale of the Company's
interest in 13 onshore fields and a gas processing plant located in Ventura
County, California, in December 1999, and (iii) a $0.3 million net loss on the
sale of other non-core properties. Gain on sale of assets for 1998 was $5.8
million. This gain on sale of assets includes a $4.1 million gain on the sale
of the Company's interest in the Sansinena field in California in the third
quarter of 1998 and a $1.7 million gain on the sale of the Company's interest in
the Coke field in Chapel Hill, Texas in the first quarter of 1998.
Interest and other income for the year ended December 31, 2000, of $4.3
million includes $1.9 million in interest income resulting from higher cash
balances in 2000 plus $1.5 million for a partial reimbursement of previously
expensed funds, resulting from a negotiated settlement of a legal claim (see
Note 11 to the Notes to Condensed Consolidated Financial Statements), as well as
several individually insignificant items. Interest and other income for the
year ended December 31, 1999, of $4.7 includes $2.4 million associated with
interest earned on the $100.0 million in proceeds from the sale of the East
Texas natural gas properties funded into an escrow account to provide "like-kind
exchange" tax treatment in the event the Company acquired domestic producing oil
and gas properties in the first half of 1999. The escrow account was liquidated
in June 1999, in connection with the Company's June 1999 acquisition of certain
California oil and gas properties from Texaco, Inc. and the repayment of a
portion of bank debt. Also included in interest and other income in 1999 is
$0.6 million related to the sale of an unconsolidated subsidiary. Interest and
other income for the year ended December 31, 1998, of $4.3 million includes $2.7
million in pipeline revenue as well as several individually insignificant items.
Expenses
Lease operating expenses ("LOE") for 2000 totaled $156.5 million, as
compared to $130.5 million and $137.9 million for 1999 and 1998, respectively.
The 20% increase in LOE from 1999 to 2000 is primarily due to a $25.7 million
increase in steam costs resulting from higher natural gas prices. The 5%
decrease in LOE from 1998
31
NUEVO ENERGY COMPANY
to 1999 is primarily due to the Company's sale of the East Texas natural gas
assets in January 1999. Even though total LOE decreased in 1999, LOE per BOE
increased 11% from 1998 to 1999. This increase primarily relates to the January
1999 sale of the East Texas assets that had relatively low LOE per BOE rates.
Exploration costs, including geological and geophysical ("G&G") costs,
dry hole costs and delay rentals, were $9.8 million, $14.0 million and $16.6
million for the years ended December 31, 2000, 1999 and 1998, respectively.
Exploration costs for the year ended 2000 included: $2.5 million of dry hole
costs, $5.4 million of G&G costs, $0.1 million of delay rentals and $1.8 million
of other exploration costs. Exploration costs for the year ended 1999 included:
$8.1 million of dry hole costs ($7.2 million of which relates to onshore
California), $3.6 million of G&G costs ($2.1 of which relates to Ghana), $0.8
million of delay rentals and $1.5 million of other exploration costs.
Exploration costs for the year ended 1998 included: $13.0 million of dry hole
costs ($7.3 million of which relates to Ghana), $2.1 million of G&G costs ($1.5
million of which relates to Ghana), $0.9 million of delay rentals and $0.6
million of other exploration costs.
Depreciation, depletion and amortization decreased 16% in 2000 as
compared to 1999. This decrease was driven by a lower depletion rate, which
primarily resulted from a significant increase in reserve estimates attributable
to higher commodity prices at year-end 1999 versus year-end 1998. Depreciation,
depletion and amortization decreased 5% in 1999 as compared to 1998. This
decrease is primarily due to the impairment of oil and gas properties of $60.8
million recognized in the fourth quarter of 1998, which reduced the capitalized
costs to be depleted in 1999. Also, the East Texas properties were depleted for
the first six months in 1998. The Company discontinued depleting these assets
in the third quarter of 1998, when it was decided to sell these properties. The
5% decrease was partially offset by higher international depletion due to
increased production.
The Company recorded a provision for impairment of oil and gas properties
in 1998 in the amount of $68.9 million ($60.8 million of fair value impairments
plus $8.1 million of unproved leasehold cost impairments). These impairments
were recorded as a result of declines in the price of oil, which caused
capitalized costs to be in excess of future net revenues. No such impairment
was recognized during 2000 or 1999.
In December 1997, the Company recorded a provision for impairment on
assets held for sale, in connection with its plans to dispose of its non-core
gas gathering, pipeline and gas storage assets during 1998, including all such
assets except its California gas plants. A positive revision to this charge was
made in the fourth quarter of 1998 in the amount of $3.7 million to reflect the
estimated current fair market value of the Illini pipeline.
General and administrative expenses ("G&A") increased only slightly in 2000
as compared to 1999. G&A expenses were up $4.2 million in 1999 versus 1998.
The 15% increase is mainly comprised of a $1.9 million increase in bonuses paid
to employees, as no bonuses were paid in 1998, and a $1.9 million increase in
the market value of the Company's obligation for the executive compensation
plan.
Interest expense of $37.5 million for year ended December 31, 2000,
increased 13% as compared to interest expense in the same period in 1999. The
increase is primarily attributable to an increase in outstanding borrowings
under the Company's credit facility during the year plus higher interest rates
on those outstanding borrowings. On September 26, 2000, all borrowings
outstanding under the credit facility were paid off with net proceeds received
from the Company's issuance of the 9-3/8% Notes (see Note 8 to the Notes to
Consolidated Financial Statements). The increase is also due to higher interest
rates as the Company exchanged its 8-7/8% Senior Subordinated Notes for 9-1/2%
Senior Subordinated Notes due 2008 in the third quarter of 1999. Interest
expense for 1999 increased slightly from 1998, however, the components of
interest expense changed from year to year. The Company issued $100.0 million
of 8-7/8% Senior Subordinated Notes in June 1998, which were exchanged for
9-1/2% Senior Subordinated Notes in July 1999. This increase was significantly
offset by lower interest expense on the Credit Agreement as a result of lower
average borrowings outstanding during 1999.
Other expense of $5.1 million in 2000 includes: a $2.0 million settlement
for a lawsuit (see Note 11 to the Notes to Consolidated Financial Statements),
$1.7 million for scientific information technology consulting, and $0.9 million
in costs to evaluate potential business transactions. The remaining amount is
made up of individually insignificant items. Other expense of $8.9 million in
1999 includes: $3.1 million in third-party charges incurred in connection with
the July 1999 exchange offer (see Note 8 to the Notes to Consolidated Financial
Statements), $1.6
32
NUEVO ENERGY COMPANY
million relating to the fraud discussed below, $1.3 million for scientific
information technology consulting, and other miscellaneous charges. In March
1999, the Company discovered that a non-officer employee had fraudulently
authorized and diverted for personal use Company funds totaling $5.9 million,
$4.3 million in 1998 and the remainder in 1999, that were intended for
international exploration. Other expense of $7.8 million in 1998 also includes
$2.0 million of pipeline operating costs plus several individually insignificant
items.
Dividends on the TECONS were $6.6 million in 2000, 1999 and 1998. The
TECONS pay dividends at a rate of 5.75% and were issued in December 1996. (See
Note 7 to the Notes to Consolidated Financial Statements.)
Income tax expense of $8.4 million was recognized in 2000, compared to a
benefit of $5.4 million in 1999 and $32.6 million in 1998. The Company's
effective income tax rate was 40.3%, (20.5)% and (25.7)% in 2000, 1999 and
1998, respectively. At December 31, 1998, the Company determined that it was
more likely than not that a portion of the deferred tax assets would not be
realized and the valuation allowance was increased by $16.9 million to a total
valuation allowance of $17.6 million. At December 31, 1999, however, the Company
determined that it was more likely than not that most of the deferred tax assets
would be realized, based on commodity prices at year-end 1999, and the valuation
allowance was decreased by $15.9 million.
Cumulative Effect of a Change in Accounting Principle
In December 2000, the staff of the Securities and Exchange Commission
announced that commodity inventories should be carried at lower of cost or
market rather than at market value. As a result, the Company changed its
inventory valuation method to the lower of cost or market in the fourth quarter
of 2000, retroactive to the beginning of the year. Accordingly, the Company
recorded a non-cash, cumulative effect of a change in accounting principle to
earnings, effective January 1, 2000, of $796,000 (net of the related income tax
benefit of $537,000) to value product inventory at lower of cost or market. (See
Note 2 to the Notes to Consolidated Financial Statements.)
Net Income (Loss)
Net income of $11.6 million and $31.4 million was reported in 2000 and 1999,
respectively, as compared to a net loss of $94.3 million in 1998.
Capital Resources and Liquidity
Since its inception, the Company has grown and diversified its operations
through a series of disciplined, low-cost acquisitions of oil and gas properties
and the subsequent exploitation and development of these properties. The Company
has complemented these efforts with divestitures of non-core assets and an
opportunistic exploration program, which provides exposure to high-potential
prospects. The funding of these activities has historically been provided by
operating cash flows, bank financing, private and public placements of debt and
equity securities, property divestitures and joint ventures with industry
participants. Net cash provided by operating activities was $93.7 million, $24.0
million, and $35.8 million in 2000, 1999 and 1998, respectively. The Company
invested $104.4 million, $125.9 million and $157.4 million in oil and gas
properties in 2000, 1999 and 1998, respectively. Additionally, the Company spent
$3.4 million, $10.2 million and $2.8 million on gas plant and other facilities
in 2000, 1999 and 1998, respectively. In June 1999, the Company acquired oil and
gas properties located onshore and offshore California for $61.4 million from
Texaco, Inc. To purchase these assets, the Company used funds from a $100.0
million interest-bearing escrow account that was created with proceeds from the
Company's January 1999 sale of its East Texas natural gas assets. Following the
Texaco transaction, the $41.0 million remaining in the escrow account, which
included $2.4 million of interest income, was used to repay a portion of
outstanding bank debt in early July 1999.
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 budget through 2001.
The Company had an unused commitment under the Credit Facility of $225.0 million
at December 31, 2000. At December 31, 2000, there were no maturities of long-
term debt for the next five years.
33
NUEVO ENERGY COMPANY
Outlook
The Company's revenues, cash flows, results of operations and liquidity are
highly dependent on oil and gas prices, as is its ability to acquire financing
for its operations. Approximately 86% of the Company's production and 76% of
the Company's revenues for 2000 were attributable to oil. Oil prices during
1998 and the first part of 1999 were very low compared to historical prices. As
a result, the Company's 1998 revenues, earnings and cash flows were materially
reduced compared to prior years, even though production levels increased during
1998. During 1999 and 2000, crude oil prices increased significantly. In late
2000, due to a natural gas shortage in California, natural gas prices increased
significantly. Nuevo has a net long gas position in California - producing more
natural gas than consumed in its thermal crude production. As gas prices
escalated in late 2000, Nuevo began to exploit this gas position by diverting
gas consumed in uneconomic cyclic steaming operations to gas sales. In January
and February 2001, Nuevo sold an average of 19 MMcfd, or 44% of its total daily
gas production, which has resulted in an increase in 2001 gas sales of 33%.
This strategy will remain as long as gas prices support sales over thermal oil
production.
In 1999, the Company's Board of Directors adopted a risk management policy,
which was implemented by management and is periodically assessed by the
Governance Committee of the Board. The Company's policy is designed to meet the
following goals: (i) to assure the Company can generate sufficient operating
cash flow to replace reserves that are produced and to (ii) assure compliance
with restrictive debt covenants that would otherwise limit the Company's ability
to incur additional debt. It is also the Company's policy that significant
capital investments whose rates of return are sensitive to future oil and gas
prices be protected from exposure to extreme price volatility.
The Company's risk management policy is based on the view that oil prices
revert to a mean price over the long term. To the extent that future markets
over a forward 18 month period are significantly higher than long term norms,
the Company will hedge as much of its production as is necessary to meet its
policy goals for that period. Variations from this policy require Board
approval. The risk management policy states that hedging activity that is
speculative or otherwise unrelated to the Company's normal business activities
is considered inappropriate. The Company recognizes the risks inherent in price
management. In order to minimize such risk, the Company has instituted a set of
controls addressing approval authority, trading limits and other control
procedures. All hedging activity is the responsibility of the Chief Financial
Officer. In addition, Internal Audit, which independently reports to the Audit
Committee, reviews the Company's price management activity.
For 2001, the Company has entered into swap arrangements on 26,000 BOPD for
the first quarter at an average WTI price of $19.52, for the second quarter on
25,000 BOPD at an average WTI price of $19.54, for the third quarter on 20,000
BOPD at an average WTI price of $21.22, and for the fourth quarter on 15,500
BOPD at an average WTI price of $22.95 per barrel. Subsequent to December 31,
2000, the Company entered into swaps on an additional 1,200 BOPD for the second
quarter, bringing the total to 26,200 BOPD at an average price of $19.84 per
barrel. On a physical volume basis, these hedges cover 47% of the Company's
estimated 2001 oil production. At December 31, 2000, the market value of the
swaps in place for 2001 was a loss of $35.1 million. A 10% increase in the
underlying commodity prices would increase this loss by $19.7 million.
For 2002, the Company has entered into swap arrangements on 12,500 BOPD for
the first quarter at an average WTI price of $25.91 per barrel. For the
remainder of 2002, the Company purchased put options with a WTI strike price of
$22.00 per barrel, on 19,000 BOPD for the second quarter, and on 14,000 BOPD for
both the third and fourth quarters. At December 31, 2000, the market value of
these hedge positions for 2002 is a gain of $8.3 million. A 10% increase in
the underlying commodity prices would reduce this gain by $2.6 million.
All of these agreements expose the Company to counterparty credit risk to the
extent that the counterparty is unable to meet its settlement commitments to the
Company.
The Company set an original base level capital spending budget for 2001 of
$181.0 million, with the potential for up to $24.0 million in additional capital
spending, depending upon the level of drilling success. Due to the high gas
prices in California, Nuevo deferred certain capital associated with its thermal
operations and recently
34
NUEVO ENERGY COMPANY
adjusted its base capital spending budget to approximately $160.0 million,
assuming gas prices remain at these high levels for the remainder of the year.
Depending on the level of drilling success this year, capital spending could be
increased by $18.0 million in 2001. Highlights of Nuevo's adjusted 2001 capital
budget include the following:
. $123.0 million (77%) for exploitation projects, primarily earmarked for
building on successful exploitation projects onshore California.
. $24.0 million (15%) for exploration, mainly for drilling eight to ten
exploration wells in California and three to four exploration wells in
Africa.
. $13.0 million (8%) for other capital projects.
Approximately 56% of Nuevo's $123.0 million exploitation budget in 2001 is
allocated to onshore California exploitation projects, 29% to offshore
California projects and 15% to international projects. The Company plans to
drill a total of 73 exploitation wells in 2001. By comparison, Nuevo spent a
total of $96.0 million company-wide for exploitation projects and drilled a
total of 178 exploitation wells in 2000.
Onshore California, the Company's single largest exploitation project in 2001
is the continuing development of its Star Fee acreage in the Cymric Field. In
2001, this development will include drilling 7 Diatomite development wells and
two follow-up wells to the highly successful Star Fee 701 well in this acreage.
Nuevo also has budgeted to continue expanding the waterflood development and
undertake other projects in its Brea Olinda Field and to continue successful
drilling projects in the Belridge Field. Offshore California, Nuevo's capital
spending is directed primarily at continuing development drilling in the Santa
Clara Field and in the Pitas Point Field to further boost natural gas
production. Internationally, the Company's exploitation budget is earmarked
mainly for drilling additional horizontal wells to enhance the ongoing
development in the Yombo Field offshore the Republic of Congo, West Africa.
Approximately 63% of Nuevo's $24.0 million exploration budget in 2001 will
be used to drill nine exploratory wells in California and approximately 37% is
allocated to drill three to four exploratory wells in West and North Africa.
The Company believes its working capital, cash provided by operating
activities, project financing resources and the Credit Facility are sufficient
to meet these capital commitments. The Company has not prepared a capital
budget for annual periods after 2001.
Estimates of future net cash flows from proved reserves of oil, gas,
condensate and natural gas liquids were made in accordance with SFAS No. 69,
"Disclosures about Oil and Gas Producing Activities." (See Note 14 to the Notes
to Consolidated Financial Statements). The estimates are based on realized
prices at year-end 2000 of $19.51 per barrel of oil and $13.94 per MCF of 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. 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. Natural gas prices were unusually high at December
31, 2000. Natural gas costs are a significant component of the Company's
thermal operating costs in California. As such, the unusually high prices at
year-end 2000 had an unfavorable effect on the Company's reserves for its
thermal oil producing properties.
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
In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities". This
statement, as amended by SFAS No. 137 and SFAS No. 138, establishes standards of
accounting for and disclosures of derivative instruments and hedging activities.
