1
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
(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, 1999
-----------------
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
incorporation or organization) Identification No.)
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, 2000, was approximately $350,119,028.
As of March 22, 2000, the number of outstanding shares of the registrant's
common stock was 17,560,829.
Documents Incorporated by Reference:
Portions of the registrant's annual proxy statement, to be filed within 120 days
after December 31, 1999, are incorporated by reference into Part III.
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NUEVO ENERGY COMPANY
ANNUAL REPORT ON FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
TABLE OF CONTENTS
PAGE
NUMBER
PART I
Item 1. Business...................................................................................... 2
Item 2. Properties.................................................................................... 13
Item 3. Legal Proceedings............................................................................. 22
Item 4. Submission of Matters to a Vote of Security Holders........................................... 22
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters..................... 23
Item 6. Selected Financial Data....................................................................... 25
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations......... 26
Item 7a. Quantitative and Qualitative Disclosures About Market Risk.................................... 38
Item 8. Financial Statements and Supplementary Data................................................... 40
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......... 77
PART III
Item 10. Directors and Executive Officers of the Registrant............................................ 77
Item 11. Executive Compensation........................................................................ 77
Item 12. Security Ownership of Certain Beneficial Owners and Management................................ 77
Item 13. Certain Relationships and Related Transactions................................................ 77
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................... 77
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"),
and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"). All
statements other than statements of historical facts included in this document,
including without limitation, statements under "Management's Discussion and
Analysis of Financial Condition and Results of Operations" regarding the
Company's financial position, estimated quantities and net present values of
reserves, business strategy, plans and objectives of management of the Company
for future operations and covenant compliance, are forward looking statements.
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 have each made substantial equity
investments in Nuevo, in order to align the Company's directors and executive
officers interests with that of 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 strategic divestitures and an opportunistic
exploration program, which provides exposure to high potential prospects. The
Company's primary strengths are its track record of rapid reserve growth on a
per share basis, achieved at extremely low cost relative to industry averages;
its large inventory of exploitation projects in its core areas of operation
which the Company believes will support future growth in
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NUEVO ENERGY COMPANY
reserves and production per share; its demonstrated ability to significantly
reduce operating costs on acquired properties from levels experienced by prior
operators; 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.
During the five years ended December 31, 1999, the Company invested $595.4
million in seven acquisitions that added estimated net proved reserves of 214.6
million barrels ("MMBBLS") of oil and 171.1 billion cubic feet ("BCF") of
natural gas and replaced 501% of its production at an average cost of $2.72 per
barrel of oil equivalent ("BOE"). As a result, the Company's estimated net
proved equivalent reserves have increased by approximately 258% since 1995.
Domestic Operations
As of December 31, 1999, the Company's estimated net U.S. proved
reserves totaled 263.4 million barrels of oil equivalent ("MMBOE") or 91% of
Nuevo's total proved reserve base. During 1999, the Company's domestic
production was 18.9 MMBOE, or 91% of total production.
West: 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 by district
as either Bakersfield, Pacific Onshore or Pacific Offshore.
Nuevo's Bakersfield district operations encompass an estimated net
proved reserve base of 135.4 MMBOE as of December 31, 1999, and produced 8.5
MMBOE in 1999. Bakersfield district 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, and in the Coalinga gas field in the North San
Joaquin Valley. The Company's Bakersfield 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 two zones in the Cymric field, the Tulare formation 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 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.
Nuevo's Pacific Onshore district operations encompass an estimated net
proved reserve base of 50.8 MMBOE as of December 31, 1999, and produced 2.5
MMBOE in 1999. Pacific Onshore district properties include the Company's
interest in the Brea Olinda oil field in northern Orange County. The Company
operates three fee properties in the Brea Olinda field with a 100% working and
net revenue interest. The Company also 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 Pacific Offshore district operations encompass an estimated net
proved reserve base of 74.9 MMBOE as of December 31, 1999, and resulted in
production of 6.9 MMBOE in 1999. Pacific Offshore district properties include
the Company's interests in the Point Pedernales, 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 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).
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East: 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
2.3 MMBOE as of December 31, 1999, and produced 1.0 MMBOE in 1999. Houston
district properties include the Company's interests in the Giddings gas fields
in Grimes and Austin Counties, Texas; and in the North Frisco City oil field in
Monroe County, Alabama. The Company owns an interest in 12 producing wells in
the Giddings field and has an average 46.9% working (35.2% net revenue) interest
in these wells. The North Frisco City field is Company-operated. Nuevo owns
approximately a 22% working (17% net revenue) interest.
General: 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 1,250
domestic exploitation projects on existing properties, at a West Texas
Intermediate ("WTI") crude price of $18.50 per barrel of oil ("BBL"). Capital
expenditures for domestic exploitation projects totaled $38.3 million in 1999
and are budgeted at approximately $105.0 million in 2000, if the crude oil
forward strip remains above $20.00 per BBL. Examples of current or planned
projects include the continuation of horizontal drilling in the Bakersfield
district and infill drilling in the recently acquired acreage 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 four dry wells in 1999.
Capital expenditures for domestic exploration activity totaled $3.9
million in 1999 and are budgeted at approximately $11.0 million in 2000.
International Operations
As of December 31, 1999, the Company's estimated international net
proved reserves totaled 26.0 MMBOE, or 9% of Nuevo's total proved reserve base.
During 1999, 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 I 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, 1999 were 26.0 MMBOE, and production during 1999
totaled 1.8 MMBOE, all from the Yombo field. In 1999, revenues relating to
production from the Yombo field accounted for approximately 13% 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 I 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 2000
include performing a study to evaluate waterflood performance and to convert up
to three wells to water injectors.
Ghana: 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 the Republic of Ghana in West Africa ("Ghana"). In
September 1998, the Company plugged and abandoned its first well in Ghana on the
East Cape
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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.
In October 1997, Nuevo Ghana, Inc., ("Nuevo Ghana"), signed a petroleum
agreement with Ghana and the Ghana National Petroleum Corporation, ("GNPC") for
petroleum rights covering 2.7 million acres offshore Ghana in the Accra-Keta
prospect area. The Company is the operator of this prospect with a 100% working
interest. The exploration program for this acreage involves reprocessing
existing seismic data, shooting additional seismic and drilling an exploration
well during the first phase of the agreement. The Company completed a 3-D
seismic survey across this concession in March 2000. The results are currently
being reviewed in-house, and based upon the results, the Company plans to drill
its first exploratory well on the concession in late 2000.
Tunisia: In December 1998, the Company temporarily abandoned the Chott
Fejaj #3 well in Tunisia, North Africa. Based on the Company's evaluation of the
initial test results on this well, the Company expensed the $1.8 million of
costs incurred as dry hole costs in 1998. The Company has acquired additional
regional seismic data across its Chott-Fejaj concession. This data was acquired
to better evaluate the sub-salt potential beneath the #3 well, which the Company
plans to deepen in late 2000. The Company owns a 17.5% working interest in the
well.
General: Capital expenditures for 1999 international exploration and
development activity totaled $2.3 million and $20.4 million, respectively. The
Company's 2000 international exploration budget of approximately $8.0 million
includes seismic evaluation, data acquisition and the drilling of two wells.
International development plans for 2000 include the continuation of the
Company's waterflood program in the Congo and are budgeted at approximately $2.0
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, 1999, 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 3.2 MMCFD at December 31, 1999. The HS&P Gas Plant is used to process
gas production from the Point Pedernales field. At December 31, 1999, the HS&P
Gas Plant was processing 2.6 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
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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. The Company retained its remaining two
California gas plants, as these plants are strategic assets for the Company's
oil and gas activities in California.
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
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 16,000 acres of agricultural property in the central valley of
California. As of December 31, 1999, there was $51.0 million allocated to land.
The office buildings are included in other facilities at December 31, 1999.
Consistent with Nuevo's proactive asset management strategy, the
Company plans to sell certain of its surface real estate assets in late 2000 or
2001. With land values rising in California, the Company expects to monetize a
significant portion of its California real estate portfolio.
The surface fee in Orange County lies within the sphere of influence of
the city of Brea, which is in north Orange County and includes three fee
parcels, the Stearns Fee, the Stearns Columbia Fee and Naranjal "B" Fee. These
are contiguous parcels with gross residential development potential of
approximately 230 acres. Nuevo is working toward entitlement of this property,
which is expected to be complete in the second half of 2000. The Company will
evaluate its options at that time, including the potential sale. Plans are being
formulated in relation to the tract of land in Santa Barbara County. 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:
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. 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,
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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 million barrels of oil equivalent
("BOE") 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.
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.
In April 1998, the Company acquired an additional working interest in
the Marine I 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 and
certain of its wholly-owned subsidiaries for a combined net purchase price of
$525.9 million, plus a contingent payment based on future realized oil prices.
The California Properties consisted of 26 fields with approximately 2,400 active
wells, and estimated net proved reserves as of December 31, 1999 of 249.3 MMBOE.
During 1999, the California Properties constituted 86% of the Company's total
oil and natural gas production on a barrel of oil equivalent basis. Since
acquiring the California Properties, the Company has spent approximately $255.0
million to complete over 470 exploitation and development projects.
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, 1999, 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 13
to the Notes to Consolidated Financial Statements.
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Markets
The markets for hydrocarbons continue to be quite volatile. The
Company's financial condition, operating results, future growth and the carrying
value of its oil and gas properties are substantially dependent on prevailing
prices of oil and gas. The Company's ability to maintain or increase its
borrowing capacity and to obtain additional capital on attractive terms is also
substantially dependent upon oil and gas prices. Prices for oil and gas are
subject to large fluctuations in response to relatively minor changes in the
supply of and demand for oil and gas, market uncertainty and a variety of
additional factors beyond the control of the Company. These factors include
weather conditions in the United States, the condition of the United States
economy, the actions of the Organization of Petroleum Exporting Countries,
governmental regulation, political stability in the Middle East and elsewhere,
the foreign supply of oil and gas, the price of foreign oil imports and the
availability of alternate fuel sources. Any substantial and extended decline in
the price of oil 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 17 to the Notes to Consolidated Financial Statements.)
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 40% of the Company's total 1999
output.
In addition, properties which produce primarily other grades of
relatively heavy oil (generally, 19 degrees API or heavier but produced through
non-thermal operations) constituted 17% of the Company's total 1999 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 Company's Yombo Field production in its Marine I 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 1999 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 79%, 60% and 62% of 1999, 1998
and 1997 oil and gas revenues, respectively. Also in 1999 and 1998, sales to
Torch Energy Marketing accounted for 12% and 10% of total 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.
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
8
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NUEVO ENERGY COMPANY
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, 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 which 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 sells its production in the spot market 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
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NUEVO ENERGY COMPANY
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 regulating the release of materials in the environment or
otherwise relating to the protection of the environment will not have a material
effect upon the operations, capital expenditures, earnings or the competitive
position of the Company.
Activities of the Company with respect to exploration, drilling and
production from wells, natural gas facilities, including the operation and
construction of pipelines, plants and other facilities for transporting,
processing, treating or storing natural gas and other products, are subject to
stringent environmental regulation by state and Federal authorities including
the Environmental Protection Agency ("EPA"), the Department of Transportation
and 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, 1999, the Company's net liability for these exit costs were approximately
$99 million. The Company is not indemnified for any part of these exit costs.
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.
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NUEVO ENERGY COMPANY
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 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
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NUEVO ENERGY COMPANY
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, 1999, the Company employed 62 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 Torch and its subsidiaries, which maintains a large
technical, operating, accounting and administrative staff to provide services to
Nuevo and its other clients. (See Note 6 to the Notes to Consolidated Financial
Statements). The combined personnel of Torch and the Company consisted of 982
employees at December 31, 1999.
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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, Louisiana, 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, 1999 increased
approximately 12% since December 31, 1998, primarily as a result of higher oil
prices. (See Note 17 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,
1999, which relates to the Company's principal oil and gas properties:
Net Proved Reserves (SEC)
December 31, 1999 1999 Production
--------------------------- ---------------------------
Gross Oil* Gas Oil* Gas
Wells (Mbbls) (Mmcf) MBOE (Mbbls) (Mmcf) MBOE PV-10**
------- ------- ------- ------- ------- ------- ------- -----------
U.S. PROPERTIES
California Fields
Cymric ................................. 574 75,285 2,260 75,662 3,798 2,001 4,131 $ 420,596
Midway-Sunset .......................... 483 37,537 -- 37,537 2,590 -- 2,590 200,526
Brea Olinda ............................ 217 33,275 21,924 36,929 783 55 792 123,790
Belridge ............................... 342 12,336 683 12,450 676 178 706 89,395
Santa Clara ............................ 26 20,572 37,565 26,833 840 628 944 84,650
Dos Cuadras ............................ 98 13,336 8,407 14,737 660 499 743 61,733
Point Pedernales ....................... 12 13,682 4,584 14,446 2,202 726 2,323 43,622
Huntington Beach ....................... 17 6,533 507 6,617 663 75 676 41,310
Other 632 26,040 58,890 35,855 3,205 10,234 4,912 146,894
------- ------- ------- ------- ------- ------- ------- -----------
Total California Fields .............. 2,401 238,596 134,820 261,066 15,417 14,396 17,817 1,212,516
------- ------- ------- ------- ------- ------- ------- -----------
Other U.S. Fields
North Frisco City, Alabama ............. 6 401 1,132 590 230 185 261 5,999
Giddings, Texas ........................ 13 8 2,724 462 6 1,739 296 3,793
Other .................................. 27 185 6,449 1,259 239 1,300 455 8,147
------- ------- ------- ------- ------- ------- ------- -----------
Total U.S. Properties ................ 2,447 239,190 145,125 263,377 15,892 17,620 18,829 1,230,455
------- ------- ------- ------- ------- ------- ------- -----------
FOREIGN PROPERTIES
Yombo, Congo ........................... 24 18,017 -- 18,017 1,835 -- 1,835 126,386
Masseko, Congo ......................... -- 8,031 -- 8,031 -- -- -- 16,615
------- ------- ------- ------- ------- ------- ------- -----------
Total Foreign Properties ............. 24 26,048 -- 26,048 1,835 -- 1,835 143,001
------- ------- ------- ------- ------- ------- ------- -----------
Unocal contingent payment ................. -- -- -- -- -- -- -- (59,413)
Hedge effect .............................. -- -- -- -- -- -- -- (69,421)
------- ------- ------- ------- ------- ------- ------- -----------
TOTAL PROPERTIES 2,471 265,238 145,125 289,425 17,727 17,620 20,664 $ 1,244,622
======= ======= ======= ======= ======= ======= ======= ===========
---------------
* includes natural gas liquids
** pre-tax
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NUEVO ENERGY COMPANY
The summary of SEC reserves, which is presented on the previous page,
is computed based on realized prices at December 31, 1999, held constant over
time (see Note 17 to the Notes to Consolidated Financial Statements). Oil prices
at December 31, 1999, were unusually high. 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 (based on NYMEX prices of $22.40 per barrel of oil in 2000 and
$20.00 per barrel thereafter, and $2.50 per Mcf of gas held constant), as of
December 31, 1999. 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, 1999
----------------------------------
Oil* Gas
(Mbbls) (Mmcf) MBOE PV-10**
-------- -------- -------- ----------
U.S. PROPERTIES
California Fields
Cymric................... 72,265 2,247 72,640 $ 247,633
Midway-Sunset............ 35,656 -- 35,656 114,632
Brea Olinda.............. 33,118 21,866 36,762 78,504
Santa Clara.............. 19,454 35,212 25,323 52,853
Belridge................. 12,259 661 12,369 50,541
Dos Cuadras ............. 12,058 7,522 13,312 34,388
Point Pedernales......... 13,636 4,597 14,402 27,533
Huntington Beach......... 5,915 457 5,991 20,702
Other.................... 22,753 60,677 32,865 90,823
-------- -------- -------- ----------
Total California
Fields............... 227,114 133,239 249,320 717,609
-------- -------- -------- ----------
Other U.S. Fields
North Frisco City,
Alabama................ 401 1,132 590 5,054
Giddings, Texas.......... 8 2,737 464 4,134
Other.................... 176 6,471 1,255 8,295
-------- -------- -------- ----------
Total U.S. Properties.. 227,699 143,579 251,629 735,092
-------- -------- -------- ----------
FOREIGN PROPERTIES
Yombo, Congo............. 18,589 -- 18,589 111,808
Masseko, Congo........... 8,057 -- 8,057 9,777
-------- -------- -------- ----------
Total Foreign
Properties........... 26,646 -- 26,646 121,585
-------- -------- -------- ----------
Hedge effect..................... -- -- -- (35,179)
-------- -------- -------- ----------
TOTAL PROPERTIES 254,345 143,579 278,275 $ 821,498
======== ======== ======== ==========
* includes natural gas liquids
** pre-tax
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,
1999. Undeveloped acreage is considered to be those leased acres on which wells
have not been drilled or completed to a point that would permit the production
of commercial quantities of oil and gas, regardless of whether or not such
acreage contains proved reserves. A gross acre in the following table refers to
the number of acres in which a working interest is owned directly by the
Company. The number of net acres is the sum of the fractional ownership of
working interests owned directly by the Company in the gross acres expressed as
a whole number and percentages thereof. A "net acre" is deemed to exist when the
sum of fractional ownership of working interests in gross acres equals one.
