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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
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(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, 2001
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
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Nuevo Energy Company
(Exact Name of Registrant as Specified in Its Charter)
Delaware 76-0304436
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1021 Main, Suite 2100, Houston, 77002
Texas (Zip Code)
(Address of principal executive
offices)
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. [_]
The aggregate market value of the voting stock held by non-affiliates of
the registrant:
The aggregate market value of the voting stock held by non-affiliates of
the registrant at March 26, 2002, was approximately $259,987,138.
The number of shares outstanding of each of the registrant's classes of
Common Stock as of the latest practicable date:
Common Stock, par value $.01 per share. Shares outstanding on March 26,
2002: 17,104,417.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the registrant's annual proxy statement, to be filed within 120
days after December 31, 2001, are incorporated by reference into Part III.
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NUEVO ENERGY COMPANY
TABLE OF CONTENTS
Page
----
PART I
Item 1. Business........................................................ 1
Item 2. Properties...................................................... 13
Item 3. Legal Proceedings............................................... 13
Item 4. Submission of Matters to a Vote of Security Holders............. 13
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters............................................ 14
Item 6. Selected Financial Data......................................... 16
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................... 17
Risk Factors and Cautionary Statement for Purposes of the "Safe
Harbor" Provisions of the Private Securities Litigation Reform
Act of 1995.................................................... 30
Item 7A. Quantitative and Qualitative Disclosures About Market Risk...... 34
Item 8. Financial Statements and Supplementary Data..................... 36
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure........................................... 74
PART III
Item 10. Directors and Executive Officers of the Registrant.............. 74
Item 11. Executive Compensation.......................................... 74
Item 12. Security Ownership of Certain Beneficial Owners and Management.. 74
Item 13. Certain Relationships and Related Transactions.................. 74
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-
K.............................................................. 75
Signatures........................................................ 83
i
PART I
ITEM 1. BUSINESS
General
Nuevo Energy Company became a public company in July 1990 and is engaged in
the acquisition, exploitation, development and production of and exploration
for crude oil and natural gas. We have increased our proved oil and gas
reserves through major acquisitions in the Republic of Congo in 1995 and in
California in 1996 and also acquired proved reserves near or adjacent to our
California assets followed by successful exploitation of our acquired
properties.
We are the largest independent oil and gas exploration and production
company in California. With approximately 93% of our reserves located in
California at year-end 2001, we have a long reserve life and highly
predictable well production profiles. Four fields in the San Joaquin Valley
accounted for 73% of our California reserves and 92% of our California value
in 2001. We also operate fields offshore California. This high asset
concentration combined with a high proportion of operated properties enables
us to control the timing of exploitation and development expenditures within
commodity price cycles.
Our international assets are principally concentrated offshore the Republic
of Congo and accounted for 7% of our reserves at year-end 2001. This non-
operated property provides a stable production profile which has been enhanced
by a recent infill development program.
As used in this annual report, the words "we", "our", "us", "Nuevo" and the
"Company" refer to Nuevo Energy Company, except as otherwise specified, and to
our subsidiaries.
Strategy
Prior to late 2001, our strategy had been focused on our strengths:
acquiring undervalued assets in familiar geographic areas and geologic plays,
developing our assets cost-effectively through secondary and tertiary recovery
methods, and pursuing logical field extensions of existing plays that fit our
competencies.
In late 2001, the new management team was formed to redirect the focus of
the Company. In order to generate greater profitability from the existing
asset base, we determined that capital expenditures and costs would have to be
reduced. A disciplined capital allocation process was implemented which
resulted in a $70 - 80 million capital budget for 2002, versus $148 million in
2001. Management is committed to spending no more capital than our cash flow
allows.
In order to reduce costs and gain greater operational control, in late
2001, we notified our California field operations and human resources
outsourcing provider that the outsourcing agreements will be terminated
effective March 15, 2002. Nuevo employees now staff the majority of these
functions. We have also implemented cost reduction measures throughout our
organization. At year-end 2001, an unsuccessful California exploration program
was terminated and the technical staff was reduced. Overall, our general and
administrative expenses, exploration expenses and lease operating expenses
will be significantly reduced in 2002 versus 2001.
These initial steps will ensure that we generate higher returns from our
existing asset base. However, our intermediate and longer-term objectives are
to increase our growth in production and reserves while improving the
profitability of our operations. This will be accomplished by reducing our
financial leverage, acquiring higher margin properties and adding one or two
additional core areas in North America.
1
Reserves
We invested $433.1 million during the three years ended December 31, 2001
and added 104.6 MMBOE, replacing 177% of our production at an average cost of
$4.14 per BOE.
The following table details our estimated proved reserves at December 31,
2001:
Net Proved Reserves
------------------------
Oil(/1/) Gas
(MBbls) (MMcf) MBOE
-------- ------- -------
U.S. Properties
California Fields
Cymric............................................ 82,845 4,048 83,521
Brea Olinda....................................... 30,185 18,014 33,188
Midway-Sunset..................................... 26,185 -- 26,185
Belridge.......................................... 15,623 1,195 15,822
Santa Clara....................................... 10,621 18,754 13,747
Dos Cuadras....................................... 9,284 4,549 10,042
Point Pedernales.................................. 8,032 1,878 8,345
Buena Vista....................................... 2,656 27,431 7,228
Other............................................. 13,325 30,092 18,339
------- ------- -------
Total California Fields......................... 198,756 105,961 216,417
------- ------- -------
Other U.S. Fields................................... 257 5,402 1,157
------- ------- -------
Total U.S. Properties........................... 199,013 111,363 217,574
------- ------- -------
Foreign Properties
Yombo, Congo...................................... 15,571 -- 15,571
Other............................................. 274 1,129 462
------- ------- -------
Total Foreign Properties........................ 15,845 1,129 16,033
------- ------- -------
Total Properties................................ 214,858 112,492 233,607
======= ======= =======
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(/1/)Includes natural gas liquids
Domestic Operations
Our domestic operations are located primarily onshore and offshore
California. We also have domestic operations in the onshore Gulf Coast region,
Alabama and Louisiana. At December 31, 2001, our net U.S. proved reserves
totaled approximately 217.6 MMBOE or 93% of our total proved reserve base.
During 2001, domestic production was 16.7 MMBOE, or 90% of total production.
We continue to create value through domestic oil and gas development
projects by initiating workovers, recompletions, development drilling,
secondary and tertiary recovery operations and other production enhancement
techniques to maximize current production and the ultimate recovery of
reserves. Capital expenditures for domestic exploitation projects totaled
$100.7 million in 2001 and are currently budgeted at approximately $65 -- 75
million in 2002. The main focus of our 2002 exploitation program will be
directed to the continued successful development of Star Fee in the Cymric
field.
The focus of our exploratory drilling was in California where we drilled 1
successful well and 8 dry holes in 2001. Capital expenditures for domestic
exploration activity totaled $10.7 million in 2001. In late 2001, we made the
decision to scale back our exploratory efforts and to discontinue all
exploration activities in California.
2
California Onshore. Net proved reserves were approximately 176.7 MMBOE at
December 31, 2001, and production was 11.1 MMBOE in 2001. Our main California
onshore properties include interests in the Cymric, Midway-Sunset and Belridge
fields in the Western San Joaquin Basin in Kern County, California, the Buena
Vista Hills field in the Southern San Joaquin Basin in Kern County and the
Brea Olinda field in the North San Joaquin Valley. We have onshore properties
that utilize thermal operations to maximize current production and the
ultimate recovery of reserves. We own a 100% working interest (93% net
revenue) in our properties in the Cymric field and the entire working interest
and an average net revenue interest of approximately 97% in our properties in
the Midway-Sunset field. Production is from several zones in the Cymric field,
including the Tulare, Diatomite and Point of Rocks formations and the Antelope
Shale. The Midway-Sunset field produces from five zones with the Potter Sand
and the thermal Diatomite accounting for the majority of the total production.
We operate the deeper zones of the Belridge field in fee with 100% working and
net revenue interests. Production from the Belridge field is from the Tulare
formation. We operate and own a 100% working interest (79% net revenue) in our
operated portion of the Buena Vista Hills field. Production from this field is
from the Etchegoin Sands and the Antelope Shale. We also operate three fee
properties in the Brea Olinda oil field in northern Orange County with a 100%
working and net revenue interest. We have 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.
California Offshore. Net proved reserves were approximately 39.7 MMBOE at
December 31, 2001, and production was 5.2 MMBOE in 2001. Offshore California,
we operate 12 platforms; 10 in federal waters and 2 in state waters and have
interests in the Point Pedernales, Dos Cuadras and East Dos Cuadras, and Santa
Clara fields. We own an 80% working interest (67% net revenue) in the Point
Pedernales field We operate the Point Pedernales field which is located 3.5
miles offshore Santa Barbara County, California, in federal waters. Production
is from the Monterey Shale at depths from 3,500-5,150 feet. The Dos Cuadras
and East Dos Cuadras fields are located offshore five and one-half miles from
Santa Barbara in the Santa Barbara Channel. We operate three platforms with a
50% working interest (42% net revenue) and a fourth platform with a 67.5%
working interest (56% net revenue). We operate the Santa Clara field with a
100% working interest (83% net revenue).
Other Domestic. We have properties located in the onshore Gulf Coast
region, Alabama and Louisiana with a total proved reserve base of 1.2 MMBOE at
December 31, 2001, and production of 0.4 MMBOE in 2001. These properties
include our interests in the Giddings field in Grimes and Austin Counties,
Texas; and in the North Frisco City field in Monroe County, Alabama. We own an
interest in 12 producing wells in the Giddings field and have an average 46.9%
working (35.2% net revenue) interest in these wells. We are the operator of
the North Frisco City field and own approximately a 22% working (17% net
revenue) interest in this field.
International Operations
At December 31, 2001, our estimated international net proved reserves
totaled 16.0 MMBOE, or 7% of our total proved reserve base. During 2001, our
international production was 1.9 MMBOE, or 10% of our total production.
Our international investments involve risks typically associated with
investments in emerging markets such as an uncertain political, economic,
legal and tax environment and possible expropriation and nationalization of
assets. In addition, if a dispute arises in our foreign operations, we may be
subject to the exclusive jurisdiction of foreign courts or may not be
successful in subjecting foreign persons to the jurisdiction of the United
States. We attempt to conduct our business and financial affairs so as to
protect against political and economic risks applicable to operations in the
various countries where we operate, but there can be no assurance that we will
be successful in so protecting ourselves. A portion of our investment in the
Congo is insured through political risk insurance provided by the Overseas
Private Investment Corporation ("OPIC"). See "Risk Factors" for a discussion
of the risks of our international investments.
Congo. Our international reserves and production consist of a 50% working
interest (37.5% average net revenue) in the Yombo oil field located in the
Marine 1 Permit offshore the Republic of Congo in West Africa
3
("Congo"). Estimated net proved reserves of the Yombo oil field as of December
31, 2001 were 16.0 MMBbl, and production during 2001 totaled 1.9 MMBbls. In
2001 revenues relating to production from the Yombo field accounted for
approximately 11% of our total oil and gas revenues. The properties are
located 27 miles offshore in approximately 370 feet of water. We also own a
50% interest in a converted super tanker with storage capacity of over one
million barrels of oil for use as a floating production, storage and off
loading vessel ("FPSO"). Our production is converted on the FPSO to No. 6 fuel
oil with less than 0.3% sulfur content. We also had a 50% interest in the
Masseko field which we have elected not to pursue due to economic conditions
at this time. Should circumstances change in the future, we may pursue
development of the field. As a result of the decision not to pursue this
field, an impairment of $13.0 million was recorded in 2001.
During 2000 and 2001, a five well development program was implemented. This
highly successful program increased our net production in the Congo from 5,000
BOPD in October 2000 to a peak production rate of 6,450 BOPD in August 2001.
The individual wells produced at rates between 500 and 1,800 BOPD. The field
is currently fully developed, due to the lack of slots for new wells. As
additional slots become available, additional drilling activity is possible.
Ghana. As of June 17, 2001, we relinquished our 1.9 million-acre Accra-Keta
Permit offshore the Republic of Ghana. The Permit was relinquished prior to
the commencement of the second phase of the work program. We were the operator
of this Permit and held a 50% working interest. A total impairment of $1.0
million was recorded during the second and third quarters of 2001 in
connection with this relinquishment.
Tunisia. In 2000, we acquired interests in two exploration permits in the
Republic of Tunisia, subject to governmental approval, that added 1.3 million
acres to our international portfolio. The first of these permits is the
171,000-acre (gross) Alyane Permit located offshore Tunisia in the Gulf of
Gabes. We owned a 100% participating interest and were operator of the block.
As a result of a shift in our international exploration strategy, we withdrew
our request for formal government approval of the Convention and Joint Venture
Agreement in January 2002 resulting in a relinquishment of our interest in
Alyane.
In April 2000, we acquired a 10.42% participating interest from Bligh
Tunisia Inc. in the 1.1 million gross acre Anaguid Permit located onshore
southern Tunisia in the Ghadames Basin for approximately $1.5 million. This
permit is operated by Anadarko Petroleum Company. In July 2001, we acquired an
additional 12.08% participating interest from Coho Anaguid Inc., which is
subject to governmental approval. The two interests total 22.5% participating
interest. The partners anticipate drilling one exploration well on the Anaguid
Permit by December 2002, subject to rig availability. Our anticipated costs
under this commitment are approximately $0.7 million. In 2001, the partners
completed the acquisition of 1,801 kilometers of new 2-D seismic data. We
currently anticipate the drilling of a subsequent well in 2003, which might be
required in connection with the acquisition of the interest from Coho Anaguid,
Inc.
In addition to acquiring our interests in the Anaguid Permit, we have,
effective April 1, 2000, increased our existing 17.5% participating interest
in the 1,000,000 gross acre Fejaj Permit onshore Tunisia, by acquiring an
additional interest from Bligh Tunisia Inc., giving us a 42.86% participating
interest. We along with our partners plan to re-enter and deepen the Chott
Fejaj #3-A well on the Fejaj Permit to test a sub-salt prospect in the fourth
quarter of 2002. Our anticipated costs under this commitment are approximately
$1.3 million. The current term of the Fejaj Permit has been extended due to a
shortage of land rigs in Tunisia. The Chott Fejaj #3-A well was initially
drilled to the top of salt in December 1998, when it was temporarily
abandoned.
Canada. In May 2000, we acquired a 50% working interest in 22,140 acres in
the Marten Hills heavy oil play in Alberta, Canada for approximately $0.4
million. The cyclic steaming potential of the acreage was evaluated in 2001,
and was determined to be non-commercial. We have no current plans for the
area.
4
Drilling Activities
Acreage
The following table sets forth the acres of developed and undeveloped oil
and gas properties in which we held an interest as of December 31, 2001.
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 we directly own a working interest. The number
of net acres is the sum of the fractional ownership of working interests we
directly own in the gross acres expressed as a whole number and percentages. A
"net acre" is deemed to exist when the sum of our fractional ownership of
working interests in gross acres equals one.
Gross Net
--------- ---------
Developed Acreage........................................ 192,857 134,047
Undeveloped Acreage...................................... 2,433,283 836,884
--------- ---------
Total.................................................. 2,626,140 970,931
========= =========
The following table sets forth our undeveloped acreage at December 31,
2001:
Gross Net
--------- ---------
California(/1/) ......................................... 250,486 123,351
Texas.................................................... 10,880 2,806
Congo, West Africa:
Marine 1 Permit........................................ 38,000 19,000
Tunisia, North Africa.................................... 2,100,000 676,071
Other.................................................... 33,917 15,656
--------- ---------
Total.................................................. 2,433,283 836,884
========= =========
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(/1/Includes)COOGER acreage
Productive Wells
The following table sets forth our gross and net interests in productive
oil and gas wells at December 31, 2001. Productive wells are producing wells
and wells capable of production.
Gross Net
----- -----
Oil Wells........................................................ 2,601 1,967
Gas Wells........................................................ 257 148
----- -----
Total.......................................................... 2,858 2,115
===== =====
5
Drilling Activity
Our drilling activities in 2001 were in the continental United States and
offshore in state and federal waters, and offshore Congo.
At December 31, 2001, we had 2 gross (0.2 net) wells in progress. The
following table details the results of our drilling activity, net to our
interest, for the last three calendar years. Gross wells are the number of
wells in which we own a direct working interest. The number of net wells is
the sum of the fractional ownership of working interests we directly own in
gross wells.
Exploratory Wells
----------------------------------------------
Gross Net
---------------------- -----------------------
Dry Dry
Productive Holes Total Productive Holes Total
---------- ----- ----- ---------- ----- ------
1999.......................... -- 4 4 -- 2.33 2.33
2000.......................... 11 2 13 11 1.45 12.45
2001.......................... 1 8 9 1 4.95 5.95
Development Wells
----------------------------------------------
Gross Net
---------------------- -----------------------
Dry Dry
Productive Holes Total Productive Holes Total
---------- ----- ----- ---------- ----- ------
1999.......................... 44 1 45 40.21 0.33 40.54
2000.......................... 175 3 178 173.25 2.68 175.93
2001.......................... 101 1 102 95.98 1.00 96.98
In 2001, we drilled 35 wells in the Cymric field in central California,
which contained 36% of our total estimated net proved equivalent reserves at
December 31, 2001, and anticipate drilling approximately 36 wells in the
Cymric field during 2002. In the Midway-Sunset field in central California,
which contained 11% of the total estimated net proved equivalent reserves at
December 31, 2001, we drilled 40 wells during 2000, and deferred the
development in this field to 2002 where we plan to drill 10 Potter Sands and 2
Diatomite wells. In the Belridge field in central California, which contained
7% of the total estimated net proved equivalent reserves at December 31, 2001,
we drilled 14 wells during 2001, and plan to drill approximately 11 wells in
2002.