This
35
NUEVO ENERGY COMPANY
statement requires all derivative instruments to be carried on the balance
sheet at fair value and is effective for the Company beginning January 1, 2001.
The Company adopted SFAS No. 133 on January 1, 2001. In accordance with the
current transition provisions of SFAS 133, the Company will record a net-of-tax
cumulative effect transition adjustment of $(16.0) million (net of related tax
benefit of $10.8 million) in accumulated other comprehensive income to recognize
the fair value of its derivatives designated as cash-flow hedging instruments at
the date of adoption.
All of the Company's derivative instruments will be recognized on the
balance sheet at their fair value. The Company currently uses swaps and options
to hedge its exposure to material changes in the future price of crude oil.
Contingencies and Other Matters
The Company had been named as a defendant in Gloria Garcia Lopez and Husband,
Hector S. Lopez, Individually, and as successors to Galo Land & Cattle Company
v. Mobil Producing Texas & New Mexico, et al. in the 79th Judicial District
Court of Brooks County, Texas. On June 9, 2000, the parties entered into a
memorandum of settlement agreement, pursuant to which the lawsuit was dismissed,
the defendants paid the plaintiffs $12.0 million and the lease agreement was
amended. Nuevo's working interest in these properties is 20%, and its share of
the settlement payment was approximately $2.4 million.
On September 22, 2000, the Company was named as a defendant in the lawsuit
Thomas Wachtell et al. versus Nuevo Energy Company in the Superior Court of Los
Angeles County, California. The plaintiffs, who own certain interests in the
Point Pedernales properties, have asserted numerous causes of action including
breach of contract, fraud and conspiracy in connection with the plaintiff's
allegation that: (i) royalties have not been properly paid to them for
production from the Point Pedernales field, (ii) payments have not been made to
them related to production from the Sacate field, and, (iii) the Company has
failed to recognize the plaintiff's interests in the Tranquillon Ridge project.
The plaintiffs have not specified damages. The Company has not yet been
required to file an answer, but believes the allegations are without merit and
intends to vigorously contest these claims. Management does not believe that
the outcome of this matter will have a material adverse impact on the Company's
operating results, financial condition or liquidity.
The Company has been named as a defendant in certain other 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 March 1999, the Company discovered that a non-officer employee had
fraudulently authorized and diverted for personal use Company funds totaling
$5.9 million, $1.6 million in 1999 and the remainder in 1998, that were intended
for international exploration. The Board of Directors engaged a Certified Fraud
Examiner to conduct an in-depth review of the fraudulent transactions. The
investigation confirmed that only one employee was involved in the matter and
that all misappropriated funds were identified. The Company has reviewed and,
where appropriate, strengthened its internal control procedures. In August
2000, the Company recorded $1.5 million of other income for a partial
reimbursement of these previously expensed funds, resulting from the negotiated
settlement of a related legal claim.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects the Company's Point Pedernales field with
shore-based processing facilities. The volume of the spill was estimated to be
163 barrels of oil. Repairs were completed by the end of 1997, and production
recommenced in December 1997. The costs of the clean- up and the cost to repair
the pipeline either have been or are expected to be covered by insurance held by
the Company, less the Company's deductibles of $120,000. The Company incurred
clean-up and repair costs of $ 0.3 million, $0.5 million, and $2.4 million
during 2000, 1999, and 1998, respectively. As of December 31, 2000, the Company
had received insurance reimbursements of $4.1 million, with a remaining
insurance receivable of $1.3 million. For amounts not covered by insurance,
including the $120,000 deductible, the Company recorded lease operating expenses
of $0.4 million and $0.5 million during 1999 and 1998,
36
NUEVO ENERGY COMPANY
respectively. No such expenses were recorded in 2000. Additionally, the Company
has exposure to certain costs that are expected to be recoverable from
insurance, including certain fines, penalties, and damages, for which the
Company accrued $0.7 million as of December 31, 2000, as a receivable and
payable. The Company also has exposure to costs that may not be recoverable from
insurance, including certain fines, penalties, and damages. Such costs are not
quantifiable at this time, but are not expected to be material to the Company's
operating results, financial condition or liquidity.
The Company's international investments involve risks typically associated
with investments in emerging markets such as an uncertain political, economic,
legal and tax environment and expropriation and nationalization of assets. In
addition, if a dispute arises in 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 that the Company will
be successful in so protecting itself. A portion of the Company's investment in
the Congo is insured through political risk insurance provided by OPIC. The
political risk insurance through OPIC covers up to $25.0 million relating to
expropriation and political violence, which is the maximum coverage available
through OPIC. The Company has no deductible for this insurance.
In connection with their respective February 1995 acquisitions of two
subsidiaries (each a "Congo subsidiary") owning interests in the Yombo field
offshore Congo, 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. Under the tax law in the Congo, as it existed when this
acquisition took place, if an entity is acquired in its entirety and that entity
has certain tax attributes, for example tax loss carryforwards from operations
in the Republic of Congo, the subsequent owners of that entity can continue to
utilize those losses without restriction. Pursuant to the agreement, the Company
and CMS may be liable to the seller for the recapture of dual consolidated
losses (net operating losses of any domestic corporation that are subject to an
income tax of a foreign country without regard to the source of its income or on
a residence basis) utilized by the seller in years prior to the acquisitions if
certain triggering events occur, including (i) a disposition by either 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 only time limit associated with the occurrence of a triggering
event relates to the utilization of a dual consolidated loss in a foreign
jurisdiction. A dual consolidated loss that is utilized to offset income in a
foreign jurisdiction is only subject to recapture for 15 years following the
year in which the dual consolidated loss was incurred for US income tax
purposes. 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 $42.5 million if a triggering event with
respect to the Company occurs. Additionally, 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 $61.0 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.
During 1997, a new government was established in the Congo. Although the
political situation in the Congo has not to date had a material adverse effect
on the Company's operations in the Congo, no assurances can be made that
continued political unrest in West Africa will not have a material adverse
effect on the Company and its operations in the Congo in the future.
In 1996, the previous Congo government requested that the convention
governing the Marine 1 Exploitation Permit be converted to a Production Sharing
Agreement ("PSA"). Preliminary discussions were held with the government in
early 1997. Nuevo is under no obligation to convert to a PSA, and its existing
convention is valid and protected by law. The Company's position is that any
conversion to a PSA would have no detrimental impact to Nuevo, otherwise, Nuevo
will not agree to any such conversion. In late 1997, a new government was
established in the Congo. The new government has recently begun discussions with
Nuevo and its partner
37
NUEVO ENERGY COMPANY
concerning the conversion to a PSA. Discussions with the new government
are ongoing and, to date, no agreement has been reached concerning conversion to
a PSA.
Contingent Payment and Price Sharing Agreements
In connection with the acquisition from Unocal in 1996 of the properties
located in California, the Company is obligated to make a contingent payment for
the years 1998 through 2004 if oil prices exceed thresholds set forth in the
agreement with Unocal. Any contingent payment will be accounted for as a
purchase price adjustment to oil and gas properties. The contingent payment
will equal 50% of the difference between the actual average annual price
received on a field-by-field basis (capped by a maximum price) and a minimum
price, less ad valorem and production taxes, multiplied by the actual number of
barrels of oil sold that are produced from the properties acquired from Unocal
during the respective year. The minimum price of $17.75 per Bbl under the
agreement (determined based on the near month delivery of WTI crude oil on the
NYMEX) is escalated at 3% per year and the maximum price of $21.75 per Bbl on
the NYMEX is escalated at 3% per year. Minimum and maximum prices are reduced to
reflect the field level price by subtracting a fixed differential established
for each field. The reduction was established at approximately the differential
between actual sales prices and NYMEX prices in effect in 1995 ($4.34 per Bbl
weighted average for all the properties acquired from Unocal). The Company
accumulates credits to offset the contingent payment when prices are $.50 per
Bbl or more below the minimum price. The Company computes this calculation
annually and had accumulated $8.5 million in price credits as of December 31,
2000, which will be used to reduce future amounts owed under the contingent
payment. There is no value attributable to this credit other than to offset
future payments. At the end of 2004, if the Company still maintains a credit
position with respect to this agreement, the credit will expire worthless. As
of December 31, 2000, the Company had never been obligated to make a payment to
Unocal under the terms of the agreement. However, a continuation of higher than
normal oil price realizations is expected to trigger payments under this
agreement beginning in March of 2002.
In connection with the acquisition of the Congo properties in 1995, the
Company entered into a price sharing agreement with the seller. There is no
termination date associated with this agreement. Under the terms of the
agreement, if the average price received for the oil production during the year
is greater than the benchmark price established by the agreement, then the
Company is obligated to pay the seller 50% of the difference between the
benchmark price and the actual price received, for all the barrels associated
with this acquisition. The benchmark price for 1999 was $14.79 per Bbl, and the
benchmark price for 2000 was $15.19 per Bbl. The benchmark price increases each
year, based on the increase in the Consumer Price Index. For 2000, the effect
of this agreement was that Nuevo only owned upside above $15.19 per Bbl on
approximately 56% of its Congo production. In 2000, the Company was obligated
to pay the seller $5.4 million pursuant to this price sharing agreement. This
obligation was accounted for as a reduction in oil revenues. No such payments
were due in 1998 or 1999.
The Company acquired a 12% working interest in the Point Pedernales oil field
from Unocal in 1994 and the remainder of its 80.3 % working interest from Torch
in 1996. The Company is entitled to all revenue proceeds up to $9.00 per Bbl,
with the excess revenue over $9.00 per Bbl, if any, shared among the Company and
the original owners from whom Torch acquired its interest. Amounts below $9.00
per Bbl are owned by the Company and the other working interest owners based on
their respective ownership interests. For 2000, the effect of this agreement is
that Nuevo was entitled to receive the pricing upside above $9.00 per Bbl on
approximately 34% of the gross Point Pedernales production. Effective January 1,
2001, the Company will be entitled to receive the pricing upside above $9.00 per
Bbl on approximately 70% of the gross Point Pedernales production. As of
December 31, 2000, the Company had $581,000 accrued as its obligation under this
agreement. As of December 31, 1999, the Company had $5.1 million accrued as its
obligation under this agreement, which was paid in the first quarter of 2000.
38
NUEVO ENERGY COMPANY
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk, including adverse changes in commodity
prices and interest rates.
Commodity Price Risk - The Company produces and sells crude oil, natural gas
and natural gas liquids. As a result, the Company's operating results can be
significantly affected by fluctuations in commodity prices caused by changing
market forces. The Company reduces its exposure to price volatility by hedging
its production through swaps, options and other commodity derivative
instruments. In a typical swap transaction, the Company will have the right to
receive from the counterparty to the hedge the excess of the fixed price
specified in the hedge contract and a floating price based on a market index,
multiplied by the quantity hedged. If the floating price exceeds the fixed
price, the Company is required to pay the counterparty the difference. In a
typical option contract, the Company purchases the right to receive from the
counterparty the difference, if any, between a fixed price specified in the
option less a floating market price. If the floating price is above the fixed
price, the Company is not entitled to a payment. The Company uses hedge
accounting for these instruments, and settlements of gains or losses on these
contracts are reported as a component of oil and gas revenues and operating cash
flows in the period realized. These agreements expose the Company to
counterparty credit risk to the extent that the counterparty is unable to meet
its settlement commitments to the Company.
The Company follows formal policies regarding the management of oil price
risk to ensure the Company's ability to optimally manage its portfolio of
investment opportunities. To accomplish this, the policy requires that
derivative financial instruments must be entered into at least 18 months in
advance of the effective period. For 2001, the Company has entered into swap
arrangements on 26,000 BOPD for the first quarter at an average WTI price of
$19.52, for the second quarter on 25,000 BOPD at an average WTI price of $19.54,
for the third quarter on 20,000 BOPD at an average WTI price of $21.22, and for
the fourth quarter on 15,500 BOPD at an average WTI price of $22.95 per barrel.
Subsequent to December 31, 2000, the Company entered into swaps on an additional
1,200 BOPD for the second quarter, bringing the total to 26,200 BOPD at an
average price of $19.84 per barrel. On a physical volume basis, these hedges
cover 47% of the Company's estimated 2001 oil production. At December 31, 2000,
the market value of the swaps in place for 2001 was a loss of $35.1 million. A
10% increase in the underlying commodity prices would increase this loss by
$19.7 million.
For 2002, the Company has entered into swap arrangements on 12,500 BOPD for
the first quarter at an average WTI price of $25.91 per barrel. For the
remainder of 2002, the Company purchased put options with a WTI strike price of
$22.00 per barrel, on 19,000 BOPD for the second quarter, and on 14,000 BOPD for
both the third and fourth quarters. At December 31, 2000, the market value of
these hedge positions for 2002 is a gain of $8.3 million. A 10% increase in
the underlying commodity prices would reduce this gain by $2.6 million.
Interest Rate Risk - The Company may enter into financial instruments such as
interest rate swaps to manage the impact of changes in interest rates. The
Company's exposure to changes in interest rates primarily results from its
short-term and long-term debt with both fixed and floating interest rates. The
following table presents principal amounts (stated in thousands) and the related
average interest rates by year of maturity for the Company's debt obligations at
December 31, 2000:
Fair
Value
2001 2002 2003 2004 Thereafter Total Liability
---- ---- ---- ---- ---------- -------- ---------
Long-term debt:
Variable rate -- -- -- -- -- -- --
Average interest rate -- -- -- -- -- -- --
Fixed rate -- -- -- -- $409,727 $409,727 $412,823
Average interest rate -- -- -- -- 9.45% 9.45%
39
NUEVO ENERGY COMPANY
Item 8. Financial Statements and Supplementary Data
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
Page
Number
------
Independent Auditors' Report.................................................................... 41
Financial Statements:
Consolidated Balance Sheets as of December 31, 2000
and 1999..................................................................................... 42
Consolidated Statements of Operations for the Years Ended
December 31, 2000, 1999 and 1998............................................................. 43
Consolidated Statements of Changes in Stockholders'
Equity for the Years Ended December 31, 2000,
1999 and 1998................................................................................ 44
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2000, 1999 and 1998............................................................. 45
Notes to Consolidated Financial Statements...................................................... 46
40
NUEVO ENERGY COMPANY
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Nuevo Energy Company:
We have audited the accompanying consolidated balance sheets of Nuevo Energy
Company and subsidiaries as of December 31, 2000 and 1999, 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, 2000.
These consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Nuevo Energy
Company and subsidiaries as of December 31, 2000 and 1999, and the results of
their operations and their cash flows for each of the years in the three-year
period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2000, the Company changed its method of accounting for its processed
fuel oil and natural gas liquids inventories.
KPMG LLP
Houston, Texas
February 8, 2001
41
NUEVO ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
(AMOUNTS IN THOUSANDS, EXCEPT SHARE DATA)
December 31,
-----------------------------------
2000 1999
---------- ----------
ASSETS
-------
CURRENT ASSETS:
Cash and cash equivalents...................................................... $ 39,447 $ 10,288
Accounts receivable............................................................ 71,777 45,004
Product inventory.............................................................. 3,230 4,610
Prepaid expenses and other..................................................... 4,042 6,389
---------- ----------
Total current assets........................................................ 118,496 66,291
---------- ----------
PROPERTY AND EQUIPMENT, at cost:
Land........................................................................... 53,246 51,017
Oil and gas properties (successful efforts method)............................. 1,102,233 1,002,779
Gas plant facilities........................................................... 12,020 12,140
Other facilities............................................................... 12,907 11,874
---------- ----------
1,180,406 1,077,810
Accumulated depreciation, depletion and amortization........................... (496,444) (429,349)
---------- ----------
683,962 648,461
---------- ----------
DEFERRED TAX ASSETS, net......................................................... 16,282 24,005
OTHER ASSETS..................................................................... 29,284 21,273
---------- ----------
$ 848,024 $ 760,030
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
Accounts payable............................................................... $ 25,895 $ 20,492
Accrued interest............................................................... 5,757 2,353
Accrued drilling costs......................................................... 12,467 13,242
Accrued lease operating costs.................................................. 30,037 13,956
Other accrued liabilities...................................................... 17,668 10,557
Current maturities of long-term debt........................................... -- 750
---------- ----------
Total current liabilities................................................... 91,824 61,350
---------- ----------
LONG-TERM DEBT, net of current maturities........................................ 409,727 340,750
OTHER LONG-TERM LIABILITIES...................................................... 8,356 9,292
COMPANY-OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED SECURITIES OF
NUEVO FINANCING I............................................................... 115,000 115,000
CONTINGENCIES (Note 11)
STOCKHOLDERS' EQUITY:
Preferred stock, $1.00 par value, 10,000,000 shares authorized; 7% Cumulative
Convertible Preferred Stock, none issued and outstanding at December 31, 2000
and 1999...................................................................... -- --
Common stock, $0.01 par value, 50,000,000 shares authorized, 20,620,296 and
20,437,371 shares issued and 16,632,318 and 17,931,393 shares outstanding at
December 31, 2000 and 1999, respectively...................................... 206 204
Additional paid-in capital..................................................... 361,643 357,855
Treasury stock, at cost, 3,813,074 and 2,430,074 shares, at December 31, 2000
and 1999, respectively........................................................ (74,703) (49,605)
Stock held by benefit trust, 174,904 and 75,904 shares, at December 31, 2000
and 1999, respectively........................................................ (3,646) (3,184)
Deferred stock compensation.................................................... (602) (216)
Accumulated deficit............................................................ (59,781) (71,416)
---------- ----------
Total stockholders' equity................................................. 223,117 233,638
---------- ----------
$ 848,024 $ 760,030
========== ==========
See Notes to Consolidated Financial Statements.