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NUEVO ENERGY COMPANY
Gross Net
----------- -----------
Developed Acreage 184,877 115,790
Undeveloped Acreage 5,710,074 4,301,168
----------- -----------
Total 5,894,951 4,416,958
=========== ===========
The following table sets forth the Company's undeveloped acreage as of December
31, 1999:
Gross Net
----------- -----------
California 232,455 111,381
Texas 37,955 14,144
Congo, West Africa:
Marine 1 Permit 38,000 19,000
Ghana, West Africa:
East Cape Three Points 1,700,000* 1,275,000*
Accra-Keta 2,700,000 2,700,000
Tunisia, North Africa 976,540 170,895
Other 25,124 10,748
----------- -----------
Total 5,710,074 4,301,168
=========== ===========
* Relinquished in February 2000
Productive Wells
The following table sets forth the Company's gross and net interests in
productive oil and gas wells as of December 31, 1999. Productive wells are
producing wells and wells capable of production.
Gross Net
-------- --------
Oil Wells 2,361 1,743
Gas Wells 110 66
-------- --------
Total 2,471 1,809
======== ========
Production
The Company's principal production volumes for the year ended December
31, 1999, were from California and the Congo.
Data relating to production volumes, average sales prices, average unit
production costs and oil and gas reserve information appears in Note 17 to the
Notes to Consolidated Financial Statements.
Drilling Activity and Present Activities
During the three year period ended December 31, 1999, 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.
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.
Between the date of the California Properties acquisition, April 9,
1996, and the end of 1999, the Company drilled 248 wells in the Cymric field in
central California, which contained 26% of the Company's total estimated net
proved equivalent reserves at December 31, 1999, and anticipates drilling
approximately 120 wells during 2000. In the Midway-Sunset field in central
California, which contained 13% of the total estimated net proved equivalent
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NUEVO ENERGY COMPANY
reserves at December 31, 1999, the Company drilled 10 wells during 1999, and
plans to drill approximately 45 wells in 2000.
In 1997, the Company drilled an exploration well to evaluate the Lower
Sendji and subsalt sections underlying the Masseko structure located several
miles to the west of the Yombo field in the Congo, as well as to further
delineate the Upper Sendji and Tchala zones, which were discovered but not
developed by the 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 2000
include performing a study to evaluate waterflood performance and to convert up
to three wells to water injectors.
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;
and (iii) successful extension to the south and east at the Monument Junction
reservoir in the Cymric Field in California. In 1997, the Company's exploration
program resulted in nine successful wells out of 14 drilled. Discoveries in 1997
included: the Masseko structure offshore Congo, the Monument Junction reservoir
in Cymric field, California and Tranquillon Ridge, offshore California.
The Company had nine gross (nine net) wells in progress at December 31,
1999. 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
---------- ----- ----- ---------- ----- -----
1997 9 5 14 6.63 2.33 8.96
1998 8 6 14 4.09 3.58 7.67
1999 -- 4 4 -- 2.33 2.33
Development Wells
---------------------------------------------------------------------------
Gross Net
---------------------------------- ----------------------------------
Dry Dry
Productive Holes Total Productive Holes Total
---------- ----- ----- ---------- ----- -----
1997 236 1 237 217.52 1.00 218.52
1998 155 -- 155 134.43 -- 134.43
1999 44 1 45 40.21 0.33 40.54
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, 1999, the Company's net liability for these exit costs were approximately
$99 million. The Company is not indemnified for any part of these exit costs.
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NUEVO ENERGY COMPANY
Gas Plant, Pipelines and Other Facilities
As of December 31, 1999, the Company owned interests in the following
gas plant facilities:
1999
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 3.7 80%
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 December 1997, the Company announced its intention to dispose of the
remainder of its non-core gas gathering, pipeline and storage assets during
1998. 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. in 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 current estimated fair value of the Illini pipeline. The Company's
results of operations included operating results from these assets through the
disposition date, as applicable; however, these assets were not depreciated
subsequent to 1997. The Company retained its remaining two California gas
plants, as these plants are strategic assets for the Company's oil and gas
activities in California.
On May 2, 1997, Nuevo Liquids, a wholly-owned subsidiary of the
Company, sold its 95% interest in the NuStar Joint Venture, which held the
Company's investment in the Benedum Plant System, for proceeds of $25.0 million.
The Company recognized a pre-tax gain of $2.3 million on this sale. The
effective date of this sale was January 1, 1997.
Risk Factors
Recently Low Oil Prices
The Company's financial condition, operating results, future growth and
the carrying value of its oil and gas properties are substantially dependent on
prevailing oil and gas prices. 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. Beginning in late 1997 and
continuing through early 1999, oil prices were very low compared with prices
received for oil historically. Oil prices improved significantly during 1999,
however, these low prices adversely affected the Company's revenues and
operating cash flows during 1998 and early 1999. Any substantial or extended
decline in future oil prices would have a material adverse effect on the Company
in the future.
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 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
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NUEVO ENERGY COMPANY
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 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.
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 increases 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
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NUEVO ENERGY COMPANY
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, 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.
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 oil 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
19
21
NUEVO ENERGY COMPANY
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 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 production is
expected to average at 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 $44.9
million in 1999, increased by $0.6 million in 1998 and reduced by $6.0 million
in 1997. For 2000, the Company has entered into swap contracts on 16,500 barrels
of oil per day ("BOPD"), at an average West Texas Intermediate ("WTI") price of
$17.94 per barrel. The Company has also entered into cost-less collars on an
additional 16,500 BOPD, with a floor of $16.00 per barrel and ceiling of $21.21
per barrel. This production is hedged based on a fixed NYMEX price for each type
of crude oil that the Company produces in California. As a result of the TOSCO
contract, (see Note 13 to the Notes to Consolidated Financial Statements), which
fixes the price of the Company's California production at approximately 72% of
the NYMEX price effective January 1, 2000, these hedge transactions have the
effect on a price basis of hedging substantially all of the Company's current
production for the year 2000. Also for the year 2000, the Company has entered
into basis swaps on 3,000 BOPD of its production in the Congo, hedging the basis
differential between No. 6 fuel oil and WTI at an average differential of $1.88
per barrel. See Item 7a. "Quantitative and Qualitative Disclosures About Market
Risk".
Hedge Policy
The Board of Directors adopted a Commodity Hedging Policy which is 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, during
periods with abnormally low commodity prices: (i) 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 hedging 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 so much of its production as is necessary to meet its policy goals for
that period. Variations from this approach require Board approval. The Company
prohibits hedging activity that is speculative or otherwise increases the
Company's risk. 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
20
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NUEVO ENERGY COMPANY
sources and the intermediate transportation of gas are factors which affect the
Company's ability to compete in the marketplace. The Company's competitors
include major integrated oil companies and a substantial number of independent
energy companies, many of which possess greater financial and other resources
than the Company.
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.
21
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NUEVO ENERGY COMPANY
ITEM 3. LEGAL PROCEEDINGS
The Company has been named as a defendant in the lawsuit 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. currently pending
in the 79th Judicial District Court of Brooks County, Texas (the "Lopez Case").
The plaintiffs, based on pleadings and deposition testimony, allege: i)
underpayment of royalties and claim damages, on a gross basis against all
working interest owners, of $56.5 million, including interest for the period
from 1985 to date; ii) that their production was improperly commingled with gas
produced from an adjoining lease, resulting in damages, including interest, of
$40.8 million, on a gross basis; (iii) failure to develop, claiming damages and
interest of $106.3 million (gross) for interest in the alleged failure to
develop; and iv) numerous other claims, including claims for drainage, breach of
the implied covenant to reasonably develop the lease, conversion, fraud,
emotional distress, lease termination and exemplary damages, that may result in
unspecified damages. Nuevo's working interest in these properties is 20%. The
Company, along with the other defendants in this case, denies these allegations
and is vigorously contesting 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 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 1999.
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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, 2000, Nuevo had
17,560,829 shares of common stock outstanding and had reserved 1,936,830 shares
of common stock for issuance upon conversion of the TECONS and 2,524,829 shares
for issuance pursuant to employee stock options. There were approximately 1,160
stockholders of record and approximately 4,936 additional beneficial owners as
of March 22, 2000. 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
10 to the Notes to Consolidated Financial Statements). The high and low recorded
prices of the Company's Common Stock during 1999 and 1998 are presented in the
following table:
Market Price
--------------------------
High Low
------- -------
Quarter Ended:
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
March 31, 1998...................... $ 40.56 $ 30.19
June 30, 1998....................... $ 37.81 $ 30.25
September 30, 1998.................. $ 32.75 $ 15.50
December 31, 1998................... $ 23.50 $ 9.94
Treasury Stock Repurchases
Since December 1997, the Board of Directors of the Company authorized
the open market repurchase of up to 3,616,600 shares of outstanding Common Stock
at times and at prices deemed appropriate by management. As of December 31,
1999, the Company had 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. As of March 22, 2000, the Company had repurchased 2,610,600
shares at an average purchase price of $16.75 per share, including commissions.
In March 1997, the Board of Directors authorized the open market
repurchase of up to 1,000,000 shares of outstanding Common Stock during 1997, at
times and prices deemed attractive by management. During April 1997, the Company
repurchased 500,000 shares of Common Stock in open market transactions, at an
average purchase price of $38.94 per share, plus 42,491 shares acquired from the
cancellation of warrants issued during 1996.
Put Options
In May 1997, the Company sold put options on its Common Stock to a
third party. The options gave the purchaser the right to sell to the Company
500,000 shares of its Common Stock at prices ranging from $40.26 to $41.04 per
share through December 31, 1997. The contract gave the Company the choice of net
cash, net shares, or physical settlement. Any repurchased shares would have been
treated as Treasury Stock. The Company generated $1.6 million in option premium
from these transactions, which is reflected in additional paid-in capital on the
balance sheet. As of December 31, 1997, 400,000 of these options had expired
with the Company's share prices
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NUEVO ENERGY COMPANY
above the strike price, and 100,000 of these options were settled on December
31, 1997, for a nominal amount of net cash.
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.
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 shares 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 restricted for a
two-year period, and 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 all executives at a level of
Vice-President and above.
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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,
---------------------------------------------------------------------------
1999 1998 1997(4) 1996(4) 1995(4)
------------ ------------ ------------ ------------ ------------
Oil and gas revenues.............. $ 239,306 $ 240,010 $ 331,973 $ 279,859 $ 102,455
Gas plant revenues................ 2,968 2,665 14,826 34,802 27,183
Pipeline and other revenues....... 4 2,700 5,772 6,774 7,222
Gain on sale of assets, net....... 85,294 5,768 1,372 6,008 --
Interest and other income......... 4,663 1,560 3,335 1,614 1,106
------------ ------------ ------------ ------------ ------------
Total revenues............... 332,235 252,703 357,278 329,057 137,966
Total costs and expenses before
extraordinary item (including
income taxes and minority
interest)(3)................. 300,793 346,975 367,954 294,779 133,834
Extraordinary loss on early
extinguishment of debt....... -- -- 3,024 -- --
------------ ------------ ------------ ------------ ------------
Net income (loss)(1)(5)........... $ 31,442 $ (94,272) $ (13,700) $ 34,278 $ 4,132
============ ============ ============ ============ ============
Net income (loss) attributable to
Common stockholders.......... $ 31,442 $ (94,272) $ (13,700) $ 33,339 $ 2,660
Earnings (loss) per Common Share -
Basic(2)..................... $ 1.62 $ (4.76) $ (0.69) $ 1.99 $ 0.24
Earnings (loss) per Common share -
Diluted(2)................... $ 1.61 $ (4.76) $ (0.69) $ 1.84 $ 0.23
Total Assets...................... $ 760,030 $ 817,685 $ 804,286 $ 817,643 $ 262,359
Long-term debt, net of current
maturities................... $ 340,750 $ 419,150 $ 305,940 $ 287,038 $ 113,032
Company-obligated Mandatorily
Redeemable Convertible
Preferred Securities of Nuevo
Financing I.................. $ 115,000 $ 115,000 $ 115,000 $ 115,000 $ --
(1) No Common Stock dividends have been declared since the formation of the
Company. See Note 10 to the Notes to Consolidated Financial Statements
concerning restrictions on the payment of Common Stock dividends.
(2) Retroactively restated to reflect the adoption of Statement of Financial
Accounting Standards (SFAS) No. 128, "Earnings per Share". (See Note 2 to the
Notes to Consolidated Financial Statements).
(3) 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.
(4) Retroactively restated to reflect the Company's January 1, 1998 conversion
from the full cost method to the successful efforts method of accounting for its
investments in oil and gas properties. (See Note 2 to the Notes to Consolidated
Financial Statements).
(5) The year ended December 31, 1996, includes activity of the California
Properties from the date of acquisition (April 9, 1996).
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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 unique 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; (iii) the outsourcing of non-strategic
functions; (iv) the alignment of employee compensation structures with
shareholder objectives; and (v) a commitment to an exemplary governance
structure which reinforces the overarching view of Nuevo as a conduit for
shareholders to achieve superior long term capital gains.
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
strategic divestitures and an opportunistic exploration program, which provides
exposure to high-potential prospects. The Company's primary strengths are its
track record of rapid reserve growth on a per share basis, achieved at extremely
low cost relative to industry averages; 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 demonstrated ability to
significantly reduce operating costs from levels experienced by prior operators;
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,
----------------------------------------
1999 1998 1997
---------- ---------- ----------
PRODUCTION:
Oil (MBBLS):
East........................ 413 838 878
West........................ 15,272 16,284 14,694
Foreign..................... 1,835 1,461 1,555
---------- ---------- ----------
Total....................... 17,520 18,583 17,127
========== ========== ==========
Natural gas (MMCF):
East........................ 3,224 18,816 20,831
West........................ 14,396 13,705 14,794
---------- ---------- ----------
Total....................... 17,620 32,521 35,625
========== ========== ==========
Natural gas liquids (MBBLS):
East........................ 62 67 76
West........................ 145 156 206
---------- ---------- ----------
Total....................... 207 223 282
========== ========== ==========
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NUEVO ENERGY COMPANY
Year Ended December 31,
----------------------------------
1999 1998 1997
-------- -------- --------
AVERAGE SALES PRICE:
Oil (per barrel):
East........................ $ 15.25 $ 12.63 $ 18.95
West........................ $ 10.44 $ 8.98 $ 14.73
Foreign..................... $ 16.69 $ 10.82 $ 14.66
Total - exclusive of
hedges.................... $ 13.82 $ 9.26 $ 14.94
Total - hedge effect........ $ (2.61) $ (0.01) $ (0.08)
-------- -------- --------
Total - net of hedge
effect.................... $ 11.21 $ 9.25 $ 14.86
======== ======== ========
Natural gas (per MCF):
East........................ $ 2.00 $ 1.80 $ 2.08
West........................ $ 2.33 $ 2.21 $ 2.06
Total - exclusive of
hedges.................... $ 2.27 $ 1.98 $ 2.19
Total - hedge effect........ $ -- $ 0.02 $ (0.13)
-------- -------- --------
Total - net of hedge
effect.................... $ 2.27 $ 2.00 $ 2.06
======== ======== ========
AVERAGE UNIT PRODUCTION COST PER
EQUIVALENT BARREL (6 MCF EQUAL 1
BARREL):
East........................ $ 2.45 $ 2.88 $ 2.71
West........................ $ 6.28 $ 5.94 $ 5.53
Foreign..................... $ 7.01 $ 8.14 $ 7.70
Total....................... $ 6.15 $ 5.56 $ 5.14
Effective January 1, 1998, the Company elected to convert from the full
cost method to the successful efforts method of accounting for its investments
in oil and gas properties. The Company believes that the successful efforts
method of accounting is preferable, as it will provide a fair presentation of
the Company's development activities in its core California business and the
drilling success of its selective exploration activities, and reflect an
impairment in the carrying value of its oil and gas properties only when there
has been a permanent decline in their fair value. Accordingly, all prior year
financial statements have been restated to conform to successful efforts
accounting. The effect, after tax, of the change in accounting method as of
December 31, 1997, was a reduction to retained earnings of $64.1 million,
primarily attributable to a decrease in net property and equipment and the
deferred tax liability of $99.2 million and $38.0 million, respectively. The
change in accounting method resulted in a decrease in net income of $32.5
million ($1.64 per share - basic and diluted) during 1997.