In 1999, we initiated a waterflood project in the Yombo field offshore
Congo to enhance production from existing Upper Sendji and Tchala zones. The
development program continued during 2000 and 2001, drilling a total of 5
infill wells which increased our production approximately 30% from 2000 to
2001. Both pipelines originating from our platforms to the Conkouati (FPSO)
were replaced in 2001. Plans for 2002 include two conversions to water
injection and facility maintenance.
Acquisitions and Divestitures of Oil and Gas Producing Properties
We have, from time to time, been an active participant in the market for
oil and gas properties. We have attempted to purchase assets which, for any of
a variety of reasons, are out of favor in the marketplace and are available
for acquisition at attractive prices. We also seek to divest lower growth
assets at times when those assets are valued highly by the marketplace.
In January 2001, we acquired producing properties previously held by Naftex
ARM, LLC, in Kern County, California for approximately $28.5 million which is
located southeast of our interest in the Cymric field.
In 2000, we sold our working interest in the Las Cienegas field in
California for approximately $4.6 million. These assets were reclassified as
assets held for sale during the third quarter of 1999, at which time we
discontinued depleting and depreciating these assets. No impairment charge was
recorded upon reclassification to assets held for sale.
6
In 1999, we sold our interests in 13 onshore fields and a gas processing
plant located in Ventura County, California for approximately $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 us. The remainder of the proceeds were used to retire bank debt.
In 1999, we acquired oil and gas properties located onshore and offshore
California for $61.4 million from Texaco Inc. We 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 our January 1999 sale of our
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 acquisition included interests in Cymric, East Coalinga, Dos
Cuadras, Buena Vista Hills and other fields we operate.
In 1999, we completed the sale of our East Texas natural gas assets to an
affiliate of Samson Resources Company for approximately $191.0 million. We
realized an $80.2 million 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.
We 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.
Gas Plant and Other Facilities
At December 31, 2001, we owned interests in the following gas plant
facilities:
2001
Capacity Throughput Ownership
Facility State Operator MMCFD MMCFD Interest
------------------------ ---------- -------------------- -------- ---------- ---------
Stearns Gas Plant....... California Nuevo Energy Company 5 3.0 100%
HS&P Gas Plant.......... California Nuevo Energy Company 13 2.1 80%
In December 1999, we sold the Santa Clara Valley Gas Plant, located east of
Ventura, California, in connection with the sale of our interest in non-core
properties onshore California.
Real Estate
In 1996, along with our acquisition of certain California upstream oil and
gas properties from Union Oil Company of California, we acquired tracts of
land in Orange and Santa Barbara Counties in California, and nearly 8,000
acres of agricultural property in the central valley of California. As of
December 31, 2001, the carrying amount of this land totaled $55.9 million. A
majority of this real estate has associated oil and gas activity.
We may, from time to time, sell certain of our surface real estate assets.
We sold 13.3 acres of our Brea Highland property in 2001 for $6.1 million and
we expect to monetize a portion of our California real estate portfolio in
2002. Our Brea Highlands residential development project, now named "Tonner
Hills", is currently going through the entitlement process in Orange 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.
Markets
The markets for hydrocarbons continue to be quite volatile. Our financial
condition, operating results, future growth and the carrying value of our oil
and gas properties are substantially dependent on oil and gas prices.
7
The ability to maintain or increase our borrowing capacity and to obtain
additional capital on attractive terms is also substantially dependent upon
oil and gas prices. Prices for oil and gas are subject to large fluctuations
in response to relatively minor changes in the supply of and demand for oil
and gas, market uncertainty and a variety of additional factors beyond our
control. These factors include weather conditions in the United States, the
condition of the United States economy, the actions of the Organization of
Petroleum Exporting Countries, governmental regulation, political stability in
the Middle East and elsewhere, the foreign supply of oil and gas, the price of
foreign oil imports and the availability of alternate fuel sources. Any
substantial and extended decline in the price of oil could have an adverse
effect on the carrying value of our proved reserves, borrowing capacity, our
ability to obtain additional capital, and our revenues, profitability and cash
flows from operations.
The price of natural gas and the threat of electrical disruptions are
factors that can create volatility in our California oil operations. We have
historically had a net long position in natural gas in California where we
produce more natural gas than we consume in thermal crude production. As gas
prices escalated in late 2000, we began to sell our California gas production
to the market rather than use it as fuel gas consumed in less economic cyclic
steaming operations to gas sales. In January and February 2001, we sold an
average of 19 MMcfd, or 44% of our total daily gas production, which resulted
in an increase in gas sales of 33%. As gas prices moderated later in 2001, we
resumed using natural gas in our steam operations in August.
In California, we generate a total of 22.5 Megawatts ("MW") of power at
various sites and consume approximately 77% in our operations. In 2000, two
turbines came on-line at our Brea Olinda field using gas previously flared.
Three turbines in Kern County produce 12 MW of power and cogenerate 15% of our
total steam needs in thermal operation. By self-generating power consumption
in Kern County, we have reduced our exposure to rising electricity prices.
With the exception of the Point Pedernales field, for which we have contracted
for firm electric power service, our facilities receive power under
interruptible service contracts. Considering the fact that California has
experienced shortages of electricity and some of our facilities receive
interruptible service, we could experience periodic power interruptions. In
addition, the State of California could increase power costs, change existing
rules or impose new rules or regulations with respect to power that could
impact our operating costs.
Production of California San Joaquin Valley heavy oil (defined herein as
those fields which produce primarily 15(degrees) API quality crude oil or
heavier through thermal operations) constituted 52% of our total 2001 crude
output. In addition, properties which produce primarily other grades of
relatively heavy oil (generally, 20(degrees) API or heavier, but produced
through non-thermal operations) constituted 14% of our total 2001 crude
output. The market price for California heavy oil differs from the established
market indices for oil elsewhere in the U.S., due principally to the higher
transportation and refining costs associated with heavy oil.
In February 2000, we entered into a 15-year contract, effective January 1,
2000, to sell all of our current and future California crude oil production to
Tosco Corporation. The contract provides pricing based on a fixed percentage
of the NYMEX crude oil price for each type of crude oil that we produce in
California. While the contract does not reduce our exposure to price
volatility, it does effectively eliminate the basis differential risk between
the NYMEX price and the field price of our California oil production. In doing
so, the contract makes it substantially easier for us to hedge our realized
prices. The Tosco contract permits, under certain circumstances, to separately
market up to ten percent of our California crude production. We exercised this
right and, effective January 1, 2001, began selling 5,000 BOPD of our San
Joaquin Valley oil production to a third party under a one-year contract
containing NYMEX pricing. A new contract was entered into with the same party
for a one-year period on January 1, 2002.
Our Yombo field production in Marine 1 Permit offshore Congo produces a
relatively heavy crude oil (16-20(degrees) API gravity) which is processed
into a low-sulfur, No. 6 fuel oil product for sale to worldwide markets.
Production from this property constituted 12% of our total 2001 oil
production. The market for residual fuel oil differs from the markets for WTI
and other benchmark crudes due to its primary use as an industrial or utility
fuel versus the higher value transportation fuel component, which is produced
from refining most grades of crude oil.
8
Sales to Tosco Corporation accounted for 63%, 84% and 79% of 2001, 2000 and
1999 oil and gas revenues. Sales to Torch Energy Marketing accounted for 23%,
11% and 12% of 2001, 2000 and 1999 oil and gas revenues. Beginning in January
2002, our natural gas is being marketed by a new provider, Coral Energy. The
loss of any single significant customer or contract could have a material
adverse short-term effect, however, our management does not believe that the
loss of any single significant customer or contract would materially affect
our business in the long-term.
Regulation
Oil and Gas Regulation
The availability of a ready market for oil and gas production depends upon
numerous factors beyond our control. These factors include state and federal
regulation of oil and gas production and transportation, as well as
regulations governing environmental quality and pollution control, state
limits on allowable rates of production by a well or proration unit, the
amount of oil and gas available for sale, the availability of adequate
pipeline and other transportation and processing facilities and the marketing
of competitive fuels. For example, a productive gas well may be "shut-in"
because of an over-supply of gas or lack of an available gas pipeline in the
areas in which we may conduct operations. State and Federal regulations are
generally intended to prevent waste of oil and gas, protect rights to produce
oil and gas between owners in a common reservoir, control the amount of oil
and gas produced by assigning allowable rates of production and control
contamination of the environment. Pipelines and gas plants are also are
subject to the jurisdiction of various Federal, state and local agencies.
Our sales of natural gas are affected by the availability, terms and costs
of transportation. The rates, terms and conditions applicable to the
interstate transportation of gas by pipelines are regulated by the Federal
Energy Regulatory Commission ("FERC") under the Natural Gas Acts ("NGA"), as
well as under Section 311 of the Natural Gas Policy Act ("NGPA"). Since 1985,
the FERC has implemented regulations intended to increase competition within
the gas industry by making gas transportation more accessible to gas buyers
and sellers on an open-access, non-discriminatory basis.
Our sales of oil are also affected by the availability, terms and costs of
transportation. The rates, terms, and conditions applicable to the interstate
transportation of oil by pipelines are regulated by the FERC under the
Interstate Commerce Act. FERC has implemented a simplified and generally
applicable ratemaking methodology for interstate oil pipelines to fulfill the
requirements of Title VIII of the Energy Policy Act of 1992 comprised of an
indexing system to establish ceilings on interstate oil pipeline rates. The
FERC has announced several important transportation-related policy statements
and rule changes, including a statement of policy and final rule issued
February 25, 2000 concerning alternatives to its traditional cost-of-service
rate-making methodology to establish the rates interstate pipelines may charge
for their services. The final rule revises FERC's pricing policy and current
regulatory framework to improve the efficiency of the market and further
enhance competition in natural gas markets.
With respect to transportation of natural gas on 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.
9
In the event we conduct operations on federal, state or Indian oil and gas
leases, such operations must comply with numerous regulatory restrictions,
including various nondiscrimination statutes, royalty and related valuation
requirements, and certain of such operations must be conducted pursuant to
certain on-site security regulations and other appropriate permits issued by
the Bureau of Land Management ("BLM") or Minerals Management Service ("MMS")
or other appropriate federal or state agencies.
Our OCS leases in federal waters are administered by the MMS and require
compliance with detailed MMS regulations and orders. The MMS has promulgated
regulations implementing restrictions on various production-related
activities, including restricting the flaring or venting of natural gas. Under
certain circumstances, the MMS may require any of our operations on federal
leases to be suspended or terminated. Any such suspension or termination could
materially and adversely affect our financial condition and operations. On
March 15, 2000, the MMS issued a final rule effective June 1, 2000, that
amends its regulations governing the calculation of royalties and the
valuation of crude oil produced from federal leases. Among other matters, this
rule amends the valuation procedure for the sale of federal royalty oil by
eliminating posted prices as a measure of value and relying instead on arm's
length sales prices and spot market prices as market value indicators. Because
we generally sell our production to third parties and therefore pays royalties
on production from federal leases, it is not anticipated that this final rule
will have a substantial impact on us.
The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or
indirect ownership of any interest in federal onshore oil and gas leases by a
foreign citizen of a country that denies "similar or like privileges" to
citizens of the United States. Such restrictions on citizens of a "non-
reciprocal" country include ownership or holding or controlling stock in a
corporation that holds a federal onshore oil and gas lease. If this
restriction is violated, the corporation's lease can be canceled in a
proceeding instituted by the United States Attorney General. Although the
regulations of the BLM (which administers the Mineral Act) provide for agency
designations of non-reciprocal countries, there are presently no such
designations in effect. We own interests in numerous federal onshore oil and
gas leases. It is possible that holders of equity interests in us may be
citizens of foreign countries, which at some time in the future might be
determined to be non-reciprocal under the Mineral Act.
Our pipelines used to gather and transport our oil and gas are subject to
regulation by the Department of Transportation ("DOT") under the Hazardous
Liquids Pipeline Safety Act of 1979, as amended ("HLPSA") relating to the
design, installation, testing, construction, operation, replacement and
management of pipeline facilities. The HLPSA requires us and other pipeline
operators to comply with regulations issued pursuant to HLPSA designed to
permit access to and allowing copying of records and to make certain reports
and provide information as required by the Secretary of Transportation.
The Pipeline Safety Act of 1992 (The "Pipeline Safety Act") amends the
HLPSA in several important respects. It requires the Research and Special
Programs Administration ("RSPA") of DOT to consider environmental impacts, as
well as its traditional public safety mandate, when developing pipeline safety
regulations. In addition, the Pipeline Safety Act mandates the establishment
by DOT of pipeline operator qualification rules requiring minimum training
requirements for operators, and requires that pipeline operators provide maps
and records to RSPA. It also authorizes RSPA to require certain pipeline
modifications as well as operational and maintenance changes. We believe our
pipelines are in substantial compliance with all HLPSA and the Pipeline Safety
Act. Nonetheless, significant expenses would be incurred if new or additional
safety measures are required.
Environmental Regulation
General. Our activities are subject to existing federal, state and local
laws and regulations governing environmental quality and pollution control. It
is anticipated that, absent the occurrence of an extraordinary event,
compliance with existing federal, state and local laws, rules and regulations
governing the release of materials in the environment or otherwise relating to
the protection of the environment will not have a material effect upon our
operations, capital expenditures, earnings or competitive position.
10
Our activities with respect to exploration, drilling and production from
wells, natural gas facilities, including the operation and construction of
pipelines, plants and other facilities for transporting, processing, treating
or storing natural gas and other products, are subject to stringent
environmental regulation by state and federal authorities including the
Environmental Protection Agency ("EPA"). Such regulation can increase the cost
of planning, designing, installing and operating such facilities. In most
instances, the regulatory requirements relate to water and air pollution
control measures. (See Note 15 to the Notes to the Consolidated Financial
Statements).
With respect to our offshore oil and gas operations in California, we have
significant exit cost liabilities. These liabilities include costs for
dismantlement, rehabilitation and abandonment. As of December 31, 2001, the
net liability for these exit costs was approximately $113.1 million. We are
not indemnified for any part of these exit costs. (See Note 15 to the Notes to
the Consolidated Financial Statements).
Waste Disposal. We currently own or lease, and have in the past owned or
leased, numerous properties that have been used for production of oil and gas
for many years. Although we utilized operating and disposal practices that
were standard in the industry at the time, hydrocarbons or other wastes may
have been disposed of or released on or under the properties that we currently
own or lease or properties that we have in the past owned or leased. In
addition, many of these properties have been operated by third parties over
whom we had no control as to such entities' treatment of hydrocarbons or other
wastes or the manner in which such substances may have been disposed of or
released. State and federal laws applicable to oil and gas wastes and
properties have become stricter. Under these new laws, we could be required to
remediate property, including ground water, containing or impacted by
previously disposed wastes (including wastes disposed of or released by prior
owners or operators) or to perform remedial plugging operations to prevent
future or mitigate existing contamination.
We may generate wastes, including hazardous wastes that are subject to the
federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The EPA has limited the disposal options for certain wastes that are
designated as hazardous under RCRA ("Hazardous Wastes") and is considering the
adoption of stricter disposal standards for nonhazardous wastes. Furthermore,
certain wastes generated by our oil and gas operations that are currently
exempt from treatment as Hazardous Wastes may in the future be designated as
Hazardous Wastes, and therefore be subject to more rigorous and costly
operating and disposal requirements.
Superfund. The federal Comprehensive Environmental Response, Compensation
and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes joint
and several liability for costs of investigation and remediation and for
natural resource damages, without regard to fault or the legality of the
original conduct, on certain classes of persons with respect to the release
into the environment of substances designated under CERCLA as hazardous
substances ("Hazardous Substances"). These classes of persons or potentially
responsible parties ("PRP's") include the current and certain past owners and
operators of a facility where there is or has been a release or threat of
release of a Hazardous Substance and persons who disposed of or arranged for
the disposal of the Hazardous Substances found at such a facility. CERCLA also
authorizes the EPA and, in some cases, third parties to take actions in
response to threats to the public health or the environment and to seek to
recover from the PRP the costs of such action. In the course of our
operations, we may have generated and may generate wastes that fall within
CERCLA's definition of Hazardous Substances. We may also be an owner of
facilities on which Hazardous Substances have been released by previous owners
or operators. We may be responsible under CERCLA for all or part of the costs
to clean up facilities at which such substances have been released and for
natural resource damages. We have not been named a PRP under CERCLA nor do we
know of any prior owners or operators of our properties that are named as
PRP's related to their ownership or operation of such property.
Air Emissions. Our operations are subject to local, state and federal
regulations for the control of emissions of air pollution. Local air quality
districts do much of the air quality regulation of sources in California.
California requires new and modified sources of air pollutants to obtain
permits prior to commencing construction. Major sources of air pollutants are
subject to more stringent, federally imposed permitting requirements,
including additional permits. Because of the severity of the ozone (smog)
problems in portions of California, the state has the most severe restrictions
on the emissions of volatile organic compounds (VOC) and
11
nitrogen oxides (Nox) of any state. Producing wells, gas plants and electric
generating facilities, all of which are owned by us generate VOC and Nox. Some
of our producing wells are in counties that are designated as nonattainment
for ozone and are therefore potentially subject to restrictive emission
limitations and permitting requirements. If the ozone problems in the state
are not resolved by the deadlines imposed by the federal Clean Air Act (2005--
2010), even more restrictive requirements may be imposed including financial
penalties based upon the quantity of ozone producing emissions. California
also operates a stringent program to control hazardous (toxic) air pollutants,
which might require installation of additional controls. Administrative
enforcement actions for failure to comply strictly with air pollution
regulations or permits are generally resolved by payment of monetary fines and
correction of any identified deficiencies. Alternatively, regulatory agencies
could require us to forego construction, modification or operation of certain
air emission sources, although we believe that in the latter cases we would
have enough permitted or permittable capacity to continue our operations
without a material adverse effect on any particular producing field.