42
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
Year Ended December 31,
-------------------------------------------------
2000 1999 1998
-------- -------- ---------
REVENUES:
Oil and gas revenues.............................................. $331,655 $242,274 $ 242,675
Gain on sale of assets, net....................................... 657 85,294 5,768
Interest and other income......................................... 4,293 4,667 4,260
-------- -------- ---------
336,605 332,235 252,703
-------- -------- ---------
COSTS AND EXPENSES:
Lease operating expenses.......................................... 156,476 130,549 137,906
Exploration costs................................................. 9,774 14,017 16,562
Revision of impairment on assets held for sale.................... -- -- (3,740)
Provision for impairment of oil and gas properties................ -- -- 68,904
General and administrative expenses............................... 32,974 32,266 28,094
Depreciation, depletion and amortization.......................... 67,370 80,652 85,036
Interest expense, net............................................. 37,472 33,110 32,471
Dividends on Guaranteed Preferred Beneficial Interests in
Company's Convertible Debentures (TECONS)......................... 6,613 6,613 6,613
Other expense..................................................... 5,103 8,945 7,754
-------- -------- ---------
315,782 306,152 379,600
-------- -------- ---------
Income (loss) before income taxes and cumulative effect............. 20,823 26,083 (126,897)
Income tax (expense) benefit........................................ (8,392) 5,359 32,625
-------- -------- ---------
Income (loss) before cumulative effect.............................. 12,431 31,442 (94,272)
Cumulative effect of a change in accounting principle, net of
income tax benefit of $537......................................... (796) -- --
-------- -------- ---------
Net income (loss)................................................... $ 11,635 $ 31,442 $ (94,272)
======== ======== =========
Earnings (loss) per Common share -- Basic:
Income (loss) before cumulative effect............................. $ 0.71 $ 1.62 $ (4.77)
Cumulative effect of a change in accounting principle, net of
income tax benefit................................................ (0.04) -- --
-------- -------- ---------
Net income (loss).................................................. $ 0.67 $ 1.62 $ (4.77)
======== ======== =========
Weighted average Common shares outstanding.......................... 17,447 19,353 19,753
======== ======== =========
Earnings (loss) per Common share -- Diluted:
Income (loss) before cumulative effect............................. $ 0.68 $ 1.61 $ (4.77)
Cumulative effect of a change in accounting principle, net of
income tax benefit................................................ (0.04) -- --
-------- -------- ---------
Net income (loss).................................................. $ 0.64 $ 1.61 $ (4.77)
======== ======== =========
Weighted average Common and dilutive potential Common shares
outstanding........................................................ 17,941 19,507 19,753
======== ======== =========
See Notes to Consolidated Financial Statements.
43
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(Amounts in Thousands)
Common Stock Additional Stock held Total
---------------- Paid-In Treasury by Benefit Deferred Stock Accumulated Stockholders'
Shares Amount Capital Stock Trust Compensation Deficit Equity
------- ------ ---------- ---------- ----------- --------------- ------------ --------------
January 1, 1998........ 19,696 $202 $354,296 $(19,929) $(1,244) $ -- $ (8,586) $324,739
====== ==== ======== ======== ======= ============== ========= ========
Exercise of stock
options and related 70 1 1,304 -- -- -- -- 1,305
tax benefit...........
Stock acquired by -- -- -- 488 (1,341) -- -- (853)
benefit trust.........
Withdrawal from 18 -- -- -- 853 -- -- 853
benefit trust.........
Sale of Treasury shares 3 -- -- 106 -- -- -- 106
Net loss............... -- -- -- -- -- -- (94,272) (94,272)
------ ---- -------- -------- ------- -------------- --------- --------
December 31, 1998...... 19,787 203 355,600 (19,335) (1,732) -- (102,858) 231,878
====== ==== ======== ======== ======= ============== ========= ========
Exercise of stock
options and related 129 1 1,810 -- -- -- -- 1,811
tax benefit...........
Stock acquired by -- -- -- 1,850 (1,850) -- -- --
benefit trust.........
Issuance of warrants -- -- 120 -- -- -- -- 120
and other.............
Withdrawal from 14 -- -- -- 398 -- -- 398
benefit trust.........
Purchase of Treasury (1,999) -- -- (32,120) -- -- -- (32,120)
shares................
Deferred stock -- -- 325 -- -- (216) -- 109
compensation..........
Net income............. -- -- -- -- -- -- 31,442 31,442
------ ---- -------- -------- ------- -------------- --------- --------
December 31, 1999...... 17,931 204 357,855 (49,605) (3,184) (216) (71,416) 233,638
====== ==== ======== ======== ======= ============== ========= ========
Exercise of stock
options and related 183 2 3,200 -- -- -- -- 3,202
tax benefit...........
Stock acquired by -- -- -- 462 (462) -- -- --
benefit trust.........
Purchase of Treasury (1,482) -- -- (25,560) -- -- -- (25,560)
shares................
Deferred stock -- -- 588 -- -- (386) -- 202
compensation..........
Net income............. -- -- -- -- -- -- 11,635 11,635
------ ---- -------- -------- ------- -------------- --------- --------
December 31, 2000...... 16,632 $206 $361,643 $(74,703) $(3,646) $(602) $ (59,781) $223,117
====== ==== ======== ======== ======= ============== ========= ========
See Notes to Consolidated Financial Statements.
44
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(AMOUNTS IN THOUSANDS)
Year Ended December 31,
-----------------------------------------------------
2000 1999 1998
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss).............................................. $ 11,635 $ 31,442 $ (94,272)
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Cumulative effect of a change in accounting principle, net
of income tax benefit...................................... 796 -- --
Depreciation, depletion and amortization................... 67,370 80,652 85,036
Dry hole costs............................................. 2,503 8,051 12,962
Amortization of debt financing costs....................... 1,983 1,696 1,643
Amortization of deferred revenue........................... -- -- (1,625)
Revision of impairment on assets held for sale............. -- -- (3,740)
Provision for impairment of oil and gas properties......... -- -- 68,904
Gain on sale of assets, net................................ (657) (85,294) (5,768)
Deferred taxes............................................. 8,763 (6,559) (32,520)
(Depreciation) appreciation of deferred compensation (234) 801 (1,138)
liability.................................................
Debt modification costs.................................... -- 3,064 --
Other...................................................... 203 229 --
--------- --------- ---------
92,362 34,082 29,482
Changes in assets and liabilities:
Accounts receivable........................................ (26,266) (20,461) 13,051
Accounts payable........................................... 5,403 (4,527) 6,634
Accrued liabilities........................................ 25,490 17,901 (5,813)
Other...................................................... (3,287) (2,971) (7,521)
--------- --------- ---------
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES.............. 93,702 24,024 35,833
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties............................ (104,420) (125,919) (157,352)
Proceeds from sales of properties.............................. 3,083 234,312 11,830
Additions to gas plant and other facilities.................... (3,388) (10,247) (2,813)
--------- --------- ---------
NET CASH FLOWS (USED IN) PROVIDED BY INVESTING ACTIVITIES.... (104,725) 98,146 (148,335)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings....................................... 197,100 142,590 240,900
Debt issuance and modification costs........................... (5,186) (8,053) (3,360)
Payments of long-term debt..................................... (128,873) (223,392) (128,254)
Proceeds from exercise of stock options........................ 2,701 1,690 1,305
Proceeds from sale of treasury stock........................... -- -- 106
Purchase of treasury shares.................................... (25,560) (32,120) --
--------- --------- ---------
NET CASH FLOWS PROVIDED BY (USED IN) FINANCING ACTIVITIES..... 40,182 (119,285) 110,697
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents............. 29,159 2,885 (1,805)
Cash and cash equivalents at beginning of year................... 10,288 7,403 9,208
--------- --------- ---------
Cash and cash equivalents at end of year......................... $ 39,447 $ 10,288 $ 7,403
========= ========= =========
See Notes to Consolidated Financial Statements.
45
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
Nuevo Energy Company ("Nuevo") was formed as a Delaware corporation on
March 2, 1990, to acquire the businesses of certain public and private
partnerships (collectively "Predecessor Partnerships"). On July 9, 1990, the
plan of consolidation ("Plan of Consolidation") was approved by limited partners
owning a majority of units of limited partner interests in the partnerships
whereby the net assets of the Predecessor Partnerships, which were subject to
such Plan of Consolidation, were exchanged for Common Stock of Nuevo ("Common
Stock"). All references to the "Company" include Nuevo and its majority and
wholly-owned subsidiaries, unless otherwise indicated or the context indicates
otherwise.
The Company is primarily engaged in the exploration for, and the acquisition,
exploitation, development and production of crude oil and natural gas. The
Company's principal oil and gas properties are located domestically onshore and
offshore California and the onshore Gulf Coast region; and internationally
offshore West Africa.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of Nuevo and its
majority and wholly-owned subsidiaries. The Company's 48.5% general partner
interest in Richfield Gas Storage Partnership was pro rata consolidated through
February 1998, at which time the Company's interest was sold. The consolidated
financial statements also include Bright Star Gathering, Inc., which was 80%
owned by the Company until it was sold in July 1998. All significant
intercompany accounts and transactions have been eliminated in consolidation.
Oil and Gas Properties
The Company utilizes the successful efforts method of accounting for its
investments in oil and gas properties. Under successful efforts, oil and gas
lease acquisition costs and intangible drilling costs associated with
exploration efforts that result in the discovery of proved reserves and costs
associated with development drilling, whether or not successful, are capitalized
when incurred. When a proved property is sold, ceases to produce or is
abandoned, a gain or loss is recognized. When an entire interest in an unproved
property is sold for cash or cash equivalent, gain or loss is recognized, taking
into consideration any recorded impairment. When a partial interest in an
unproved property is sold, the amount received is treated as a reduction of the
cost of the interest retained.
Unproved leasehold costs are capitalized pending the results of exploration
efforts. Significant unproved leasehold costs are reviewed periodically and a
loss is recognized to the extent, if any, that the cost of the property has been
impaired. An impairment of unproved leasehold costs of $8.1 million was
recognized as of December 31, 1998. No such impairment was recognized for the
years ended December 31, 2000 or 1999. Exploration costs, including geological
and geophysical expenses, exploratory dry holes and delay rentals, are charged
to expense as incurred.
Costs of successful wells, development dry holes and proved leases are
capitalized and depleted on a unit-of-production basis over the life of the
remaining proved reserves. Capitalized drilling costs are depleted on a unit-
of-production basis over the life of the remaining proved developed reserves.
Total estimated costs of $82.1 million (net of salvage value) for future
dismantlement, abandonment and site remediation are computed by the Company and
an independent consultant and are included when calculating depreciation and
depletion using the unit-of-production method. At December 31, 2000, the
Company had recorded $60.8 million as a component of accumulated depreciation,
depletion and amortization.
46
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
In accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of", the Company reviews its
long-lived assets to be held and used, including proved oil and gas properties
accounted for using the successful efforts method of accounting, on a depletable
unit basis whenever events or circumstances indicate that the carrying value of
those assets may not be recoverable. SFAS No. 121 requires an impairment loss be
recognized when the carrying amount of an asset exceeds the sum of the
undiscounted estimated future cash flows. In this circumstance, the Company
recognizes an impairment loss equal to the difference between the carrying value
and the fair value of the asset. Fair value is estimated to be the present value
of expected future net cash flows from proved reserves, utilizing a risk-
adjusted rate of return.
During 1998, the Company recorded a fair value impairment totaling $60.8
million on its East Coalinga, Las Cienegas, Beta, Point Pedernales and South
Mountain fields and certain other insignificant oil and gas properties due to
the significant, sustained decline in domestic oil prices during the year from
an average Company realized price of $14.86 per barrel for 1997 to an average
realized price of $9.25 per barrel in 1998. No such impairment was recognized
during 2000 or 1999.
During 1999 and 1998, interest costs associated with non-producing leases and
exploration and development projects were capitalized only for the period that
activities were in progress to bring these projects to their intended use. The
capitalization rates were based on the Company's weighted average cost of funds
used to finance expenditures. No such costs were capitalized in 2000.
Any reference to oil and gas reserve information in the Notes to Consolidated
Financial Statements is unaudited.
Environmental Liabilities
Environmental expenditures that relate to current or future revenues are
expensed or capitalized as appropriate. Expenditures that relate to an existing
condition caused by past operations, and do not contribute to current or future
revenue generation, are expensed. Liabilities are recorded when environmental
assessments and/or clean-ups are probable, and the costs can be reasonably
estimated. Generally, the timing of these accruals coincides with the Company's
commitment to a formal plan of action.
Gas Plant and Other Facilities
Gas plant and other facilities include the costs to acquire certain gas plant
and other facilities and to secure rights-of-way. Capitalized costs associated
with gas plant and other facilities are amortized primarily over the estimated
useful lives of the various components of the facilities utilizing the straight-
line method. The estimated useful lives of such assets range from three to
thirty years. The Company reviews these assets for impairment whenever events
or changes in circumstances indicate that their carrying amounts may not be
recoverable.
Comprehensive Income
Comprehensive income includes net income and all changes in other
comprehensive income including, among other things, foreign currency translation
adjustments, and unrealized gains and losses on investments in debt and equity
securities that are classified as available-for-sale. There are no differences
between comprehensive income (loss) and net income (loss) for the periods
presented.
Recognition of Crude Oil and Natural Gas Revenue
The Company uses the entitlement method for recording sales of crude oil and
natural gas from producing wells. Under the entitlement method, revenue is
recorded based on the Company's net revenue interest in production. Deliveries
of crude oil and natural gas in excess of the Company's net revenue interests
are recorded as liabilities and under-deliveries are recorded as assets.
Production imbalances are recorded at the lower of the sales price in effect at
the time of production or the current market value. Substantially all such
amounts are
47
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
anticipated to be settled with production in future periods. The Company's
imbalance position was not significant in terms of units or value at
December 31, 2000 and 1999.
Derivative Financial Instruments
The Company utilizes derivative financial instruments to reduce its exposure
to decreases in the market prices of crude oil and natural gas. Commodity
derivatives utilized as hedges include futures, swap and option contracts, which
are used to hedge crude oil and natural gas prices. Basis swaps are sometimes
used to hedge the basis differential between the derivative financial instrument
index price and the commodity field price. In order to qualify as a hedge,
price movements in the underlying commodity derivative must be highly 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 and losses on option and futures contracts 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. Premiums paid on option
contracts are deferred in other assets and amortized into oil and gas revenues
over the terms of the respective option contracts. Gains or losses attributable
to the termination of a derivative financial instrument 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, 2000
or 1999. Gains or losses on derivative financial instruments that do not
qualify as a hedge are recognized in income currently.
As a result of hedging transactions, oil and gas revenues were reduced by
$117.7 million and $44.9 million in 2000 and 1999, respectively, and increased
by $0.6 million in 1998.
New Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities". This statement, as amended by
SFAS No. 137 and SFAS No. 138, establishes standards of accounting for and
disclosures of derivative instruments and hedging activities. This statement
requires all derivative instruments to be carried on the balance sheet at fair
value and is effective for the Company beginning January 1, 2001.
The Company adopted SFAS No. 133 on January 1, 2001. In accordance with the
current transition provisions of SFAS 133, the Company will record a net-of-tax
cumulative-effect transition adjustment of $(16.0) million (net of related tax
benefit of $10.8 million)(unaudited) in accumulated other comprehensive income
to recognize the fair value of its derivatives designated as cash-flow hedging
instruments at the date of adoption.
All of the Company's derivative instruments will be recognized on the
balance sheet at their fair value. The Company currently uses swaps and options
to hedge its exposure to material changes in the future price of crude oil.
Earnings per Share ("EPS")
Basic EPS is computed by dividing income available to common stockholders by
the weighted-average number of common shares outstanding for the period.