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, 1999 or 1997. Exploration costs,
including geological and geophysical expenses, exploratory dry holes and delay
rentals, are charged to expense as incurred.
Costs of productive wells, development dry holes and productive 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
27
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NUEVO ENERGY COMPANY
value) of dismantlement, abandonment and site remediation are computed by the
Company's independent reserve engineers and are included when calculating
depreciation and depletion using the unit-of-production method.
The Company reviews proved oil and gas properties on a depletable unit
basis whenever events or circumstances indicate that the carrying value of those
assets may not be recoverable. For each depletable unit determined to be
impaired, an impairment loss equal to the difference between the carrying value
and the fair value of the depletable unit is recognized. Fair value, on a
depletable unit basis, is estimated to be the value of the undiscounted expected
future net revenues computed by application of estimated future oil and gas
prices, production and expenses, as determined by management, to estimated
future production of oil and gas reserves over the economic life of the
reserves. If the carrying value exceeds the undiscounted future net revenues, an
impairment is recognized equal to the difference between the carrying value and
the discounted estimated future net revenues of that depletable unit. The
Company considers all proved reserves and commodity pricing based on market
information available at year-end in its estimate of future net revenues. 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. During 1997, the Company recorded a fair value
impairment totaling $30.0 million on its Brea Olinda field and certain other
insignificant oil and gas properties due to decreases in the fair value of the
depletable units attributable to a decline in domestic oil prices. No such
impairment was recognized during 1999.
Interest costs associated with non-producing leases and exploration and
development projects are capitalized only for the period that activities are in
progress to bring these projects to their intended use. The capitalization rates
are based on the Company's weighted average cost of funds used to finance
expenditures.
Any reference to oil and gas reserve information in the Notes to
Consolidated Financial Statements is unaudited.
Financing Activities
The Company had $341.5 million in outstanding indebtedness at December
31, 1999, which is scheduled to mature as follows (amounts in thousands):
2000................................ $ 750
2001................................ --
2002................................ --
2003................................ 81,000
2004................................ --
Thereafter.......................... 259,750
-----------
$ 341,500
===========
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 $157.46 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.
28
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NUEVO ENERGY COMPANY
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 of 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. 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.
In June 1998, the Company issued $100.0 million, 8 7/8% Notes. In
August 1999, most of the 8 7/8% Notes, except for $150,000, were exchanged for
9 1/2% Notes. The remaining $150,000 were retired in December 1999. No
significant costs were incurred in connection with this early retirement of
debt.
Nuevo's Amended and Restated Credit Agreement, (the "Agreement"), dated
June 30, 1999, provides for secured revolving credit availability of up to
$400.0 million (subject to a semi-annual borrowing base determination) from a
bank group led by Bank of America, N.A. and Morgan Guaranty Trust Company of New
York, until its expiration on April 1, 2003.
The borrowing base determination establishes the maximum borrowings
that may be outstanding under the credit facility, and is determined by a
two-thirds vote of the banks (three-fourths 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.
The borrowing base was reduced from $380.0 million to $200.0 million in
January 1999, reflecting the sale on that date of the Company's East Texas
natural gas reserves, and also reflecting a significant decline in projected oil
prices since the previous determination. The borrowing base was subsequently
increased in October 1999 to $300.0 million, as a result of the significant
increase in commodity prices and the inclusion of recently acquired oil and gas
properties in California (see Note 3 to the Notes to Consolidated Financial
Statements).
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. At December 31, 1999, the
Company's interest rate under the credit facility was LIBOR plus .625%, or
7.13%. Outstandings under this facility at December 31, 1999 were $81.0 million.
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 Agreement at December
31, 1999, and does not anticipate any issues of non-compliance arising in the
foreseeable future.
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NUEVO ENERGY COMPANY
On July 24, 1992, the Company closed the sale of $75.0 million
aggregate principal amount of 12 1/2% Senior Subordinated Notes (the "Notes")
due June 15, 2002. In June 1997, the Company redeemed the Notes at a total cost
of $78.0 million, representing $75.0 million face value of the debt plus a 4%
premium of $3.0 million. In addition to the premium, the Company wrote off
approximately $2.0 million of unamortized discount and deferred financing costs.
The redemption resulted in an extraordinary loss on early extinguishment of debt
of $3.0 million, net of the related tax benefit of $2.0 million. The Company
used proceeds from the Credit Facility to fund the redemption.
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. The interest rate associated with
such credit facility is LIBOR plus 20 basis points and a guaranty fee of 2.75%
of the outstanding loan balance, all of which is payable quarterly. At December
31, 1999, the interest rate was 5.8%, plus the 2.75% guaranty fee. The loan
agreement requires a sixteen-quarter repayment period and will be fully 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.
Other Matters
Year 2000
In 1998, the Company and its outside service provider, Torch Energy
Advisers Incorporated ("Torch"), jointly developed a plan to address Nuevo's
risks associated with the Year 2000 issues ("Y2K.") The plan grouped the risks
associated with Y2K into three general areas: i) financial and administrative
systems, ii) embedded systems in field process control units, and iii) third
party exposures. The Company did not encounter any critical financial and
administrative system or embedded system failures during the date roll over to
the Year 2000, and has not experienced any disruptions of business activities as
a result of Year 2000 failures encountered by third parties (customers,
suppliers and service providers.) To date, the Company has not incurred, and
does not expect to incur, any material expenditures in connection with
identifying, assessing or remediating Y2K compliance issues.
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. 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 $44.9 million in 1999, increased by $0.6 million in 1998, and
reduced by $6.0 million in 1997.
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.
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NUEVO ENERGY COMPANY
Oil and gas revenues for 1998 were 28% lower than 1997 oil and gas
revenues primarily due to a 38% decrease in average realized oil prices from
1997 to 1998. Also contributing to this decline in oil and gas revenues were
decreases in natural gas production and realized gas prices. The Company's gas
production decreased 9% from 1997 to 1998, and average realized gas prices
decreased 3% from 1997 to 1998. The decline in oil and gas revenues was
partially offset by a 9% increase in the Company's oil production from 1997 to
1998.
Gas plant revenues were 11% higher in 1999 as compared to 1998,
primarily due to a 27% increase in natural gas liquids price realizations. Gas
plant revenues in 1998 were 82% lower than 1997 revenues due to the sale of the
Company's interest in the Benedum Plant System in May 1997. The Company
recognized a $2.3 million pre-tax gain on the sale in 1997.
Pipeline and other revenues decreased 100% from 1998 to 1999 and 53%
from 1997 to 1998. These decreases are due to the sale of the Company's
interests in the Richfield Gas Storage facility in February 1998 and Bright Star
Gathering, Inc. in July 1998.
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. The net gain
on sale of assets for 1997 was $1.4 million, which is comprised of: (i) a $1.4
million gain on the sale of the Company's interest in Second Bayou, Weeks
Island, Louisiana; (ii) a $2.3 million gain on the Company's interest in the
Benedum Plant System; (iii) a $1.6 million loss on the sale of the Company's
interest in the South Timbalier field; and (iv) a $0.7 million loss on the sale
of other non-core properties.
Interest and other income for the year ended December 31, 1999 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.
Expenses
Lease operating expenses ("LOE") for 1999 totaled $127.2 million, as
compared to $134.7 million and $120.0 million for 1998 and 1997, respectively.
The 6% decrease in LOE from 1998 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 barrel of oil equivalent ("BOE") increased 11% from
1998 to 1999. This increase relates to two main factors: (i) the East Texas
assets that were sold in January 1999 had relatively low LOE/BOE rates, and (ii)
the cost of natural gas used in the Company's thermal operations in California
increased. The annual LOE increase of 12% in 1998, as compared to 1997, is
generally reflective of higher production and costs associated with the
California Properties, which constituted 77% and 73% of total production in 1998
and 1997, respectively. In 1998, the Company experienced an increase in
workovers of $11.2 million as compared to the same period in 1997, as well as
poor weather conditions in the first quarter of 1998 in California that caused
landslides and power outages, which resulted in $2.3 million of incremental,
unusual costs.
Gas plant operating expenses in 1999 increased 6% as compared to 1998
as a result of higher ad valorem taxes. Gas plant operating expenses in 1998
decreased 76% from 1997, due to the sale of the Company's investment in the
Benedum Plant System in May 1997.
Pipeline and other operating expenses for 1999 totaled $0.3 million, as
compared to $2.0 million and $5.2 million in 1998 and 1997, respectively. The
86% decrease in 1999 and the 61% decrease in 1998 are primarily due
31
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NUEVO ENERGY COMPANY
to the sale of the Company's interests in the Richfield Gas Storage facility in
February 1998 and Bright Star Gathering, Inc. in July 1998.
Exploration costs, including geological and geophysical (G&G) costs,
dry hole costs and delay rentals, were $14.0 million, $16.6 million and $11.1
million for the years ended December 31, 1999, 1998 and 1997, respectively.
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.
Exploration costs for the year ended 1997 included: $9.3 million of dry hole
costs, $0.7 million of G&G costs, $1.0 million of delay rentals and $0.1 million
of other exploration costs.
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. Depreciation, depletion and
amortization in 1998 decreased 17% from 1997. The decrease in 1998 is primarily
due to the year-end 1997 impairment of $30.0 million related to the excess of
capitalized costs over future net revenues, as well as the reclassification of
the East Texas properties to assets held for sale as of July 1, 1998, at which
point the properties were no longer depleted.
The Company recorded provisions for impairment of oil and gas
properties in 1998 and 1997 in the amounts of $68.9 million ($60.8 million of
fair value impairments plus $8.1 million of unproved leasehold cost impairments)
and $30.0 million, respectively. 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 1999.
In December 1997, the Company recorded a $23.9 million 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. (See Note 4 to the
Notes to Consolidated Financial Statements.) 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") were up $4.5 million in
1999 versus 1998. The 33% 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. G&A decreased 22% from 1997 to 1998 due to no
employee bonuses in 1998 and a $1.7 million severance expense incurred in the
third quarter of 1997 associated with the resignation of the Company's President
and Chief Executive Officer. These decreases were offset in part by
non-recurring costs incurred in 1998 associated with outside engineering costs
and third-party consulting studies associated with the re-negotiation of the
Company's outsourcing agreements.
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 Company's bank debt as a
result of lower average borrowings outstanding during 1999. Interest expense
increased 19% from 1997 to 1998, primarily as a result of additional borrowings
under the Company's Credit Facility and the issuance in June 1998 of $100.0
million of 8 7/8% Notes.
Other expense in 1999 includes $3.1 million in third-party charges
incurred in connection with the July 1999 exchange offer (see Note 10 to the
Notes to Consolidated Financial Statements), $1.6 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
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NUEVO ENERGY COMPANY
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. 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. The Company is
attempting to recoup the loss, however, there is no certainty that any of the
funds will be recovered.
Dividends on the TECONS were $6.6 million in 1999, 1998 and 1997. The
TECONS pay dividends at a rate of 5.75% and were issued in December 1996. (See
Note 9 to the Notes to Consolidated Financial Statements.)
An income tax benefit of $5.4 million was recognized in 1999, compared
to a benefit of $32.6 million in 1998 and $6.7 million in 1997. The Company's
effective income tax rate was (20.5)%, (25.7)% and (38.8)% in 1999, 1998 and
1997, 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.
Extraordinary Item
In June 1997, the Company recorded an extraordinary loss on the early
extinguishment of its 12 1/2% Notes in the amount of $3.0 million, net of the
related tax benefit of $2.0 million. No extraordinary items were recorded in
1999 or 1998.
Net Income (Loss)
Net income of $31.4 million was reported in 1999, as compared to a net
loss of $94.3 million in 1998 and $13.7 million in 1997.
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 strategic divestitures and an
opportunistic exploration program, which provides exposure to prospects that
have the potential to add substantially to the growth of the Company. 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 $24.0 million, $35.8 million, and
$165.5 million in 1999, 1998 and 1997, respectively. The Company invested $125.9
million, $157.4 million and $195.1 million in oil and gas properties in 1999,
1998 and 1997, respectively. Additionally, the Company spent $10.2 million, $2.8
million and $1.7 million on gas plant and other facilities in 1999, 1998 and
1997, 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 2000.
The Company had an unused commitment under the Credit Facility of $219.0 million
at December 31, 1999. The Borrowing Base was redetermined in connection with the
Company's sale of its East Texas natural gas assets. As a result of this sale
and the low oil price environment in early 1999, the Borrowing Base was reduced
to $200.0 million effective January 6, 1999. In October 1999, the Borrowing Base
was increased to $300.0 million, as a result of the significant increase in
commodity prices and the inclusion of recently acquired oil and gas assets in
California. At December 31, 1999, maturities of long-term debt for the next five
years totaled $81.8 million.
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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 85% of the Company's production for
1999 was 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 1997, even though
production levels increased during 1998. During 1999, crude oil prices increased
significantly and, in March 2000, reached a ten-year high.
In 1999, the Company's Board of Directors adopted a Commodity Hedging
Policy which is 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, during periods with abnormally low commodity prices: (i) 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 hedging 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 so much of its production as is necessary to meet its
policy goals for that period. Variations from this approach require Board
approval. The Company prohibits hedging activity that is speculative or
otherwise increases the Company's risk. 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 2000, the Company has entered into swap contracts on 16,500 barrels
of oil per day ("BOPD"), at an average West Texas Intermediate ("WTI") price of
$17.94 per barrel. The Company has also entered into cost-less collars on an
additional 16,500 BOPD, with a floor of $16.00 per barrel and ceiling of $21.21
per barrel. This production is hedged based on a fixed NYMEX price for each type
of crude oil that the Company produces in California. As a result of the TOSCO
contract, (see Note 13 to the Notes to Consolidated Financial Statements), which
fixes the price of the Company's California production at approximately 72% of
the NYMEX price effective January 1, 2000, these hedge transactions have the
effect on a price basis of hedging substantially all of the Company's current
production for the year 2000. Also for the year 2000, the Company has entered
into basis swaps on 3,000 BOPD of its production in the Congo, hedging the basis
differential between No. 6 fuel oil and WTI at an average differential of $1.88
per barrel. At December 31, 1999, the market value of the hedge positions was a
loss of approximately $35.7 million. A 10% increase in the underlying commodity
prices would increase this loss by $18.8 million.
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, and for the third quarter on
20,000 BOPD at an average WTI price of $21.22. At December 31, 1999, the market
value of these swaps was a gain of $0.5 million.