Clean Water Act. The Clean Water Act ("CWA") imposes restrictions and
strict controls regarding the discharge of wastes, including produced waters
and other oil and natural gas wastes, into waters of the United States, a term
broadly defined. These controls have become more stringent over the years, and
it is probable that additional restrictions will be imposed in the future.
Permits must be obtained to discharge pollutants into federal waters. The CWA
provides for civil, criminal and administrative penalties for unauthorized
discharges of pollutants and of oil and Hazardous Substances. It imposes
substantial potential liability for the costs of removal or remediation
associated with discharges of oil or Hazardous Substances. State laws
governing discharges to water also provide varying civil, criminal and
administrative penalties and impose liabilities in the case of a discharge of
petroleum or it derivatives, or other Hazardous Substances, into state waters.
In addition, the EPA has promulgated regulations that may require us to obtain
permits to discharge storm water runoff, including discharges associated with
construction activities. In the event of an unauthorized discharge of wastes,
we may be liable for penalties and costs.
Oil Pollution Act. The Oil Pollution Act of 1990 ("OPA"), which amends and
augments oil spill provisions of CWA, imposes certain duties and liabilities
on "responsible parties" related to the prevention of oil spills and damages
resulting from such spills in United States waters and adjoining shorelines. A
"responsible party" includes the owner or operator of a facility or vessel,
that is a source of an oil discharge or poses the substantial threat of
discharge, or the lessee or permittee of the area in which a facility covered
by OPA is located. OPA assigns joint and several liability, without regard to
fault, to each responsible party for oil removal costs and a variety of public
and private damages. Few defenses exist to the liability imposed by OPA. In
the event of an oil discharge, or substantial threat of discharge, we may be
liable for costs and damages.
The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. Certain amendments to the OPA that were enacted in 1996 require owners
and operators of offshore facilities that have a worst case oil spill
potential of more than 1,000 barrels to demonstrate financial responsibility
in amounts ranging from $10 million in specified state waters and $35 million
in federal OCS waters, with higher amounts, up to $150 million based upon
worst case oil-spill discharge volume calculations. We believe that we
currently have established adequate proof of financial responsibility for our
offshore facilities.
California Coastal Act. The California Coastal Act regulates the
conservation and development of California's coastal resources. The California
Coastal Commission ("The Commission") works with local government to make
permit decisions for new development in certain coastal areas and reviews
local coastal programs, such as land use restrictions. The Commission also
works with the California State Office of Oil Spill Prevention and Response to
protect against and respond to coastal oil spills. The Commission has direct
regulatory authority over offshore oil and gas development within the State's
three mile jurisdiction and has authority, through the Federal Coastal Zone
Management Act, over federally permitted projects that affect the State's
coastal zone resources. We conduct activities that may be subject to the
California Coastal Act and the jurisdiction of the California Coastal
Commission.
12
Our management believes that we are 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 us.
Competition
We operate in the highly competitive areas of oil and gas exploration,
development and production. The availability of funds and information relating
to a property, the standards established by us for the minimum projected
return on investment and the availability of alternate fuel sources are
factors that affect our ability to compete in the marketplace. Competitors
include major integrated oil companies and a substantial number of independent
energy companies, many of which possess greater financial and other resources.
We compete to acquire producing properties, exploration leases, licenses,
concessions and marketing agreements.
Personnel
At December 31, 2001, we had 95 full time employees, at which time we
outsourced certain administrative and operational functions to third-party
service providers. In late 2001, we terminated our California field operations
and human resources outsource contracts and brought the professional and other
positions in-house. At March 16, 2002, we had approximately 377 full time
employees. (See Note 7 to the Notes to Consolidated Financial Statements).
ITEM 2. PROPERTIES
A description of our properties is included in Item 1, Business, and is
incorporated herein by reference.
ITEM 3. LEGAL PROCEEDINGS
See Item 7, Management's Discussion and Analysis of Financial Condition and
Results of Operations, which is incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
13
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Our common stock is traded on the New York Stock Exchange under the Symbol
NEV. On March 26, 2002, we had 17,102,417 shares of common stock outstanding.
There were approximately 994 stockholders of record and approximately 2,789
additional beneficial owners as of March 22, 2002. We have not paid dividends
on our common stock and do not anticipate paying cash dividends in the
immediate future. In addition, certain restrictions contained in our financing
arrangements restrict the payment of dividends. See Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Capital Resources and Liquidity and Note 12 to the Notes to Consolidated
Financial Statements. The high and low recorded prices of our common stock
during 2001 and 2000 are presented in the following table.
Market Price
-----------------
High Low
-------- --------
2001
First Quarter............................................ $19.3500 $15.8750
Second Quarter........................................... $21.5600 $15.2500
Third Quarter............................................ $18.5000 $13.0000
Fourth Quarter........................................... $16.0000 $11.1000
2000
First Quarter............................................ $26.0000 $15.5000
Second Quarter........................................... $22.0600 $16.8125
Third Quarter............................................ $20.2500 $14.3125
Fourth Quarter........................................... $21.0000 $14.5000
Treasury Stock Repurchases
On February 12, 2001, our Board of Directors authorized the open market
repurchase of an additional 1.0 million shares of common stock increasing the
total amount authorized to 5.6 million shares of which 2.0 million are
remaining. Repurchases may be made at times and at prices deemed appropriate
by management and consistent with the authorization of our Board. During the
first quarter of 2001, we repurchased 0.1 million shares at an average
purchase price of $16.32 per share, including commissions. There were no
shares repurchased during the second, third or fourth quarters of 2001. As of
December 31, 2001, we had repurchased a total of 3.6 million shares since
December 1997, at an average purchase price of $16.56 per share, including
commissions.
Shareholder Rights Plan
In March 1997, we adopted a Shareholder Rights Plan to protect our
shareholders from coercive or unfair takeover tactics. Under the Shareholder
Rights Plan, each outstanding share and each share of subsequently issued
common stock has attached to it one Right. Generally, in the event a person or
group ("Acquiring Person") acquires or announces an intention to acquire
beneficial ownership of 15% or more of the outstanding shares of common stock
without our prior consent, or we are acquired in a merger or other business
combination, or 50% or more of our assets or earning power is sold, each
holder of a Right will have the right to receive, upon exercise of the Right,
that number of shares of common stock of the acquiring company, which at the
time of such transaction will have a market price of two times the exercise
price of the Right. We may redeem the Right for $.01 at any time before a
person or group becomes an Acquiring Person without prior approval. The Rights
will expire on March 21, 2007, subject to earlier redemption by us.
On January 10, 2000, we amended the Shareholder Rights Plan to provide that
if we receive and consummate a transaction pursuant to a qualifying offer, the
provisions of the Shareholder Rights Plan are not triggered. In general, a
qualifying offer is an all cash, fully funded tender offer for all outstanding
common stock by a person who, at the commencement of the offer, beneficially
owns less than 5% of the outstanding common
14
stock. A qualifying offer must remain open for at least 120 days, must be
conditioned on the person commencing the qualifying offer acquiring at least
75% of the outstanding common stock and the per share consideration must
exceed the greater of: (1) 135% of the highest closing price of the common
stock during the one-year period prior to the commencement of the qualifying
offer or (2) 150% of the average closing price of the common stock during the
20 day period prior to the commencement of the qualifying offer.
Executive Compensation Plan
In 1997, we adopted a plan to encourage senior executives to personally
invest in our stock, and to regularly review executives' ownership versus
targeted ownership objectives. These incentives include a deferred
compensation plan (the "Plan") that gives key executives the ability to defer
all or a portion of their salaries and bonuses and invest in our common stock
or make other investments at the employee's discretion. Stock acquired will be
held in a benefit trust and will be restricted for a two-year period. The Plan
was amended in 2001 to remove the discount on investments in our common stock
and to provide additional investment alternatives. Target levels of ownership
are based on multiples of base salary and are administered by the Compensation
Committee of the Board of Directors. The Plan applies to certain highly
compensated employees and all executives at a level of Vice-President and
above.
15
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction with the
consolidated financial statements and supplementary information included in
Item 8, Financial Statements and Supplementary Data.
As of and for the Years ended December 31,
----------------------------------------------
2001 2000 1999 1998 1997
-------- -------- -------- -------- --------
(In thousands, except per share data)
Operating Results Data
Revenues
Oil and gas revenues......... $368,560 $331,655 $242,274 $242,675 $331,973
Other........................ 2,695 4,950 89,961 10,028 25,305
-------- -------- -------- -------- --------
Total revenues............. 371,255 336,605 332,235 252,703 357,278
Costs and expenses
Lease operating expense...... 191,877 156,476 130,549 139,934 138,641
Exploration.................. 22,058 9,774 14,017 16,562 11,082
General and administrative... 36,904 32,974 32,266 28,094 31,806
Depreciation, depletion and
amortization................ 76,154 67,370 80,652 85,036 102,158
Impairments.................. 103,490 -- -- 68,904 30,000
Interest expense............. 43,006 37,472 33,110 32,471 27,357
Dividends on TECONS.......... 6,613 6,613 6,613 6,613 6,613
Cumulative effect of a change
in accounting principle net
of income tax benefit........ -- 796 -- -- --
Extraordinary loss on early
extinguishment of debt....... -- -- -- -- 3,024
Net income (loss)(/1/)........ (79,171) 11,635 31,442 (94,272) (13,700)
Earnings (loss) per Common
share--Basic................. (4.73) 0.67 1.62 (4.77) (0.69)
Earnings (loss) per Common
share--Diluted............... (4.73) 0.64 1.61 (4.77) (0.69)
Financial Position Data
Total assets.................. $839,812 $848,024 $760,030 $817,685 804,286
Long-term debt, net of current
maturities................... 450,444 409,727 340,750 419,150 305,940
Company-Obligated Mandatorily
Redeemable Convertible
Preferred Securities of Nuevo
Financing I.................. 115,000 115,000 115,000 115,000 115,000
- --------
(/1/No)common stock dividends have been declared since our formation. See Note
10 to the Notes to Consolidated Financial Statements concerning
restrictions on the payment of common stock dividends.
16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
We began operations in 1990 as an independent oil and gas company and have
grown through a series of acquisitions of oil and gas properties and the
subsequent exploitation and development of these properties, and complemented
these efforts with divestitures of non-core assets and an exploration program.
Results of Operations
Our results of operations are significantly affected by fluctuations in oil
and gas prices. Success in acquiring oil and gas properties and our ability to
maintain or increase production through exploitation activities has also
significantly affected our operating results. The following table reflects our
production and average prices for oil and natural gas:
Year Ended December 31,
-------------------------
2001 2000 1999
------- ------- -------
Production
Oil (MBbls)
Domestic........................................ 14,345 15,413 15,685
Foreign......................................... 1,882 1,843 1,835
------- ------- -------
Total......................................... 16,227 17,256 17,520
======= ======= =======
Natural gas (MMcf)
Domestic........................................ 12,751 15,215 17,620
Natural gas liquids (MBbls)
Domestic........................................ 189 178 207
Average sales price
Oil ($/Bbl)
Domestic........................................ $ 19.06 $ 21.73 $ 13.59
Foreign......................................... 20.94 22.19 16.69
Total--excluding hedges......................... 19.27 21.88 13.82
Total--hedge effect............................. (3.13) (7.13) (2.61)
------- ------- -------
Total--net of hedge effect...................... $ 16.14 $ 14.75 $ 11.21
======= ======= =======
Natural gas ($/Mcf)
Domestic/Total.................................. $ 8.03 $ 4.78 $ 2.27
======= ======= =======
Average production cost per BOE
Domestic........................................ $ 10.67 $ 7.88 $ 6.07
Foreign......................................... 7.47 7.39 7.01
Total........................................... 10.35 7.84 6.15
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000
We had a net loss of $79.2 million for 2001, or ($4.73) per diluted share
as compared to net income of $11.6 million, or $0.64 per diluted share in
2000. In 2001, we had $131.7 million ($78.9 million after-tax) of non-
recurring items. The largest component of the non-recurring items was a $103.5
million Statement of Financial Accounting Standards (SFAS) No. 121 impairment
of the carrying value of our oil and gas properties. Other components of the
non-recurring charge included costs associated with the termination of all
outstanding derivative contracts with Enron Corp. and certain of its
affiliates ("Enron"), restructuring charges related to the termination of two
outsource contracts and the reorganization of our exploration and production
operations and the write-off of certain domestic projects and project costs.
Excluding these charges, the net loss for 2001 was $0.2 million, or ($0.01)
per diluted share.
17
The following table details our 2001 results of operations excluding the
non-recurring charges discussed above:
Year Ended December 31, 2001
--------------------------------------
Excluding
Non-Recurring Non-Recurring
Reported Items Items(/1/)
--------- ------------- -------------
(In thousands)
Revenues............................ $ 371,255 $ (2,068) $373,323
Costs and Expenses
Lease operating expenses.......... 191,877 1,666 190,211
Exploration costs................. 22,058 -- 22,058
General and administrative
expenses......................... 36,904 3,799 33,105
Depreciation, depletion and
amortization..................... 76,154 -- 76,154
Impairment of oil and gas
properties....................... 103,490 103,490 --
Restructuring charges............. 4,859 4,859 --
Loss on assets held for sale...... 3,494 3,494 --
Interest expense, net............. 43,006 263 42,743
Dividends on TECONS............... 6,613 -- 6,613
Other expense..................... 14,928 12,077 2,851
--------- --------- --------
503,383 129,648 373,735
--------- --------- --------
Loss Before Income Taxes............ (132,128) (131,716) (412)
Income Tax Benefit.................. 52,957 52,792 165
--------- --------- --------
Net Loss............................ $ (79,171) $ (78,924) $ (247)
========= ========= ========
- --------
(/1/The)above presentation should not be used as a substitute for amounts
reported under generally accepted accounting principles. It is presented
solely to improve the understanding of the impact of the charges.
Revenues
Oil and Gas Revenues. Oil and gas revenues increased 11% to $368.6 million
in 2001 from $331.7 million in 2000 principally due to higher commodity prices
and lower hedging losses during 2001, partially offset by lower production.
The realized oil price in 2001 was $16.14 per Bbl, an increase of $1.39 per
Bbl from 2000. Oil production averaged 44.5 MBbls per day, a decrease of 2.7
MBbls per day due to an eight-month curtailment of steaming operations in
California as well as production shut-ins for facility repairs in 2001. Our
hedging losses were $47.6 million in 2001 and $117.7 million in 2000. Natural
gas production averaged 34.9 MMcf per day in 2001, declining 16% from 41.6
MMcf per day in 2000. The decline was due to lower domestic production onshore
in the Gulf Coast and offshore California. The 2001 realized natural gas price
was $8.03 per Mcf, which increased 68% from $4.78 per Mcf in 2000.
Gain on Sale of Assets. Our net gain from the sales of assets for 2001 was
$0.9 million, primarily related to the gain from our sale of real estate in
Brea, California of $1.1 million. The net gain on sale of assets for 2000 was
$0.7 million primarily representing a $0.9 million gain on the sale of our
working interest in the Las Cienagas field in California.
Interest and Other Income. Interest and other income for 2001 of $1.8
million includes $1.2 million of interest income on the overnight investment
of excess cash and a gain on derivatives of $0.2 million. Interest and other
income for 2000 of $4.3 million includes $1.9 million in interest income
resulting from higher cash balances in 2000 plus $1.5 million for a partial
reimbursement of previously expensed funds, resulting from a negotiated
settlement of a legal claim, as well as several individually insignificant
items
18
Costs and Expenses Excluding Non-Recurring Items
Costs and Expenses. Lease operating expenses ("LOE") for 2001 totaled
$190.2 million, as compared to $156.5 million for 2000. The 22% increase in
LOE from 2000 to 2001 is primarily due to a 68% increase in gas prices in 2001
compared to 2000. We use gas as a feedstock to generate steam which is
injected into reservoirs to facilitate the production of heavy California oil.
Exploration costs, including geological and geophysical costs, dry hole costs
and delay rentals, were $22.1 million in 2001, an increase of $12.3 million
from 2000, primarily due to $11 million of dry hole costs associated with non-
commercial wells drilled onshore California. Depreciation, depletion and
amortization increased 13% in 2001 due to higher depletion rates which were
primarily driven by a lower reserve base. General and administrative expense
of $33.1 million in 2001 was comparable to 2000.
Interest Expense. Interest expense of $42.7 million in 2001 increased 14%
compared to interest expense of $37.5 million in 2000. The increase is
primarily due to the inclusion of a full year of interest for our 9 3/8%
Senior Subordinated Notes issued in September 2000, offset by a decrease in
the use of a line of credit and an increase of interest capitalized.
Dividends. Dividends on the TECONS were $6.6 million in 2001 and 2000. The
TECONS pay dividends at a rate of 5.75% and were issued in December 1996. (See
Note 11 to the Notes to Consolidated Financial Statements.)
Income Tax Benefit. We had an income tax benefit of $53.0 million in 2001
compared to an expense of $8.4 million in 2000. Our effective income tax rate
was 40.1% in 2001 and 40.3% in 2000.
Non-Recurring Items
Impairments. During 2001, we recorded an impairment totaling $103.5 million
on our Santa Clara, Huntington Beach, Pitas Point, Masseko and Point
Pedernales fields and certain other oil and gas properties. SFAS No. 121
requires an impairment loss be recognized when the carrying value of an asset
exceeds the sum of the undiscounted estimated future net cash flows. We
recognized an impairment loss equal to the difference between the carrying
amount and the fair value of the assets. The fair value of an oil and gas
property equals the present value of expected future net cash flows from
estimated proved reserves, utilizing a risk-adjusted rate of return. We had no
impairments in 2000. (See Note 3 to the Notes to the Consolidated Financial
Statements.)
Restructuring. We incurred $4.9 million of restructuring charges in 2001
related to the termination of two outsourcing contracts and the reorganization
of our exploration and production operations. These costs included termination
fees and severance. We had no such costs in 2000. (See Note 8 to the Notes to
the Consolidated Financial Statements.)