Diluted EPS reflects the potential dilution that could occur if securities or
other contracts to issue Common Stock were exercised or converted into Common
Stock or resulted in the issuance of Common Stock that then shared in the
earnings of the entity. For the year ended December 31, 2000 and 1999, the
Company's potentially dilutive securities included dilutive stock options. For
the year ended December 31, 1998, the Company did not have any potentially
dilutive securities, as a net loss was incurred during this period. Potential
dilution may also occur in future periods due to the Company-Obligated
Mandatorily Redeemable Convertible Preferred Securities of Nuevo Financing I
("TECONS").
48
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Stock-Based Compensation
The Company applies the intrinsic value method for accounting for stock and
stock-based compensation described by Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees". Had the Company applied the
fair value method described by SFAS No. 123, "Accounting for Stock-Based
Compensation", it would have incurred compensation expense for stock-based
compensation in 2000, 1999 and 1998. (See Note 6 for the SFAS No. 123 pro forma
effects on income and earnings per share.)
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
money market instruments with an original maturity of three months or less to be
cash equivalents. Interest paid in cash, net of amounts capitalized, for 2000,
1999 and 1998 was $32.1 million, $33.5 million and $31.6 million, respectively.
Net amounts (refunded) paid in cash for income taxes for 2000, 1999 and 1998
were ($486,000), $2,250,000 and $1,332,000, respectively.
Cumulative Effect of a Change in Accounting Principle
Historically, the Company recorded inventory relating to quantities of
processed fuel oil and natural gas liquids in storage at current market pricing.
Also, fuel oil in inventory was stated at year end market prices less
transportation costs, and the Company recognized changes in the market value of
inventory from one period to the next as oil revenues. In December 2000, the
staff of the Securities and Exchange Commission announced that commodity
inventories should be carried at lower of cost or market rather than at market
value. As a result, the Company changed its inventory valuation method to the
lower of cost or market in the fourth quarter of 2000, retroactive to the
beginning of the year. Accordingly, the Company recorded a non-cash, cumulative
effect of a change in accounting principle to earnings, effective January 1,
2000, of $796,000 (net of the related income tax benefit of $537,000) to value
product inventory at lower of cost or market. Quarterly results for 2000 were
restated to reflect this change in accounting.
Had the Company valued its product inventory at lower of cost or market prior
to 2000, net income (loss) would have been $30.6 million and $(94.3) million for
the years ended December 31, 1999 and 1998, respectively.
Use of Estimates
In order to prepare these financial statements in conformity with accounting
principles generally accepted in the United States, 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. Actual
results could differ from those estimates.
Reclassifications
Certain reclassifications of prior period amounts have been made to conform
to the current presentation.
3. ACQUISITIONS
In June 1999, the Company acquired working interests in oil and gas
properties located onshore and offshore California for $61.4 million from Texaco
Inc. The working interests in the acquired properties range
49
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
from an additional 25% interest in properties already owned and operated by the
Company to 100%. To purchase these assets, the Company used funds from a $100.0
million interest-bearing escrow account that provided "like-kind exchange" tax
treatment for the purchase of domestic oil and gas producing properties. The
escrow account was created with proceeds from the Company's January 1999 sale of
its East Texas natural gas assets (see discussion in Note 4). Following the
Texaco transaction, the $41.0 million remaining in the escrow account, which
included $2.4 million of interest income, was used to repay a portion of
outstanding bank debt in early July 1999. The acquired properties had estimated
net proved reserves at June 30, 1999, of 33.7 MMBOE (unaudited) and are either
additional interests in the Company's existing properties or are located near
its existing properties. The acquisition included interests in Cymric, East
Coalinga, Dos Cuadras, Buena Vista Hills and other fields the Company operates.
In April 1998, the Company acquired an additional working interest in the
Marine 1 Permit in the Republic of Congo, West Africa ("Congo") for $7.8
million. This acquisition increased the Company's net working interest in the
Congo from 43.75% to 50.0%.
4. DIVESTITURES
In May 2000, the Company sold its working interest in the Las Cienegas field
in California for proceeds of approximately $4.6 million. The Company
reclassified these assets to assets held for sale during the third quarter of
1999, at which time it discontinued depleting and depreciating these assets. No
impairment charge was recorded upon reclassification to assets held for sale.
In connection with this sale, the Company unwound hedges of 2,800 BOPD for the
period May 2000 through December 2000 and recorded an adjusted net gain on sale
of approximately $923,000. Also, the Company sold certain of its non-core
assets during 2000, recognizing a net loss of approximately $266,000.
On December 31, 1999, the Company completed the sale of its working interests
(ranging from 8% to 100%) in 13 onshore fields and a gas processing plant
located in Ventura County, California, to Vintage Petroleum, Inc. The effective
date of the sale was September 1, 1999. Accordingly, the Company reclassified
these properties to assets held for sale and discontinued depleting and
depreciating these assets during the third quarter of 1999. Revenues less costs
for the period September 1, 1999, through December 31, 1999, and other
adjustments resulted in an adjusted sales price of $29.6 million at closing on
December 31, 1999. A portion of the proceeds, $4.5 million, was deposited in
escrow to address possible remediation issues. The funds will remain in escrow
until the Los Angeles Regional Water Quality Control Board approves completion
of the remediation work. All or any portion of the funds not used in
remediation shall be delivered to the Company. As of December 31, 2000, the
balance in the escrow account remained at $4.5 million. The remainder of the
proceeds from the sale were used to repay a portion of the Company's outstanding
bank debt. The assets accounted for approximately 3% of Nuevo's September 1,
1999 estimated proved reserves. Production from the properties for the year
ended December 31, 1999, averaged 2,510 barrels of oil equivalent per day. The
Company recorded a gain of $5.3 million on the sale of these properties.
On January 6, 1999, the Company completed the sale of its East Texas natural
gas assets to an affiliate of Samson Resources Company for an adjusted sales
price of approximately $191.0 million. Of the proceeds, $100.0 million was set
aside to fund an escrow account, as discussed in Note 3. The remainder of the
proceeds were used to repay outstanding senior bank debt. The Company realized
an $80.2 million adjusted pre-tax gain on the sale of the East Texas natural gas
assets resulting in the realization of $14.6 million of the Company's deferred
tax asset. A $5.2 million gain on settled hedge transactions was realized in
connection with the closing of this sale in 1999. The effective date of the
sale was July 1, 1998. The Company reclassified these assets to assets held for
sale and discontinued depleting these assets during the third quarter of 1998.
Estimated net proved reserves associated with these properties totaled
approximately 329.0 Bcfe (unaudited) at January 1, 1999.
During the third quarter of 1998, the Company sold its 100% working interest
in the Sansinena field in California for proceeds of $4.2 million, and recorded
a gain on the sale of $4.1 million. During the first quarter of 1998, the
Company sold its 100% working interest in the Coke field in Chapel Hill, Texas
for proceeds of $1.9 million, and recorded a $1.7 million gain on this sale.
50
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
5. OUTSOURCING SERVICES
Torch Energy Advisors Incorporated ("Torch"), the Company's outside service
provider, 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.
In early 1999, Nuevo signed new outsourcing agreements with Torch and its
subsidiaries, effective January 1, 1999, to provide the following services: (i)
oil and gas administration (accounting, information technology and land
administration); (ii) human resources; (iii) corporate administration (legal,
graphics, support, and corporate insurance); (iv) crude oil marketing; (v)
natural gas marketing; (vi) land leasing, and (vii) field operations. Each of
the new agreements is stand alone, with different terms ranging from one to four
years. In addition, the Company executed a Master Services Agreement with
Torch, which contains the overall terms and conditions governing each individual
service agreement. Several functions that were previously outsourced, such as
mergers and acquisitions and internal audit, were brought in-house during 1999.
In 2000, Nuevo extended the oil and gas administration agreement, entered into a
new field operations agreement and terminated the corporate administration and
land leasing agreements. As a result, Nuevo reduced both the staffing
requirements and cost structure under the Torch agreements and brought certain
professional and other positions in-house.
The major components of compensation under each Torch agreement are as
follows: (i) under the oil and gas administration agreement, Nuevo is charged a
monthly base fee which is adjusted upward or downward to reflect the current
number and type of properties for which services are provided; (ii) under the
human resources agreement, Nuevo is charged a monthly base fee which is adjusted
upward or downward to reflect changes in the total number of its employees;
(iii) both the crude oil and natural gas marketing agreements obligate Nuevo to
pay a base charge and a variable charge based on the volume of crude oil and
natural gas sold or marketed; and (iv) under the field operation agreement,
Nuevo is charged a base fee and pays performance based incentive fees related
to, among other matters, regulatory compliance and cost control.
Prior to January 1, 1999, the Company's outsourcing services were governed by
an agreement with Torch (the "Torch Agreement") whereby Torch administered
certain business activities of the Company for a monthly fee. The Torch
Agreement required 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 were rendered.
In addition, the Torch Agreement contained a provision whereby 20% of the
overhead fees on Torch operated properties were credited against the monthly fee
paid to Torch, as well as a provision whereby the monthly fee was credited for
one-twelfth of $900,000. For the years ended December 31, 2000, 1999 and 1998,
outsourcing fees paid to Torch amounted to $13.7 million, $14.1 million and
$14.5 million, respectively.
A subsidiary of Torch markets oil, natural gas and natural gas liquids from
certain oil and gas properties and gas plants in which the Company owns an
interest. In 2000, 1999 and 1998, such marketing fees were $1.8 million, $1.2
million and $2.0 million, respectively.
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
fees charged for these activities for the years ended December 31, 2000, 1999
and 1998, were $21.8 million, $25.1 million and $20.5 million, respectively.
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 are established by the
Board of Directors of the Company. All shares of Common Stock have equal voting
rights of one vote per share on all matters to be voted upon by stockholders.
Cumulative voting for the election of
51
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
directors is not permitted. Certain restrictions contained in the Company's loan
agreements limit the amount of dividends that may be declared. Under the terms
of the most restrictive covenant in its indenture for the 9 1/2% Senior
Subordinated Notes due 2008 described in Note 8, the Company and its restricted
subsidiaries had $20.5 million available for the payment of dividends and share
repurchases at December 31, 2000. The Company has not paid dividends on its
Common Stock and does not anticipate the payment of cash dividends in the
immediate future.
EPS Computation
SFAS No. 128, "Earnings per Share", requires a reconciliation of the
numerator (income) and denominator (shares) of the basic EPS computation to the
numerator and denominator of the diluted EPS computation. In 1999 and 1998,
weighted average shares held by benefit trust of 64,000 and 42,000,
respectively, are not included in the calculation of diluted loss per share due
to their anti-dilutive effect. In 1998, weighted average potential dilutive
common shares of 331,000 are not included in the calculation of diluted loss per
share due to their anti-dilutive effect. The Company's reconciliation is as
follows (amounts in thousands):
For the Year Ended December 31,
------------------------------------------------------------
2000 1999 1998
------------------ ----------------- -------------------
Income Shares Income Shares Loss Shares
-------- ------ -------- ------ --------- ------
Earnings (loss) before cumulative effect per
Common share -- Basic......................... $12,431 17,447 $31,442 19,353 $(94,272) 19,753
Effect of dilutive securities:
Stock options.................................. -- 335 -- 154 -- --
Shares held by Benefit Trust................... (152) 159 -- -- -- --
------- ------ ------- ------ -------- ------
Earnings (loss) before cumulative effect per
Common share -- Diluted....................... $12,279 17,941 $31,442 19,507 $(94,272) 19,753
======= ====== ======= ====== ======== ======
Treasury Stock Repurchases
Since December 1997, the Board of Directors of the Company authorized the
open market repurchase of up to 4,616,600 shares of outstanding Common Stock at
times and at prices deemed appropriate by management. During 2000, the Company
repurchased 1,482,000 shares of its Common Stock in open market transactions at
an average purchase price, including commissions, of $16.67 per share. During
1999, the Company repurchased 1,999,100 shares of its Common Stock in open
market transactions at an average purchase price, including commissions, of
$16.50 per share. No Common Stock was repurchased during 1998. As of March 22,
2001, the Company had repurchased 3,608,900 shares, on a cumulative basis, at an
average purchase price of $16.56 per share, including commissions, under the
current share repurchase program.
Shareholder Rights Plan
In March 1997, the Company adopted a Shareholder Rights Plan to protect the
Company's shareholders from coercive or unfair takeover tactics. Under the
Shareholder Rights Plan, each outstanding share and each share of subsequently
issued Common Stock has attached to it one Right. Generally, in the event a
person or group ("Acquiring Person") acquires or announces an intention to
acquire beneficial ownership of 15% or more of the outstanding shares of Common
Stock without the prior consent of the Company, or the Company is acquired in a
merger or other business combination, or 50% or more of its assets or earning
power is sold, each holder of a Right will have the right to receive, upon
exercise of the Right, that number of shares of common stock of the acquiring
company, which at the time of such transaction will have a market price of two
times the exercise price of the Right. The Company may redeem the Right for
$.01 at any time before a person or group becomes an Acquiring Person without
prior approval. The Rights will expire on March 21, 2007, subject to earlier
redemption by the Board of Directors of the Company.
52
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
On January 10, 2000, the Company amended the Shareholder Rights Plan to
provide that if the Company receives and consummates a transaction pursuant to a
qualifying offer, the provisions of the Shareholder Rights Plan are not
triggered. In general, a qualifying offer is an all cash, fully-funded tender
offer for all outstanding Common shares by a person who, at the commencement of
the offer, beneficially owns less than five percent of the outstanding Common
shares. A qualifying offer must remain open for at least 120 days, must be
conditioned on the person commencing the qualifying offer acquiring at least 75%
of the outstanding Common shares and the per share consideration must exceed the
greater of (1) 135% of the highest closing price of the Common shares during the
one-year period prior to the commencement of the qualifying offer or (2) 150% of
the average closing price of the Common shares during the 20 day period prior to
the commencement of the qualifying offer.
Executive Compensation Plan
During July 1997, the Board of Directors of the Company adopted a plan to
encourage senior executives to personally invest in the stock of the Company,
and to regularly review executives' ownership versus targeted ownership
objectives. These incentives include a deferred compensation plan (the "Plan")
that gives key executives the ability to defer all or a portion of their
salaries and bonuses and invest in Common Stock of the Company at a discount to
market prices or make other investments at the employee's discretion. Stock
acquired at a discount will be held in a benefit trust and will be restricted
for a two-year period. The stock held in the benefit trust (174,904 shares,
75,904 shares and 47,759 shares at December 31, 2000, 1999 and 1998,
respectively) is accounted for as a liability of the Company and is marked-to-
market, with any necessary adjustment to general and administrative expense.
The Company recorded a net benefit of $0.1 million in 2000 related to deferred
compensation, total expenses of $1.7 million in 1999, and a net benefit of $0.6
million in 1998. The Plan does not permit investment in a diversified equity
portfolio until and unless targeted levels of Common Stock ownership in the
Company are achieved and maintained. Target levels of ownership are based on
multiples of base salary and are administered by the Compensation Committee of
the Board of Directors. Upon withdrawal from the Plan, the obligation to the
employee can be settled by the Company in cash or Common Stock, at the option of
the employee. The Plan applies to certain highly compensated employees and all
executives at a level of Vice-President and above.
Director Compensation
In May 1999, the Compensation Committee of the Board of Directors implemented
changes to the compensation of the Company's non-employee directors. Non-
employee directors may elect to receive all or part of the annual cash retainer
of $30,000 in restricted shares of the Company's Common Stock at a 33% increase
in value. The election must be made in increments of 25% ($7,500). Therefore,
for each $7,500 of compensation for which the election is exercised, the
director would receive $9,975 in restricted stock. Each non-employee director
also receives a semi-annual grant of 1,750 ten-year options to purchase the
Company's Common Stock at the market price of the stock on the date of the
grant. Non-employee directors also receive a semi-annual grant of 1,250
restricted shares of the Company's common stock. All restricted shares are
subject to a three-year restricted period. Directors have the option of
deferring delivery of restricted shares beyond the three-year period.
Stock Incentive Plan
In 1990, the Company established its 1990 Stock Option Plan with respect to
its Common Stock; in 1993, the Board of Directors adopted the Nuevo Energy
Company 1993 Stock Incentive Plan; and in 1999, the Board of Directors adopted
the Nuevo Energy Company 1999 Stock Incentive Plan (collectively, the "Stock
Incentive Plans"). The purpose of the Stock Incentive Plans is to provide
directors and key employees of the Company performance incentives and to provide
a means of encouraging stock ownership in the Company by such persons.
The total maximum number of shares subject to options under the Stock
Incentive Plans is 5,000,000 shares. Options are granted under the Stock
Incentive Plans on the basis of the optionee's contribution to the Company. No
option may exceed a term of more than ten years. Options granted under the
Stock Incentive Plans may be either incentive stock options or options that do
not qualify as incentive stock options. 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, the terms of payment upon
exercise of the options, and the time during
53
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
which the options may be exercised. Options granted are exercisable, in full,
six months following the date of the grant. Options vest over a three-year
period for officers of the Company who have not met the ownership target set out
under the Targeted Stock Ownership Plan.