On February 26, 1999, the Company entered into a swap arrangement with
a major financial institution that effectively converts the interest rate on
$16.4 million notional amount of the 9 1/2% Notes to a variable LIBOR-based
rate through February 25, 2000. Based on LIBOR rates in effect at December 1,
1999, this amounted to a net reduction in the carrying cost of the 9 1/2% Notes
from 9.5% to 7.09%, or 241 basis points. In addition, the swap arrangement also
effectively hedges the price at which these Notes can be repurchased by the
Company. At December 31, 1999, the Company recorded an unrealized gain of
$131,000 related to the fair value of the notes.
The Company set a base level capital spending budget for 2000 of
approximately $110.0 million, plus up to an additional $30.0 million depending
on the level of crude oil prices. In the Company's 2000 base level capital
34
36
NUEVO ENERGY COMPANY
budget, approximately $77.0 million is allocated to exploitation and development
projects and approximately $33.0 million is directed to exploration and business
development. Exploitation spending is anticipated to consist of $74.0 million in
California ($68.0 million of which is for proved undeveloped reserves), $1.0
million in the Gulf Coast region, and $2.0 million internationally. If the crude
oil forward strip remains above $20.00 per BBL, the California exploitation
budget will increase to approximately $104.0 million. Of the total California
exploitation budget, the Company expects to spend approximately $52.0 million to
drill and complete 120 wells and on related facilities at the Company's Cymric
field. Exploration spending is planned to be allocated $11.0 million in
California, and $8.0 million internationally. The remaining $14.0 million is
allocated to business development and other capital projects. The Company
believes that its cash flows from operations and available borrowings under its
Credit Facility will be sufficient to finance this capital budget. The Company
has not prepared a capital budget for periods after 2000.
The Company plans to sell certain of its surface real estate assets in
Orange County, California, during 2000 to help fund the 2000 capital program. In
addition, the Company believes its working capital, cash provided by operating
activities, property divestitures, project financing resources and the Credit
Facility are sufficient to meet these capital commitments.
Estimates of future net cash flows from proved reserves of oil, gas,
condensate and natural gas liquids were made in accordance with SFAS No. 69,
"Disclosures about Oil and Gas Producing Activities." (See Note 17 to the Notes
to Consolidated Financial Statements). The estimates are based on realized
prices at year-end 1999 of $18.97 per barrel of oil (including hedge effect) and
$2.31 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.
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.
Recent 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, 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;
however, early adoption is permitted. The Company has not yet determined the
impact of this statement on its financial condition or results of operations or
whether it will adopt the statement early.
Contingencies and Other Matters
The Company has been named as a defendant in the Lopez case. The
plaintiffs allege, among other things, underpayment of royalties and that their
production was improperly commingled with gas produced from an adjoining lease.
See "Legal Proceedings" and Note 14 to the Notes to Consolidated Financial
Statements. The Company, along with the other defendants in this case, denies
these allegations and is vigorously contesting 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.
35
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NUEVO ENERGY COMPANY
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 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. The Company is attempting to recoup the loss, however, there
is no certainty that any of the funds will be recovered.
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. 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 $0.5 million, and $3.2 million during
1999, 1998, and 1997, respectively. As of December 31, 1999, the Company had
received insurance reimbursements of $3.7 million, with a remaining insurance
receivable of $1.4 million. For amounts not covered by insurance, including the
$120,000 deductible, the Company recorded lease operating expenses of $0.4
million, $0.5 million, and $0.1 million during 1999, 1998, and 1997,
respectively. Repairs were completed by the end of 1997, and production
recommenced in December 1997. Additionally, the Company has exposure to certain
costs 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, 1999. Although, the Company may have additional exposure, 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.
The Company and its partners underwent a tax examination related to
their ownership interests in the Yombo field offshore Congo for the years 1994
though 1997. In June 1999, the Company and its partners settled this tax
assessment for a total of $1.0 million, of which the Company's share was
$400,000.
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
36
38
NUEVO ENERGY COMPANY
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 $48.5 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 $64.1 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 operation in the Congo in the future.
In 1996, the previous Congo government requested that the convention
governing the Marine I 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 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 of the properties located in
California from Unocal in 1996, 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 taxes, multiplied by the actual number of barrels of oil sold during
the respective year. The minimum price of $17.75 per Bbl under the agreement
(determined based on near month of 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 will be netted down to the
field level using a fixed differential equal to 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 future, possible contingent payment when prices
are $.50 per Bbl or more below the minimum price. As of December 31, 1999, the
Company had accumulated $30.8 million in price credits since the inception of
the agreement. These accumulated credits will be used to reduce future amounts
owed under the contingent payment.
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 is $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 is that Nuevo only owns upside above $15.19 per Bbl on
approximately 44% of its Congo production. In 1997, the Company paid the seller
$845,000 pursuant to this price sharing agreement. This payment 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 interest from Torch in 1996.
The realized oil price on these properties is capped at $9.00 per Bbl, with the
excess field price over the realized price, if any, shared among the Company and
the original owners from whom Torch acquired its interest. For 2000, the effect
of this agreement is that Nuevo only owns upside above $9.00 per Bbl on
approximately 28% of the Point Pedernales production.
37
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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.
During 1999, the Company formalized its 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 2000, the Company has entered
into swap contracts on 16,500 barrels of oil per day ("BOPD"), at an average
West Texas Intermediate ("WTI") price of $17.94 per barrel. The Company has also
entered into cost-less collars on an additional 16,500 BOPD, with a floor of
$16.00 per barrel and ceiling of $21.21 per barrel. This production is hedged
based on a fixed NYMEX price for each type of crude oil that the Company
produces in California. As a result of the TOSCO contract, (see Note 13 to the
Notes to Consolidated Financial Statements), which fixes the price of the
Company's California production at approximately 72% of the NYMEX price
effective January 1, 2000, these hedge transactions have the effect on a price
basis of hedging substantially all of the Company's current production for the
year 2000. Also for the year 2000, the Company has entered into basis swaps on
3,000 BOPD of its production in the Congo, hedging the basis differential
between No. 6 fuel oil and WTI at an average differential of $1.88 per barrel.
At December 31, 1999, the market value of the hedge positions was a loss of
approximately $35.7 million. A 10% increase in the underlying commodity prices
would increase this loss by $18.8 million.
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, and for the third quarter on
20,000 BOPD at an average WTI price of $21.22. At December 31, 1999, the market
value of these swaps was a gain of $0.5 million. The Company has not hedged in
excess of its anticipated 2001 production. 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.
Interest Rate Risk - The Company may enter into financial instruments
such as interest rate swaps to manage the impact of changes in interest rates.
On February 26, 1999, the Company entered into a swap agreement, with a notional
amount of $16.4 million, which hedges the price at which the Company may
repurchase a portion of its fixed rate debt and effectively converts such debt
to a floating rate exposure for a period of 364 days. This agreement is not held
for trading purposes. As the swap provider is a major financial institution, the
Company does not anticipate non-performance by the provider. In addition, the
swap arrangement also effectively hedges the price at which these notes can be
repurchased by the Company. At December 31, 1999, the Company recorded an
unrealized gain adjustment of $131,000 related to the fair value of the notes.
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, 1999:
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NUEVO ENERGY COMPANY
Fair
Value
2000 2001 2002 2003 Thereafter Total Liability
---- ---- ---- ---- ---------- ----- ---------
Long-term debt, including
current maturities:
Variable rate $750 -- -- $81,000 -- $81,750 $81,750
Average interest rate 5.8% -- -- 7.13% -- 7.12%
Fixed rate -- -- -- -- $259,750 $259,750 $256,972
Average interest rate -- -- -- -- 9.5% 9.5%
39
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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, 1999
and 1998.......................................................... 42
Consolidated Statements of Operations for the Years Ended
December 31, 1999, 1998 and 1997 (Restated)....................... 43
Consolidated Statements of Changes in Stockholders'
Equity for the Years Ended December 31, 1999,
1998 and 1997 (Restated).......................................... 44
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997 (Restated)....................... 45
Notes to Consolidated Financial Statements.............................. 46
40
42
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, 1999 and 1998, 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,
1999. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to
above present fairly, in all material respects, the financial position of Nuevo
Energy Company and subsidiaries as of December 31, 1999 and 1998, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 1999, in conformity with generally accepted
accounting principles.
KPMG LLP
Houston, Texas
February 10, 2000
41
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NUEVO ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
(AMOUNTS IN THOUSANDS, EXCEPT SHARE DATA)
December 31,
----------------------------
1999 1998
----------- -----------
ASSETS
------
CURRENT ASSETS:
Cash and cash equivalents ................................................. $ 10,288 $ 7,403
Accounts receivable ....................................................... 45,004 25,096
Product inventory ......................................................... 4,610 5,998
Assets held for sale ...................................................... -- 120,055
Prepaid expenses and other ................................................ 6,389 2,700
----------- -----------
Total current assets ................................................. 66,291 161,252
----------- -----------
PROPERTY AND EQUIPMENT, at cost:
Land ...................................................................... 51,017 51,038
Oil and gas properties (successful efforts method) ........................ 1,002,779 959,348
Gas plant facilities ...................................................... 12,140 17,112
Other facilities .......................................................... 11,874 6,696
----------- -----------
1,077,810 1,034,194
Accumulated depreciation, depletion and amortization ...................... (429,349) (417,622)
----------- -----------
648,461 616,572
----------- -----------
DEFERRED TAX ASSETS, net ........................................................ 24,005 27,534
OTHER ASSETS .................................................................... 21,273 12,327
----------- -----------
$ 760,030 $ 817,685
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES:
Accounts payable .......................................................... $ 20,492 $ 24,393
Accrued interest .......................................................... 2,353 4,161
Accrued drilling costs .................................................... 13,242 8,380
Accrued lease operating costs ............................................. 13,956 4,694
Other accrued liabilities ................................................. 10,557 4,843
Current maturities of long-term debt ...................................... 750 3,152
----------- -----------
Total current liabilities ............................................ 61,350 49,623
----------- -----------
LONG-TERM DEBT, NET OF CURRENT MATURITIES ....................................... 340,750 419,150
OTHER LONG-TERM LIABILITIES ..................................................... 9,292 2,034
COMPANY-OBLIGATED MANDATORILY REDEEMABLE
CONVERTIBLE PREFERRED SECURITIES OF NUEVO FINANCING I ......................... 115,000 115,000
CONTINGENCIES (Note 14)
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, 1999 and 1998 ............................................. -- --
Common stock, $0.01 par value, 50,000,000 shares authorized, 20,437,371 and
20,308,462 shares issued and 17,931,393 and 19,786,827 shares outstanding
at December 31, 1999 and 1998, respectively ............................. 204 203
Additional paid-in capital ................................................ 357,855 355,600
Treasury stock, at cost, 2,430,074 and 473,876 shares, at December 31, 1999
and 1998, respectively .................................................. (49,605) (19,335)
Stock held by benefit trust, 75,904 and 47,759 shares, at December 31, 1999
and 1998, respectively .................................................. (3,184) (1,732)
Deferred stock compensation ............................................... (216) --
Accumulated deficit ....................................................... (71,416) (102,858)
----------- -----------
Total stockholders' equity ........................................... 233,638 231,878
----------- -----------
$ 760,030 $ 817,685
=========== ===========
See Notes to Consolidated Financial Statements.
42
44
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
Year Ended December 31,
--------------------------------------
1999 1998 1997*
--------- --------- ---------
REVENUES:
Oil and gas revenues ........................................................ $ 239,306 $ 240,010 $ 331,973
Gas plant revenues .......................................................... 2,968 2,665 14,826
Pipeline and other revenues ................................................. 4 2,700 5,772
Gain on sale of assets, net ................................................. 85,294 5,768 1,372
Interest and other income ................................................... 4,663 1,560 3,335
--------- --------- ---------
332,235 252,703 357,278
--------- --------- ---------
COSTS AND EXPENSES:
Lease operating expenses .................................................... 127,164 134,704 120,042
Gas plant operating expenses ................................................ 3,385 3,202 13,356
Pipeline and other operating costs .......................................... 286 2,028 5,243
Exploration costs ........................................................... 14,017 16,562 11,082
(Revision of) provision for impairment on assets held for sale .............. -- (3,740) 23,942
Provision for impairment of oil and gas properties .......................... -- 68,904 30,000
General and administrative expenses ......................................... 18,137 13,636 17,396
Outsourcing fees ............................................................ 14,129 14,458 14,410
Depreciation, depletion and amortization .................................... 80,652 85,036 102,158
Interest expense ............................................................ 33,110 32,471 27,357
Dividends on Guaranteed Preferred Beneficial Interests in Company's
Convertible Debentures (TECONS) ........................................... 6,613 6,613 6,613
Other expense ............................................................... 8,659 5,726 3,019
--------- --------- ---------
306,152 379,600 374,618
--------- --------- ---------
Income (loss) before income taxes, minority interest and extraordinary
item ........................................................................... 26,083 (126,897) (17,340)
Income tax benefit ................................................................ 5,359 32,625 6,656
Minority interest in loss of subsidiary ........................................... -- -- 8
--------- --------- ---------
Income (loss) before extraordinary item ........................................... 31,442 (94,272) (10,676)
Extraordinary loss on early extinguishment of debt, net of income tax benefit of
$2,037 ......................................................................... -- -- (3,024)
--------- --------- ---------
Net income (loss) ................................................................. $ 31,442 $ (94,272) $ (13,700)
========= ========= =========
Earnings (loss) per Common share -- Basic:
Income (loss) before extraordinary item (net of dividends on
preferred stock) ......................................................... $ 1.62 $ (4.76) $ (0.54)
Extraordinary loss on early extinguishment of debt, net of income
tax benefit .............................................................. -- -- (0.15)
--------- --------- ---------
Net income (loss) ........................................................... $ 1.62 $ (4.76) $ (0.69)
========= ========= =========
Weighted average Common shares outstanding ........................................ 19,418 19,795 19,796
========= ========= =========
Earnings (loss) per Common share -- Diluted:
Income (loss) before extraordinary item ..................................... $ 1.61 $ (4.76) $ (0.54)
Extraordinary loss on early extinguishment of debt, net of income
tax benefit .............................................................. -- -- (0.15)
--------- --------- ---------
Net income (loss) ........................................................... $ 1.61 $ (4.76) $ (0.69)
========= ========= =========
Weighted average Common and dilutive potential Common shares outstanding .......... 19,571 19,795 19,796
========= ========= =========
----------
* Restated
See Notes to Consolidated Financial Statements.
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NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
(AMOUNTS IN THOUSANDS)
Common Stock Additional Stock held Deferred Retained Total
--------------------- Paid-In Treasury by Benefit Stock Earnings Stockholders'
Shares Amount Capital Stock Trust Compensation (Deficit) Equity
--------- --------- --------- --------- --------- --------- --------- ---------
January 1, 1997 ............... 19,852 $ 199 $ 340,126 $ -- $ -- $ -- $ 5,114 $ 345,439
========= ========= ========= ========= ========= ========= ========= =========
Exercise of stock options and
related tax benefit ........ 386 3 11,332 -- -- -- -- 11,335
Stock put options ............. -- -- 1,630 -- -- -- -- 1,630
Employee stock awards ......... -- -- 1,208 -- -- -- -- 1,208
Purchase of Treasury Shares ... (542) -- -- (21,173) -- -- -- (21,173)
Stock acquired by benefit
trust ...................... -- -- -- 1,244 (1,244) -- -- --
Net loss* ..................... -- -- -- -- -- -- (13,700) (13,700)
--------- --------- --------- --------- --------- --------- --------- ---------
December 31, 1997* ............ 19,696 202 354,296 (19,929) (1,244) -- (8,586) 324,739
========= ========= ========= ========= ========= ========= ========= =========
Exercise of stock options and
related tax benefit ........ 70 1 1,304 -- -- -- -- 1,305
Stock acquired by benefit
trust -- -- -- 488 (1,341) -- -- (853)
Withdrawal from benefit
trust ...................... 18 -- -- -- 853 -- -- 853
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 tax benefit ........ 129 1 1,810 -- -- -- -- 1,811
Stock acquired by benefit
trust ...................... -- -- -- 1,850 (1,850) -- -- --
Issuance of warrants and
other ...................... -- -- 120 -- -- -- -- 120
Withdrawal from benefit
trust ...................... 14 -- -- -- 398 -- -- 398
Purchase of Treasury Shares ... (1,999) -- -- (32,120) -- -- -- (32,120)
Deferred stock compensation ... -- -- 325 -- -- (216) -- 109
Net income .................... -- -- -- -- -- -- 31,442 31,442
--------- --------- --------- --------- --------- --------- --------- ---------
December 31, 1999 ............. 17,931 $ 204 $ 357,855 $ (49,605) $ (3,184) $ (216) $ (71,416) $ 233,638
========= ========= ========= ========= ========= ========= ========= =========
----------
* Restated
See Notes to Consolidated Financial Statements.