Loss on Assets Held for Sale. In 2001, we made the decision not to proceed
with our power plant project in Santa Barbara and Kern County California and
transferred our remaining equipment to assets held for sale and recorded a
$3.5 million loss representing the write down to estimated fair market value
less estimated costs to sell these assets of $0.8 million. (See Note 4 to the
Notes to the Consolidated Financial Statements.)
Other. We had other non-recurring income and expenses of $19.8 million in
2001 which were primarily related to the termination of hedging contracts with
Enron, the reversal of a royalty refund claim, insurance costs related to
business interruption and various consulting and legal costs. We had no such
costs in 2000.
19
Year Ended December 31, 2000 Compared to Year Ended December 31, 1999
Revenues
Oil and gas revenues for 2000 were 37% higher than 1999 oil and gas
revenues primarily due to a 32% increase in average realized oil prices and a
111% increase in average realized gas prices from 1999 to 2000. Partially
offsetting these increases in realized prices, our gas production decreased
14% from 1999 to 2000, and oil production decreased 2% from 1999 to 2000. The
production decreases were primarily a result of asset sales.
Gain on Sale of Assets. The net gain on sale of assets for 2000 was $0.7
million, primarily representing a $0.9 million gain on the sale of our Las
Cienegas field in California, partially offset by a $0.3 million net loss on
the sale of several individually insignificant non-core assets. The net gain
on sale of assets for 1999 was $85.3 million, which is comprised of an $80.2
million gain on the sale of our East Texas natural gas assets in January 1999,
a $5.4 million gain on the sale of our interest in 13 onshore fields and a gas
processing plant located in Ventura County, California, in December 1999, and
a $0.3 million net loss on the sale of other non-core properties.
Interest and Other Income. Interest and other income for the year ended
December 31, 2000, of $4.3 million includes $1.9 million in interest income
resulting from higher cash balances in 2000 plus $1.5 million for a partial
reimbursement of previously expensed funds, resulting from a negotiated
settlement of a legal claim (see Note 15 to the Notes to the Consolidated
Financial Statements). Interest and other income for the year ended December
31, 1999, of $4.7 million 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 we acquired domestic producing oil and
gas properties in the first half of 1999. The escrow account was liquidated in
June 1999, in connection with our 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.
Costs and Expenses
Costs and Expenses. LOE for 2000 totaled $156.5 million, as compared to
$130.5 million for 1999. The 20% increase in LOE from 1999 to 2000 is
primarily due to a $25.7 million increase in steam costs resulting from higher
natural gas prices. Exploration costs, including geological and geophysical
("G&G") costs, dry hole costs and delay rentals, were $9.8 million and $14.0
million for the years ended December 31, 2000 and 1999. Exploration costs for
the year ended 2000 included: $2.5 million of dry hole costs, $5.4 million of
G&G costs, $0.1 million of delay rentals and $1.8 million of other exploration
costs. Exploration costs for the year ended 1999 included: $8.1 million of dry
hole costs ($7.2 million of which relates to onshore California), $3.6 million
of G&G costs ($2.1 million of which relates to Ghana), $0.8 million of delay
rentals and $1.5 million of other exploration costs. Depreciation, depletion
and amortization decreased 16% in 2000 as compared to 1999. This decrease was
driven by a lower depletion rate, which primarily resulted from a significant
increase in reserve estimates attributable to higher commodity prices at year-
end 2000 versus year-end 1999. General and administrative expenses increased
only slightly in 2000 as compared to 1999.
Interest Expense. Interest expense of $37.5 million for year ended December
31, 2000, increased 13% as compared to interest expense in the same period in
1999. The increase is primarily attributable to an increase in outstanding
borrowings under our credit facility during the year plus higher interest
rates on those outstanding borrowings. On September 26, 2000, all borrowings
outstanding under the credit facility were paid off with net proceeds received
from our issuance of the 9 3/8% Notes (see Note 12 to the Notes to
Consolidated Financial Statements). The increase is also due to higher
interest rates as we exchanged our 8 7/8% Senior Subordinated Notes due 2008
for 9 1/2% Senior Subordinated Notes due 2008 in the third quarter of 1999.
Other Expense. Other expense of $5.1 million in 2000 includes: a $2.0
million settlement for a lawsuit (see Note 15 to the Notes to the Consolidated
Financial Statements), $1.7 million for scientific information technology
consulting, and $0.9 million in costs to evaluate potential business
transactions. Other expense of $8.9 million in
20
1999 includes: $3.1 million in third-party charges incurred in connection with
the July 1999 exchange offer (see Note 12 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, we discovered that a non-officer
employee had fraudulently authorized and diverted for personal use our
company's funds totaling $5.9 million, $4.3 million in 1998 and the remainder
in 1999, that were intended for international exploration.
Dividends. Dividends on the TECONS were $6.6 million in 2000 and 1999. The
TECONS pay dividends at a rate of 5.75% and were issued in December 1996.
Income Tax Expense. Income tax expense of $8.4 million was recognized in
2000, compared to a benefit of $5.4 million in 1999. Our effective income tax
rate was 40.3% and 20.5% in 2000 and 1999. At December 31, 1999, we 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.
Change in Accounting Principle.
In December 2000, the staff of the Securities and Exchange Commission
announced that commodity inventories should be carried at the lower of cost or
market rather than at market value. As a result, we changed our inventory
valuation method to the lower of cost or market in the fourth quarter of 2000,
retroactive to the beginning of the year. Accordingly, we recorded a non-cash,
cumulative effect of a change in accounting principle to earnings, effective
January 1, 2000, of $0.8 million (net of the related income tax benefit of
$0.5 million) to value product inventory at the lower of cost or market. (See
Note 2 to the Notes to the Consolidated Financial Statements.)
Capital Resources and Liquidity
We have grown and diversified our operations through a series of
disciplined, low-cost acquisitions of oil and gas properties and the
subsequent exploitation and development of these properties. We have
historically funded our operations and acquisitions with operating cash flows,
bank financing, private and public placements of debt and equity securities,
property divestitures and joint ventures with industry participants.
Net cash provided by operating activities was $101.1 million, $93.7 million
and $24.0 million in 2001, 2000 and 1999. We invested $145.4 million, $104.4
million and $125.9 million in oil and gas properties in 2001, 2000 and 1999.
Additionally, we spent $8.6 million, $3.4 million and $10.2 million on gas
plant and other facilities in 2001, 2000 and 1999. In January 2001, we
acquired a producing property in California for $28.5 million.
In June 1999, we acquired working interests in oil and gas properties
located onshore and offshore California for $61.4 million from Texaco
Inc.("Texaco"). To purchase these assets, we used funds from a $100.0 million
interest-bearing escrow account that was created with proceeds from our
January 1999 sale of our 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.
We believe our working capital, cash flow from operations and available
financing sources are sufficient to meet our obligations as they become due
and to finance our capital budget through 2002. Under our Credit Agreement
which provides for secured revolving credit, we have a $225 million borrowing
base with $102 million available at December 31, 2001 and had drawn $41.5
million under the agreement. In late December 2001 and early January 2002, we
entered into interest rate swaps totaling $200 million; $150 million on our 9
3/8% notes and $50 million on our 9 1/2% Notes. (See Item 7A, Qualitative and
Quantitative Disclosures About Market Risk).
21
Contractual Cash Obligations
The following table summarizes our contractual cash obligations by payment
due date:
Less than 1-3 4-5 After 5
Total 1 Year Years Years Years
-------- --------- -------- -------- --------
(In thousands)
Long-term debt............... $409,577 $ -- $ -- $ 2,367 $407,210
Operating leases............. 9,978 1,521 3,086 3,011 2,360
Capital commitments.......... 2,643 1,964 679 -- --
-------- -------- -------- -------- --------
Total contractual cash
obligations............... $422,198 $ 3,485 $ 3,765 $ 5,378 $409,570
======== ======== ======== ======== ========
Long-term Debt
The following table details our long-term debt at December 31:
2001
--------------
(In thousands)
9 3/8% Senior Subordinated Notes due 2010..................... $150,000
9 1/2% Senior Subordinated Notes due 2008..................... 257,210
9 1/2% Senior Subordinated Notes due 2006..................... 2,367
--------
Total long-term debt........................................ $409,577
========
9 3/8% Notes due 2010. In 2000, we issued $150.0 million of 9 3/8% Senior
Subordinated Notes due October 1, 2010. Interest accrues at 9 3/8% per annum
and is payable semi-annually in arrears on April 1 and October 1. The Notes
are redeemable, in whole or in part, at our option, on or after October 1,
2005, under certain conditions. We are not required to make mandatory
redemption or sinking fund payments with respect to these Notes. The Notes are
unsecured general obligations, and are subordinated in right of payment to all
existing and future senior indebtedness. In the event of a defined change in
control, we will be required to make an offer to repurchase all outstanding 9
3/8% Notes at 101% of the principal amount, plus accrued and unpaid interest
to the date of redemption.
9 1/2% Notes due 2008. In July 1999, we authorized a new issuance of $260.0
million of 9 1/2% Senior Subordinated Notes due June 1, 2008. In August 1999,
we exchanged $157.5 million of our 9 1/2% Notes due 2006 and $99.9 million of
our 8 7/8% Senior Subordinated Notes due 2008. In connection with the exchange
offers, we solicited consents to proposed amendments to the indentures under
which the exchanged notes were issued. Interest accrues at the rate of 9 1/2%
per annum and is payable semi-annually in arrears on June 1 and December 1.
These Notes are redeemable, in whole or in part, at our option, on or after
June 1, 2003, under certain conditions. We are not required to make mandatory
redemption or sinking fund payments on these Notes. The 9 1/2% Notes are
unsecured general obligations, and are subordinated in right of payment to all
of our existing and future senior indebtedness. In the event of a defined
change in control, we will be required to make an offer to repurchase all
outstanding Notes at 101% of the principal amount, plus accrued and unpaid
interest to the date of redemption.
9 1/2% Notes due 2006. In 1996, we issued $160.0 million of 9 1/2% Notes
and used the proceeds to pay for a portion of the purchase price of the Unocal
Properties. Interest accrues at the rate of 9 1/2% per annum and is payable
semi-annually in arrears on April 15 and October 15 and are redeemable, in
whole or in part, at our option, on or after April 15, 2001, under certain
conditions. These Notes have not been redeemed, in whole or in part, at
December 31, 2001. We are not required to make mandatory redemption or sinking
fund payments with respect to these Notes and they are unsecured general
obligations, and are subordinated in right of payment to all existing and
future senior indebtedness.
Operating Leases
We have operating leases in the normal course of business, which include
those for office space and operating facilities and office and operating
equipment, with varying terms from 2002 to 2009. At December 31, 2001, our
total commitments under operating leases were approximately $10.0 million.
22
Minimum annual rental commitments at December 31, 2001, were as follows:
Operating
Leases
--------------
(In thousands)
2002.......................................................... $1,521
2003.......................................................... 1,503
2004.......................................................... 1,583
2005.......................................................... 1,604
2006.......................................................... 1,407
Thereafter.................................................... 2,360
------
Total....................................................... $9,978
======
Capital Commitments
At December 31, 2001, we had capital commitments of $2.6 million primarily
relating to our international oil and gas exploration and development
activity. Our other planned capital projects are discretionary in nature, with
no substantial capital commitments made in advance of the actual expenditures.
Commercial Commitments
The following table summarizes our Commercial Commitments by date of
expiration. Each of these commitments is discussed in further detail below:
Amount of Commitment
Expiration Per Period
-------------------------------
Total Less
Amounts than 1-3 4-5 After
Committed 1 Year Years Years 5 Years
--------- ------- ------- ------- -------
(In thousands)
Bank credit facility.............. $41,500 $ -- $ -- $41,500 $ --
Letters of credit................. 250 250 -- -- --
------- ------- ------- ------- -------
Total commercial commitments.... $41,750 $ 250 $ -- $41,500 $ --
======= ======= ======= ======= =======
Lines of Credit
Bank Credit Facility. Our Third Amended and Restated Credit Agreement,
dated June 7, 2000, provides for secured revolving credit availability of up
to $410.0 million from a bank group led by Bank of America, N.A., Bank One,
N.A., and Bank of Montreal until its expiration on June 7, 2005.
The borrowing base is subject to a semi-annual borrowing base determination
within 60 days following March 1 and August 15 of each year and establishes
the maximum borrowings that may be outstanding under the credit facility. It
is determined by a 60% vote of the banks (two-thirds in the event of an
increase in the borrowing base), each of which bases its judgement on: (i) the
present value of our oil and gas reserves based on their own assumptions
regarding future prices, production, costs, risk factors and discount rates,
and (ii) projected cash flow coverage ratios calculated under varying
scenarios. If amounts outstanding under the credit facility exceed the
borrowing base, as redetermined from time to time, we would be required to
repay such excess over a defined period of time. We have a $225 million
borrowing base under our Credit Facility with $102 million available at
December 31, 2001 and had drawn $41.5 million under the agreement. Amounts
outstanding under the credit facility bear interest at a rate equal to the
London Interbank Offered Rate ("LIBOR") plus an amount which increases as the
Indebtedness to Capitalization (as defined under the Credit Agreement)
increases.
23
Letters of Credits
We had one letter of credit outstanding at December 31, 2001 in the amount
of $0.3 million, which expires in February 2002.
Contingencies and Other Matters
Legal Proceedings
On September 14, 2001, during an annual inspection, we discovered fractures
in the heat affected zone of certain flanges on our pipeline that connects the
Point Pedernales field with onshore processing facilities. We voluntarily
elected to shut-in production in the field while repairs were being made. The
daily net production from this field was approximately 5,000 barrels of crude
oil and 1.2 MMcf of natural gas, representing approximately 11% of our daily
production. We replaced the damaged flanges, as well as others which had not
shown signs of damage. The cost of repair is expected to be partially covered
by insurance. We may have exposure to costs that may not be recoverable from
insurance, including those associated with the repair of undamaged equipment.
Production was back on in January 2002.
On June 15, 2001, we experienced a failure of a carbon dioxide treatment
vessel at the Rincon Onshore Separation Facility ("ROSF") located in Ventura
County, California. There were no injuries associated with this event and the
cause of the failure is under investigation. Crude oil and natural gas
produced from three fields offshore California are transported onshore by
pipeline to the ROSF plant where crude oil and water are separated and
treated, and carbon dioxide is removed from the natural gas stream. The daily
net production associated with these fields is 3,000 barrels of crude oil and
2.4 MMcf of natural gas, representing approximately 6% of our daily
production. Crude oil production resumed in early July and full gas sales
resumed by mid August. The cost of repair, less a $50,000 deductible, is
expected to be covered by insurance. We may have exposure to costs that may
not be recoverable from insurance.
On September 22, 2000, we were named as a defendant in the lawsuit Thomas
Wachtell et al. versus Nuevo Energy Company in the Superior Court of Los
Angeles County, California. We successfully removed this lawsuit to the United
States District Court for the Central District of California. The plaintiffs,
who own certain interests in the Point Pedernales properties, have asserted
numerous causes of action including breach of contract, fraud and conspiracy
in connection with the plaintiff's allegation that:
. royalties have not been properly paid to them for production from the
Point Pedernales field;
. payments have not been made to them related to production from the
Pescado and Sacate fields, and;
. we have failed to recognize the plaintiff's interests in the Tranquillon
Ridge project.
The plaintiffs have not specified damages. We intend to vigorously contest
these claims.
On April 5, 2000, we filed a lawsuit against ExxonMobil Corporation in the
United States District Court for the Central District of California, Western
Division. The Company and ExxonMobil each own a 50% interest in the Sacate
Field, offshore Santa Barbara County, California. We have alleged that by
grossly inflating the fee that ExxonMobil insists we must pay to use an
existing ExxonMobil platform and production infrastructure, ExxonMobil failed
to submit a proposal for the development of the Sacate field consistent with
the Unit Operating Agreement. We, therefore believe that we have been denied a
reasonable opportunity to exercise our rights under the Unit Operating
Agreement. We have alleged that ExxonMobil's actions breach the Unit Operating
Agreement and the covenant of good faith and fair dealing. We are seeking
damages and a declaratory judgment as to the payment that must be made to
access ExxonMobil's platform and facilities.
We have been named as a defendant in certain other lawsuits incidental to
our business. Management does not believe that the outcome of such litigation
will have a material adverse impact on our operating results, financial
condition or liquidity above the amounts we have reserved to cover any
potential losses. However, these
24
actions and claims in the aggregate seek substantial damages against us and
are subject to the inherent uncertainties in any litigation. We are defending
ourselves vigorously in all such matters.
In March 1999, it was discovered that a non-officer employee had
fraudulently authorized and diverted, for personal use, Company funds of $5.9
million; $1.6 million in 1999 and the remainder in 1998, that were intended
for international exploration. The Board of Directors engaged a Certified
Fraud Examiner to conduct an in-depth review of the fraudulent transactions.
The investigation confirmed that only one employee was involved in the matter
and that all misappropriated funds were identified. We have reviewed and,
where appropriate, strengthened our internal control procedures. In August
2000, we recorded $1.5 million of other income for a partial reimbursement of
these previously expensed funds, resulting from the negotiated settlement of a
related legal claim.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects our Point Pedernales field with shore-
based processing facilities. The volume of the spill was estimated to be 163
Bbls of oil. Repairs were completed by the end of 1997 and production
recommenced in December 1997. The costs of the clean-up and the cost to repair
the pipeline either have been or are expected to be covered by our insurance,
less a deductible of $0.1 million. We incurred clean up and repair costs of
$0.3 million, $ 0.3 million and $0.5 million during 2001, 2000 and 1999. As of
December 31, 2001, we had received insurance reimbursements of $4.2 million,
with a remaining insurance receivable of $0.5 million. For amounts not covered
by insurance, including the $0.1 million deductible, we recorded lease
operating expenses of $1.1 million in 2001 and $0.4 million during 1999. No
such expenses were recorded in 2000. We also have exposure to costs that may
not be recoverable from insurance, including certain fines, penalties, and
damages and certain legal fees. Such costs are not quantifiable at this time,
but are not expected to be material to our operating results, financial
condition or liquidity.