A summary of activity in the stock option plans during the three years ended
1999 is set forth below:
Weighted-
Average
Options Exercise Price
------------------ -----------------
Outstanding at January 1, 1998.............................. 2,089,463 $30.61
Granted................................................... 1,124,800 * $16.27
Exercised................................................. (70,925) $18.35
Canceled.................................................. (466,975)* $36.19
---------
Outstanding at December 31, 1998............................ 2,676,363 $23.94
Granted................................................... 481,225 $16.02
Exercised................................................. (128,909) $14.16
Canceled.................................................. (411,500) $25.52
---------
Outstanding at December 31, 1999............................ 2,617,179 $22.72
Granted................................................... 419,189 $15.69
Exercised................................................. (182,925) $13.40
Canceled.................................................. (80,525) $34.18
---------
Outstanding at December 31, 2000............................ 2,772,918 $21.94
=========
* Reflects the cancellation and re-issuance of 401,850 non-executive employee
stock options on December 14, 1998.
The Company had options exercisable of 2,361,979 (weighted average exercise
price of $23.04), 2,202,454 (weighted average exercise price of $24.00), and
1,756,263 (weighted average exercise price of $29.44) at December 31, 2000, 1999
and 1998, respectively. Detail of stock options outstanding and options
exercisable at December 31, 2000 follows:
Outstanding Exercisable
------------------------------------------------ -----------------------------
Weighted- Weighted- Weighted-
Average Average Average
Remaining Exercise Exercise
Range of Exercise Prices Number Life (Years) Price Number Price
----------------------------------- ------------- ---------------- ------------- ------------- -------------
$10.31 to $15.06................... 760,013 8.36 $12.21 577,325 $11.30
$15.50 to $19.63................... 982,205 7.14 $16.67 753,954 $16.82
$20.38 to $29.88................... 430,700 6.10 $23.44 430,700 $23.44
$34.00 to $47.88................... 600,000 6.66 $41.84 600,000 $41.84
--------- ---------
Total............................ 2,772,918 2,361,979
========= =========
The weighted-average fair value of options granted during 2000, 1999 and
1998, was $10.87, $11.38 and $7.55, 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: expected stock price
volatility of 112% in 2000, 55.7% in 1999 and 50.9% in 1998; risk free interest
of 5% in 2000, 6% in 1999 and 5% in 1998, and average expected option lives of
three years in 2000 and five years in 1999 and 1998. Had compensation expense
for stock-based compensation been determined based on the fair value at the date
of grant, the Company's net income, earnings available to common stockholders
and earnings per share would have been reduced to the pro forma amounts
indicated below (amounts in thousands, except per share data):
Year Ended December 31,
----------------------------------------
2000 1999 1998
------- ------- ---------
Net income (loss)........................................ As reported $11,635 $31,442 $ (94,272)
Pro forma $ 6,740 $24,673 $(103,434)
Earnings (loss) per Common share -- Basic................ As reported $ 0.67 $ 1.62 $ (4.77)
Pro forma $ 0.39 $ 1.27 $ (5.24)
Earnings (loss) per Common share -- Diluted.............. As reported $ 0.64 $ 1.61 $ (4.77)
Pro forma $ 0.38 $ 1.26 $ (5.24)
54
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 price to the public of the TECONS was $50.00 per
TECONS. Distributions on the TECONS began to accumulate from December 23, 1996,
and are payable quarterly on March 15, June 15, September 15, and December 15,
at an annual rate of $2.875 per TECONS. Each TECONS is convertible at any time
prior to the close of business on December 15, 2026, at the option of the holder
into shares of Common Stock at the rate of .8421 shares of Common Stock for each
TECONS, subject to adjustment. The sole asset of the Trust as the obligor on
the TECONS is $115.0 million aggregate principal amount of 5.75% Convertible
Subordinated Debentures ("Debentures") of the Company due December 15, 2026.
The Debentures were issued by Nuevo to the Trust to facilitate the offering of
the TECONS. The TECONS must be redeemed for $50.00 per TECON plus accrued and
unpaid dividends on December 15, 2026.
8. LONG-TERM DEBT
Long-term debt is comprised of the following at December 31, 2000 and 1999
(amounts in thousands):
2000 1999
-------- --------
9 3/8% Senior Subordinated Notes due 2010 (a).............................. $150,000 $ --
9 1/2 % Senior Subordinated Notes due 2008 (b)............................ 257,310 257,310
9 1/2 % Senior Subordinated Notes due 2006 (b) (c)........................ 2,417 2,440
OPIC credit facility (at 5.8% at December 31, 1999, plus a guaranty fee of
2.75%) (d)................................................................ -- 750
Bank credit facility (at 7.13% at December 31, 1999) (e)................... -- 81,000
-------- --------
Total debt.............................................................. 409,727 341,500
Less current maturities.................................................... -- (750)
-------- --------
Long-term debt............................................................. $409,727 $340,750
======== ========
_______
(a) On September 26, 2000, the Company issued $150.0 million of 9 3/8% Senior
Subordinated Notes due September 15, 2010 ("9 3/8% Notes"). Interest on
the 9 3/8% Notes accrues at the rate of 9 3/8% per annum and is payable
semi-annually in arrears on April 1 and October 1. The 9 3/8% Notes are
redeemable, in whole or in part, at the option of the Company, on or after
October 1, 2005, under certain conditions. The Company is not required to
make mandatory redemption or sinking fund payments with respect to the
9 3/8% Notes. The indenture contains covenants that, among other things,
limit the Company's ability to incur additional indebtedness, limit
restricted payments, limit issuances and sales of capital stock by
restricted subsidiaries, limit dispositions of proceeds from asset sales,
limit dividends and other payment restrictions affecting restricted
subsidiaries, and restrict mergers, consolidations or sales of assets. If a
subsidiary of the Company guarantees other subordinated indebtedness of the
Company, the subsidiary must also guarantee the 9 3/8% Notes. Currently,
none of the Company's subsidiaries guarantees subordinated indebtedness of
the Company. The 9 3/8% 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 repurchase all
outstanding 9 3/8% Notes at 101% of the principal amount thereof, plus
accrued and unpaid interest to the date of redemption.
(b) In July 1999, the Company authorized a new issuance of $260.0 million of
9 1/2% Senior Subordinated Notes due June 1, 2008 ("9 1/2% Notes"). The
Company offered to exchange the new notes for its outstanding $160.0
million of 9 1/2% Senior Subordinated Notes due 2006 ("Old 9 1/2% Notes")
and $100.0 million of 8 7/8% Senior Subordinated Notes due 2008 ("8 7/8 %
Notes"). In August 1999, the Company received tenders to exchange $157.
5 million of its Old 9 1/2% Notes and $99. 9 million of the 8 7/8% Notes.
In connection with
55
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
the exchange offers, the Company solicited consents to
proposed amendments to the indentures under which the old notes were
issued. These amendments streamline the Company's covenant structure and
provide the Company with additional flexibility to pursue its operating
strategy. The exchange was accounted for as a debt modification. As such,
the consideration that the Company paid to the holders of the Old 9 1/2%
Notes who tendered in the exchange offer (equal to 3% of the outstanding
principal amount of the Old 9 1/2% Notes exchanged, or $4.7 million) was
accounted for as deferred financing costs. Also in connection with this
exchange offer, the Company incurred a total of $3.1 million in third-party
fees during the third and fourth quarters of 1999, which are included in
other expense.
Interest on the 9 1/2% Notes accrues at the rate of 9 1/2% per annum and is
payable semi-annually in arrears on June 1 and December 1. The 9 1/2% Notes
are redeemable, in whole or in part, at the option of the Company, on or
after June 1, 2003, 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, limit
restricted payments, limit issuances and sales of capital stock by
restricted subsidiaries, limit dispositions of proceeds from asset sales,
limit dividends and other payment restrictions affecting restricted
subsidiaries, and restrict mergers, consolidations or sales of assets. The
9 1/2% Notes are not currently guaranteed by Nuevo's subsidiaries but are
required to be guaranteed by any subsidiary that guarantees pari passu or
subordinated indebtedness. Currently, none of the Company's subsidiaries
guarantees subordinated indebtedness of the Company. 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 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 April 1996, the Company financed a portion of the purchase price of the
Unocal Properties with proceeds from the sale to the public of a principal
amount of $160.0 million, Old 9 1/2% Notes. In August 1999, most of the
Old 9 1/2% Notes, except for $2,540,000, were exchanged for 9 1/2% Notes.
In October 1999, the Company purchased $100,000 of the remaining Old
9 1/2% Notes. No significant costs were incurred in connection with the
early retirement of the $100,000 notes. Interest on the Old 9 1/2% Notes
accrues at the rate of 9 1/2% per annum and is payable semi-annually in
arrears on April 15 and October 15. The Old 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 Old 9 1/2% Notes.
The Old 9 1/2% Notes were guaranteed by certain of Nuevo's subsidiaries
until February 1998, at which time such subsidiaries were released as
guarantors. The Old 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.
(d) In February 1995, in connection with the purchase of the stock of Amoco
Congo Production Company, the Company negotiated with the Overseas Private
Investment Corporation ("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 the Nuevo Congo Company ("NCC"). The credit
facility expired in June 1999. The initial drawdown on the facility was
$8.8 million to finance a portion of the purchase price. 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 loan agreement required a sixteen-quarter repayment period and
was fully paid in April 2000.
(e) Nuevo's Third Amended and Restated Credit Agreement, (the "Credit
Agreement"), dated June 7, 2000, provides for secured revolving credit
availability of up to $410.0 million (subject to a semi-annual borrowing
base determination) from a bank group led by Bank of America, N.A., Bank
One, NA, and Bank of Montreal until its expiration on June 7, 2005.
The borrowing base is subject to a semi-annual borrowing base determination
within 60 days following March 1 and August 15 of each year. The borrowing
base determination establishes the maximum borrowings that may be
outstanding under the credit facility, and is determined by a 60% vote of
the banks (two-thirds in the event of an increase in the borrowing base),
each of which bases its judgement on: (i) the present value of the
56
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Company's oil and gas reserves based on its own assumptions regarding future
prices, production, costs, risk factors and discount rates, and (ii) on
projected cash flow coverage ratios calculated under varying scenarios. If
amounts outstanding under the credit facility exceed the borrowing base, as
redetermined from time to time, the Company would be required to repay such
excess over a defined period of time. As of December 31, 2000, the Company's
borrowing base was $225.0 million. There were no outstanding borrowings under
this facility at December 31, 2000.
Amounts outstanding under the credit facility bear interest at a rate equal to
the London Interbank Offered Rate ("LIBOR") plus an amount which increases as
borrowing base utilization increases.
The Credit Agreement has customary covenants including, but not limited to,
covenants with respect to the following matters: (i) limitations on certain
restricted payments and investments; (ii) limitations on guarantees and
indebtedness; (iii) limitations on prepayments of subordinated and certain
other indebtedness; (iv) limitations on mergers and consolidations, on certain
types of acquisitions and on the issuance of certain securities by
subsidiaries; (v) limitations on liens; (vi) limitations on sales of
properties; (vii) limitations on transactions with affiliates; (viii)
limitations on derivative contracts; and (ix) limitations on debt in
subsidiaries. The Company is also required to maintain certain financial
ratios and conditions, including without limitation an EBITDAX (earnings
before interest, taxes, depreciation, depletion, amortization and exploration
expenses) to fixed charge coverage ratio and a funded debt to capitalization
ratio. The Company was in compliance with all covenants of the Credit
Agreement at December 31, 2000, and does not anticipate any issues of non-
compliance arising in the foreseeable future.
The amount of scheduled debt maturities during the next five years and
thereafter is as follows (amounts in thousands):
2001......................................... $ --
2002......................................... --
2003......................................... --
2004......................................... --
2005......................................... --
Thereafter................................... 409,727
---------
Total debt............................... $ 409,727
=========
Based upon the quoted market price, the fair value of the 9 3/8% Notes was
estimated to be $150.0 million at December 31, 2000; the fair value of the
9 1/2% Notes was estimated to be $260.4 million and $254.6 million at December
31, 2000 and 1999, respectively; and the fair value of the Old 9 1/2% Notes
was estimated to be $2.5 million and $2.4 million at December 31, 2000 and
1999, respectively. For the 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, 1999.
9. Income Taxes
Income tax expense (benefit) is summarized as follows (amounts in thousands):
Year Ended December 31,
---------------------------------------------------
2000 1999 1998
------ ------- --------
Current
Federal................................................ $ (371) $ 1,012 $ (105)
State.................................................. -- 188 --
------ ------- --------
(371) 1,200 (105)
------ ------- --------
Deferred
Federal............................................... 7,102 (8,457) (24,172)
State................................................. 1,661 1,898 (8,348)
------ ------- --------
8,763 (6,559) (32,520)
------ ------- --------
Total income tax expense (benefit)................... $8,392 $(5,359) $(32,625)
====== ======= ========
57
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Also for the year ended December 31, 2000, the Company recorded a tax benefit
of $537,000 related to a cumulative effect of a change in accounting principle
(see Note 2).
A deferred tax benefit related to the exercise of employee stock options of
approximately $0.5 million and $0.2 million was allocated directly to additional
paid-in capital in 2000 and 1999, respectively.
Total income tax expense (benefit) differs from the amount computed by
applying the federal income tax rate to income (loss) before income taxes and
cumulative effect. The reasons for these differences are as follows:
Year Ended December 31,
------------------------------------------------
2000 1999 1998
----- ------ ------
Statutory federal income tax rate................................ 35.0 % 35.0 % (35.0)%
(Decrease) increase in tax rate resulting from:
State income taxes, net of federal benefit..................... 5.2 5.2 (4.3)
(Decrease) increase in valuation allowance.................. -- (60.8) 13.4
Nondeductible travel and entertainment and other............ 0.1 0.1 0.2
----- ------ ------
40.3 % (20.5)% (25.7)%
===== ====== ======
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 (amounts in
thousands):
As of December 31,
---------------------------------
2000 1999
-------- --------
Net operating loss carryforwards....................... $ 51,033 $ 41,814
Alternative minimum tax credit carryforwards........... 1,704 2,066
Capital loss carryforwards............................. -- 2,426
-------- --------
Total deferred income tax assets..................... 52,737 46,306
Less: valuation allowance............................ (1,777) (1,777)
-------- --------
Net deferred income tax assets....................... 50,960 44,529
-------- --------
Property and equipment................................. (31,338) (19,881)
Equity in foreign subsidiaries......................... (1,684) --
State income taxes..................................... (1,656) (643)
-------- --------
Total deferred income tax liabilities................ (34,678) (20,524)
-------- --------
Net deferred income tax asset.......................... $ 16,282 $ 24,005
======== ========
At December 31, 2000, the Company had a net operating loss carryforward for
regular tax of approximately $146.0 million, which will begin expiring in 2018.
The alternative minimum tax credit carryforward of $1.7 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. At December 31, 1998, the
Company determined that it was more likely than not that a portion of the
deferred tax assets would not be realized and the valuation allowance was
increased by $16.9 million to a total valuation allowance of $17.6 million. At
December 31, 1999, however, the Company determined that it was more likely than
not that most of the deferred tax assets would be realized, based on current
projections of taxable income due to higher commodity prices at year-end 1999,
and the valuation allowance was decreased by $15.9 million to a total valuation
allowance of $1.8 million. The decrease in the valuation allowance was
accounted for as a reduction in 1999 deferred income tax expense.
58
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
10. INDUSTRY SEGMENT INFORMATION
The Company's operations are concentrated primarily in two segments:
exploration and production of oil and natural gas, and gas plant and other
facilities.