44
46
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(AMOUNTS IN THOUSANDS)
Year Ended December 31,
------------------------------------------
1999 1998 1997*
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) .......................................................... $ 31,442 $ (94,272) $ (13,700)
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
Depreciation, depletion and amortization ............................. 80,652 85,036 102,158
Dry hole costs ....................................................... 8,051 12,962 9,311
Amortization of debt financing costs ................................. 1,696 1,643 1,513
Amortization of deferred revenue ..................................... -- (1,625) (3,203)
(Revision of) provision for impairment on assets held for sale ....... -- (3,740) 23,942
Provision for impairment of oil and gas properties ................... -- 68,904 30,000
Gain on sale of assets, net .......................................... (85,294) (5,768) (1,372)
Loss on early extinguishment of debt ................................. -- -- 5,061
Stock awards ......................................................... 109 -- 1,208
Deferred taxes ....................................................... (6,559) (32,520) (9,249)
Appreciation (depreciation) of deferred compensation liability ....... 801 (1,138) --
Debt modification costs .............................................. 3,064 -- --
Other ................................................................ 120 -- (8)
--------- --------- ---------
34,082 29,482 145,661
Changes in assets and liabilities, net of acquisition effects:
Accounts receivable .................................................. (20,461) 13,051 578
Gas imbalances ....................................................... (92) 333 20
Accounts payable ..................................................... (4,527) 6,634 1,663
Accrued liabilities .................................................. 17,901 (5,813) 13,719
Other ................................................................ (2,879) (7,854) 3,821
--------- --------- ---------
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES .................. 24,024 35,833 165,462
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas properties ........................................ (125,919) (157,352) (195,108)
Proceeds from sale of gas plant ............................................ -- -- 24,992
Proceeds from sales of properties .......................................... 234,312 11,830 2,385
Additions to gas plant and other facilities ................................ (10,247) (2,813) (1,747)
--------- --------- ---------
NET CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES ........ 98,146 (148,335) (169,478)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings ................................................... 142,590 240,900 234,000
Debt issuance and modification costs ....................................... (8,053) (3,360) --
Payments of long-term debt ................................................. (223,392) (128,254) (217,503)
Proceeds from exercise of stock options .................................... 1,690 1,305 6,074
Premium on early extinguishment of debt .................................... -- -- (3,440)
Proceeds from sale of stock put options .................................... -- -- 1,630
Proceeds from sale of treasury stock ....................................... -- 106 --
Purchase of treasury shares ................................................ (32,120) -- (21,173)
--------- --------- ---------
NET CASH FLOWS (USED IN) PROVIDED BY FINANCING ACTIVITIES ............ (119,285) 110,697 (412)
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents .......................... 2,885 (1,805) (4,428)
Cash and cash equivalents at beginning of year ................................ 7,403 9,208 13,636
--------- --------- ---------
Cash and cash equivalents at end of year ...................................... $ 10,288 $ 7,403 $ 9,208
========= ========= =========
----------
* Restated
See Notes to Consolidated Financial Statements.
45
47
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. NuStar Joint Venture and
its 66.7% investment in the Benedum Plant System, of which the Company owned a
95% interest, was pro rata consolidated through May 2, 1997, at which time the
Company's interest was sold. Minority interests have been deducted from results
of operations and stockholders' equity in the appropriate periods. All
significant intercompany accounts and transactions have been eliminated in
consolidation.
Change in Accounting Method
Effective January 1, 1998, the Company elected to convert from the full
cost method to the successful efforts method of accounting for its investments
in oil and gas properties. The Company believes that the successful efforts
method of accounting is preferable, as it will provide a fair presentation of
the Company's development activities in its core California business and the
drilling success of its selective exploration activities, and reflect an
impairment in the carrying value of its oil and gas properties only when there
has been a permanent decline in their fair value. Accordingly, all prior year
financial statements have been restated to conform with successful efforts
accounting. The effect, after tax, of the change in accounting method as of
December 31, 1997, was a reduction to retained earnings of $64.1 million,
primarily attributable to a decrease in net property and equipment and the
deferred tax liability of $99.2 million and $38.0 million, respectively. The
change in accounting method resulted in a decrease in net income of $32.5
million ($1.64 per share - basic and diluted) during 1997.
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.
46
48
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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, 1999 or 1997. Exploration costs,
including geological and geophysical expenses, exploratory dry holes and delay
rentals, are charged to expense as incurred.
Costs of productive wells, development dry holes and productive 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 approximately $99.0 million (net of salvage
value) for future dismantlement, abandonment and site remediation are computed
by the Company's independent reserve engineers and are included when calculating
depreciation and depletion using the unit-of-production method. At December 31,
1999, the Company had recorded $50.2 million as a component of accumulated
depreciation, depletion and amortization.
The Company reviews proved oil and gas properties on a depletable unit
basis whenever events or circumstances indicate that the carrying value of those
assets may not be recoverable. For each depletable unit determined to be
impaired, an impairment loss equal to the difference between the carrying value
and the fair value of the depletable unit is recognized. Fair value, on a
depletable unit basis, is estimated to be the value of the undiscounted expected
future net revenues computed by application of estimated future oil and gas
prices, production and expenses, as determined by management, to estimated
future production of oil and gas reserves over the economic life of the
reserves. If the carrying value exceeds the undiscounted future net revenues, an
impairment is recognized equal to the difference between the carrying value and
the discounted estimated future net revenues of that depletable unit. The
Company considers all proved reserves and commodity pricing based on market
information in its estimate of future net revenues. 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. During 1997, the Company recorded a fair value impairment totaling $30.0
million on its Brea Olinda field and certain other insignificant oil and gas
properties due to decreases in the fair value of the depletable units
attributable to a decline in domestic oil prices. No such impairment was
recognized during 1999.
Interest costs associated with non-producing leases and exploration and
development projects are capitalized only for the period that activities are in
progress to bring these projects to their intended use. The capitalization rates
are based on the Company's weighted average cost of funds used to finance
expenditures.
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
47
49
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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.
Recent 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, 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, however, early adoption is
permitted. The Company has not yet determined the impact of this statement on
its financial condition or results of operations or whether it will adopt the
statement early.
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 certain investments in debt and
equity securities. 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 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, 1999 and 1998.
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, 1999 or 1998. 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 $44.9 million in 1999, increased by $0.6 million in 1998 and reduced by $6.0
million in 1997.
48
50
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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, 1999, the
Company's potentially dilutive securities included dilutive stock options. For
the years ended December 31, 1998 and 1997, the Company did not have any
potentially dilutive securities, as net losses were incurred during these
periods. Potential dilution may also occur in future periods due to the
Company-Obligated Mandatorily Redeemable Convertible Preferred Securities of
Nuevo Financing I ("TECONS").
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 1999, 1998 and 1997. (See Note 8 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 1999, 1998 and 1997 was $33.5 million, $31.6 million and $28.2 million,
respectively. Net amounts paid (refunded) in cash for income taxes for 1999,
1998 and 1997 were $2,250,000, $1,332,000 and ($45,000), respectively.
Product Inventory
Inventory relating to quantities of processed fuel oil and natural gas
liquids in storage as of the balance sheet date is carried at current market
pricing. Fuel oil in inventory is stated at year end market prices less
transportation costs; the Company recognizes changes in the market value of
inventory from one period to the next as oil revenues.
Use of Estimates
In order to prepare these financial statements in conformity with
generally accepted accounting principles, 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.
49
51
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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 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 million barrels of oil equivalent ("BOE") 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 I 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
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. 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 billion cubic feet of natural gas equivalent 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.
In December 1997, the Company announced its intention to dispose of the
remainder of its non-core gas gathering, pipeline and storage 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
50
52
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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. The Company retained its remaining two
California gas plants, as these plants are strategic assets for the Company's
oil and gas activities in California.
In May 1997, Nuevo Liquids, a wholly-owned subsidiary of the Company,
sold its 95% interest in the NuStar Joint Venture, which held the Company's
investment in the Benedum Plant System, for proceeds of $25.0 million. The
effective date of the sale was January 1, 1997. Proceeds from the sale were used
to reduce outstanding debt under the Company's revolving credit facility, as
well as project debt related to the Benedum Gas Plant in the amount of $5.9
million. The Company recorded a pre-tax gain of $2.3 million relating to the
sale.
During the first quarter of 1997, the Company sold its 25% working
interest in the Second Bayou field in Cameron Parish, Louisiana for proceeds of
$1.5 million, and recorded a gain of $1.4 million. During the third quarter of
1997, the Company recognized a loss of $1.6 million on the sale of its 80%
working interest in South Timbalier Block 8. Proceeds for this sale were $1.5
million. In addition, the Company recorded a negative revision of $679,000
related to a gain on sale of properties in a prior period.
5. PRODUCTION PAYMENTS
In April 1994, the Company entered into a four-year commitment for a
$30.0 million volumetric production payment for the development of certain
infill drilling locations in the Oak Hill field in East Texas. The proceeds from
this agreement financed the capital expenditures for well drilling, fracturing
and completing and for surface facility installations. The advance under the
production payment obligated the Company to deliver a fixed volume of natural
gas, based upon prevailing market conditions at the time of the advance as
determined by the third-party. During 1994, the Company received $18.4 million,
committing the Company to deliver 10.7 BCF of natural gas through December 1998.
The Company did not receive any other advances under this commitment. This
commitment terminated on December 31, 1998.
6. 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.
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) the corporate administrative services agreement and the land leasing
agreement
51
53
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
each provide for a monthly base which entitles Nuevo to a specified amount of
services while incremental services are charged on a time and materials basis;
(iv) 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 (v) 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, 1999, 1998 and
1997, outsourcing fees paid to Torch amounted to $14.1 million, $14.5 million
and $14.4 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 1999, 1998 and 1997, such marketing fees were $1.2 million, $2.0
million and $2.9 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, 1999, 1998
and 1997, were $25.1 million, $20.5 million and $22.4 million, respectively.
7. RELATED PARTY TRANSACTIONS
On April 9, 1996, a broker's fee of 30,000 warrants was granted to a
company, of which a director of the Company is a partner, for services
associated with the acquisition of the Unocal Properties. These warrants had an
exercise price of $28.00 and were exercised in the first quarter of 1997. The
warrants contained a settlement provision whereby the Company, at its election,
could convert the warrants into shares of Common Stock based on the ratio of the
market price of the Company's Common Stock on the date of conversion over the
warrant exercise price, divided by the market price of the Company's Common
Stock. Changes in the fair value of the warrants subsequent to their issuance
were not recorded. During the first quarter of 1997, these warrants were
converted into Common Stock based on the formula discussed above, resulting in
no cash received by the Company in connection with the conversion. The market
price on the date of conversion was $50.25, resulting in the issuance of 13,284
shares of Common Stock.
Included in general and administrative expenses for 1997 was a $1.7
million severance payment to the Company's former President and Chief Executive
Officer.
8. 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 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 10, the Company and its restricted subsidiaries had $25.7
million available for the payment of dividends and share repurchases at December
31, 1999. The Company has not paid dividends on its Common Stock and does not
anticipate the payment of cash dividends in the immediate future.
52
54
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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 1998 and 1997,
weighted average potential dilutive common shares of 331,000 and 670,000 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,
-----------------------------------------------------------------
1999 1998 1997*
------------------- -------------------- --------------------
Income Shares Loss Shares Loss Shares
-------- -------- -------- -------- -------- --------
Earnings (loss) before extraordinary item per Common
share -- Basic ..................................... $ 31,442 19,418 $(94,272) 19,795 $(10,676) 19,796
Effect of dilutive securities:
Stock options ...................................... -- 153 -- -- -- --
-------- -------- -------- -------- -------- --------
Earnings (loss) before extraordinary item per Common
share -- Diluted ................................... $ 31,442 19,571 $(94,272) 19,795 $(10,676) 19,796
======== ======== ======== ======== ======== ========
----------
* Restated
Treasury Stock Repurchases
In March 1997, the Board of Directors authorized the open market
repurchase of up to 1,000,000 shares of outstanding Common Stock during 1997, at
times and prices deemed attractive by management. During April 1997, the Company
repurchased 542,491 shares of Common Stock, at an average purchase price of
$39.03 per share.
Since December 1997, the Board of Directors of the Company authorized
the open market repurchase of up to 3,616,600 shares of outstanding Common Stock
at times and at prices deemed appropriate by management. 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, 2000, the
Company had repurchased 2,610,600 shares at an average purchase price of $16.75
per share, including commissions, under the current share repurchase program.
Put Options
In May 1997, the Company sold put options on its Common Stock to a third
party. The options gave the purchaser the right to sell to the Company 500,000
shares of its Common Stock at prices ranging from $40.26 to $41.04 per share
through December 31, 1997. The contract gave the Company the choice of net cash,
net shares, or physical settlement. Any repurchased shares would have been
treated as Treasury Stock. The Company generated $1.6 million in option premium
from these transactions, which is reflected in additional paid-in capital on the
balance sheet. As of December 31, 1997, 400,000 of these options had expired
with the Company's share prices above the strike price, and 100,000 of these
options were settled on December 31, 1997, for a nominal amount of net cash.
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
53
55
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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.
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 shares 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 restricted for a
two-year period. The stock held in the benefit trust (75,904 shares, 47,759
shares and 45,119 shares at December 31, 1999, 1998 and 1997, 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
total expenses related to deferred compensation of $1.7 million in 1999, a net
benefit of $0.6 million in 1998 and expenses of $0.8 million in 1997. 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 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
based on a Towers Perrin report. 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.
54
56
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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 which the options may be exercised.
Options granted are exercisable, in full, six months following the date of the
grant.
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, 1997.................... 1,766,138 $24.24
Granted..................................... 652,875 $41.89
Exercised................................... (328,550) $18.59
Canceled.................................... (1,000) $47.88
---------
Outstanding at December 31, 1997.................. 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
=========
*Reflects the cancellation and re-issuance of 401,850 non-executive
employee stock options on December 14, 1998.
The Company had 2,202,454 options and 1,756,263 options exercisable at
December 31, 1999 and 1998, respectively. Detail of stock options outstanding
and options exercisable at December 31, 1999 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 $13.69................... 711,025 8.74 $11.33 711,025 $11.33
$15.50 to $19.63................... 769,204 7.39 $16.80 354,479 $17.77
$20.38 to $29.88................... 489,450 6.91 $23.19 489,450 $23.19
$34.00 to $47.88................... 647,500 7.66 $41.94 647,500 $41.94
--------- ---------
Total........................ 2,617,179 2,202,454
========= =========
The weighted-average fair value of options granted during 1999, 1998 and
1997, was $11.38, $7.55 and $12.89, 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 55.7% in 1999, 50.9% in 1998 and 35.2% in 1997; risk free interest
of 6% in 1999, 5% in 1998, and 5.75% in 1997, and average expected option lives
of five years in 1999 and 1998 and three years in 1997. 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
55
57
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
forma amounts indicated below (amounts in thousands, except per share data):
Year Ended December 31,
-------------------------------------
1999 1998 1997*
--------- --------- ---------
Net income (loss)................................................. As reported $ 31,442 $ (94,272) $ (13,700)
Pro forma $ 24,673 $(103,434) $ (16,315)
Earnings (loss) per Common share -- Basic......................... As reported $ 1.62 $ (4.76) $ (0.69)
Pro forma $ 1.27 $ (5.23) $ (0.82)
Earnings (loss) per Common share -- Diluted....................... As reported $ 1.61 $ (4.76) $ (0.69)
Pro forma $ 1.26 $ (5.23) $ (0.82)
----------
* Restated
9. 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.