Our international investments involve risks typically associated with
investments in emerging markets such as an uncertain political, economic,
legal and tax environment and expropriation and nationalization of assets. In
addition, if a dispute arises in our foreign operations, we may be subject to
the exclusive jurisdiction of foreign courts or may not be successful in
subjecting foreign persons to the jurisdiction of the United States. We
attempt to conduct our business and financial affairs so as to protect against
political and economic risks applicable to operations in the various countries
where we operate, but there can be no assurance that we will be successful in
so protecting ourselves. A portion of our investment in the Congo is insured
through political risk insurance provided by the Overseas Private Investment
Corporation ("OPIC"). The political risk insurance through OPIC covers up to
$25.0 million relating to expropriation and political violence, which is the
maximum coverage available through OPIC. We have no deductible for this
insurance.
In connection with our February 1995 acquisitions of two subsidiaries (each
a "Congo subsidiary") owning interests in the Yombo field offshore Congo, we
and a wholly-owned subsidiary of CMS NOMECO Oil & Gas Co. ("CMS") agreed with
the seller of the subsidiaries not to claim certain tax losses ("dual
consolidated losses") incurred by such subsidiaries prior to the acquisitions.
Under the tax law in the Congo, as it existed when this acquisition took
place, if an entity is acquired in its entirety and that entity has certain
tax attributes, for example tax loss carryforwards from operations in the
Republic of Congo, the subsequent owners of that entity can continue to
utilize those losses without restriction. Pursuant to the agreement, we and
CMS may be liable to the seller for the recapture of dual consolidated losses
(net operating losses of any domestic corporation that are subject to an
income tax of a foreign country without regard to the source of its income or
on a residence basis) utilized by the seller in years prior to the
acquisitions if certain triggering events occur, including:
. a disposition by either us or CMS of our respective Congo subsidiary,
. either Congo subsidiary's sale of its interest in the Yombo field,
. the acquisition of us or CMS by another consolidated group or
. the failure of CMS's Congo subsidiary or us to continue as a member of
its respective consolidated group.
25
A triggering event will not occur, however, if a subsequent purchaser
enters into certain agreements specified in the consolidated return
regulations intended to ensure that such dual consolidated losses will not be
claimed. The only time limit associated with the occurrence of a triggering
event relates to the utilization of a dual consolidated loss in a foreign
jurisdiction. A dual consolidated loss that is utilized to offset income in a
foreign jurisdiction is only subject to recapture for 15 years following the
year in which the dual consolidated loss was incurred for U.S. income tax
purposes. We and CMS have agreed among ourselves that the party responsible
for the triggering event shall indemnify the other for any liability to the
seller as a result of such triggering event. Our potential direct liability
could be as much as $38.5 million if a triggering event with respect to us
occurs. Additionally, we believe that CMS's liability (for which we would be
jointly liable with an indemnification right against CMS) could be as much as
$56.2 million. We do not expect a triggering event to occur with respect to us
or CMS and do not believe the agreement will have a material adverse effect
upon us.
During 1997, a new government was established in the Congo. Although the
political situation in the Congo has not to date had a material adverse effect
on our operations in the Congo, no assurances can be made that continued
political unrest in West Africa will not have a material adverse effect on us
or our operations in the Congo in the future.
In 1996, the previous Congo government requested that the convention
governing the Marine 1 Exploitation Permit be converted to a Production
Sharing Agreement ("PSA"). Preliminary discussions were held with the
government in early 1997. We are under no obligation to convert to a PSA, and
our existing convention is valid and protected by law. Our position is that
any conversion to a PSA would have no detrimental impact to us, otherwise, we
will not agree to any such conversion. The new government established in the
Congo in 1997 has recently begun discussions with us and our 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 from Unocal in 1996 of the properties
located in California, we are obligated to make a contingent payment for the
years 1998 through 2004 if oil prices exceed thresholds set forth in the
agreement with Unocal. Any contingent payment will be accounted for as a
purchase price adjustment to oil and gas properties. The contingent payment
will equal 50% of the difference between the actual average annual price
received on a field-by-field basis (capped by a maximum price) and a minimum
price, less ad valorem and production taxes, multiplied by the actual number
of barrels of oil sold that are produced from the properties acquired from
Unocal during the respective year. The minimum price of $17.75 per Bbl under
the agreement (determined based on the near month delivery of WTI crude oil on
the NYMEX) is escalated at 3% per year and the maximum price of $21.75 per Bbl
on the NYMEX is escalated at 3% per year. Minimum and maximum prices are
reduced to reflect the field level price by subtracting a fixed differential
established for each field. The reduction was established at approximately the
differential between actual sales prices and NYMEX prices in effect in 1995
($4.34 per Bbl weighted average for all the properties acquired from Unocal).
We accumulate credits to offset the contingent payment when prices are $.50
per Bbl or more below the minimum price. We paid $10.8 million to Unocal under
this agreement on March 15, 2002.
In connection with the acquisition of the Congo properties in 1995, we
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, we are
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 was $15.78 per Bbl for 2001, $15.19 per Bbl
for 2000 and $14.79 per Bbl for 1999. The benchmark price increases each year,
based on the increase in the Consumer Price Index. For 2001, the effect of
this agreement was that we only owned upside above $15.78 per Bbl on
approximately 56% of our Congo production. We were obligated to pay the seller
$3.4 million in 2001 and $5.4 million in 2000 under this price sharing
agreement. This obligation was accounted for as a reduction in oil revenues.
No payment was due in 1999.
26
We acquired a 12% working interest in the Point Pedernales oil field from
Unocal in 1994 and the remainder of our 80.3 % working interest from Torch in
1996. We are entitled to all revenue proceeds up to $9.00 per Bbl, with the
excess revenue over $9.00 per Bbl, if any, shared with the original owners
from whom Torch acquired its interest. We own amounts below $9.00 per Bbl with
the other working interest owners based on their respective ownership
interests. For 2001, the effect of this agreement is that we were entitled to
receive the pricing upside above $9.00 per Bbl on approximately 73% of the
gross Point Pedernales production. As of December 31, 2001, we had $0.2
million accrued as our obligation under this agreement. As of December 31,
2000, we had $0.6 million accrued as our obligation under this agreement. As
of December 31, 1999, we had $5.1 million accrued as our obligation under this
agreement.
Critical Accounting Policies
Oil and Gas Properties
We use the successful efforts method to account for our 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, 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. Exploration costs, including G&G expenses, exploratory dry
holes and delay rentals, are charged to expense as incurred.
Costs of successful wells, development dry holes and proved leases are
capitalized and depleted on a unit-of-production basis over the remaining
proved reserves. Capitalized drilling costs are depleted on a unit-of-
production basis over the remaining proved developed reserves. Total estimated
costs of $113.1 million (net of salvage value) for future dismantlement,
abandonment and site remediation are included when calculating depreciation
and depletion using the unit-of-production method. At December 31, 2001, we
had recorded $74.2 million as a component of accumulated depreciation,
depletion and amortization.
In accordance with SFAS No. 121, Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed of, we review our long-
lived assets to be held and used, including proved oil and gas properties
accounted for using the successful efforts method of accounting, on a
depletable unit basis whenever events or circumstances indicate that the
carrying value of those assets may not be recoverable. SFAS No. 121 requires
an impairment loss to be recognized when the carrying amount of an asset
exceeds the sum of the undiscounted estimated future net cash flows and we
recognize an impairment loss equal to the difference between the carrying
value and the fair value of the asset. Fair value is estimated to be the
present value of expected future net cash flows from proved reserves,
utilizing a risk-adjusted rate of return. Due to low commodity prices in the
fourth quarter of 2001, we estimated the expected undiscounted future net cash
flows of our oil and gas properties and compared such undiscounted future net
cash flows to the carrying amount of the oil and gas properties to determine
if the carrying amount was recoverable. For some of our oil and gas
properties, the carrying amount of the properties exceeded the estimated
undiscounted future net cash flows; thus, we adjusted the carrying amount of
the respective oil and gas properties to their fair value as determined by
discounting their estimated future net cash flows. The factors used to
determine fair value included, but were not limited to, estimates of proved
reserves, future commodity prices, timing of future production, future capital
expenditures and a discount rate commensurate with our internal rate of return
on our oil and gas properties. As a result, we recognized a non-cash pre-tax
charge of $103.5 million ($62.0 million after tax) related to the impairment
of oil and gas properties in 2001.
27
Recognition of Crude Oil and Natural Gas Revenue
Crude oil and natural gas revenues are recognized when title passes to the
purchaser. We use the entitlement method for recording sales of crude oil and
natural gas from producing wells. Under the entitlement method, revenue is
recorded based on our net revenue interest in production. Deliveries of crude
oil and natural gas in excess of our net revenue interests are recorded as
liabilities and under-deliveries are recorded as assets. Production imbalances
are recorded at the lower of the sales price in effect at the time of
production or the current market value. Substantially all such amounts are
anticipated to be settled with production in future periods. We did not have a
material imbalance position in terms of units or value at December 31, 2001 or
2000. Approximately $ 58.1 million, $46.0 million and $20.4 million is
included as oil and gas revenues and operating expenses related to gas
production used in our steam injection projects in 2001, 2000 and 1999.
Derivative Financial Instruments
We adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities, effective January 1, 2001 which requires all derivative
instruments to be carried on the balance sheet at fair value. In accordance
with the transition provisions of SFAS No. 133, we recorded a cumulative
effect transition adjustment of $(16.0) million, net of related tax benefit of
$10.8 million, in other comprehensive income to recognize the fair value of
our derivatives designated as cash-flow hedging instruments at the date of
adoption.
Beginning on January 1, 2001, all of our derivative instruments are
recognized on the balance sheet at their fair value. We currently use swaps
and options to hedge our exposure to material changes in the future price of
crude oil and interest rate swaps to hedge the fair value of our long-term
debt.
On the date the derivative contract is entered into, we designate the
derivative as either a hedge of fair value of a recognized asset or liability
("fair value" hedge), as a hedge of the variability of cash flows to be
received ("cash-flow" hedge), or as a foreign currency cash flow hedge.
Changes in the fair value of a derivative that is highly effective as, and
that is designated and qualifies as, a fair-value hedge, along with the loss
or gain on the hedged asset or liability that is attributable to the hedged
risk (including losses or gains on firm commitments), are recorded in current
period earnings. Changes in the fair value of a cash-flow hedge are recorded
in other comprehensive income (loss) until earnings are affected by the
variability of cash flows. At December 31, 2001, we had both cash-flow hedges
and fair value hedges.
We formally document all relationships between hedging instruments and
hedged items, as well as our risk-management objective and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated as cash-flow hedges to forecasted
transactions. We also formally assess, both at the hedge's inception and on an
ongoing basis, whether the derivatives that are used in hedging transactions
are highly effective in offsetting changes in cash flows of hedged
transactions. When it is determined that a derivative is not highly effective
as a hedge or that it has ceased to be a highly effective hedge, we
discontinue hedge accounting prospectively.
When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value, and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately. In all other situations in which hedge accounting is
discontinued, the derivative will be carried at its fair value on the balance
sheet, with changes in its fair value recognized in earnings prospectively.
At December 31, 2001, we had recorded $11.5 million, net of related taxes
of $7.8 million, of cumulative hedging gains in other comprehensive income,
which will be reclassified to earnings within the next 12 months. The amounts
ultimately reclassified to earnings will vary due to changes in the fair value
of the open derivative contracts prior to settlement.
As a result of hedging transactions, oil and gas revenues were reduced by
$47.6 million, $117.7 million and $44.9 million in 2001, 2000 and 1999. The
portion of our hedging transactions that were ineffective totaled $0.4 million
in 2001 and was recorded in interest and other income.
28
Price Risk Management Activities
We use price risk management activities to manage non-trading market risks.
We use derivative financial instruments such as swaps and put options to hedge
the impact of market price risk exposure on our crude oil and natural gas
production and to mitigate our exposure to interest rate risk.
New Accounting Pronouncements
Accounting for Asset Retirement Obligations. In August 2001, the Financial
Accounting Standards Board ("FASB") issued SFAS No. 143, Accounting for Asset
Retirement Obligations. This Statement requires companies to record a
liability relating to the retirement and removal of assets used in their
business. The liability is discounted to its present value, and the related
asset value is increased by the amount of the resulting liability. Over the
life of the asset, the liability will be accreted to its future value and
eventually extinguished when the asset is taken out of service. The provisions
of this Statement are effective for fiscal years beginning after June 15,
2002. We are currently evaluating the effects of this pronouncement.
Accounting for the Impairment or Disposal of Long-Lived Assets. In October
2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal
of Long-Lived Assets. This Statement requires that long-lived assets that are
to be disposed of by sale be measured at the lower of historical net book
value or fair value less cost to sell. The standard also expands the scope of
discontinued operations to include all components of an entity with operations
that can be distinguished from the rest of the entity and that will be
eliminated from the ongoing operations of the entity in a disposal
transaction. We adopted the provisions of this Statement effective January 1,
2002 and this Statement does not have a material impact on our financial
condition or results of operations.
29
RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference forward looking
statements within the meaning of Section 27A of the Securities Act of 1933, as
amended, Section 21E of the Securities Exchange Act of 1934 and the Private
Securities Litigation Reform Act of 1995. All statements other than statements
of historical facts included in this document, including without limitation,
statements in Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations regarding our financial position,
estimated quantities and net present values of reserves, business strategy,
plans and objectives of our management for future operations and covenant
compliance, are forward looking statements. We can give no assurances that the
assumptions upon which such forward-looking statements are based will prove to
be correct. Important factors that could cause actual results to differ
materially from our expectations are included throughout this document. The
Cautionary Statements expressly qualify all subsequent written and oral
forward-looking statements attributable to us or persons acting on our behalf.
Volatility of Oil and Gas Prices
Prices for oil and gas are subject to large fluctuations in response to
relatively minor changes in the supply of and demand for oil and gas, market
uncertainty and a variety of additional factors beyond our control. These
factors include weather conditions in the United States, the condition of the
United States economy, the actions of the Organization of Petroleum Exporting
Countries ("OPEC"), governmental regulation, political stability in the Middle
East and elsewhere, the foreign supply of oil and gas, the price of foreign
oil imports and the availability of alternate fuel sources. Any substantial
and extended decline in the price of oil or gas would have an adverse effect
on the carrying value of our proved reserves, borrowing capacity, our ability
to obtain additional capital, and our revenues, profitability and cash flows
from operations.
Volatile oil and gas prices make it difficult to estimate the value of
producing properties for acquisition and divestiture and often cause
disruption in the market for oil and gas producing properties, as buyers and
sellers have difficulty agreeing on such value. Price volatility also makes it
difficult to budget for and project the return on acquisitions and development
and exploitation projects.
Pricing of Heavy Oil Production
A portion of our production is California heavy oil. The market price for
California heavy oil differs substantially from the established market indices
for oil and gas, principally due to the higher transportation and refining
costs associated with heavy oil. As a result, the price received for heavy oil
is generally lower than the price for medium and light oil, and the production
costs associated with heavy oil are relatively higher than for lighter grades.
The margin (sales price minus production costs) on heavy oil sales is
generally less than that of lighter oil, and the effect of material price
decreases will more adversely affect the profitability of heavy oil production
compared with lighter grades of oil. (See "Hedging" below for discussion of
15-year crude oil contract).
Reserve Replacement Risks
Our future performance depends upon the ability to find, develop and
acquire additional oil and gas reserves that are economically recoverable.
Without successful exploration, exploitation or acquisition activities, our
reserves and revenues will decline. No assurances can be given that we will be
able to find and develop or acquire additional reserves at an acceptable cost.
The successful acquisition and development of oil and gas properties
requires an assessment of recoverable reserves, future oil and gas prices and
operating costs, potential environmental and other liabilities and other
factors. Such assessments are necessarily inexact and their accuracy
inherently uncertain. In addition, no assurances can be given that our
exploitation and development activities will result in any increase in
reserves.
30
Our operations may be curtailed, delayed or canceled as a result of lack of
adequate capital and other factors, such as title problems, weather,
compliance with governmental regulations or price controls, mechanical
difficulties or shortages or delays in the delivery of equipment. In addition,
the costs of exploitation and development may materially exceed initial
estimates.
Substantial Capital Requirements
We make, and will continue to make, substantial capital expenditures for
the exploitation, exploration, acquisition and production of oil and gas
reserves. Historically, these expenditures were financed with cash generated
by operations, proceeds from bank borrowings and the proceeds of debt and
equity issuances. We believe that we will have sufficient cash provided by
operating activities and borrowings under our bank credit facility to fund
planned capital expenditures. If revenues or our borrowing base decreases as a
result of lower oil and gas prices, operating difficulties or declines in
reserves, we may have limited ability to expend the capital necessary to
undertake or complete future drilling programs. There can be no assurance that
additional debt or equity financing or cash generated by operations will be
available to meet these requirements.
Uncertainty of Estimates of Reserves and Future Net Cash Flows
Estimates of economically recoverable oil and gas reserves and of future
net cash flows are based upon a number of variable factors and assumptions,
all of which are to some degree speculative and may vary considerably from
actual results. Therefore, actual production, revenues, taxes, and development
and operating expenditures may not occur as estimated. Future results of
operations will depend upon our ability to develop, produce and sell our oil
and gas reserves. The reserve data included herein are estimates only and are
subject to many uncertainties. Actual quantities of oil and gas may differ
considerably from the amounts set forth herein. In addition, different reserve
engineers may make different estimates of reserve quantities and cash flows
based upon the same available data.
Operating Risks
Our operations are subject to risks inherent in the oil and gas industry,
such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or
well fluids, fires, pollution, earthquakes and other environmental risks.