As of and For the Year Ended
December 31,
-------------------------------------------------------
2000 1999 1998
-------- -------- ---------
(Amounts in thousands)
Sales to unaffiliated customers:
Oil and gas -- Domestic........................................... $290,774 $211,647 $ 226,865
Oil and gas -- Foreign............................................ 40,881 30,627 15,810
-------- -------- ---------
Total sales....................................................... 331,655 242,274 242,675
Gain on sale of assets, net....................................... 657 85,294 5,768
Interest and other income......................................... 4,293 4,667 4,260
-------- -------- ---------
Total revenues.................................................... $336,605 $332,235 $ 252,703
======== ======== =========
Operating profit (loss) before income taxes:
Oil and gas -- Domestic (1)....................................... $ 84,747 $ 97,948 $ (46,418)
Oil and gas -- Foreign............................................ 14,899 5,208 (12,849)
-------- -------- ---------
99,646 103,156 (59,267)
Unallocated corporate expenses.................................... 34,738 37,350 28,546
Interest expense.................................................. 37,472 33,110 32,471
Dividends on TECONS............................................... 6,613 6,613 6,613
-------- -------- ---------
Operating profit (loss) before income taxes....................... $ 20,823 $ 26,083 $(126,897)
======== ======== =========
Identifiable assets:
Oil and gas -- Domestic........................................... $613,658 $566,256 $ 748,695
Oil and gas -- Foreign............................................ 103,204 82,074 40,700
Gas plant and other facilities.................................... 11,455 12,297 14,893
-------- -------- ---------
728,317 660,627 804,288
Corporate assets, investments and other............................ 119,707 99,403 13,397
-------- -------- ---------
Total............................................................. $848,024 $760,030 $ 817,685
======== ======== =========
Capital expenditures:
Oil and gas -- Domestic........................................... $101,773 $106,071 $ 132,776
Oil and gas -- Foreign............................................ 11,694 24,570 30,498
-------- -------- ---------
Oil and gas capital expenditures................................. 113,467 130,641 163,274
Less: Geological & geophysical, delay rentals and other expenses.. (9,047) (4,722) (5,922)
-------- -------- ---------
Additions to oil and gas properties per Statement of Cash Flows.. $104,420 $125,919 $ 157,352
======== ======== =========
Gas plant and other facilities.................................... $ 3,388 $ 10,247 $ 2,813
======== ======== =========
Depreciation, depletion and amortization:
Oil and gas -- Domestic........................................... $ 57,819 $ 70,024 $ 78,555
Oil and gas -- Foreign............................................ 8,085 9,177 4,971
Gas plant and other facilities.................................... 512 666 812
Corporate.......................................................... 954 785 698
-------- -------- ---------
$ 67,370 $ 80,652 $ 85,036
======== ======== =========
(1) Includes gain on sale of the East Texas natural gas asset of $80.2 million for the year ended 1999.
Credit Risks due to Certain Concentrations
In 2000, 1999 and 1998, the Company had one customer that accounted for
84%, 79%, and 60% of oil and gas revenues, respectively. In 2000, 1999 and
1998, the Company had another customer that accounted for 11%, 12% and 10% of
oil and gas revenues, respectively.
59
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
In February 2000, the Company entered into a 15-year contract, effective
January 1, 2000, to sell substantially all of its current and future California
crude oil production to Tosco Corporation. The contract provides pricing based
on a fixed percentage of the NYMEX crude oil price for each type of crude oil
that Nuevo produces in California. Therefore, the actual price received as a
percentage of NYMEX will vary with the Company's production mix. Based on the
Company's current production mix, the price received by Nuevo for its California
production is expected to average approximately 72% of WTI. While the contract
does not reduce the Company's exposure to price volatility, it does effectively
eliminate the basis differential risk between the NYMEX price and the field
price of the Company's California oil production. The Tosco contract permits the
Company under certain circumstances to separately market up to ten percent of
its California crude production. The Company exercised this right and,
effective January 1, 2001, began selling 5,000 BOPD of its San Joaquin Valley
oil production to a third party under a one-year contract containing NYMEX
pricing.
11. CONTINGENCIES AND OTHER MATTERS
In August 1996, the Company had been named as a defendant in Gloria Garcia
Lopez and Husband, Hector S. Lopez, Individually, and as successors to Galo Land
& Cattle Company v. Mobil Producing Texas & New Mexico, et al. in the 79th
Judicial District Court of Brooks County, Texas. On June 9, 2000, the parties
entered into a memorandum of settlement agreement, pursuant to which the lawsuit
was dismissed, the defendants paid the plaintiffs $12.0 million and the lease
agreement was amended. Nuevo's working interest in these properties is 20%, and
its share of the settlement payment was approximately $2.4 million.
On September 22, 2000, the Company was named as a defendant in the lawsuit
Thomas Wachtell et al. versus Nuevo Energy Company in the Superior Court of Los
Angeles County, California. The plaintiffs, who own certain interests in the
Point Pedernales properties, have asserted numerous causes of action including
breach of contract, fraud and conspiracy in connection with the plaintiff's
allegation that: (i) royalties have not been properly paid to them for
production from the Point Pedernales field, (ii) payments have not been made to
them related to production from the Sacate field, and, (iii) the Company has
failed to recognize the plaintiff's interests in the Tranquillon Ridge project.
The plaintiffs have not specified damages. The Company has not yet been
required to file an answer, but believes the allegations are without merit and
intends to vigorously contest these claims. Management does not believe that
the outcome of this matter will have a material adverse impact on the Company's
operating results, financial condition or liquidity.
The Company has been named as a defendant in certain other 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 March 1999, the Company discovered that a non-officer employee had
fraudulently authorized and diverted for personal use Company funds totaling
$5.9 million, $1.6 million in 1999 and the remainder in 1998, that were intended
for international exploration. The Board of Directors engaged a Certified Fraud
Examiner to conduct an in-depth review of the fraudulent transactions. The
investigation confirmed that only one employee was involved in the matter and
that all misappropriated funds were identified. The Company has reviewed and,
where appropriate, strengthened its internal control procedures. In August
2000, the Company recorded $1.5 million of other income for a partial
reimbursement of these previously expensed funds, resulting from the negotiated
settlement of a related legal claim.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects the Company's Point Pedernales field with
shore-based processing facilities. The volume of the spill was estimated to be
163 barrels of oil. Repairs were completed by the end of 1997, and production
recommenced in December 1997. The costs of the clean- up and the cost to repair
the pipeline either have been or are expected to be covered by insurance held by
the Company, less the Company's deductibles of $120,000. The Company incurred
clean-up and repair costs of $ 0.3 million, $0.5 million, and $2.4 million
during 2000, 1999, and 1998, respectively. As of December 31, 2000, the Company
had received insurance reimbursements of $4.1 million, with a remaining
insurance receivable of $1.3 million. For amounts not covered by insurance,
including the
60
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
$120,000 deductible, the Company recorded lease operating expenses of $0.4
million and $0.5 million during 1999 and 1998, respectively. No such expenses
were recorded in 2000. Additionally, the Company has exposure to certain costs
that are expected to be recoverable from insurance, including certain fines,
penalties, and damages, for which the Company accrued $0.7 million as of
December 31, 2000, as a receivable and payable. The Company also has exposure to
costs that may not be recoverable from insurance, including certain fines,
penalties, and damages. Such costs are not quantifiable at this time, but are
not expected to be material to the Company's operating results, financial
condition or liquidity.
The Company's international investments involve risks typically associated
with investments in emerging markets such as an uncertain political, economic,
legal and tax environment and expropriation and nationalization of assets. In
addition, if a dispute arises in 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 that the Company will
be successful in so protecting itself. A portion of the Company's investment in
the Congo is insured through political risk insurance provided by OPIC. The
political risk insurance through OPIC covers up to $25.0 million relating to
expropriation and political violence, which is the maximum coverage available
through OPIC. The Company has no deductible for this insurance.
In connection with their respective February 1995 acquisitions of two
subsidiaries (each a "Congo subsidiary") owning interests in the Yombo field
offshore Congo, 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. Under the tax law in the Congo, as it existed when this
acquisition took place, if an entity is acquired in its entirety and that entity
has certain tax attributes, for example tax loss carryforwards from operations
in the Republic of Congo, the subsequent owners of that entity can continue to
utilize those losses without restriction. Pursuant to the agreement, the Company
and CMS may be liable to the seller for the recapture of dual consolidated
losses (net operating losses of any domestic corporation that are subject to an
income tax of a foreign country without regard to the source of its income or on
a residence basis) utilized by the seller in years prior to the acquisitions if
certain triggering events occur, including (i) a disposition by either 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 only time limit associated with the occurrence of a triggering
event relates to the utilization of a dual consolidated loss in a foreign
jurisdiction. A dual consolidated loss that is utilized to offset income in a
foreign jurisdiction is only subject to recapture for 15 years following the
year in which the dual consolidated loss was incurred for US income tax
purposes. 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 $42.5 million if a triggering event with
respect to the Company occurs. Additionally, 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 $61.0 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.
During 1997, a new government was established in the Congo. Although the
political situation in the Congo has not to date had a material adverse effect
on the Company's operations in the Congo, no assurances can be made that
continued political unrest in West Africa will not have a material adverse
effect on the Company and its operations in the Congo in the future.
12. FINANCIAL INSTRUMENTS
The Company follows formal policies regarding the management of oil price risk
to ensure the Company's ability to optimally manage its portfolio of investment
opportunities. To accomplish this, the policy requires that derivative
financial instruments must be entered into at least 18 months in advance of the
effective period. To the
61
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
extent that future markets over a forward 18 month period are significantly
higher than long term norms, the Company will hedge as much of its production as
is necessary to meet its policy goals for that period.
For 2001, the Company has entered into swap arrangements on 26,000 BOPD for
the first quarter at an average WTI price of $19.52, for the second quarter on
25,000 BOPD at an average WTI price of $19.54, for the third quarter on 20,000
BOPD at an average WTI price of $21.22, and for the fourth quarter on 15,500
BOPD at an average WTI price of $22.95 per barrel. Subsequent to December 31,
2000, the Company entered into swaps on an additional 1,200 BOPD for the second
quarter, bringing the total to 26,200 BOPD at an average price of $19.84 per
barrel. On a physical volume basis, these hedges cover 47% of the Company's
estimated 2001 oil production. At December 31, 2000, the market value of the
swaps in place for 2001was a loss of $35.1 million.
For 2002, the Company has entered into swap arrangements on 12,500 BOPD for
the first quarter at an average WTI price of $25.91 per barrel. For the
remainder of 2002, the Company purchased put options with a strike price of
$22.00 per barrel WTI, on 19,000 BOPD for the second quarter, and on 14,000 BOPD
for both the third and fourth quarters. At December 31, 2000, the market value
of these hedge positions is a gain of $8.3 million. All of these agreements
expose the Company to counterparty credit risk to the extent that the
counterparty is unable to meet its settlement commitments to the Company.
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, 2000 and 1999.
December 31, 2000 December 31, 1999
-------------------------------- --------------------------------
Carrying Approximate Carrying Approximate
Value Fair Value Value Fair Value
-------------- --------------- -------------- ---------------
Other investments...................................... $ 78 $ 78 $ 78 $ 78
Derivative Instruments:
Option premium.................................... 5,595 11,088 -- --
Commodity price swaps........................... -- (32,253) -- (35,244)
Long-term debt (see Note 8)............................ 409,727 412,823 340,750 337,972
TECONS................................................. 115,000 60,950 115,000 62,675
13. CONTINGENT PAYMENT AND PRICE SHARING AGREEMENTS
In connection with the acquisition from Unocal in 1996 of the properties
located in California, the Company is obligated to make a contingent payment for
the years 1998 through 2004 if oil prices exceed thresholds set forth in the
agreement with Unocal. Any contingent payment will be accounted for as a
purchase price adjustment to oil and gas properties. The contingent payment
will equal 50% of the difference between the actual average annual price
received on a field-by-field basis (capped by a maximum price) and a minimum
price, less ad valorem and production taxes, multiplied by the actual number of
barrels of oil sold that are produced from the properties acquired from Unocal
during the respective year. The minimum price of $17.75 per Bbl under the
agreement (determined based on the near month delivery of WTI crude oil on the
NYMEX) is escalated at 3% per year and the maximum price of $21.75 per Bbl on
the NYMEX is escalated at 3% per year. Minimum and maximum prices are reduced to
reflect the field level price by subtracting a fixed differential established
for each field. The reduction was established at approximately the differential
between actual sales prices and NYMEX prices in effect in 1995 ($4.34 per Bbl
weighted average for all the properties acquired from Unocal). The Company
accumulates credits to offset the contingent payment when prices are $.50 per
Bbl or more below the minimum price. The Company computes this calculation
annually and had accumulated $8.5 million in price credits as of December 31,
2000, which will be used to reduce future amounts owed under the contingent
payment. There is no value attributable to this credit other than to offset
future payments. At the end of 2004, if the Company still maintains a credit
position with respect to this agreement, the credit will expire worthless. As
of December 31, 2000, the Company had never been obligated to make a payment to
Unocal under the terms of the agreement.
62
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
However, a continuation of higher than normal oil price realizations is expected
to trigger payments under this agreement beginning in March of 2002.
In connection with the acquisition of the Congo properties in 1995, the
Company entered into a price sharing agreement with the seller. There is no
termination date associated with this agreement. Under the terms of the
agreement, if the average price received for the oil production during the year
is greater than the benchmark price established by the agreement, then the
Company is obligated to pay the seller 50% of the difference between the
benchmark price and the actual price received, for all the barrels associated
with this acquisition. The benchmark price for 1999 was $14.79 per Bbl, and the
benchmark price for 2000 was $15.19 per Bbl The benchmark price increases each
year, based on the increase in the Consumer Price Index. For 2000, the effect
of this agreement was that Nuevo only owned upside above $15.19 per Bbl on
approximately 56% of its Congo production. In 2000, the Company was obligated
to pay the seller $5.4 million pursuant to this price sharing agreement. This
obligation was accounted for as a reduction in oil revenues. No such payments
were due in 1998 or 1999.
The Company acquired a 12% working interest in the Point Pedernales oil field
from Unocal in 1994 and the remainder of its 80.3 % working interest from Torch
in 1996. The Company is entitled to all revenue proceeds up to $9.00 per Bbl,
with the excess revenue over $9.00 per Bbl, if any, shared among the Company and
the original owners from whom Torch acquired its interest. Amounts below $9.00
per Bbl are owned by the Company and the other working interest owners based on
their respective ownership interests. For 2000, the effect of this agreement is
that Nuevo was entitled to receive the pricing upside above $9.00 per Bbl on
approximately 34% of the gross Point Pedernales production. As of December 31,
2000, the Company had $581,000 accrued as its obligation under this agreement.
As of December 31, 1999, the Company had $5.1 million accrued as its obligation
under this agreement, which was paid in the first quarter of 2000.
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, 2000 are based primarily on reserve reports prepared by the
independent petroleum engineering firm of Ryder Scott Company. Reserve
quantities and future production for previous years are based primarily upon
reserve reports prepared by Ryder Scott Company. These estimates are inherently
imprecise and subject to substantial revision.
Estimates of future net cash flows from proved reserves of gas, oil,
condensate and natural gas liquids ("NGL") were made in accordance with SFAS
No. 69, "Disclosures about Oil and Gas Producing Activities". The estimates are
based on realized prices at year-end 2000, of $19.51 per Bbl and $13.94 per Mcf,
and are adjusted for the effects of contractual agreements with Unocal and Amoco
in connection with the California and Congo property acquisitions (see Note 13).
Natural gas prices were unusually high at December 31, 2000. Natural gas costs
are a significant component of the Company's thermal operating costs in
California. As such, the unusually high prices at year-end 2000 had an
unfavorable effect on the Company's reserves for its thermal oil producing
properties.
Estimated future cash inflows are reduced by estimated future development and
production costs based on year-end cost levels, assuming continuation of
existing economic conditions, and by estimated future income tax expense. Tax
expense is calculated by applying the existing statutory tax rates, including
any known future changes, to the pre-tax net cash flows, less depreciation of
the tax basis of the properties and depletion allowances applicable to the gas,
oil, condensate and NGL production. Because the disclosure requirements are
standardized, significant changes can occur in these estimates based upon oil
and gas prices currently in effect. The results of these disclosures should not
be construed to represent the fair market value of 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.
63
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Costs incurred (amounts in thousands)-
The following table sets forth the costs incurred in property acquisition and
development activities:
Year Ended December 31,
------------------------------------------------
2000 1999 1998
-------- -------- --------
Domestic
Property acquisition:
Proved properties.................................................. $ -- $ 62,300 $ 200
Unproved properties................................................ 4,892 520 1,320
Exploration......................................................... 5,591 4,973 26,706
Development (1):
Proved reserves.................................................... 79,857 35,372 102,025
Unproved reserves.................................................. 11,433 2,906 2,525
-------- -------- --------
$101,773 $106,071 $132,776
======== ======== ========
FOREIGN
Property acquisition:
Proved properties.................................................. $ -- $ -- $ 7,809
Unproved properties................................................ 479 424 1,404
Exploration......................................................... 6,467 3,742 9,204
Development:
Proved reserves.................................................... 4,406 20,404 10,808
Unproved reserves.................................................. 342 -- 1,273
-------- -------- --------
$ 11,694 $ 24,570 $ 30,498
======== ======== ========
Total
Property acquisition:
Proved properties.................................................. $ -- $ 62,300 $ 8,009
Unproved properties................................................ 5,371 944 2,724
Exploration......................................................... 12,058 8,715 35,910
Development:
Proved reserves.................................................... 84,263 55,776 112,833
Unproved reserves.................................................. 11,775 2,906 3,798
-------- -------- --------
$113,467 $130,641 $163,274
======== ======== ========
(1) Includes capitalized interest directly related to development activities of $0.3 million in 1999 and $0.6 million in 1998.