10. LONG-TERM DEBT
Long-term debt is comprised of the following at December 31, 1999 and
1998 (amounts in thousands):
1999 1998
--------- ---------
9-1/2% Senior Subordinated Notes due 2008(a) ..................................................... $ 257,310 $ --
8-7/8% Senior Subordinated Notes(a)(b) ........................................................... -- 100,000
9-1/2% Senior Subordinated Notes due 2006(a)(c) .................................................. 2,440 160,000
OPIC credit facility (at 5.8% and 5.55% at December 31, 1999 and 1998, respectively, plus
a guaranty fee of 2.75%)(d) .................................................................. 750 3,902
Bank credit facility (at 7.13% and 5.94% at December 31, 1999 and 1998, respectively)(e)
.................................................................................................. 81,000 158,400
--------- ---------
Total debt ................................................................................... 341,500 422,302
Less current maturities .......................................................................... (750) (3,152)
--------- ---------
Long-term debt ................................................................................... $ 340,750 $ 419,150
========= =========
----------
(a) 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
$157,460,000 of its Old 9-1/2% Notes and $99,850,000 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
56
58
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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
of 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. 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.
(b) In June 1998, the Company issued $100.0 million, 8 7/8% Notes. In August
1999, most of the 8 7/8% Notes, except for $150,000, were exchanged for
9 1/2% Notes. The remaining $150,000 were retired in December 1999. No
significant costs were incurred in connection with this early retirement
of debt.
(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 interest rate associated with such credit facility is
the London Interbank Offered Rate ("LIBOR") plus 20 basis points and a
guaranty fee of 2.75% of the outstanding loan balance, payable quarterly.
At December 31, 1999, the interest rate was 5.8%, plus the guarantee fee
of 2.75%. The loan agreement requires a sixteen-quarter repayment period
and will be fully paid in April 2000.
(e) Nuevo's Amended and Restated Credit Agreement, (the "Agreement"), dated
June 30, 1999, provides for secured revolving credit availability of up to
$400.0 million (subject to a semi-annual borrowing base determination)
from a bank group led by Bank of America, N.A. and Morgan Guaranty Trust
Company of New York, until its expiration on April 1, 2003.
The borrowing base determination establishes the maximum borrowings that
may be outstanding under the credit facility, and is determined by a
two-thirds vote of the banks (three-fourths 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
57
59
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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.
During 1999, the borrowing base was reduced from $380.0 million to $200.0
million in January 1999, reflecting the January sale of the Company's East
Texas natural gas reserves, and also reflecting a significant decline in
projected oil prices since the previous determination. The borrowing base
was subsequently increased in October 1999, to $300.0 million, as a result
of the significant increase in commodity prices and the inclusion of
recently acquired oil and gas properties in California (see Note 3).
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. At December 31, 1999
the Company's interest rate under the credit facility was LIBOR plus
.625%, or 7.13%. Outstanding borrowings under this facility at December
31, 1999 were $81.0 million.
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 all covenants of the
Agreement at December 31, 1999, and does not anticipate any issues of
non-compliance arising in the foreseeable future.
In June 1997, the Company redeemed its 12-1/2% Senior Subordinated Notes
at a total cost of $78.0 million, representing $75.0 million face value of
the debt plus a 4% premium of $3.0 million. In addition to the premium,
the Company wrote off approximately $2.0 million of unamortized discount
and deferred financing costs. The redemption resulted in an extraordinary
loss on early extinguishment of debt in the amount of $3.0 million, net of
the related tax benefit of $2.0 million. The Company used proceeds from
its bank facility to fund the redemption.
The amount of scheduled debt maturities during the next five years and
thereafter is as follows (amounts in thousands):
2000 ......................................................................... $ 750
2001 ......................................................................... --
2002 ......................................................................... --
2003 ......................................................................... 81,000
2004 ......................................................................... --
Thereafter ................................................................... 259,750
--------
Total debt ............................................................... $341,500
========
Based upon the quoted market price, the fair value of the 9-1/2% Notes was
estimated to be $254.6 million at December 31, 1999, the fair value of the
Old 9-1/2% Notes was estimated to be $2.4 million and $160.2 million at
December 31, 1999 and 1998, respectively, and the fair value of the 8-7/8%
Notes was estimated to be $90.6 million at December 31, 1998. 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 and 1998.
58
60
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
11. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
NCC is a U.S. corporation with foreign branch operations in the Congo. The
functional currency of NCC is the U.S. Dollar and its income is taxed in the
United States. The Company's Congo investment involves risks typically
associated with investments in emerging markets such as an uncertain political,
economic, legal and tax environment, and expropriation and nationalization of
assets. The Company's investment is insured through political risk insurance
provided by OPIC.
The OPIC credit facility, discussed in Note 10, requires the Company to
provide consolidating financial statements that separately show NCC. Also shown
separately is Nuevo Congo LTD. ("NCL") which is the company that holds Nuevo's
additional interest in the Yombo field in the Congo (see Note 3) that was
acquired in 1998. These condensed consolidating financial statements are
presented below:
CONDENSED CONSOLIDATED BALANCE SHEET
AS OF DECEMBER 31, 1999
(AMOUNTS IN THOUSANDS)
Nuevo NCC NCL Consolidated
-------- -------- -------- ------------
Total current assets ..................................... $ 50,408 $ 13,893 $ 1,990 $ 66,291
Net property and equipment ............................... 588,416 49,175 10,870 648,461
Deferred tax assets, net ................................. 23,348 657 -- 24,005
Total other assets ....................................... 21,273 -- -- 21,273
-------- -------- -------- --------
Total assets ....................................... $683,445 $ 63,725 $ 12,860 $760,030
======== ======== ======== ========
Total current liabilities ................................ $ 25,589 $ 36,500 $ (739) $ 61,350
Long-term debt ........................................... 340,750 -- -- 340,750
Other long-term liabilities .............................. 9,292 -- -- 9,292
Mandatorily Redeemable Convertible Preferred Securities of
Nuevo Financing I ..................................... 115,000 -- -- 115,000
Total stockholders' equity ............................... 192,814 27,225 13,599 233,638
-------- -------- -------- --------
Total liabilities and stockholders' equity ......... $683,445 $ 63,725 $ 12,860 $760,030
======== ======== ======== ========
CONDENSED CONSOLIDATED BALANCE SHEET
AS OF DECEMBER 31, 1998
(AMOUNTS IN THOUSANDS)
Nuevo NCC NCL Consolidated
-------- -------- -------- ------------
Total current assets ..................................... $145,906 $ 12,870 $ 2,476 $161,252
Net property and equipment ............................... 568,509 39,112 8,951 616,572
Deferred tax assets, net ................................. 27,059 475 -- 27,534
Total other assets ....................................... 12,308 19 -- 12,327
-------- -------- -------- --------
Total assets ....................................... $753,782 $ 52,476 $ 11,427 $817,685
======== ======== ======== ========
Total current liabilities ................................ $ 18,006 $ 31,163 $ 454 $ 49,623
Long-term debt ........................................... 418,400 750 -- 419,150
Other long-term liabilities .............................. 2,034 -- -- 2,034
Mandatorily Redeemable Convertible Preferred Securities of
Nuevo Financing I ..................................... 115,000 -- -- 115,000
Total stockholders' equity ............................... 200,342 20,563 10,973 231,878
-------- -------- -------- --------
Total liabilities and stockholders' equity ......... $753,782 $ 52,476 $ 11,427 $817,685
======== ======== ======== ========
59
61
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1999
(AMOUNTS IN THOUSANDS)
Nuevo NCC NCL Consolidated
--------- --------- --------- ------------
Revenues ................. $ 301,135 $ 26,460 $ 4,640 $ 332,235
Expenses ................. 284,161 19,879 2,112 306,152
--------- --------- --------- ---------
Income before income
taxes................... 16,974 6,581 2,528 26,083
Income tax benefit ....... (5,177) (182) -- (5,359)
--------- --------- --------- ---------
Net income ............... $ 22,151 $ 6,763 $ 2,528 $ 31,442
========= ========= ========= =========
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR YEAR ENDED DECEMBER 31, 1998
(AMOUNTS IN THOUSANDS)
Nuevo NCC NCL Consolidated
--------- --------- --------- ------------
Revenues ........................ $ 236,758 $ 14,607 $ 1,338 $ 252,703
Expenses ........................ 362,103 16,279 1,218 379,600
--------- --------- --------- ---------
(Loss) income before income
taxes.......................... (125,345) (1,672) 120 (126,897)
Income tax benefit .............. (31,935) (690) -- (32,625)
--------- --------- --------- ---------
Net (loss) income ............... $ (93,410) $ (982) $ 120 $ (94,272)
========= ========= ========= =========
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1997
(AMOUNTS IN THOUSANDS)
Nuevo* NCC* Consolidated*
--------- --------- -------------
Revenues ............................................................. $ 334,446 $ 22,832 $ 357,278
Expenses ............................................................. 358,079 16,531 374,610
--------- --------- ---------
(Loss) income before income taxes and extraordinary item ............. (23,633) 6,301 (17,332)
Income tax (benefit) expense ......................................... (6,883) 227 (6,656)
--------- --------- ---------
(Loss) income before extraordinary item .............................. (16,750) 6,074 (10,676)
Extraordinary loss on early extinguishment of debt, net of tax
benefit............................................................. 3,024 -- 3,024
--------- --------- ---------
Net (loss) income .................................................... $ (19,774) $ 6,074 $ (13,700)
========= ========= =========
----------
* Restated
60
62
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1999
(AMOUNTS IN THOUSANDS)
Nuevo NCC NCL Consolidated
--------- --------- --------- ------------
Cash flows from operating activities:
Net (loss) income ...................................... $ 22,151 $ 6,763 $ 2,528 $ 31,442
Non-cash adjustments ................................... (5,594) 7,595 639 2,640
Change in assets and liabilities ....................... (12,436) 4,036 (1,658) (10,058)
--------- --------- --------- ---------
Net cash provided by operating activities ......... 4,121 18,394 1,509 24,024
--------- --------- --------- ---------
Cash flows from investing activities:
Additions to oil and gas properties .................... (105,515) (17,840) (2,564) (125,919)
Proceeds from sale of properties ....................... 234,312 -- -- 234,312
Additions to other properties and other ................ (10,247) -- -- (10,247)
--------- --------- --------- ---------
Net cash provided by (used in) investing
activities....................................... 118,550 (17,840) (2,564) 98,146
--------- --------- --------- ---------
Cash flows from financing activities:
Proceeds from borrowings ............................... 142,590 -- -- 142,590
Payments of long-term debt ............................. (220,240) (3,152) -- (223,392)
Other .................................................. (38,483) -- -- (38,483)
--------- --------- --------- ---------
Net cash used in financing activities ............. (116,133) (3,152) -- (119,285)
--------- --------- --------- ---------
Net increase (decrease) in cash & cash equivalents ........... 6,538 (2,598) (1,055) 2,885
Cash and cash equivalents at beginning of year ............... 600 5,339 1,464 7,403
--------- --------- --------- ---------
Cash and cash equivalents at end of year ..................... $ 7,138 $ 2,741 $ 409 $ 10,288
========= ========= ========= =========
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1998
(AMOUNTS IN THOUSANDS)
Nuevo NCC NCL Consolidated
--------- --------- --------- ------------
Cash flows from operating activities:
Net (loss) income ...................................... $ (93,410) $ (982) $ 120 $ (94,272)
Non-cash adjustments ................................... 119,473 4,281 -- 123,754
Change in assets and liabilities ....................... (8,015) 14,923 (557) 6,351
--------- --------- --------- ---------
Net cash provided by (used in) operating
activities....................................... 18,048 18,222 (437) 35,833
--------- --------- --------- ---------
Cash flows from investing activities:
Additions to oil and gas properties .................... (137,430) (10,971) (8,951) (157,352)
Proceeds from sale of properties ....................... 11,830 -- -- 11,830
Additions to other properties and other ................ (2,813) -- -- (2,813)
--------- --------- --------- ---------
Net cash used in investing activities ............. (128,413) (10,971) (8,951) (148,335)
--------- --------- --------- ---------
Cash flows from financing activities:
Proceeds from borrowings ............................... 240,900 -- -- 240,900
Payments of long-term debt ............................. (124,551) (3,703) -- (128,254)
Contribution to (from) Nuevo ........................... (10,852) -- 10,852 --
Other .................................................. (1,949) -- -- (1,949)
--------- --------- --------- ---------
Net cash provided by (used in) financing
activities....................................... 103,548 (3,703) 10,852 110,697
--------- --------- --------- ---------
Net increase (decrease) in cash & cash equivalents ........... (6,817) 3,548 1,464 (1,805)
Cash and cash equivalents at beginning of year ............... 7,417 1,791 -- 9,208
--------- --------- --------- ---------
Cash and cash equivalents at end of year ..................... $ 600 $ 5,339 $ 1,464 $ 7,403
========= ========= ========= =========
61
63
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1997
(AMOUNTS IN THOUSANDS)
Nuevo* NCC* Consolidated*
--------- --------- -------------
Cash flows from operating activities:
Net (loss) income ...................................... $ (19,774) $ 6,074 $ (13,700)
Non-cash adjustments ................................... 155,749 3,612 159,361
Change in assets and liabilities ....................... 12,846 6,955 19,801
--------- --------- ---------
Net cash provided by operating activities ......... 148,821 16,641 165,462
--------- --------- ---------
Cash flows from investing activities:
Additions to oil and gas properties .................... (182,261) (12,847) (195,108)
Proceeds from sale of properties ....................... 27,377 -- 27,377
Additions to other properties and other ................ (1,747) -- (1,747)
--------- --------- ---------
Net cash used in investing activities ............. (156,631) (12,847) (169,478)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from borrowings ............................... 234,000 -- 234,000
Payments of long-term debt ............................. (213,800) (3,703) (217,503)
Other .................................................. (16,909) -- (16,909)
--------- --------- ---------
Net cash provided by (used in) financing
activities ...................................... 3,291 (3,703) (412)
--------- --------- ---------
Net (decrease) increase in cash and cash equivalents ......... (4,519) 91 (4,428)
Cash and cash equivalents at beginning of year ............... 11,936 1,700 13,636
--------- --------- ---------
Cash and cash equivalents at end of year ..................... $ 7,417 $ 1,791 $ 9,208
========= ========= =========
12. INCOME TAXES
Income tax (benefit) expense is summarized as follows (amounts in
thousands):
Year Ended December 31,
---------------------------------------
1999 1998 1997*
-------- -------- --------
Current
Federal ...................... $ 1,012 $ (105) $ 135
State ........................ 188 -- 421
-------- -------- --------
1,200 (105) 556
-------- -------- --------
Deferred
Federal ...................... (8,457) (24,172) (7,449)
State ........................ 1,898 (8,348) (1,800)
-------- -------- --------
(6,559) (32,520) (9,249)
-------- -------- --------
Total income tax
benefit ............... $ (5,359) $(32,625) $ (8,693)
======== ======== ========
A deferred tax benefit related to the exercise of employee stock options
of approximately $0.2 million and $5.3 million was allocated directly to
additional paid-in capital in 1999 and 1997, respectively. A current tax benefit
of $2.0 million was allocated to the extraordinary loss in 1997.