These risks could result in substantial losses due to injury and loss of life,
severe damage to and destruction of property and equipment, pollution and
other environmental damage and suspension of operations. Our offshore
operations are subject to a variety of operating risks peculiar to the marine
environment, such as hurricanes or other adverse weather conditions, to more
extensive governmental regulation, including regulations that may, in certain
circumstances, impose strict liability for pollution damage, and to
interruption or termination of operations by governmental authorities based on
environmental or other considerations. Our operations could result in
liability for personal injuries, property damage, oil spills, discharge of
hazardous materials, remediation and clean-up costs and other environmental
damages. We could be liable for environmental damages caused by previous
property owners. As a result, substantial liabilities to third parties or
governmental entities may be incurred, the payment of which could have a
material adverse effect on our financial condition and results of operations.
We maintain insurance coverage for our operations, including limited coverage
for sudden environmental damages and for existing contamination, but do not
believe that insurance coverage for environmental damages that occur over time
or insurance coverage for the full potential liability that could be caused by
sudden environmental damages is available at a reasonable cost, and we may be
subject to liability or may lose substantial portions of our properties in the
event of certain environmental damages.
California Natural Gas and Electricity Markets
The price of natural gas and the threat of electrical disruptions are
factors that create volatility in our California oil and gas operations.
Because of the recent developments in these commodities, we have made
significant changes in our natural gas disposition and electricity production
in California. Regarding natural gas, we have historically had a net long
position in California--producing more natural gas than consumed in thermal
31
crude production. Moreover, as gas prices escalated in late 2000, we began to
exploit this gas position by diverting gas consumed in less economic cyclic
steaming operations to gas sales. In January and February 2001, we sold an
average of 19 MMcf per day, or 44% of our total daily gas production, which
resulted in an increase in gas sales of 33%. As natural gas prices moderated
later in 2001, we resumed the use of previously diverted natural gas in our
steam operations.
In California, we generate a total of 22.5 Megawatts ("MW") of power at
various sites. In 2000, two turbines came on-line at our Brea Olinda field
using gas previously flared. Three turbines in Kern County produce 12 MW of
power and cogenerate 15% of our total steam needs in thermal operation. By
self-generating power consumption in Kern County, we have reduced our exposure
to rising electricity prices. With the exception of the Point Pedernales
field, for which we have contracted for firm electric power service, our
facilities receive power under interruptible service contracts. Considering
the fact that California has experienced shortages of electricity and some of
our facilities receive interruptible service, we could experience periodic
power interruptions. In addition, the State of California could change
existing rules or impose new rules or regulations with respect to power that
could impact our operating costs.
Foreign Investments
Our foreign investments involve risks typically associated with investments
in emerging markets such as uncertain political, economic, legal and tax
environments and expropriation and nationalization of assets. We attempt to
conduct our business and financial affairs so as to protect against political
and economic risks applicable to operations in the various countries where we
operate, but there can be no assurance that we will be successful in
protecting against such risks.
Our international assets and operations are subject to various political,
economic and other uncertainties, including, among other things, the risks of
war, expropriation, nationalization, renegotiation or nullification of
existing contracts, taxation policies, foreign exchange restrictions, changing
political conditions, international monetary fluctuations, currency controls
and foreign governmental regulations that favor or require the awarding of
drilling contracts to local contractors or require foreign contractors to
employ citizens of, or purchase supplies from, a particular jurisdiction. In
addition, if a dispute arises with foreign operations, we may be subject to
the exclusive jurisdiction of foreign courts or may not be successful in
subjecting foreign persons, especially foreign oil ministries and national oil
companies, to the jurisdiction of the United States.
Our private ownership of oil and gas reserves under oil and gas leases in
the United States differs distinctly from our ownership of foreign oil and gas
properties. In the foreign countries in which we do business, the state
generally retains ownership of the minerals and consequently retains control
of (and in many cases, participates in) the exploration and production of
hydrocarbon reserves. Accordingly, operations outside the United States, and
estimates of reserves attributable to properties located outside the United
States, may be materially affected by host governments through royalty
payments, export taxes and regulations, surcharges, value added taxes,
production bonuses and other charges.
Hedging
We reduce our exposure to price volatility by hedging our production
through swaps, options and other commodity derivative instruments. In a
typical swap transaction, we will have the right to receive from the
counterparty to the hedge the excess of the fixed price specified in the hedge
contract and a floating price based on a market index, multiplied by the
quantity hedged. If the floating price exceeds the fixed price, we are
required to pay the counterparty the difference. We would be required to pay
the counterparty the difference between such prices regardless of whether our
production was sufficient to cover the quantities specified in the hedge. 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
32
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, we entered into a 15-year contract, effective
January 1, 2000, to sell substantially all of our current and future
California crude oil production to Tosco Corporation. The contract provides
pricing based on a fixed percentage of the NYMEX crude oil price for each type
of crude oil that we produce in California. Therefore, the actual price
received as a percentage of NYMEX will vary with our production mix. Based on
our current production mix, the price we receive for our California oil
production is expected to average approximately 72% of WTI. While the contract
does not reduce our exposure to price volatility, it does effectively
eliminate the basis differential risk between the NYMEX price and the field
price of our California oil production, thereby facilitating the ability to
effectively hedge our realized prices.
As a result of hedging transactions, oil and gas revenues were reduced by
$47.6 million, $117.7 million and $44.9 million in 2001, 2000 and 1999.
Insurance
As a result of the September 11, 2001 terrorist attack, the ability to
secure certain insurance coverages at prices that we consider reasonable may
be impacted and other coverages or endorsements may not be made available. No
assurance can be given that we will be able to duplicate our current insurance
package when our policies come up for renewal.
Risk Management Policy
Our risk management policy is based on the view that oil prices revert to a
mean price over the long term. To the extent that future markets over a
forward 18 month period are significantly higher than long term norms, we will
hedge production volumes up to certain maximums set forth in our oil hedging
policy approved by our Board in March 2002. Maximum hedged volumes increase as
the price of oil increases. Variations from this policy require Board
approval. The risk management policy states that hedging activity that is
speculative or otherwise unrelated to our normal business activities is
considered inappropriate. We recognize the risks inherent in price management.
In order to minimize such risk, we have instituted a set of controls
addressing approval authority, trading limits and other control procedures.
All hedging activity is the responsibility of our Senior Vice President of
Planning and Asset Management. In addition, Internal Audit, which
independently reports to the Audit Committee, reviews our price management
activity.
Competition/Markets for Production
We operate in the highly competitive areas of oil and gas exploration,
exploitation, development and production. The availability of funds and
information relating to a property, the minimum projected return on
investment, the availability of alternate fuel sources and the intermediate
transportation of oil and gas are factors which affect our ability to compete
in the marketplace. Our competitors include major integrated oil companies and
a substantial number of independent energy companies, many of which possess
greater financial and other resources than we do.
Our heavy crude oil production in California requires special processing
treatment available only from a limited number of refineries. Substantial
damage to such a refinery or closures or reductions in capacity due to
financial or other factors could adversely affect the market for our heavy
crude oil production.
33
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk, including adverse changes in commodity
prices and interest rates.
Commodity Price Risk. We produce and sell crude oil, natural gas and
natural gas liquids therefore our operating results can be significantly
affected by fluctuations in commodity prices caused by changing market forces.
We reduce our exposure to price volatility by hedging our production through
swaps, put options and other commodity derivative instruments. In a typical
swap transaction, if the floating price is less than the fixed price, we will
have the right to receive from the counterparty to the hedge the excess of the
fixed price specified in the hedge contract and a floating price based on a
market index, multiplied by the quantity hedged. If the floating price exceeds
the fixed price, we are required to pay the counterparty the difference. In a
typical put option contract, we purchase the right to receive from the
counterparty the difference, if any, between a fixed price specified in the
option less a floating market price. If the floating price is above the fixed
price, we are not entitled to a payment. Quantities covered by these hedges
are based on West Texas Intermediate ("WTI") barrels. Our production is
expected to average 73% of WTI, therefore, each WTI barrel effectively hedges
1.37 barrels of our production. We use hedge accounting for these instruments,
and settlements of gains or losses on these contracts are reported as a
component of oil and gas revenues and operating cash flows in the period
realized. These agreements expose us to counterparty credit risk to the extent
that the counterparty is unable to meet their settlement commitments to us.
At December 31, 2001, we had entered into the following cash flow hedges:
Average
WTI Barrels Strike
Per Day Price
----------- -------
Swaps
First quarter 2002..................................... 12,500 $25.91
Second quarter 2002.................................... 2,000 23.50
Third quarter 2002..................................... 6,800 23.20
Fourth quarter 2002.................................... 5,000 23.90
Put Options
Second quarter 2002.................................... 14,000 $22.00
Third quarter 2002..................................... 9,000 22.00
Fourth quarter 2002.................................... 9,000 22.00
At December 31, 2001, the fair market value of these hedge positions is
$19.6 million, net of the cost of the options of $3.8 million. A 10% increase
in the underlying commodity prices would reduce this gain by $7.7 million.
Subsequent to December 31, 2001, we entered into the following swap
agreements:
Average
WTI Barrels Strike
Per Day Price
----------- -------
Second quarter 2002.................................... 9,000 $24.31
Third quarter 2002..................................... 4,200 24.41
Fourth quarter 2002.................................... 6,000 24.01
First quarter 2003..................................... 6,000 23.36
Second quarter 2003.................................... 4,000 23.03
Third quarter 2003..................................... 4,000 23.07
Interest Rate Risk. We may enter into financial instruments such as
interest rate swaps to manage the impact of changes in interest rates. Our
exposure to changes in interest rates primarily results from our long-term
debt with both fixed and floating interest rates.
34
In late December 2001, we entered into two interest rate swap agreements
with notional amounts totaling $150 million to hedge the fair value of our 9
1/2% Notes due 2008 and our 9 3/8% Notes due 2010. These swaps are designated
as fair value hedges and are reflected as a reduction of long-term debt of
$0.6 million as of December 31, 2001,with a correlating increase in long-term
liabilities. Under the terms of the agreements for the 9 3/8% Notes, the
counterparty pays us a weighted average fixed annual rate of 9 3/8% on total
notional amounts of $100 million, and we pay the counterparty a variable
annual rate equal to the six-month LIBOR rate plus a weighted average rate of
3.49%. Under the terms of the agreement for the 9 1/2% Notes, the counterparty
pays us a weighted average fixed annual rate of 9 1/2% on total notional
amounts of $50 million, and we pay the counterparty a variable annual rate
equal to the six-month LIBOR rate plus a weighted average rate of 3.92%.
Subsequent to December 31, 2001, we entered into an interest rate swap
agreement with a notional amount totaling $50 million to hedge the fair value
of our 9 3/8% Notes. Under the terms of this agreement, the counterparty pays
us a weighted average fixed annual rate of 9 3/8% on the notional amount of
$50 million, and we pay the counterparty a variable annual rate equal to the
three-month LIBOR rate plus a weighted average rate of 3.49%.
The following table presents principal amounts and the related average
interest rates by year of maturity for our debt obligations at December 31,
2001:
Fair
Value
2002 2003 2004 2005 Thereafter Total Liability
---- ---- ---- ------- ---------- -------- ---------
(In thousands, except percentages)
Long-term debt:
Variable rate.......... $-- $-- $-- $41,500 $ -- $ 41,500 $ 41,500
Average interest rate.. -- -- -- 3.71% -- 3.71%
Fixed rate............. $-- $-- $-- $ -- $409,577 $409,577 $394,512
Average interest rate.. -- -- -- -- 9.41% 9.41%
35
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
Page
----
Report of Independent Public Accountants--2001............................. 37
Independent Auditors' Report--2000 and 1999................................ 38
Financial Statements:
Consolidated Statements of Income for the Years Ended
December 31, 2001, 2000 and 1999.......................................... 39
Consolidated Balance Sheets as of
December 31, 2001 and 2000................................................ 40
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2000 and 1999.......................................... 41
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 2001, 2000 and 1999.......................................... 42
Consolidated Statements of Comprehensive Income and
Changes in Accumulated Other Comprehensive Income
for the Years Ended December 31, 2001, 2000 and 1999...................... 43
Notes to the Consolidated Financial Statements............................. 44
Schedule II--Valuation and Qualifying Accounts............................. 73
36
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of
Nuevo Energy Company:
We have audited the accompanying consolidated balance sheet of Nuevo Energy
Company (a Delaware corporation) and subsidiaries as of December 31, 2001, and
the related consolidated statements of income, cash flows, stockholders'
equity and comprehensive income and changes in accumulated other comprehensive
income for the year then ended. 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
audit.
We conducted our audit in accordance with auditing standards generally
accepted in the United States. 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 audit provides 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, 2001, and the results of
their operations and their cash flows for the year then ended in conformity
with accounting principles generally accepted in the United States.
As discussed in Note 2 to the Consolidated Financial Statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments.
Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The information included in Schedule II
is presented for purposes of complying with the Securities and Exchange
Commission's rules and is not a required part of the basic financial
statements. This information has been subjected to the auditing procedures
applied in our audit of the basic financial statements and, in our opinion,
amounts pertaining to the year ended December 31, 2001 are fairly stated in
all material respects in relation to the basic financial statements taken as a
whole.
ARTHUR ANDERSEN LLP
Houston, Texas
February 8, 2002
37
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Nuevo Energy Company:
We have audited the accompanying consolidated balance sheet of Nuevo Energy
Company and subsidiaries as of December 31, 2000, and the related consolidated
statements of income, stockholders' equity, cash flows and comprehensive
income and changes in accumulated other comprehensive income for each of the
years in the two-year period ended December 31, 2000. These consolidated
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these consolidated financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Nuevo
Energy Company and subsidiaries as of December 31, 2000, and the results of
their operations and their cash flows for each of the years in the two-year
period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2000, the Company changed its method of accounting for its
processed fuel oil and natural gas liquids inventories.
KPMG LLP
Houston, Texas
February 8, 2001
38
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(In thousands, except per share data)
Year Ended December 31,
-----------------------------
2001 2000 1999
--------- -------- --------
Revenues
Oil and gas revenues.......................... $ 368,560 $331,655 $242,274
Gain on sale of assets, net................... 882 657 85,294
Interest and other income..................... 1,813 4,293 4,667
--------- -------- --------
371,255 336,605 332,235
--------- -------- --------
Costs and Expenses
Lease operating expenses...................... 191,877 156,476 130,549
Exploration costs............................. 22,058 9,774 14,017
General and administrative expenses........... 36,904 32,974 32,266
Depreciation, depletion and amortization...... 76,154 67,370 80,652
Impairment of oil and gas properties.......... 103,490 -- --
Restructuring charges......................... 4,859 -- --
Loss on assets held for sale.................. 3,494 -- --
Interest expense, net......................... 43,006 37,472 33,110
Dividends on TECONS........................... 6,613 6,613 6,613
Other expense................................. 14,928 5,103 8,945
--------- -------- --------
503,383 315,782 306,152
--------- -------- --------
Income (loss) before income taxes and cumulative
effect......................................... (132,128) 20,823 26,083
Income tax (expense) benefit.................... 52,957 (8,392) 5,359
--------- -------- --------
Income (loss) before cumulative effect.......... (79,171) 12,431 31,442
Cumulative effect of a change in accounting
principle, net of income tax benefit of $537... -- (796) --
--------- -------- --------
Net income (loss)............................... $ (79,171) $ 11,635 $ 31,442
========= ======== ========
Basic earnings (loss) per common share
Income (loss) before cumulative effect........ $ (4.73) $ 0.71 $ 1.62
Cumulative effect of a change in accounting
principle, net of income tax benefit......... -- (0.04) --
--------- -------- --------
Net income (loss)............................. $ (4.73) $ 0.67 $ 1.62
========= ======== ========
Weighted average Common shares outstanding--
Basic.......................................... 16,735 17,447 19,353
========= ======== ========
Diluted earnings (loss) per common share
Income (loss) before cumulative effect........ $ (4.73) $ 0.68 $ 1.61
Cumulative effect of a change in accounting
principle, net of income tax benefit......... -- (0.04) --
--------- -------- --------
Net income (loss)............................. $ (4.73) $ 0.64 $ 1.61
========= ======== ========
Weighted average Common shares outstanding--
Diluted........................................ 16,735 17,941 19,507
========= ======== ========
See accompanying notes.
39
NUEVO ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share amounts)
December 31,
----------------------
2001 2000
---------- ----------
ASSETS
Current assets
Cash and cash equivalents............................ $ 7,110 $ 39,447
Accounts receivable, net of allowance of $1,280 in
2001 and $766 in 2000............................... 48,304 71,777
Inventory............................................ 3,839 4,546
Assets held for sale................................. 819 --
Assets from price risk management activities......... 19,610 --
Prepaid expenses and other........................... 2,050 2,726
---------- ----------
Total current assets............................... 81,732 118,496
---------- ----------
Property and equipment, at cost
Land................................................. 55,859 53,246
Oil and gas properties (successful efforts method)... 1,014,429 1,102,233
Gas plant facilities................................. 8,723 12,020
Other facilities..................................... 10,365 12,907
---------- ----------
1,089,376 1,180,406
Accumulated depreciation, depletion and
amortization........................................ (424,837) (496,444)
---------- ----------
Total property and equipment, net.................. 664,539 683,962
---------- ----------
Deferred tax assets, net............................... 70,013 16,282
Other assets........................................... 23,528 29,284
---------- ----------
Total assets....................................... $ 839,812 $ 848,024
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable..................................... $ 35,771 $ 25,895
Accrued interest..................................... 5,635 5,757
Accrued drilling costs............................... 15,081 12,467
Accrued lease operating costs........................ 23,244 30,037
Deferred income tax.................................. 7,783 --
Other accrued liabilities............................ 11,610 17,668
---------- ----------
Total current liabilities.......................... 99,124 91,824
---------- ----------
Long-term debt (Note 12)............................... 450,444 409,727
Other long-term liabilities............................ 15,337 8,356
Company-Obligated Mandatorily Redeemable Convertible
Preferred Securities of Nuevo Financing I............. 115,000 115,000
Commitments and contingencies (Note 15)
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,
2001 and 2000....................................... -- --
Common stock, $0.01 par value, 50,000,000 shares
authorized, 20,905,796 and 20,620,296 shares issued
and 16,880,080 and 16,632,318 shares outstanding at
December 31, 2001 and 2000.......................... 209 206
Additional paid-in capital........................... 366,792 361,643
Treasury stock, at cost, 3,902,721 and 3,813,074
shares, at December 31, 2001 and 2000............... (75,855) (74,703)
Stock held by benefit trust, 122,995 and 174,904
shares, at December 31, 2001 and 2000............... (2,919) (3,646)
Deferred stock compensation.......................... (902) (602)
Accumulated other comprehensive income............... 11,534 --
Accumulated deficit.................................. (138,952) (59,781)
---------- ----------
Total stockholders' equity......................... 159,907 223,117
---------- ----------
Total liabilities and stockholders' equity....... $ 839,812 $ 848,024
========== ==========
See accompanying notes.