64
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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:
As of December 31,
-----------------------------------------------------
2000 1999 1998
---------- ---------- ---------
Domestic
Proved properties................................................... $ 986,889 $ 898,032 $ 877,230
Unproved properties................................................. 25,341 21,755 20,984
---------- ---------- ---------
Total capitalized costs............................................ 1,012,230 919,787 898,214
Accumulated depreciation, depletion and amortization............... (461,225) (403,727) (401,139)
---------- ---------- ---------
Net capitalized costs............................................. $ 551,005 $ 516,060 $ 497,075
========== ========== =========
FOREIGN
Proved properties................................................... $ 84,558 $ 80,374 $ 59,774
Unproved properties................................................. 5,445 2,618 1,360
---------- ---------- ---------
Total capitalized costs............................................ 90,003 82,992 61,134
Accumulated depreciation, depletion and amortization............... (29,008) (20,901) (11,724)
---------- ---------- ---------
Net capitalized costs............................................. $ 60,995 $ 62,091 $ 49,410
========== ========== =========
TOTAL
Proved properties................................................... $1,071,447 $ 978,406 $ 937,004
Unproved properties................................................. 30,786 24,373 22,344
---------- ---------- ---------
Total capitalized costs............................................ 1,102,233 1,002,779 959,348
Accumulated depreciation, depletion and amortization............... (490,233) (424,628) (412,863)
---------- ---------- ---------
Net capitalized costs............................................. $ 612,000 $ 578,151 $ 546,485
========== ========== =========
65
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Results of operations for producing activities (amounts in thousands) --
Year Ended December 31,
----------------------------------------------------
2000 1999 1998
--------- --------- ---------
Domestic
Revenues from oil and gas producing activities...................... $ 290,774 $ 211,647 $ 226,865
Production costs.................................................... (142,850) (117,680) (126,018)
Exploration costs................................................... (5,503) (10,643) (5,137)
Depreciation, depletion and amortization............................ (57,819) (70,024) (78,555)
Provision for impairment of oil and gas properties.................. -- -- (68,529)
Income tax (provision) benefit...................................... (34,096) (2,727) 13,374
--------- --------- ---------
Results of operations from producing activities (excluding
corporate overhead and interest costs)............................. $ 50,506 $ 10,573 $ (38,000)
========= ========= =========
FOREIGN
Revenues from oil and gas producing activities...................... $ 40,881 $ 30,627 $ 15,810
Production costs.................................................... (13,626) (12,869) (11,888)
Exploration costs................................................... (4,271) (3,374) (11,425)
Depreciation, depletion and amortization............................ (8,085) (9,177) (4,971)
Provision for impairment of oil and gas properties.................. -- -- (375)
Income tax (provision) benefit...................................... (6,005) (1,067) 3,174
--------- --------- ---------
Results of operations from producing activities (excluding
corporate overhead and interest costs)............................. $ 8,894 $ 4,140 $ (9,675)
========= ========= =========
TOTAL
Revenues from oil and gas producing activities...................... $ 331,655 $ 242,274 $ 242,675
Production costs.................................................... (156,476) (130,549) (137,906)
Exploration costs................................................... (9,774) (14,017) (16,562)
Depreciation, depletion and amortization............................ (65,904) (79,201) (83,526)
Provision for impairment of oil and gas properties.................. -- -- (68,904)
Income tax (provision) benefit...................................... (40,101) (3,794) 16,548
--------- --------- ---------
Results of operations from producing activities (excluding
corporate overhead and interest costs)............................. $ 59,400 $ 14,713 $ (47,675)
========= ========= =========
66
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company's estimated total proved and proved developed reserves of oil and
gas are as follows:
Year Ended December 31,
---------------------------------------------------------------
2000 1999 1998
----------------- ------------------- ------------------
Oil* Gas Oil* Gas Oil* Gas
(Mbbl) (Mmcf) (Mbbl) (Mmcf) (Mbbl) (Mmcf)
------- ------- ------- -------- ------- -------
DOMESTIC
Proved reserves at beginning of year....... 239,190 145,125 164,300 403,256 202,771 390,691
Revisions of previous estimates............ (40,340) 20,740 61,168 56,097 (41,399) (8,953)
Extensions and discoveries................. 15,945 17,678 10,795 11,800 17,694 55,575
Production................................. (15,591) (15,215) (15,892) (17,620) (17,345) (32,521)
Sales of reserves in-place................. (2,512) (2,351) (10,270) (335,927) (1,595) (1,536)
Purchase of reserves in-place.............. -- -- 29,089 27,519 4,174 --
------- ------- ------- -------- ------- -------
Proved reserves at end of year............. 196,692 165,977 239,190 145,125 164,300 403,256
======= ======= ======= ======== ======= =======
Proved developed reserves--
Beginning of year........................ 174,846 112,204 123,077 308,667 143,486 266,179
======= ======= ======= ======== ======= =======
End of year.............................. 160,039 122,500 174,846 112,204 123,077 308,667
======= ======= ======= ======== ======= =======
Foreign
Proved reserves at beginning of year....... 26,048 -- 25,841 -- 24,493 --
Revisions of previous estimates............ (1,003) -- 2,042 -- (420) --
Extensions and discoveries................. -- -- -- -- -- --
Production................................. (1,843) -- (1,835) -- (1,461) --
Sales of reserves in-place................. -- -- -- -- -- --
Purchase of reserves in-place.............. -- -- -- -- 3,229 --
------- ------- ------- -------- ------- -------
Proved reserves at end of year............. 23,202 -- 26,048 -- 25,841 --
======= ======= ======= ======== ======= =======
Proved developed reserves--
Beginning of year........................ 13,749 -- 10,242 -- 9,526 --
======= ======= ======= ======== ======= =======
End of year.............................. 11,013 -- 13,749 -- 10,242 --
======= ======= ======= ======== ======= =======
Total
Proved reserves at beginning of year....... 265,238 145,125 190,141 403,256 227,264 390,691
Revisions of previous estimates............ (41,343) 20,740 63,210 56,097 (41,819) (8,953)
Extensions and discoveries................. 15,945 17,678 10,795 11,800 17,694 55,575
Production................................. (17,434) (15,215) (17,727) (17,620) (18,806) (32,521)
Sales of reserves in-place................. (2,512) (2,351) (10,270) (335,927) (1,595) (1,536)
Purchase of reserves in-place.............. -- -- 29,089 27,519 7,403 --
------- ------- ------- -------- ------- -------
Proved reserves at end of year............. 219,894 165,977 265,238 145,125 190,141 403,256
======= ======= ======= ======== ======= =======
Proved developed reserves--
Beginning of year........................ 188,595 112,204 133,319 308,667 153,012 266,179
======= ======= ======= ======== ======= =======
End of year.............................. 171,052 122,500 188,595 112,204 133,319 308,667
======= ======= ======= ======== ======= =======
__________
* Includes estimated NGL reserves.
67
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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,
--------------------------------------------------------
2000 1999 1998
----------- ----------- -----------
Domestic
Future cash inflows........................................... $ 6,168,033 $ 4,823,952 $ 1,989,898
Future production costs....................................... (2,968,448) (2,132,655) (1,061,638)
Future development costs...................................... (349,150) (357,708) (289,686)
----------- ----------- -----------
Future net inflows before income tax.......................... 2,850,435 2,333,589 638,574
Future income taxes........................................... (896,974) (704,236) --
----------- ----------- -----------
Future net cash flows......................................... 1,953,461 1,629,353 638,574
10% discount factor........................................... (803,899) (739,181) (360,611)
----------- ----------- -----------
Standardized measure of discounted future net cash flows...... $ 1,149,562 $ 890,172 $ 277,963
=========== =========== ===========
FOREIGN
Future cash inflows........................................... $ 521,831 $ 469,327 $ 260,627
Future production costs....................................... (235,825) (177,150) (134,549)
Future development costs...................................... (54,475) (46,750) (66,715)
----------- ----------- -----------
Future net inflows before income tax.......................... 231,531 245,427 59,363
Future income taxes........................................... (70,452) (66,971) --
----------- ----------- -----------
Future net cash flows......................................... 161,079 178,456 59,363
10% discount factor........................................... (55,752) (61,455) (37,393)
----------- ----------- -----------
Standardized measure of discounted future net cash flows...... $ 105,327 $ 117,001 $ 21,970
=========== =========== ===========
Total
Future cash inflows........................................... $ 6,689,864 $ 5,293,279 $ 2,250,525
Future production costs....................................... (3,204,273) (2,309,805) (1,196,187)
Future development costs...................................... (403,625) (404,458) (356,401)
----------- ----------- -----------
Future net inflows before income tax.......................... 3,081,966 2,579,016 697,937
Future income taxes........................................... (967,426) (771,207) --
----------- ----------- -----------
Future net cash flows......................................... 2,114,540 1,807,809 697,937
10% discount factor........................................... (859,651) (800,636) (398,004)
----------- ----------- -----------
Standardized measure of discounted future net cash flows...... $ 1,254,889 $ 1,007,173 $ 299,933
=========== =========== ===========
*In addition to the information presented in the above table, the Company had
entered into swap arrangements on a portion of its future crude production as of
December 31, 2000 (see Note 12). The effects of these hedges would decrease the
PV-10 by approximately $39.3 million as of December 31, 2000.
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NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following are the principal sources of change in the standardized measure of
discounted future net cash flows:
Year Ended December 31,
-------------------------------------------------
2000 1999 1998
---------- ---------- ---------
Domestic
Standardized measure -- beginning of year..................... $ 890,172 $ 277,963 $ 711,038
Sales, net of production costs................................ (147,924) (94,384) (101,383)
Purchases of reserves in-place................................ -- 224,251 2,278
Net change in prices and production costs..................... 387,009 439,615 (466,018)
Extensions, discoveries and improved recovery, net of future
production and development costs............................. 181,885 59,873 46,713
Changes in estimated future development costs................. (8,806) (12,375) (14,956)
Development costs incurred.................................... 79,857 32,380 94,366
Revisions of quantity estimates............................... (233,132) 276,965 (86,459)
Accretion of discount......................................... 110,162 27,796 83,281
Net change in income taxes.................................... (149,592) (211,448) 121,770
Sales of reserves in-place.................................... (9,242) (151,348) (356)
Changes in production rates and other......................... 49,173 20,884 (112,311)
---------- ---------- ---------
Standardized measure -- end of year........................... $1,149,562 $ 890,172 $ 277,963
========== ========== =========
FOREIGN
Standardized measure -- beginning of year..................... $ 117,001 $ 21,970 $ 53,747
Sales, net of production costs................................ (27,255) (17,759) (3,923)
Purchases of reserves in-place................................ -- -- 2,750
Net change in prices and production costs..................... 19,595 59,641 (56,690)
Extensions, discoveries and improved recovery, net of future
production and development costs............................. -- -- --
Changes in estimated future development costs................. (7,167) 12,711 (3,091)
Development costs incurred.................................... 4,406 7,175 12,081
Revisions of quantity estimates............................... (7,204) 8,479 (750)
Accretion of discount......................................... 14,300 2,197 6,830
Net change in income taxes.................................... (7,284) (26,001) 14,552
Changes in production rates and other......................... (1,065) 48,588 (3,536)
---------- ---------- ---------
Standardized measure -- end of year........................... $ 105,327 $ 117,001 $ 21,970
========== ========== =========
Total
Standardized measure -- beginning of year..................... $1,007,173 $ 299,933 $ 764,785
Sales, net of production costs................................ (175,179) (112,143) (105,306)
Purchases of reserves in-place................................ -- 224,251 5,028
Net change in prices and production costs..................... 406,604 499,256 (522,708)
Extensions, discoveries and improved recovery, net of future
production and development costs.............................. 181,885 59,873 46,713
Changes in estimated future development costs................. (15,973) 336 (18,047)
Development costs incurred.................................... 84,263 39,555 106,447
Revisions of quantity estimates............................... (240,336) 285,444 (87,209)
Accretion of discount......................................... 124,462 29,993 90,111
Net change in income taxes.................................... (156,876) (237,449) 136,322
Sales of reserves in-place.................................... (9,242) (151,348) (356)
Changes in production rates and other......................... 48,108 69,472 (115,847)
---------- ---------- ---------
Standardized measure -- end of year........................... $1,254,889 $1,007,173 $ 299,933
========== ========== =========
*In addition to the information presented in the above table, the Company had
entered into swap arrangements on a portion of its future crude production as of
December 31, 2000 (see Note 12). The effects of these hedges would decrease the
PV-10 by approximately $39.3 million as of December 31, 2000.
69
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
SELECTED QUARTERLY FINANCIAL DATA (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED):
Quarter Ended (1)(2)
-------------------------------------------------------
March 31, June 30, September 30, December 31,
2000 2000 2000 2000
-------- -------- ------------ -----------
Revenues....................................... $ 71,505 $ 72,171 $91,274 $101,655
Operating earnings............................. $ 20,372 $ 20,505 $32,689 $ 25,424
Net income..................................... $ 651 $ 263 $ 8,850 $ 1,871
Earnings per Common share -- Basic............. $ 0.04 $ 0.02 $ 0.51 $ 0.11
Earnings per Common share -- Diluted........... $ 0.04 $ 0.00 $ 0.49 $ 0.10
Quarter Ended (1)(2)
-------------------------------------------------------
March 31, June 30, September 30, December 31,
1999 1999 1999 1999
-------- -------- ------------ -----------
Revenues....................................... $126,643 $ 52,860 $70,248 $ 82,484
Operating (loss) earnings...................... $(11,803) $ (8,125) $15,554 $ 21,943
Net income (loss) (3).......................... $ 31,342 $(15,558) $(2,756) $ 18,414
Earnings (loss) per Common share -- Basic...... $ 1.58 $ (0.78) $ (0.14) $ 1.00
Earnings (loss) per Common share -- Diluted.... $ 1.58 $ (0.78) $ (0.14) $ 0.99
_________
(1) Certain reclassifications of prior period amounts have been made to conform
with the current presentation.
(2) Results for the 2000 quarters have been revised due to a change in
accounting for processed fuel oil and natural gas liquids inventories (see
Note 2).
(3) Includes a fourth quarter decrease in the deferred tax asset valuation
allowance of $15.9 million.
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NUEVO ENERGY COMPANY
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
On March 9, 2001, Nuevo Energy Company ("Nuevo") notified KPMG LLP ("KPMG") that
their engagement as Nuevo's independent accountants will be terminated following
the issuance of their report on Nuevo's consolidated financial statements for
the fiscal year ended December 31, 2000. On March 9, 2001, the Board of
Directors of Nuevo, on the recommendation of the Audit Committee, appointed
Arthur Andersen LLP as Nuevo's independent accountants to audit its consolidated
financial statements for the year ending December 31, 2001.
Nuevo and KPMG have not, in connection with the audit of Nuevo's consolidated
financial statements for each of the prior two years ended December 31, 2000 and
December 31, 1999 or for any subsequent or interim period prior to and including
March 9, 2001, had any disagreement on any matter of accounting principles or
practice, financial statement disclosure, or auditing scope or procedure, which
disagreement, if not resolved to KPMG's satisfaction, would have caused KPMG to
make reference to the subject matter of the disagreement in connection with its
reports.
The reports of KPMG on the Nuevo financial statements for the past two fiscal
years did not contain an adverse opinion or a disclaimer of opinion and were not
qualified or modified as to uncertainty or audit scope.
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, 2000. 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, 2000. 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, 2000. 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, 2000. 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 bylaws.
3.1 Certificate of Incorporation of Nuevo Energy Company (Incorporated by
reference from Exhibit 3.1 to Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 1999).
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NUEVO ENERGY COMPANY
3.2 Certificate of Amendment to the Certificate of Incorporation of
Nuevo Energy Company (Incorporated by reference from Exhibit 3.2 to
Quarterly Report on Form 10-Q for the quarterly period ended June
30, 1999).
3.3 Bylaws of Nuevo Energy Company (Incorporated by reference from
Exhibit 3.3 to Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 1999).
3.4 Amendment to section 3.1 of the Bylaws of Nuevo Energy Company
(Incorporated by reference from Exhibit 3.4 to Quarterly Report on
Form 10-Q for the quarterly period ended June 30, 1999).
(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 Indenture dated April 1, 1996 among Nuevo Energy Company as Issuer,
various Subsidiaries as the Guarantors, and State Street Bank and
Trust Company as the Trustee - 9 1/2% Senior Subordinated Notes due
2006. (Incorporated by reference from Form S-3 (No. 333-1504).
4.3 Form of Amended and Restated Declaration of Trust dated December 23,
1996, among the Company, as Sponsor, Wilmington Trust Company, as
Institutional Trustee and Delaware Trustee, and Michael D. Watford,
Robert L. Gerry, III and Robert M. King, as Regular Trustees.
(Incorporated by reference from Exhibit 4.1 to Form 8-K filed on
December 23, 1996).