---------
*Restated
62
64
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
Total income tax benefit differs from the amount computed by applying the
Federal income tax rate to income (loss) before income taxes, minority interest
and extraordinary item. The reasons for these differences are as follows:
Year Ended December 31
----------------------------------
1999 1998 1997*
------ ------ ------
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 (4.3) (4.0)
Non-realization of tax benefits related to provision for impairment on
assets held for sale ................................................ -- -- 3.6
(Decrease) increase in valuation allowance ................................ (60.8) 13.4 --
Nondeductible travel and entertainment and other .......................... 0.1 0.2 (3.4)
------ ------ ------
(20.5)% (25.7)% (38.8)%
====== ====== ======
----------
* Restated
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,
-----------------------
1999 1998
-------- --------
Net operating loss carryforwards ................ $ 41,814 $ 45,610
Alternative minimum tax credit carryforwards..... 2,066 1,054
State income taxes .............................. -- 1,520
Capital loss carryforwards ...................... 2,426 2,365
-------- --------
Total deferred income tax assets .......... 46,306 50,549
Less: valuation allowance ................. (1,777) (17,646)
-------- --------
Net deferred income tax assets ............ 44,529 32,903
-------- --------
Property and equipment .......................... (19,881) (5,369)
State income taxes .............................. (643) --
-------- --------
Total deferred income tax liabilities...... (20,524) (5,369)
-------- --------
Net deferred income tax asset ................... $ 24,005 $ 27,534
======== ========
At December 31, 1999, the Company had a net operating loss carryforward
for regular tax of approximately $119.5 million, which will expire in 2018. The
alternative minimum tax credit carryforward of $2.1 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.
63
65
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
13. 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,
-----------------------------------------
1999 1998 1997*
--------- --------- ---------
(Amounts in thousands)
Sales to unaffiliated customers:
Oil and gas -- East ........................ $ 13,282 $ 46,885 $ 61,456
Oil and gas -- West ........................ 195,397 177,315 247,723
Oil and gas -- Foreign ..................... 30,627 15,810 22,794
Gas plant, pipeline and other facilities ... 2,972 5,365 20,598
--------- --------- ---------
Total sales ........................... 242,278 245,375 352,571
Gain on sale of assets, net ...... 85,294 5,768 1,372
Interest and other income ........ 4,663 1,560 3,335
--------- --------- ---------
Total revenues ........................ $ 332,235 $ 252,703 $ 357,278
========= ========= =========
Operating profit (loss) before income taxes:
Oil and gas -- East(2) ..................... $ 81,171 $ 22,608 $ 24,745
Oil and gas -- West ........................ 17,716 (67,677) 40,369
Oil and gas -- Foreign ..................... 5,208 (12,849) 6,172
Gas plant, pipeline and other
facilities(1) ............................ (1,242) 3,063 (22,478)
--------- --------- ---------
102,853 (54,855) 48,808
Unallocated corporate expenses ............. 37,047 32,958 32,170
Interest expense ........................... 33,110 32,471 27,357
Dividends on TECONS ........................ 6,613 6,613 6,613
Minority interest in loss of subsidiary .... -- -- 8
--------- --------- ---------
Operating profit (loss) before income
taxes .................................... $ 26,083 $(126,897) $ (17,340)
========= ========= =========
Identifiable assets:
Oil and gas -- Domestic .................... $ 566,256 $ 748,695 $ 671,603
Oil and gas -- Foreign ..................... 82,074 40,700 40,139
Gas plant and other facilities ............. 12,297 14,893 17,387
--------- --------- ---------
660,627 804,288 729,129
Corporate assets and investments ........... 99,403 13,397 75,157
--------- --------- ---------
Total ................................. $ 760,030 $ 817,685 $ 804,286
========= ========= =========
Capital expenditures:
Oil and gas -- East ........................ $ 5,941 $ 36,597 $ 32,857
Oil and gas -- West ........................ 100,130 96,179 148,927
Oil and gas -- Foreign ..................... 24,570 30,498 14,111
--------- --------- ---------
Oil and gas capital expenditures............ 130,641 163,274 195,895
Less: Geological & geophysical, delay rentals
and other expenses........................ (4,722) (5,922) (787)
--------- --------- ---------
Additions to oil and gas properties
per Statement of Cash Flows............... $ 125,919 $ 157,352 $ 195,108
========= ========= =========
Gas plant and other facilities ............. $ 10,247 $ 2,813 $ 1,747
========= ========= =========
Depreciation, depletion and amortization:
Oil and gas -- East ........................ $ 7,805 $ 10,391 $ 14,252
Oil and gas -- West ........................ 62,219 68,164 81,011
Oil and gas -- Foreign ..................... 9,177 4,971 3,385
Gas plant and other facilities ............. 666 812 2,830
Corporate .................................. 785 698 680
--------- --------- ---------
$ 80,652 $ 85,036 $ 102,158
========= ========= =========
----------
* Restated
64
66
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
(1) Gas plant and other facilities operations for 1998 include a positive
revision to a prior period charge of $3.7 million and for 1997 include a
charge for $23.9 million to record an impairment on assets held for sale
and a $2.3 million gain on sale. See Note 4.
(2) Includes gain on sale of the East Texas natural gas asset of $80.2 million
for the year ended 1999. In 1999, 1998 and 1997, the Company had one
customer that accounted for 79%, 60%, and 62% of oil and gas revenues,
respectively. In 1999 and 1998, the Company had another customer that
accounted for 12% and 10% of oil and gas revenues, respectively.
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 at 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.
14. CONTINGENCIES AND OTHER MATTERS
In August 1996, the Company was named as a defendant in the lawsuit 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.
currently pending in the 79th Judicial District Court of Brooks County, Texas
(the "Lopez Case"). The plaintiffs, based on pleadings and deposition testimony,
allege: i) underpayment of royalties and claim damages, on a gross basis against
all working interest owners, of $56.5 million, including interest for the period
from 1985 to date; ii) that their production was improperly commingled with gas
produced from an adjoining lease, resulting in damages, including interest, of
$40.8 million, on a gross basis; (iii) failure to develop, claiming damages and
interest of $106.3 million (gross) for interest in the alleged failure to
develop; and iv) numerous other claims, including claims for drainage, breach of
the implied covenant to reasonably develop the lease, conversion, fraud,
emotional distress, lease termination and exemplary damages, that may result in
unspecified damages. Nuevo's working interest in these properties is 20%. The
Company, along with the other defendants in this case, denies these allegations
and is vigorously contesting 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. As of December 31, 1999,
management believes that the estimated ultimate resolution of this matter is
adequately reflected in the consolidated financial statements.
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, $4.3 million in 1998 and the remainder in 1999, that were intended
for international exploration. Such amounts are included in other expense during
the respective periods. 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. The Company is
attempting to recoup the loss, however, there is no certainty that any of the
funds will be recovered.
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. 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 $0.5 million, , and $3.2 million during 1999, 1998,
and 1997,
65
67
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
respectively. As of December 31, 1999, the Company had received insurance
reimbursements of $3.7 million, with a remaining insurance receivable of $1.4
million. For amounts not covered by insurance, including the $120,000
deductible, the Company recorded lease operating expenses of $0.4 million, $0.5
million, and $0.1 million during 1999, 1998, and 1997, respectively. Repairs
were completed by the end of 1997, and production recommenced in December 1997.
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, 1999. Although, the
Company may have additional exposure, 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.
The Company and its partners underwent a tax examination related to
their ownership interests in the Yombo field offshore Congo for the years 1994
through 1997. In June 1999, the Company and its partners settled this tax
assessment for a total of $1.0 million, of which the Company's share was
$400,000.
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 $48.5 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 $64.1 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.
66
68
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
15. FINANCIAL INSTRUMENTS
During 1999, the Company formalized its 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 extent that future markets over a
forward 18 month period are significantly higher than long term norms, the
Company will hedge so much of its production as is necessary to meet its policy
goals for that period. For 2000, the Company has entered into swap contracts on
16,500 barrels of oil per day ("BOPD"), at an average West Texas Intermediate
("WTI") price of $17.94 per barrel. The Company has also entered into cost-less
collars on an additional 16,500 BOPD, with a floor of $16.00 per barrel and
ceiling of $21.21 per barrel. On a physical volume basis, these hedges cover 64%
of the Company's estimated 2000 oil production. This production is hedged based
on a fixed NYMEX price for each type of crude oil that the Company produces in
California. As a result of the TOSCO contract, (see Note 13 to the Notes to
Consolidated Financial Statements), which fixes the price of the Company's
California production at approximately 72% of the NYMEX price effective January
1, 2000, these hedge transactions have the effect on a price basis of hedging
substantially all of the Company's current production for the year 2000. Also
for the year 2000, the Company has entered into basis swaps on 3,000 BOPD of its
production in the Congo, hedging the basis differential between No. 6 fuel oil
and WTI at an average differential of $1.88 per barrel. At December 31, 1999,
the market value of the hedge positions was a loss of approximately $35.7
million.
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, and for the third quarter on
20,000 BOPD at an average WTI price of $21.22. On a physical volume basis, these
hedges cover 32% of the Company's estimated 2001 oil production. On a price
basis, the Company has not hedged in excess of its anticipated 2001 production.
At December 31, 1999, the market value of these swaps was a gain of $0.5
million. 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.
On February 26, 1999, the Company entered into a swap arrangement with a
major financial institution that effectively converts the interest rate on $16.4
million notional amount of the 9 1/2% Notes to a variable LIBOR-based rate
through February 25, 2000. Based on LIBOR rates in effect at December 1, 1999,
this amounted to a net reduction in the carrying cost of the 9 1/2% Notes from
9.5% to 7.09%, or 241 basis points. In addition, the swap arrangement also
effectively hedges the price at which these Notes can be repurchased by the
Company. At December 31, 1999, the Company recorded an unrealized gain of
$131,000 related to the fair value of the notes.
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, 1999 and 1998.
December 31, 1999 December 31, 1998
----------------------- -------------------------
Carrying Approximate Carrying Approximate
Value Fair Value Value Fair Value
-------- -------- --------- --------
Other investments ............ $ 78 $ 78 $ 80 $ 80
-------- -------- --------- --------
Derivative Instruments:
Option premium ......... -- -- 292 241
Commodity price swaps... -- (35,244) -- (2,636)
Long-term debt (see Note 10).. 340,750 337,972 419,150 409,938
TECONS ....................... 115,000 62,675 115,000 71,875
67
69
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
16. CONTINGENT PAYMENT AND PRICE SHARING AGREEMENTS
In connection with the acquisition of the properties located in
California from Unocal in 1996, 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 taxes, multiplied by the actual number of barrels of oil sold during
the respective year. The minimum price of $17.75 per Bbl under the agreement
(determined based on near month of 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 will be netted down to the
field level using a fixed differential equal to 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 future, possible contingent payment when prices
are $.50 per Bbl or more below the minimum price. As of December 31, 1999, the
Company had accumulated $30.8 million in price credits since the inception of
the agreement. These cumulative credits will be used to reduce future amounts
owed under the contingent payment, if any. The cumulative credit of $30.8
million has not been recognized in the consolidated financial statements as it
is only available to offset future payments. 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, 1999, the Company has never
been obligated under the terms of the agreement to make a payment to Unocal.
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 is $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 is that Nuevo only owns upside above $15.19 per Bbl on
approximately 44% of its Congo production. In 1997, the Company paid the seller
$845,000 pursuant to this price sharing agreement. This payment 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 realized oil price on these properties is capped at
$9.00 per Bbl, with the excess field price over the realized price, if any,
shared among the Company and the original owners from whom Torch acquired its
interest. For 2000, the effect of this agreement is that Nuevo only owns upside
above $9.00 per Bbl on approximately 28% of the Point Pedernales production.
Amounts below $9.00 per Bbl are owned by the Company and the other working
interest owners based on their respective ownership interests. 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.
17. 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, 1999 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.
68
70
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
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 1999, of $18.97 per BBL (including hedge
effect) and $2.31 per thousand cubic feet of gas ("MCF"), and are adjusted for
the effects of hedging and contractual agreements with Unocal and Amoco in
connection with the California and Congo property acquisitions (see Note 16).
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.
69
71
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,
-----------------------------------
1999 1998 1997*
-------- -------- --------
DOMESTIC
Property acquisition:
Proved properties .... $ 62,300 $ 200 $ 10,206
Unproved properties... 520 1,320 --
Exploration ................ 4,973 26,706 18,474
Development(1):
Proved reserves ...... 2,906 2,525 13,927
Unproved reserves .... 35,372 102,025 139,177
-------- -------- --------
$106,071 $132,776 $181,784
======== ======== ========
FOREIGN
Property acquisition:
Proved properties .... $ -- $ 7,809 $ --
Unproved properties... 424 1,404 --
Exploration ................ 3,742 9,204 10,887
Development:
Proved reserves ...... -- 1,273 --
Unproved reserves .... 20,404 10,808 3,224
-------- -------- --------
$ 24,570 $ 30,498 $ 14,111
======== ======== ========
TOTAL
Property acquisition:
Proved properties .... $ 62,300 $ 8,009 $ 10,206
Unproved properties... 944 2,724 --
Exploration ................ 8,715 35,910 29,361
Development:
Proved reserves ...... 2,906 3,798 13,927
Unproved reserves .... 55,776 112,833 142,401
-------- -------- --------
$130,641 $163,274 $195,895
======== ======== ========
(1) Includes capitalized interest directly related to development
activities of $0.3 million in 1999, $0.6 million in 1998 and $2.4
million in 1997.