40
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
-------------------------------
2001 2000 1999
--------- --------- ---------
Cash flows from operating activities
Net income (loss)............................ $ (79,171) $ 11,635 $ 31,442
Adjustments to reconcile net income (loss) to
net cash provided by operating activities
Cumulative effect of a change in accounting
principle, net of income taxes............. -- 796 --
Depreciation, depletion and amortization.... 76,154 67,370 80,652
Dry hole costs.............................. 14,138 2,503 8,051
Amortization of debt financing costs........ 2,399 1,983 1,696
Impairment of oil and gas properties........ 103,490 -- --
Gain on sale of assets, net................. (882) (657) (85,294)
Loss on assets held for sale................ 3,494 -- --
Deferred income taxes....................... (52,957) 8,763 (6,559)
Debt modification costs..................... -- -- 3,064
Other....................................... 6,912 (31) 1,030
--------- --------- ---------
73,577 92,362 34,082
Working capital changes, net of non-cash
transactions
Accounts receivable......................... 23,043 (26,266) (20,461)
Accounts payable............................ 9,876 5,403 (4,527)
Accrued liabilities......................... (7,880) 25,490 17,901
Other....................................... 2,468 (3,287) (2,971)
--------- --------- ---------
Net cash provided by operating
activities............................... 101,084 93,702 24,024
--------- --------- ---------
Cash flows from investing activities
Additions to oil and gas properties.......... (145,418) (104,420) (125,919)
Acquisitions of oil and gas properties....... (28,456) -- --
Proceeds from sales of properties............ 6,145 3,083 234,312
Additions to gas plant and other facilities.. (8,554) (3,388) (10,247)
--------- --------- ---------
Net cash provided by (used in) investing
activities............................... (176,283) (104,725) 98,146
--------- --------- ---------
Cash flows from financing activities
Proceeds from borrowings..................... 143,450 197,100 142,590
Debt issuance and modification costs......... (97) (5,186) (8,053)
Payments of long-term debt................... (102,100) (128,873) (223,392)
Proceeds from exercise of stock options...... 3,694 2,701 1,690
Purchase of treasury shares.................. (2,085) (25,560) (32,120)
--------- --------- ---------
Net cash provided by (used in) financing
activities............................... 42,862 40,182 (119,285)
--------- --------- ---------
Increase (decrease) in cash and cash
equivalents.................................. (32,337) 29,159 2,885
Cash and cash equivalents
Beginning of year............................ 39,447 10,288 7,403
--------- --------- ---------
End of year.................................. $ 7,110 $ 39,447 $ 10,288
========= ========= =========
See accompanying notes.
41
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(In thousands)
Accumulated
Common Stock Additional Other Total
-------------- Paid-In Treasury Stock Held by Comprehensive Deferred Accumulated Stockholders'
Shares Amount Capital Stock Benefit Trust Income Compensation Deficit Equity
------ ------ ---------- -------- ------------- ------------- ------------ ----------- -------------
January 1,
1999........... 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
====== ==== ======== ======== ======= ========== ===== ========= ========
Exercise of
stock options
and related tax
benefit........ 183 2 3,200 -- -- -- -- -- 3,202
Stock acquired
by benefit
trust.......... -- -- -- 462 (462) -- -- -- --
Purchase of
Treasury
shares......... (1,482) -- -- (25,560) -- -- -- -- (25,560)
Deferred stock
compensation... -- -- 588 -- -- -- (386) -- 202
Net income...... -- -- -- -- -- -- -- 11,635 11,635
------ ---- -------- -------- ------- ---------- ----- --------- --------
December 31,
2000........... 16,632 206 361,643 (74,703) (3,646) (602) (59,781) 223,117
====== ==== ======== ======== ======= ========== ===== ========= ========
Exercise of
stock options
and related tax
benefit........ 287 3 4,463 -- -- -- -- -- 4,466
Stock acquired
by benefit
trust.......... -- -- -- 933 (933) -- -- -- --
Purchase of
Treasury
shares......... (128) -- -- (2,085) -- -- -- -- (2,085)
Deferred stock
compensation... -- -- 686 -- -- -- (300) -- 386
Withdrawal from
benefit trust
(Note 10)...... 89 -- -- -- 1,660 -- -- -- 1,660
Other
comprehensive
income......... -- -- -- -- -- 11,534 -- -- 11,534
Net loss........ -- -- -- -- -- -- -- (79,171) (79,171)
------ ---- -------- -------- ------- ---------- ----- --------- --------
December 31,
2001........... 16,880 $209 $366,792 $(75,855) $(2,919) $11,534 $(902) $(138,952) $159,907
====== ==== ======== ======== ======= ========== ===== ========= ========
See accompanying notes.
42
NUEVO ENERGY COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(In thousands)
Year Ended December 31,
-------------------------
2001 2000 1999
-------- ------- -------
Comprehensive Income
Net income (loss).................................... $(79,171) $11,635 $31,442
Unrealized gains (losses) from cash flow hedging
activity:
Cumulative effect transition adjustment
(net of tax benefit of $10,784)................... (15,976) -- --
Reclassification of initial cumulative effect
transition adjustment at original value (net of
taxes of $14,120)................................. 20,917 -- --
Additional reclassification adjustments for changes
in initial value to settlement date ( net of taxes
of $5,082)........................................ 7,529 -- --
Changes in fair value of derivative instruments
during the period (net of tax benefit of $632).... (936) -- --
-------- ------- -------
Other comprehensive income........................ 11,534 -- --
-------- ------- -------
Comprehensive income................................. $(67,637) $11,635 $31,442
======== ======= =======
Accumulated Other Comprehensive Income
Beginning balances as of December 31, 2000, 1999 and
1998................................................ $ -- $ -- $ --
Unrealized gains (losses) from cash flow hedging
activity:
Cumulative effect transition adjustment, net of tax
benefit........................................... (15,976) -- --
Reclassification of initial cumulative effect
transition adjustment at original value, net of
taxes............................................. 20,917 -- --
Additional reclassification adjustments for changes
in initial value to settlement date, net of
taxes............................................. 7,529 -- --
Changes in fair value of derivative instruments
during the period, net of tax benefit............. (936) -- --
-------- ------- -------
Balance as of December 31,............................ $ 11,534 $ -- $ --
======== ======= =======
See accompanying notes.
43
NUEVO ENERGY COMPANY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. Organization
Nuevo Energy Company ("Nuevo") was formed as a Delaware corporation on
March 2, 1990, to acquire the businesses of certain public and private
partnerships (collectively "Predecessor Partnerships"). On July 9, 1990, the
plan of consolidation ("Plan of Consolidation") was approved by limited
partners owning a majority of units of limited partner interests in the
partnerships whereby the net assets of the Predecessor Partnerships, which
were subject to the Plan of Consolidation, were exchanged for Common Stock of
Nuevo ("Common Stock"). All references to the "Company" include Nuevo and its
majority and wholly-owned subsidiaries, unless otherwise indicated or the
context indicates otherwise.
We are engaged in the exploration for, and the acquisition, exploitation,
development and production of crude oil and natural gas. Our principal oil and
gas properties are located domestically onshore and offshore California and
the onshore Gulf Coast region, and internationally offshore the Republic of
Congo, West Africa.
2. Summary of Significant Accounting Policies
Principles of Consolidation
Our consolidated financial statements include the accounts of Nuevo and our
majority and wholly-owned subsidiaries. All significant intercompany accounts
and transactions have been eliminated in consolidation.
Oil and Gas Properties
We use the successful efforts method to account for our investments in oil
and gas properties. Under 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, 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. Exploration costs, including geological and geophysical
expenses, exploratory dry holes and delay rentals, are charged to expense as
incurred.
Costs of successful wells, development dry holes and proved leases are
capitalized and depleted on a unit-of-production basis over the remaining
proved reserves. Capitalized drilling costs are depleted on a unit-of-
production basis over the remaining proved developed reserves. Total estimated
costs of $113.1 million (net of salvage value) for future dismantlement,
abandonment and site remediation are included when calculating depreciation
and depletion using the unit-of-production method. At December 31, 2001, we
had recorded $74.2 million as a component of accumulated depreciation,
depletion and amortization related to this future obligation.
In accordance with Statement of Financial Accounting Standards ("SFAS") No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of, we review our long-lived assets to be held and used,
including proved oil and gas properties accounted for using the successful
efforts method of accounting, on a depletable unit basis whenever events or
circumstances indicate that the carrying value of those assets may not be
recoverable. SFAS No. 121 requires an impairment loss to be recognized when
the carrying amount of an asset exceeds the sum of the undiscounted estimated
future net cash flows and we recognize an impairment loss equal to the
difference between the carrying value and the fair value of the asset. Fair
value is estimated to be the present value of expected future net cash flows
from proved reserves, utilizing a risk-adjusted
44
rate of return. Also, in accordance with SFAS No. 121, when we classify an
asset as held for sale, if the carrying amount of the asset is less than their
fair market value less our estimated costs to sell the asset, the difference
is recognized as a loss in the period that we classify the asset as held for
sale.
During 2001, we recorded an impairment totaling $103.5 million on our Santa
Clara, Huntington Beach, Pitas Point, Masseko and Point Pedernales fields and
certain other oil and gas properties. We recorded no impairments in 2000 or
1999. (See Note 3.)
During 2001 and 1999, interest costs associated with non-producing leases
and exploration and development projects were capitalized only for the period
that activities were in progress to bring these projects to their intended
use. The capitalization rates were based on our weighted average cost of funds
used to finance expenditures. We capitalized $2.5 million and $0.3 million of
interest costs in 2001 and 1999. There were no interest costs capitalized in
2000.
Any reference to oil and gas reserve information in the Notes to the
Consolidated Financial Statements is unaudited.
Derivative Financial Instruments
We adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities, effective January 1, 2001. This statement requires all derivative
instruments to be carried on the balance sheet at fair value. In accordance
with the transition provisions of SFAS No. 133, we recorded a cumulative
effect transition adjustment of $(16.0) million, net of related tax benefit of
$10.8 million, in other comprehensive income to recognize the fair value of
our derivatives designated as cash-flow hedging instruments at the date of
adoption.
Beginning on January 1, 2001, all of our derivative instruments are
recognized on the balance sheet at their fair value. We currently use swaps
and put options to hedge our exposure to material changes in the future price
of crude oil and interest rate swaps to hedge the fair value of our long-term
debt.
On the date the derivative contract is entered into, we designate the
derivative as either a hedge of the fair value of a recognized asset,
liability or firm commitment ("fair value" hedge), as a hedge of the
variability of cash flows to be received ("cash-flow" hedge), or as a foreign
currency cash flow hedge. Changes in the fair value of a derivative that is
highly effective as, and that is designated and qualifies as, a fair-value
hedge, along with the change in fair value of the hedged asset or liability
that is attributable to the hedged risk (including losses or gains on firm
commitments), are recorded in current period earnings. Changes in the fair
value of a cash-flow hedge are recorded in other comprehensive income (loss)
until earnings are affected by the variability of cash flows. At December 31,
2001, we had both cash-flow hedges and fair value hedges. (See Note 16.)
We formally document all relationships between hedging instruments and
hedged items, as well as its risk-management objective and strategy for
undertaking various hedge transactions. This process includes linking all
derivatives that are designated as cash-flow hedges to forecasted
transactions. We also formally assess, both at the hedge's inception and on an
ongoing basis, whether the derivatives that are used in hedging transactions
are highly effective in offsetting changes in cash flows of hedged
transactions. When it is determined that a derivative is not highly effective
as a hedge or that it has ceased to be a highly effective hedge, we
discontinue hedge accounting prospectively.
When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value, and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately. In all other situations in which hedge accounting is
discontinued, the derivative will be carried at its fair value on the balance
sheet, with changes in its fair value recognized in earnings prospectively.
45
At December 31, 2001, we had recorded $11.5 million, net of related taxes
of $7.8 million, of cumulative hedging gains in other comprehensive income,
which will be reclassified to earnings within the next 12 months. The amounts
ultimately reclassified to earnings will vary due to changes in the fair value
of the open derivative contracts prior to settlement.
As a result of hedging transactions, oil and gas revenues were reduced by
$47.6 million, $117.7 million and $44.9 million in 2001, 2000 and 1999. The
portion of our hedging transactions that were ineffective totaled $0.4 million
in 2001 and was recorded in interest and other income.
Price Risk Management Activities
We use price risk management activities to manage non-trading market risks.
We use derivative financial instruments such as swaps and put options to hedge
the impact market price risk exposures on our crude oil and natural gas
production.
Comprehensive Income
Comprehensive income includes net income and all changes in other
comprehensive income including changes in the fair value of derivatives
designated as cash-flow hedges.
Environmental Liabilities
Environmental expenditures that relate to current or future revenues are
expensed or capitalized as appropriate. Expenditures that relate to an
existing condition caused by past operations, and do not contribute to current
or future revenue generation, are expensed. Liabilities are recorded when
environmental assessments and/or clean-ups are probable, and the costs can be
reasonably estimated. Generally, the timing of these accruals coincides with
our commitment to a formal plan of action. As of December 31, 2001, we had
accrued approximately $5.1 million for future environmental expenditures.
Inventory
Our inventory is valued at the lower of cost or market. We had crude oil
inventory in Congo of $0.8 million and $3.2 million at December 31, 2001 and
2000. Our materials and supplies inventory totaled $3.0 million and $1.3
million at December 31, 2001 and 2000.
Gas Plant and Other Facilities
Gas plant and other facilities include the costs to acquire certain gas
plant and other facilities and to secure rights-of-way. Capitalized costs
associated with gas plant and other facilities are amortized primarily over
the estimated useful lives of the various components of the facilities
utilizing the straight-line method. The estimated useful lives of such assets
range from three to thirty years. We review these assets for impairment
whenever events or changes in circumstances indicate that their carrying
amounts may not be recoverable.
Recognition of Crude Oil and Natural Gas Revenue
Crude oil and natural gas revenue is recognized when title passes to the
purchaser. We use the entitlement method for recording sales of crude oil and
natural gas from producing wells. Under the entitlement method, revenue is
recorded based on our net revenue interest in production. Deliveries of crude
oil and natural gas in excess of our net revenue interests are recorded as
liabilities and under-deliveries are recorded as assets. Production imbalances
are recorded at the lower of the sales price in effect at the time of
production or the current market value. Substantially all such amounts are
anticipated to be settled with production in future periods. We did not have a
material imbalance position in terms of units or value at December 31, 2001 or
2000. Approximately $ 58.1 million, $46.0 million and $20.4 million in 2001,
2000 and 1999 is included as oil and gas revenues and operating expenses
related to gas production used in our steam injection projects.
46
Stock-Based Compensation
We account for stock options under Accounting Principles Board Opinion
(APB) No. 25, Accounting for Stock Issued to Employees. No compensation
expense is recognized for such options. As allowed by SFAS No. 123, Accounting
for Stock-Based Compensation, we have continued to apply APB Opinion No. 25
for purposes of determining net income and to present the pro forma disclosure
required by SFAS No. 123.
Income Taxes
Deferred income taxes are accounted for under the asset and liability
method of accounting for income taxes. Under this method, deferred income
taxes are recognized for the tax consequences of temporary differences by
applying enacted statutory tax rates applicable to future years to differences
between the financial statement carrying amounts and the tax basis of existing
assets and liabilities. The effect on deferred taxes of a change in tax rates
is recognized in income in the period the change occurs.
Statements of Cash Flows
For cash flow presentation purposes, we consider all highly liquid money
market instruments with an original maturity of three months or less to be
cash equivalents. Interest paid in cash, net of amounts capitalized, for 2001,
2000 and 1999 was $38.3 million, $32.1 million and $33.5 million. Net amounts
paid (refunded) in cash for income taxes for 2001, 2000 and 1999 were $0.4
million, $(0.5) million and $2.3 million.
Change in Accounting Principle
Prior to December 31, 2000, we recorded inventory relating to quantities of
processed fuel oil and natural gas liquids in storage at current market
pricing. Also, fuel oil in inventory was stated at year end market prices less
transportation costs, and we recognized changes in the market value of
inventory from one period to the next as oil revenues. In December 2000, the
staff of the Securities and Exchange Commission announced that commodity
inventories should be carried at the lower of cost or market rather than at
market value. As a result, we changed our inventory valuation method to the
lower of cost or market in the fourth quarter of 2000, retroactive to the
beginning of the year and recorded a non-cash, cumulative effect of a change
in accounting principle to earnings, effective January 1, 2000, of $0.8
million, net of related income tax benefit of $0.5 million, to value product
inventory at the lower of cost or market. Quarterly results for 2000 were
restated to reflect this change in accounting.
Had we valued our product inventory at the lower of cost or market prior to
2000, net income would have been $30.6 million for the year ended December 31,
1999.