4.4 Form of Subordinated Indenture dated as of November 25, 1996,
between the Company and Wilmington Trust Company, as Indenture
Trustee. (Incorporated by reference from Exhibit 4.2 to Form 8-K
filed on December 23, 1996).
4.5 Form of First Supplemental Indenture dated December 23, 1996,
between the Company and Wilmington Trust Company, as Indenture
Trustee. (Incorporated by reference from Exhibit 4.3 to Form 8-K
filed on December 23, 1996).
4.6 Form of Preferred Securities Guarantee Agreement dated as of
December 23, 1996, between the Company and Wilmington Trust Company,
as Guarantee Trustee. (Incorporated by reference from Exhibit 4.4
to Form 8-K filed on December 23, 1996).
4.7 Form of Certificate representing TECONS. (Incorporated by reference
from Exhibit 4.5 to Form 8-K filed on December 23, 1996).
4.8 Shareholder Rights Plan, dated March 5, 1997, between Nuevo Energy
Company and American Stock Transfer & Trust Company, as Rights Agent
(incorporated by reference to Exhibit 1 to the Company's Form 8-A
filed on April 1, 1997).
4.9 Release and Termination of Subsidiary Guarantees with respect to the
9 1/2% Senior Subordinated Notes due 2006. (Incorporated by
reference to Exhibit 4.11 of Form 10-K for the year ended December
31, 1997.)
4.10 Second Supplemental Indenture to the Indenture dated April 1, 1996,
dated August 9, 1999 between Nuevo Energy Company and State Street
Bank and Trust Company - 9 1/2% Senior Subordinated Notes due 2006
(Incorporated by reference from Exhibit 4.10 to Registration
Statement on Form S-4 (No. 333-90235) filed on November 3, 1999).
4.11 Indenture dated as of August 20, 1999, between Nuevo Energy Company
and State Street Bank Trust Company, as Trustee (Incorporated by
reference from Exhibit 4.11 to Registration Statement on Form S-4
(No. 333-90235) filed on November 3, 1999).
72
4.12 Registration Agreement dated August 20, 1999, between Nuevo Energy
Company, Banc of America Securities LLC and Salomon Smith Barney
Inc. (Incorporated by reference from Exhibit 4.12 to Registration
Statement on Form S-4 (No. 333-90235) filed on November 3, 1999).
4.13 Indenture dated September 26, 2000, between Nuevo Energy Company
and State Street Bank and Trust Company as the Trustee - 9 3/8%
Senior subordinated Notes due 2010 (Incorporated by reference from
Exhibit 4.12 to Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 2000).
4.14 Registration Agreement dated September 26, 2000, between Nuevo
Energy Company and Banc of America Securities LLC, Banc One Capital
Markets, Inc. and J.P. Morgan & Co. (Incorporated by reference from
Exhibit 4.13 to Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 2000).
(10) Material Contracts.
10.1 Third Restated Credit Agreement dated June 7, 2000, between Nuevo
Energy Company (Borrower) and Bank of America N.A. (Administrative
Agent), Bank One, NA (Syndication Agent), Bank of Montreal
(Documentation Agent) and certain lenders (Incorporated by reference
from Exhibit 10.1 to Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 2000).
10.2 1990 Stock Option Plan of the Company, as amended (Incorporated by
reference from Exhibit 10.8 to Registration Statement on Form S-1
dated July 13, 1992).
10.3 1993 Stock Incentive Plan, as amended (Incorporated by reference
from Exhibit 4.2 to Registration Statement on Form S-8 (No. 333-
21063) filed on February 4, 1997.
10.4 1999 Stock Incentive Plan (Incorporated by reference from Exhibit
99.1) to Registration Statement on Form S-8 (No, 333-87899) filed on
September 28, 1999).
10.5 Nuevo Energy Company Deferred Compensation Plan (Incorporated
by reference from Exhibit 99 to Registration Statement on Form S-8
(No. 333-51217) filed on April 28, 1998).
10.6 Stock Purchase Agreement, dated as of June 30, 1994, among Amoco
Production Company ("APC"), Walter International Inc. ("Walter"),
Walter Congo Holdings, Inc. ("Walter Holdings"), Walter
International Congo, Inc. (before the merger "Walter Congo" and
after the merger "Old Walter Congo"), Nuevo, Nuevo Holding and The
Nuevo Congo Company (before the merger, "Nuevo Congo" and after the
merger, "Old Nuevo Congo"). (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.
73
NUEVO ENERGY COMPANY
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).
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 Exhibit 2.11 to
Form 8-K dated March 10, 1995).
10.17 Latent ORRI Contract dated February 25, 1995, among Walter,
Walter Holdings, Walter Congo, Nuevo, Nuevo Holding and Nuevo Congo.
(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 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).
10.20 Asset Purchase Agreement dated as of April 4, 1997, by and among
Torch California Company and Express Acquisition Company, as
Sellers, and Nuevo Energy Company, as Purchaser. (Incorporated by
reference from Exhibit 2.2 to Form S-3 (No. 333-1504)).
10.21 Employment Agreement with Douglas L. Foshee. (Incorporated by
reference to Exhibit 10.23 to Form 10-K for the year ended December
31, 1997.)
10.22 Employment Agreement with Robert M. King. (Incorporated by
Reference from Exhibit 10.24 to Form 10-K for the year ended
December 31, 1998).
10.23 Employment Agreement with Dennis Hammond. (Incorporated by
reference to Exhibit 10.26 to Form 10-K for the year ended December
31, 1997.)
10.24 Employment Agreement with Michael P. Darden. (Incorporated by
reference from Exhibit 10.1 to Form 10-Q filed November 13, 1998).
74
NUEVO ENERGY COMPANY
10.25 Purchase and sale agreement dated October 16, 1998 between Nuevo
Energy Company (Seller) and Samson Lone Star Limited Partnership
(Buyer). (Incorporated by reference from Exhibit 10.28 to Form 10-K
for the year ended December 31, 1998).
10.26 Master Services Agreement among the Company and Torch Energy
Advisors Incorporated, Torch Operating Company, Torch Energy
Marketing, Inc., and Novistar, Inc. dated January 1, 1999.
(Incorporated by reference from Exhibit 10.29 to Form 10-K for the
year ended December 31, 1998).
10.27 Employment Agreement with Bruce Murchison dated June 1, 1999.
(Incorporated by reference from Exhibit 10.27 to Form 10-Q for the
quarter ended September 30, 1999).
10.28 Employment Agreement with John P. McGinnis dated July 15, 1999.
(Incorporated by reference from Exhibit 10.28 to Form 10-Q for the
quarter ended September 30, 1999).
10.29 Crude Oil Purchase Agreement dated February 4, 2000 between Nuevo
Energy Company and Tosco Corporation. (Incorporated by reference
from Exhibit 10.1 to Form 8-K dated March 23, 2000).
10.30 Employment Agreement with Phillip Gobe dated February 26, 2001.
10.31 Severance Protection Agreement dated March 25, 2001.
(21) Subsidiaries of the Registrant
(23) Consents of experts and counsel:
23.1 Consent of KPMG LLP
(b) Reports on Form 8-K:
1. A Current Report on Form 8-K, dated November 13, 2000, reporting Item 9.
Regulation FD Disclosure was filed on November 13, 2000.
2. A Current Report on Form 8-K, dated December 15, 2000, reporting Item 9.
Regulation FD Disclosure was filed on December 15, 2000.
(99) Additional Exhibits
None.
75
NUEVO ENERGY COMPANY
GLOSSARY OF OIL AND GAS TERMS
TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS
. Bbl -- One stock tank barrel, or 42 US gallons liquid volume, of crude oil
or other liquid hydrocarbons.
. Bcf -- One billion cubic feet of natural gas.
. Bcfe -- One billion cubic feet of natural gas equivalent.
. BOE -- One barrel of oil equivalent, converting gas to oil at the ratio of
6 Mcf of gas to 1 Bbl of oil.
. BOPD -- One barrel of oil per day.
. MBbl -- One thousand Bbls.
. Mcf -- One thousand cubic feet of natural gas.
. MMBbl -- One million Bbls of oil or other liquid hydrocarbons.
. MMcf -- One million cubic feet of natural gas.
. MBOE -- One thousand BOE.
. MMBOE -- One million BOE.
TERMS USED TO DESCRIBE THE COMPANY'S INTERESTS IN WELLS AND ACREAGE
. Gross oil and gas wells or acres -- The Company's gross wells or gross
acres represent the total number of wells or acres in which the Company
owns a working interest.
. Net oil and gas wells or acres -- Determined by multiplying "gross" oil
and natural gas wells or acres by the working interest that the Company
owns in such wells or acres represented by the underlying properties.
TERMS USED TO ASSIGN A PRESENT VALUE TO THE COMPANY'S RESERVES
. Standard measure of proved reserves -- The present value, discounted at
10%, of the pre-tax future net cash flows attributable to estimated net
proved reserves. The Company calculates this amount by assuming that it
will sell the oil and gas production attributable to the proved reserves
estimated in its independent engineer's reserve report for the prices it
received for the production on the date of the report, unless it had a
contractual arrangement specific to a property to sell the production for
a different price. The Company also assumes that the cost to produce the
reserves will remain constant at the costs prevailing on the date of the
report. The assumed costs are subtracted from the assumed revenues
resulting in a stream of future net cash flows. Estimated future income
taxes using rates in effect on the date of the report are deducted from
the net cash flow stream. The after-tax cash flows are discounted at 10%
to result in the standardized measure of the Company's proved reserves.
The standardized measure of the Company's proved reserves is disclosed in
the Company's audited financial statements in Note 14.
. Pre-tax discounted present value -- The discounted present value of proved
reserves is identical to the standardized measure, except that estimated
future income taxes are not deducted in calculating future net cash flows.
The Company discloses the discounted present value without deducting
estimated income taxes to provide what it believes is a better basis for
comparison of its reserves to the producers who may have different tax
rates.
76
TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES
. Proved reserves -- The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering data,
appear with reasonable certainty to be recoverable in the future from known
oil and natural gas reservoirs under existing economic and operating
conditions.
The SEC definition of proved oil and gas reserves, per Article 4-10(a)(2) of
Regulation S-X, is as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable
in future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future conditions.
(a) Reservoirs are considered proved if economic producibility is supported
by either actual production or conclusive formation test. The area of a
reservoir considered proved includes (A) that portion delineated by drilling
and defined by gas-oil and/or oil-water contacts, if any; and (B) the
immediately adjoining portions not yet drilled, but which can be reasonably
judged as economically productive on the basis of available geological and
engineering data. In the absence of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the lower proved limit of
the reservoir.
(b) Reserves which can be produced economically through application of
improved recovery, techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(c) Estimates of proved reserves do not include the following: (1) oil that
may become available from known reservoirs, but is classified separately as
"indicated additional reserves"; (2) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (3)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (4) crude oil, natural gas, and natural gas liquids, that may
be recovered from oil shales, coal, gilsonite and other such sources.
. Proved developed reserves -- Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
. Proved undeveloped reserves -- Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where
a relatively major expenditure is required.
TERMS WHICH DESCRIBE THE COST TO ACQUIRE THE COMPANY'S RESERVES
. Finding costs -- The Company's finding costs compare the amount the
Company spent to acquire, explore and develop its oil and gas properties,
explore for oil and gas and to drill and complete wells during a period,
with the increases in reserves during the period. This amount is calculated
by dividing the net change in the Company's evaluated oil and property costs
during a period by the change in proved reserves plus production over the
same period. The Company's finding costs as of December 31 of any year
represent the average finding costs over the three-year period ending
December 31 of that year.
TERMS WHICH DESCRIBE THE PRODUCTIVE LIFE OF A PROPERTY OR GROUP OF PROPERTIES
. Reserve life index -- A measure of the productive life of an oil and gas
property or a group of oil and gas properties, expressed in years. Reserve
life index for the years ended December 31, 2000, 1999 or 1998 equal the
estimated net proved reserves attributable to a property or group of
properties divided by production from the property or group of properties
for the four fiscal quarters preceding the date as of which the proved
reserves were estimated.
77
NUEVO ENERGY COMPANY
TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF THE COMPANY'S OIL AND GAS
PROPERTIES
. Royalty interest -- A real property interest entitling the owner to
receive a specified portion of the gross proceeds of the sale of oil and
natural gas production or, if the conveyance creating the interest provides,
a specific portion of oil and natural gas produced, without any deduction
for the costs to explore for, develop or produce the oil and natural gas. A
royalty interest owner has no right to consent to or approve the operation
and development of the property, while the owners of the working interests
have the exclusive right to exploit the mineral on the land.
. Working interest -- A real property interest entitling the owner to
receive a specified percentage of the proceeds of the sale of oil and
natural gas production or a percentage of the production, but requiring the
owner of the working interest to bear the cost to explore for, develop and
produce such oil and natural gas. A working interest owner who owns a
portion of the working interest may participate either as operator or by
voting his percentage interest to approve or disapprove the appointment of
an operator and drilling and other major activities in connection with the
development and operation of a property.
. Net revenue interest -- A real property interest entitling the owner to
receive a specified percentage of the proceeds of the sale of oil and
natural gas production or a percentage of the production, net of royalty
interests and costs to explore for, develop and produce such oil and natural
gas.
TERMS USED TO DESCRIBE SEISMIC OPERATIONS
. Seismic data -- Oil and gas companies use seismic data as their principal
source of information to locate oil and gas deposits, both to aid in
exploration for new deposits and to manage or enhance production from known
reservoirs. To gather seismic data, an energy source is used to send sound
waves into the subsurface strata. These waves are reflected back to the
surface by underground formations, where they are detected by geophones
which digitize and record the reflected waves. Computers are then used to
process the raw data to develop an image of underground formations.
. 2-D seismic data -- 2-D seismic survey data has been the standard
acquisition technique used to image geologic formations over a broad area.
2-D seismic data is collected by a single line of energy sources which
reflect seismic waves to a single line of geophones. When processed, 2-D
seismic data produces an image of a single vertical plane of sub-surface
data.
. 3-D seismic -- 3-D seismic data is collected using a grid of energy
sources, which are generally spread over several miles. A 3-D survey
produces a three dimensional image of the subsurface geology by collecting
seismic data along parallel lines and creating a cube of information that
can be divided into various planes, thus improving visualization.
Consequently, 3-D seismic data is a more reliable indicator of potential oil
and natural gas reservoirs in the area evaluated than 2-D seismic data.
THE COMPANY'S MISCELLANEOUS DEFINITIONS
. Infill drilling - Infill drilling is the drilling of an additional well or
additional wells in excess of those provided for by a spacing order in order
to more adequately drain a reservoir.
. No. 6 fuel oil (Bunker) - No. 6 fuel oil is a heavy residual fuel oil used
by ships, industry, and for large-scale heating installations.
. Upstream oil and gas properties - Upstream is a term used in describing
operations performed before those at a point of reference. Production is an
upstream operation and marketing is a downstream operation when the refinery
is used as a point of reference. On a gas pipeline, gathering activities are
considered to have ended when gas reaches a central point for delivery into
a single line, and facilities used before this point of reference are
upstream facilities used in gathering, whereas facilities employed after
commingling at the central point and employed to make ultimate delivery of
the gas are downstream facilities.
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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 28, 2001 By: /s/Douglas L. Foshee
------------------ ---------------------
Douglas L. Foshee
Chairman of the Board of Directors,
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
is signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
By: /s/ Douglas L. Foshee Date: March 28, 2001
---------------------------------- --------------
Douglas L. Foshee
Chairman of the Board of Directors,
President and Chief Executive Officer
(Principal Executive Officer)
By: /s/ Robert M. King Date: March 28, 2001
---------------------------------- --------------
Robert M. King
Senior Vice President and
Chief Financial Officer (Principal
Financial Officer)
By: /s/ Sandra D. Kraemer Date: March 28, 2001
---------------------------------- --------------
Sandra D. Kraemer
Controller (Principal Accounting
Officer)
By: /s/ Robert L. Gerry III Date: March 28, 2001
---------------------------------- --------------
Robert L. Gerry III
Director
By: /s/ Gary R. Petersen Date: March 28, 2001
---------------------------------- --------------
Gary R. Petersen
Director
By: /s/ Thomas D. Barrow Date: March 28, 2001
---------------------------------- --------------
Thomas D. Barrow
Director
By: /s/ Isaac Arnold, Jr. Date: March 28, 2001
---------------------------------- --------------
Director
By: /s/ David Ross Date: March 28, 2001
---------------------------------- --------------
David Ross
Director
By: /s/ Robert W. Shower Date: March 28, 2001
---------------------------------- --------------
Robert W. Shower
Director
By: /s/ Charles M. Elson Date: March 28, 2001
---------------------------------- --------------
Charles M. Elson
Director
By: /s/ David H. Batchelder Date: March 28, 2001
---------------------------------- --------------
David H. Batchelder
Director
79