----------
* Restated
70
72
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:
Year Ended December 31,
-----------------------------------------
1999 1998 1997*
----------- --------- ---------
DOMESTIC
Proved properties ..................................... $ 898,032 $ 877,230 $ 903,096
Unproved properties ................................... 21,756 20,984 41,661
----------- --------- ---------
Total capitalized costs ............................ 919,788 898,214 944,757
Accumulated depreciation, depletion and
amortization ..................................... (403,727) (401,139) (315,038)
----------- --------- ---------
Net capitalized costs ........................... $ 516,061 $ 497,075 $ 629,719
=========== ========= =========
FOREIGN
Proved properties ..................................... $ 80,374 $ 59,774 $ 39,516
Unproved properties ................................... 2,618 1,360 --
----------- --------- ---------
Total capitalized costs ............................ 82,992 61,134 39,516
Accumulated depreciation, depletion and
amortization ..................................... (20,901) (11,724) (6,378)
----------- --------- ---------
Net capitalized costs ........................... $ 62,091 $ 49,410 $ 33,138
=========== ========= =========
TOTAL
Proved properties ..................................... $ 978,406 $ 937,004 $ 942,612
Unproved properties ................................... 24,374 22,344 41,661
----------- --------- ---------
Total capitalized costs ............................ 1,002,780 959,348 984,273
Accumulated depreciation, depletion and
amortization ..................................... (424,628) (412,863) (321,416)
----------- --------- ---------
Net capitalized costs ........................... $ 578,152 $ 546,485 $ 662,857
=========== ========= =========
----------
* Restated
71
73
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
Results of operations for producing activities (amounts in thousands) --
Year Ended December 31,
-----------------------------------------
1999 1998 1997*
--------- --------- ---------
DOMESTIC
Revenues from oil and gas producing activities ..................... $ 208,679 $ 224,200 $ 309,179
Production costs ................................................... (114,295) (122,816) (108,074)
Exploration costs .................................................. (10,643) (5,137) (9,813)
Depreciation, depletion and amortization ........................... (71,475) (78,555) (95,263)
Provision for impairment of oil and gas properties ................. -- (68,529) (30,000)
Income tax (provision) benefit ..................................... (2,515) 13,234 (26,449)
--------- --------- ---------
Results of operations from producing activities (excluding corporate
overhead and interest costs) ..................................... $ 9,751 $ (37,603) $ 39,580
========= ========= =========
FOREIGN
Revenues from oil and gas producing activities ..................... $ 30,627 $ 15,810 $ 22,794
Production costs ................................................... (12,869) (11,888) (11,968)
Exploration costs .................................................. (3,374) (11,425) (1,269)
Depreciation, depletion and amortization ........................... (9,177) (4,971) (3,385)
Provision for impairment of oil and gas properties ................. -- (375) --
Income tax (provision) benefit ..................................... (1,067) 3,174 (2,469)
--------- --------- ---------
Results of operations from producing activities (excluding corporate
overhead and interest costs) ..................................... $ 4,140 $ (9,675) $ 3,703
========= ========= =========
TOTAL
Revenues from oil and gas producing activities ..................... $ 239,306 $ 240,010 $ 331,973
Production costs ................................................... (127,164) (134,704) (120,042)
Exploration costs .................................................. (14,017) (16,562) (11,082)
Depreciation, depletion and amortization ........................... (80,652) (83,526) (98,648)
Provision for impairment of oil and gas properties ................. -- (68,904) (30,000)
Income tax (provision) benefit ..................................... (3,582) 16,408 (28,918)
--------- --------- ---------
Results of operations from producing activities (excluding corporate
overhead and interest costs) ..................................... $ 13,891 $ (47,278) $ 43,283
========= ========= =========
---------
* Restated
Per unit sales prices and costs:
Year Ended December 31,
------------------------------------
1999 1998 1997
-------- -------- --------
DOMESTIC
Average sales price:
Oil (per barrel) ............................ $ 10.57 $ 9.10 $ 14.88
Gas (per MCF) ............................... $ 2.27 $ 2.00 $ 2.06
Average production cost per equivalent barrel .. $ 6.07 $ 5.33 $ 4.96
FOREIGN
Average sales price:
Oil (per barrel) ............................ $ 16.69 $ 10.82 $ 14.66
Average production cost per equivalent barrel .. $ 7.01 $ 8.14 $ 7.70
TOTAL
Average sales price:
Oil (per barrel) - exclusive of hedges ...... $ 13.82 $ 9.26 $ 14.94
Oil (per barrel) - hedge effect ............. $ (2.61) $ (0.01) $ (0.08)
-------- -------- --------
Oil (per barrel) - net of hedge effect ...... $ 11.21 $ 9.25 $ 14.86
======== ======== ========
Gas (per MCF) - exclusive of hedges ......... $ 2.27 $ 1.98 $ 2.19
Gas (per MCF) - hedge effect ................ $ -- $ 0.02 $ (0.13)
-------- -------- --------
Gas (per MCF) - net of hedge effect ......... $ 2.27 $ 2.00 $ 2.06
======== ======== ========
Average production cost per equivalent barrel .. $ 6.15 $ 5.56 $ 5.14
72
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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:
For the Year Ended December 31,
------------------------------------------------------------------------------
1999 1998 1997
---------------------- ---------------------- ----------------------
Oil* Gas Oil* Gas Oil* Gas
(Mbbl) (Mmcf) (Mbbl) (Mmcf) (Mbbl) (Mmcf)
-------- -------- -------- -------- -------- --------
DOMESTIC
Proved reserves at beginning of
year ............................. 164,300 403,256 202,771 390,691 165,839 394,630
Revisions of previous estimates .... 61,168 56,097 (41,399) (8,953) 10,177 (5,105)
Extensions and discoveries ......... 10,795 11,800 17,694 55,575 39,911 35,682
Production ......................... (15,892) (17,620) (17,345) (32,521) (15,854) (35,625)
Sales of reserves in-place ......... (10,270) (335,927) (1,595) (1,536) (15) (675)
Purchase of reserves in-place ...... 29,089 27,519 4,174 -- 2,713 1,784
-------- -------- -------- -------- -------- --------
Proved reserves at end of year ..... 239,190 145,125 164,300 403,256 202,771 390,691
======== ======== ======== ======== ======== ========
Proved developed reserves --
Beginning of year ............ 123,077 308,667 143,486 266,179 122,088 236,013
======== ======== ======== ======== ======== ========
End of year .................. 174,846 112,204 123,077 308,667 143,486 266,179
======== ======== ======== ======== ======== ========
FOREIGN
Proved reserves at beginning of
year ............................. 25,841 -- 24,493 -- 20,214 --
Revisions of previous estimates .... 2,042 -- (420) -- (1,313) --
Extensions and discoveries ......... -- -- -- -- 7,147 --
Production ......................... (1,835) -- (1,461) -- (1,555) --
Sales of reserves in-place ......... -- -- -- -- -- --
Purchase of reserves in-place ...... -- -- 3,229 -- -- --
-------- -------- -------- -------- -------- --------
Proved reserves at end of year ..... 26,048 -- 25,841 -- 24,493 --
======== ======== ======== ======== ======== ========
Proved developed reserves --
Beginning of year ............ 10,242 -- 9,526 -- 16,727 --
======== ======== ======== ======== ======== ========
End of year .................. 13,749 -- 10,242 -- 9,526 --
======== ======== ======== ======== ======== ========
TOTAL
Proved reserves at beginning of
year ............................. 190,141 403,256 227,264 390,691 186,053 394,630
Revisions of previous estimates .... 63,210 56,097 (41,819) (8,953) 8,864 (5,105)
Extensions and discoveries ......... 10,795 11,800 17,694 55,575 47,058 35,682
Production ......................... (17,727) (17,620) (18,806) (32,521) (17,409) (35,625)
Sales of reserves in-place ......... (10,270) (335,927) (1,595) (1,536) (15) (675)
Purchase of reserves in-place ...... 29,089 27,519 7,403 -- 2,713 1,784
-------- -------- -------- -------- -------- --------
Proved reserves at end of year ..... 265,238 145,125 190,141 403,256 227,264 390,691
======== ======== ======== ======== ======== ========
Proved developed reserves --
Beginning of year ............ 133,319 308,667 153,012 266,179 138,815 236,013
======== ======== ======== ======== ======== ========
End of year .................. 188,595 112,204 133,319 308,667 153,012 266,179
======== ======== ======== ======== ======== ========
--------
* Includes estimated NGL reserves.
73
75
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,
---------------------------------------------
1999 1998 1997
----------- ----------- -----------
DOMESTIC
Future cash inflows .................................... $ 4,823,952 $ 1,989,898 $ 3,566,450
Future production costs ................................ (2,132,655) (1,061,638) (1,643,774)
Future development costs ............................... (357,708) (289,686) (329,997)
----------- ----------- -----------
Future net inflows before income tax ................... 2,333,589 638,574 1,592,679
Future income taxes .................................... (704,236) -- (427,618)
----------- ----------- -----------
Future net cash flows .................................. 1,629,353 638,574 1,165,061
10% discount factor .................................... (739,181) (360,611) (454,023)
----------- ----------- -----------
Standardized measure of discounted future net cash flows $ 890,172 $ 277,963 $ 711,038
=========== =========== ===========
FOREIGN
Future cash inflows .................................... $ 469,327 $ 260,627 $ 360,959
Future production costs ................................ (177,150) (134,549) (171,331)
Future development costs ............................... (46,750) (66,715) (59,985)
----------- ----------- -----------
Future net inflows before income tax ................... 245,427 59,363 129,643
Future income taxes .................................... (66,971) -- (39,243)
----------- ----------- -----------
Future net cash flows .................................. 178,456 59,363 90,400
10% discount factor .................................... (61,455) (37,393) (36,653)
----------- ----------- -----------
Standardized measure of discounted future net cash flows $ 117,001 $ 21,970 $ 53,747
=========== =========== ===========
TOTAL
Future cash inflows .................................... $ 5,293,279 $ 2,250,525 $ 3,927,409
Future production costs ................................ (2,309,805) (1,196,187) (1,815,105)
Future development costs ............................... (404,458) (356,401) (389,982)
----------- ----------- -----------
Future net inflows before income tax ................... 2,579,016 697,937 1,722,322
Future income taxes .................................... (771,207) -- (466,861)
----------- ----------- -----------
Future net cash flows .................................. 1,807,809 697,937 1,255,461
10% discount factor .................................... (800,636) (398,004) (490,676)
----------- ----------- -----------
Standardized measure of discounted future net cash flows $ 1,007,173 $ 299,933 $ 764,785
=========== =========== ===========
74
76
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,
-------------------------------------------
1999 1998 1997
----------- --------- -----------
DOMESTIC
Standardized measure -- beginning of year .................. $ 277,963 $ 711,038 $ 988,155
Sales, net of production costs ............................. (94,384) (101,383) (201,198)
Purchases of reserves in-place ............................. 224,251 2,278 18,293
Net change in prices and production costs .................. 439,615 (466,018) (581,640)
Extensions, discoveries and improved recovery, net of future
production and development costs ........................ 59,873 46,713 180,146
Changes in estimated future development costs .............. (12,375) (14,956) (65,102)
Incurred development costs ................................. 32,380 94,366 152,708
Revisions of quantity estimates ............................ 276,965 (86,459) 33,358
Accretion of discount ...................................... 27,796 83,281 125,138
Net change in income taxes ................................. (211,448) 121,770 141,452
Sales of reserves in-place ................................. (151,348) (356) (1,598)
Changes in production rates and other ...................... 20,884 (112,311) (78,674)
----------- --------- -----------
Standardized measure -- end of year ........................ $ 890,172 $ 277,963 $ 711,038
=========== ========= ===========
FOREIGN
Standardized measure -- beginning of year .................. $ 21,970 $ 53,747 $ 74,794
Sales, net of production costs ............................. (17,759) (3,923) (10,826)
Purchases of reserves in-place ............................. -- 2,750 --
Net change in prices and production costs .................. 59,641 (56,690) (22,193)
Extensions, discoveries and improved recovery, net of future
production and development costs ........................ -- -- 5,486
Changes in estimated future development costs .............. 12,711 (3,091) (9,436)
Incurred development costs ................................. 7,175 12,081 3,224
Revisions of quantity estimates ............................ 8,479 (750) (5,609)
Accretion of discount ...................................... 2,197 6,830 10,720
Net change in income taxes ................................. (26,001) 14,552 17,857
Changes in production rates and other ...................... 48,588 (3,536) (10,270)
----------- --------- -----------
Standardized measure -- end of year ........................ $ 117,001 $ 21,970 $ 53,747
=========== ========= ===========
TOTAL
Standardized measure -- beginning of year .................. $ 299,933 $ 764,785 $ 1,062,949
Sales, net of production costs ............................. (112,143) (105,306) (212,024)
Purchases of reserves in-place ............................. 224,251 5,028 18,293
Net change in prices and production costs .................. 499,256 (522,708) (603,833)
Extensions, discoveries and improved recovery, net of future
production and development costs ........................ 59,873 46,713 185,632
Changes in estimated future development costs .............. 336 (18,047) (74,538)
Incurred development costs ................................. 39,555 106,447 155,932
Revisions of quantity estimates ............................ 285,444 (87,209) 27,749
Accretion of discount ...................................... 29,993 90,111 135,858
Net change in income taxes ................................. (237,449) 136,322 159,309
Sales of reserves in-place ................................. (151,348) (356) (1,598)
Changes in production rates and other ...................... 69,472 (115,847) (88,944)
----------- --------- -----------
Standardized measure -- end of year ........................ $ 1,007,173 $ 299,933 $ 764,785
=========== ========= ===========
75
77
NUEVO ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(CONTINUED)
SELECTED QUARTERLY FINANCIAL DATA (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
(UNAUDITED):
Quarter Ended(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)(4) ......................... $ 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
Quarter Ended(2)
----------------------------------------------------
March 31, June 30, September 30, December 31,
1998 1998 1998 1998
--------- --------- ------------- ------------
Revenues ..................................... $ 67,661 $ 61,512 $ 65,966 $ 57,564
Operating earnings (loss)(1) ................. $ 4,011 $ 3,317 $ (5,369) $(66,858)
Net loss(1)(3) ............................... $ (6,582) $ (7,622) $(11,245) $(68,823)
Loss per Common share -- Basic ............... $ (0.33) $ (0.39) $ (0.57) $ (3.47)
Loss per Common share -- Diluted.............. $ (0.33) $ (0.39) $ (0.57) $ (3.47)
---------
(1) Includes a fourth quarter charge of $68.9 million to record an
impairment of oil and gas properties and a fourth quarter $3.7 million
positive revision to a prior period impairment on assets held for sale.
(2) Certain reclassifications of prior period amounts have been made to
conform with the current presentation.
(3) Includes a fourth quarter increase in the deferred tax asset valuation
allowance of $16.9 million.
(4) Includes a fourth quarter decrease in the deferred tax asset valuation
allowance of $15.9 million.
76
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NUEVO ENERGY COMPANY
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
On March 29, 2000, the Company and Relational Investors, LLC agreed to terminate
that Letter Agreement of March 1, 1999, and release each other from future
obligations and duties set out therein, all of which is more particularly
described in Exhibit 99(i).
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, 1999. 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, 1999. 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, 1999. 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, 1999. 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).
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.
77
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NUEVO ENERGY COMPANY
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).
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).
(10) Material Contracts.
10.1 Second Restated Credit Agreement dated June 30, 1999 between
Nuevo Energy Company (Borrower) and Bank of America N.A.,
formerly NationsBank, N.A. (Administrative Agent), Morgan
Guaranty Trust Company of New York (Documentation Agent), Banc
of America
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NUEVO ENERGY COMPANY
Securities LLC (Lead Arranger and Sole Book Manager) and
certain lenders (Incorporated by reference from Exhibit 10.1
to Quarterly Report on Form 10-Q for the quarterly period
ended June 30, 1999).
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.
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).
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NUEVO ENERGY COMPANY
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).
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).
(21) Subsidiaries of the Registrant
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NUEVO ENERGY COMPANY
(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 December 16, 1999,
reporting Item 5. Other Events and Item 7. Financial
Statements and Exhibits was filed on December 16, 1999.
2. A Current Report on Form 8-K, dated December 20, 1999,
reporting Item 5. Other Events and Item 7. Financial
Statements and Exhibits was filed on December 21, 1999.
(27) Financial Data Schedule
(99) Additional Exhibits
(i) Termination of March 1, 1999 Letter Agreement, dated March
29, 2000, between the Company and Relational Investors,
LLC.
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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.
- 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 contract 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 at note 16.
- 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.
TERMS USED TO CLASSIFY OUR RESERVE QUANTITIES
- Proved reserves -- The estimated quantities of crude oil, natural gas
and natural gas liquids which, upon
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NUEVO ENERGY COMPANY
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. The Company's finding
costs as of June 30, 1999 represent average finding costs over a two and
one half year period ending on June 30, 1999.
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, 1996, 1997 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. In order to reflect the divestiture
of the East Texas properties and the Star acquisition, the Company's
reserve life index for June 30, 1999 was calculated by dividing estimated
net proved reserves at June 30, 1999 by the Company's annualized pro
forma production for the first six months of 1999, assuming the Company
closed the Star acquisition on January 1, 1999.
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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.
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.
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 29, 2000 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 29, 2000
------------------------------------------------ -------------------------
Douglas L. Foshee
Chairman of the Board of Directors,
President and Chief Executive Officer
(Principal Executive Officer)
By: /s/ Robert M. King Date: March 29, 2000
------------------------------------------------ -------------------------
Robert M. King
Senior Vice President and
Chief Financial Officer (Principal Financial Officer)
By: /s/ Sandra D. Kraemer Date: March 29, 2000
------------------------------------------------ -------------------------
Sandra D. Kraemer
Controller (Principal Accounting Officer)
By: /s/ Robert L. Gerry III Date: March 29, 2000
------------------------------------------------ -------------------------
Robert L. Gerry III
Director
By: /s/ Gary R. Petersen Date: March 29, 2000
------------------------------------------------ -------------------------
Gary R. Petersen
Director
By: /s/ Thomas D. Barrow Date: March 29, 2000
------------------------------------------------ -------------------------
Thomas D. Barrow
Director
By: /s/ Isaac Arnold, Jr. Date: March 29, 2000
------------------------------------------------ -------------------------
Isaac Arnold, Jr.
Director
By: /s/ David Ross III Date: March 29, 2000
------------------------------------------------ -------------------------
David Ross III
Director
By: /s/ Robert W. Shower Date: March 29, 2000
------------------------------------------------ -------------------------
Robert W. Shower
Director
By: /s/ Charles M. Elson Date: March 29, 2000
------------------------------------------------ -------------------------
Charles M. Elson
Director
By: /s/ David H. Batchelder Date: March 29, 2000
------------------------------------------------ -------------------------
David H. Batchelder
Director
87
Index to Exhibits
Exhibit Description
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21 Subsidiaries of the Registrant
23.1 Consent of KPMG LLP