Use of Estimates
In order to prepare these financial statements in conformity with
accounting principles generally accepted in the United States, our management
has made a number of estimates and assumptions relating to the reporting of
assets and liabilities and the disclosure of contingent assets and
liabilities, as well as reserve information, which affects the depletion
calculation. Actual results could differ from those estimates.
Functional Currency
Our functional currency for all operations is the U.S. dollar.
New Accounting Pronouncements
Accounting for Asset Retirement Obligations. In August 2001, the Financial
Accounting Standards Board ("FASB") issued SFAS No. 143, Accounting for Asset
Retirement Obligations. This Statement requires companies to record a
liability relating to the retirement and removal of assets used in their
business. The liability is discounted to its present value, and the related
asset value is increased by the amount of the resulting liability.
47
Over the life of the asset, the liability will be accreted to its future value
and eventually extinguished when the asset is taken out of service. The
provisions of this Statement are effective for fiscal years beginning after
June 15, 2002. We are currently evaluating the effects of this pronouncement.
Accounting for the Impairment or Disposal of Long-Lived Assets. In October
2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal
of Long-Lived Assets. This Statement requires that long-lived assets that are
to be disposed of by sale be measured at the lower of book value or fair value
less cost to sell. The standard also expanded the scope of discontinued
operations to include all components of an entity with operations that can be
distinguished from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. We adopted the
provisions of this statement effective January 1, 2002 and do not expect that
it will have a material impact on our financial condition or results of
operations.
Reclassifications
Certain reclassifications of prior period amounts have been made to conform
to the current presentation.
3. Impairments
In accordance with SFAS No. 121, we review oil and gas properties for
impairment whenever events and circumstances indicate a decline in the
recoverability of their carrying value. If the expected undiscounted future
net cash flows of our oil and gas properties are lower than the carrying
amount of the oil and gas properties, the carrying amount is reduced to the
fair market value. For some of our oil and gas properties, due to persistently
low commodity prices, the carrying amount of the properties exceeded the
estimated undiscounted future net cash flows; thus, we adjusted the carrying
amount of the respective oil and gas properties to their fair value as
determined by discounting their estimated future net cash flows. The factors
used to determine fair value included, but were not limited to, estimates of
proved reserves, future commodity prices, timing of future production, future
capital expenditures and a discount rate commensurate with our internal rate
of return on our oil and gas properties. As a result, we recognized a non-cash
pre-tax charge of $103.5 million ($62.0 million after tax) related to the
impairment of oil and gas properties in the fourth quarter of 2001. There were
no impairments in 2000 or 1999.
4. Assets Held for Sale
In 2001, we made the decision not to pursue our power plant project in Kern
County, California due to the inability to secure the proper permits required.
We transferred our remaining equipment to assets held for sale and recognized
a $3.5 million loss in connection with writing down the equipment to their
estimated fair value less our costs to sell the assets of $0.8 million.
5. Acquisitions
In July 2001, we entered into a definitive agreement with Coho Anaguid,
Inc., Anadarko Tunisia Anaguid Company, and Pioneer Natural Resources Anaguid
Ltd., to acquire a portion of Coho's interest in the Anaguid Permit, a 1.1
million-acre permit located onshore southern Tunisia in the Ghadames Basin.
Our 10.42% working interest increased to 22.5%, subject to approval by the
Tunisian government. The Anaguid Permit, operated by Anadarko, is on trend
with the prolific Hassi Berkine and El Borma fields located to the west in
Algeria and Tunisia. Under the current work commitment, a well is expected to
be drilled in the Anaguid Permit during 2002.
In January 2001, we acquired approximately 2,900 acres of producing
properties previously held by Naftex ARM, LLC, in Kern County, California for
approximately $28.5 million. The newly acquired acreage is southeast of our
interest in the Cymric field, of which more than half is natural gas. In
addition, the acreage provides significant development potential.
In June 1999, we 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 us to 100%. We used funds
from a $100.0
48
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 our sale of East Texas natural
gas assets (see discussion in Note 6). Following this acquisition, the $41.0
million remaining in the escrow account, including $2.4 million of interest
income, was used to repay a portion of outstanding bank debt in early July
1999. The acquisition included interests in Cymric, East Coalinga, Dos
Cuadras, Buena Vista Hills and other fields we operate.
6. Divestitures
In January 2002, we withdrew our request for formal government approval of
the Convention and Joint Venture resulting in a relinquishment of our interest
in the Alyane Permit located offshore Tunisia in the Gulf of Gabes.
As of June 17, 2001, we relinquished our 1.9 million-acre Accra-Keta Permit
offshore the Republic of Ghana. The Permit was relinquished prior to the
commencement of the second phase of the work program. We were the operator of
this Permit and held a 50% working interest. An impairment of $1.0 million was
recorded during the second and third quarters of 2001 in connection with this
relinquishment.
In May 2000, we sold our working interest in the Las Cienegas field in
California for approximately $4.6 million. We reclassified these assets to
assets held for sale during the third quarter of 1999, at which time we
discontinued depletion and depreciation. No impairment charge was recorded
upon reclassification to assets held for sale. In connection with this sale,
we unwound hedges of 2,800 BOPD for the period from May 2000 through December
2000 and recorded an adjusted net gain on sale of approximately $0.9 million.
We also sold certain non-core assets during 2000, recognizing a net loss of
approximately $0.3 million.
On December 31, 1999, we completed the sale of our 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. We 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. Approximately $4.5 million of the proceeds 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 returned. As of December 31, 2001, the balance in the escrow account
remained at $4.5 million. The remainder of the proceeds from the sale were
used to repay a portion of our outstanding bank debt. We recorded a gain of
$5.3 million on the sale of these properties.
On January 6, 1999, we completed the sale of our East Texas natural gas
assets to an affiliate of Samson Resources Company for approximately $191.0
million. An escrow account of $100.0 million was funded with a portion of the
proceeds as discussed in Note 5. The remainder of the proceeds were used to
repay outstanding senior bank debt. We 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 our deferred tax asset. A $5.2 million gain on
settled hedge transactions was realized in connection with the closing of this
sale in 1999.
7. Outsourcing Services
Torch Energy Advisors Incorporated ("Torch"), through its affiliates is an
outside service provider primarily in the business of providing management and
advisory services relating to oil and gas assets.
Effective March 16, 2002, we will have the following outsourcing contracts
in force:
. oil and gas administration: we pay a monthly base fee which is adjusted
upward or downward to reflect the current number and type of properties
for which services are provided
. crude oil marketing: we pay a base charge and a variable charge based on
the volume of crude oil sold or marketed
49
Since 1999 Torch has provided the following services: oil and gas
administration (accounting, information technology and land administration),
human resources, corporate administration (legal, graphics, support, and
corporate insurance), crude oil marketing, natural gas marketing, land leasing
and field operations.
We have a Master Services Agreement with Torch, which contains the overall
terms and conditions governing each individual service agreement. The crude
oil marketing contract has one year remaining on its term while the oil and
gas administration agreement runs through 2003, with a possible one-year
extension. In late 2001, we terminated the California field operations and
human resources contracts and did not renew the gas marketing contract. The
termination required ninety days notice and is effective March 15, 2002. We
have reduced both the staffing requirements and cost structure under the Torch
agreements and brought certain professional and other positions in-house.
Under the Master Services Agreement, we paid outsourcing fees to Torch in
the amount of $8.4 million, $13.7 million and $14.1 million in 2001, 2000 and
1999. Torch operated certain oil and gas interests that we own. Since 1999 we
were charged, on the same basis as other third parties, for all customary
expenses and cost reimbursements associated with these activities. Fees
charged for field operations for the years ended December 31, 2001, 2000 and
1999, were $22.3 million, $21.8 million and $25.1 million. Upon the effective
date of the termination of these outsourcing agreements, we assume direct
responsibility for the California field operations.
A subsidiary of Torch marketed oil, natural gas and natural gas liquids
from certain of our oil and gas properties and gas plants. In 2001, 2000 and
1999, the marketing fees were $1.9 million, $1.8 million and $1.2 million.
Beginning in 2002, our natural gas is being marketed by a new provider, Coral
Energy.
8. Restructuring Charges
Termination of Outsourcing Agreements.
We terminated two outsourcing agreements with the objective of exercising
greater control over certain operating functions and lowering our costs. The
terminated agreements were the California field operations and human resources
effective March 15, 2002. We have retained a majority of the field employees
currently working on our California properties while the human resources
function was brought in-house. (See Note 7.)
Reorganization of Exploration and Production Operations.
We have reorganized our exploration and production operations in an effort
to reflect a smaller, more focused exploitation program and eliminated our
California exploration program. In connection with this reorganization,
approximately 20 technical positions were eliminated.
The following table details the amounts related to our restructuring:
2001 Liability at
Restructuring Payments December 31,
Charges in 2001 2001
------------- -------- ------------
(In thousands)
Severance and benefits................. $2,178 $ 503 $1,675
Contract termination................... 2,681 -- 2,681
------ ------ ------
$4,859 $ 503 $4,356
====== ====== ======
We expect that the balance of the restructuring liability will be paid
during the first half of 2002.
50
9. Accounts Receivable
Our accounts receivable consisted of the following at December 31:
2001 2000
------- -------
(In thousands)
Oil and gas sales........................................... $32,220 $61,018
Joint interest billings..................................... 9,348 7,754
Other....................................................... 6,736 3,005
------- -------
$48,304 $71,777
======= =======
10. Stockholders' Equity
Common and Preferred Stock
Our Certificate of Incorporation authorizes the issuance of up to 50
million shares of Common Stock and 10 million shares of Preferred Stock, the
terms, preferences, rights and restrictions of which are established by our
Board of Directors. All shares of Common Stock have equal voting rights of one
vote per share on all matters to be voted upon by stockholders. Cumulative
voting for the election of directors is not permitted. Certain restrictions
contained in our loan agreements limit the amount of dividends that may be
declared. Under the terms of the most restrictive covenant in our indenture
for the 9 1/2% Senior Subordinated Notes due 2008 described in Note 12, we and
our restricted subsidiaries had $17.7 million available for the payment of
dividends and share repurchases at December 31, 2001. We have not paid
dividends on our Common Stock and do not anticipate the payment of cash
dividends in the immediate future.
EPS Computation
SFAS No. 128, Earnings per Share, requires a reconciliation of the
numerator (income) and denominator (shares) of the basic EPS computation to
the numerator and denominator of the diluted EPS computation. In 2001 and
1999, weighted average shares held by the benefit trust of 145,000 and 64,000
are not included in the calculation of diluted loss per share due to their
anti-dilutive effect. In 2001, stock options were excluded from the
calculation of diluted loss per share due to their anti-dilutive effect. In
2000 and 1999, we had 2.4 million and 2.5 million stock options which were not
included in the calculation of diluted earnings per share because the option
exercise price exceeded the average market price. We also have 2.3 million
Term Convertible Securities, Series A ("TECONS") that were not included in the
calculation of diluted earnings (loss) per share in 2001, 2000 or 1999 due to
their anti-dilutive effect. The reconciliation is as follows:
For the Year Ended December 31,
-----------------------------------------------
2001 2000 1999
---------------- --------------- --------------
Net Net
Net Loss Shares Income Shares Income Shares
-------- ------ ------- ------ ------- ------
(In thousands)
Earnings (loss) before
cumulative effect per Common
share--Basic................. $(79,171) 16,735 $12,431 17,447 $31,442 19,353
Effect of dilutive securities:
Stock options............... -- -- -- 335 -- 154
Shares held by Benefit
Trust...................... -- -- (152) 159 -- --
-------- ------ ------- ------ ------- ------
Earnings (loss) before
cumulative effect per Common
share--Diluted............... $(79,171) 16,735 $12,279 17,941 $31,442 19,507
======== ====== ======= ====== ======= ======
Treasury Stock Repurchases
On February 12, 2001, our Board of Directors authorized the open market
repurchase of an additional 1.0 million shares of common stock increasing the
amount authorized to repurchase to 5.6 million shares, of which
51
2.0 million is remaining. Repurchases may be made at times and at prices
deemed appropriate by management and consistent with the authorization of our
Board. During the first quarter of 2001, we repurchased 0.1 million shares at
an average purchase price of $16.32 per share, including commissions. There
were no shares repurchased during the second, third or fourth quarters of
2001. As of December 31, 2001, we had repurchased a total of 3.6 million
shares since December 1997, at an average purchase price of $16.56 per share,
including commissions.
Shareholder Rights Plan
In March 1997, we adopted a Shareholder Rights Plan to protect our
shareholders from coercive or unfair takeover tactics. Under the Shareholder
Rights Plan, each outstanding share and each share of subsequently issued
common stock has attached to it one Right. Generally, in the event a person or
group ("Acquiring Person") acquires or announces an intention to acquire
beneficial ownership of 15% or more of the outstanding shares of common stock
without our prior consent, or we are acquired in a merger or other business
combination, or 50% or more of our assets or earning power is sold, each
holder of a Right will have the right to receive, upon exercise of the Right,
that number of shares of common stock of the acquiring company, which at the
time of such transaction will have a market price of two times the exercise
price of the Right. We may redeem the Right for $.01 at any time before a
person or group becomes an Acquiring Person without prior approval. The Rights
will expire on March 21, 2007, subject to earlier redemption by us.
On January 10, 2000, we amended the Shareholder Rights Plan to provide that
if we receive and consummate a transaction pursuant to a qualifying offer, the
provisions of the Shareholder Rights Plan are not triggered. In general, a
qualifying offer is an all cash, fully-funded tender offer for all outstanding
common shares by a person who, at the commencement of the offer, beneficially
owns less than five percent of the outstanding common shares. A qualifying
offer must remain open for at least 120 days, must be conditioned on the
person commencing the qualifying offer acquiring at least 75% of the
outstanding common shares and the per share consideration must exceed the
greater of (1) 135% of the highest closing price of the common shares during
the one-year period prior to the commencement of the qualifying offer or (2)
150% of the average closing price of the common shares during the 20 day
period prior to the commencement of the qualifying offer.
Executive Compensation Plan
In 1997, we adopted a plan to encourage senior executives to personally
invest in our stock, and to regularly review executives' ownership versus
targeted ownership objectives. These incentives include a deferred
compensation plan (the "Plan") that gives key executives the ability to defer
all or a portion of their salaries and bonuses and invest in our common stock
or make other investments at the employee's discretion. Stock is held in a
benefit trust and is restricted for a two-year period. The stock held in the
benefit trust (122,995 shares, 174,904 shares and 75,904 shares at December
31, 2001, 2000 and 1999) is accounted for as a liability at market value, with
any changes in market value charged or credited to general and administrative
expense. We recorded a net benefit of $0.2 million and $0.1 million in 2001
and 2000 and an expense of $1.7 million in 1999 related to deferred
compensation. The Plan was amended in 2001 to remove the discount on
investments in our common stock and to provide additional investment
alternatives. Target levels of ownership are based on multiples of base salary
and are administered by the Compensation Committee of the Board of Directors.
Upon withdrawal from the Plan, the obligation to the employee can be settled
in cash or Common Stock, at the option of the employee. In 2001 and 1999,
89,000 shares and 14,000 shares were withdrawn from the Plan at a fair market
value of $1.7 million and $0.4 million. In 2000, there were no such
withdrawals from the Plan. The Plan applies to certain highly compensated
employees and all executives at a level of Vice-President and above.
Director Compensation
In May 1999, the Compensation Committee of our Board of Directors
implemented changes to the compensation of our non-employee directors. Non-
employee directors may elect to receive all or part of the annual cash
retainer of $30,000 in restricted shares of our Common Stock at a 33% increase
in value. The election must be made in increments of 25% ($7,500). Therefore,
for each $7,500 of compensation for which the
52
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 our 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 our 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 Plans
In 1990, we established the 1990 Stock Option Plan; in 1993, the Board of
Directors adopted the Nuevo Energy Company 1993 Stock Incentive Plan; and in
1999, the Board of Directors adopted the Nuevo Energy Company 1999 Stock
Incentive Plan (collectively, the "Stock Incentive Plans"). In 2001, the Board
of Directors adopted the 2001 Stock Incentive Plan as well as individual
incentive plans to induce our Chief Financial Officer and our Senior Vice
President to accept employment with us. In 2001, we recorded $0.1 million of
general and administration expense related to 9,073 shares of common stock
granted to our Chief Executive Officer in accordance with his employment
agreement. The purpose of the Stock Incentive Plans is to provide our
directors and key employees performance incentives and to provide a means of
encouraging these individuals to own our stock.
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 us. No option
may exceed a term of more than ten years. Options granted under the Stock
Incentive Plans may be either incentive stock options or options that do not
qualify as incentive stock options. Our Compensation Committee is authorized
to designate the recipients of options, the dates of grants, the number of
shares subject to options, the option price, the terms of payment upon
exercise of the options, and the time during which the options may be
exercised. Options for officers vest over a term of one to three years, as
specified by the Compensation Committee. Officers who have met their targeted
stock ownership requirement receive accelerated vesting on all options issued
prior to October 15, 2001.
The following table details a summary of activity in the stock option plans
during the three years ended 2001:
Weighted-
Average
Option Exercise Price
--------- --------------
Outstanding at January 1, 1999.................... 2,676,363 $23.94
Granted......................................... 481,225 $16.02
Exercised....................................... (128,909) $14.16
Canceled........................................ (411,500) $25.52
---------
Outstanding at December 31, 1999.................. 2,617,179 $22.72
Granted......................................... 419,189 $15.69
Exercised....................................... (182,925) $13.40
Canceled........................................ (80,525) $34.18
---------
Outstanding at December 31, 2000.................. 2,772,918 $21.94
Granted......................................... 875,026 $15.51
Exercised....................................... (285,000) $12.93
Canceled........................................ (104,525) $33.88
---------
Outstanding at December 31, 2001.................. 3,258,419 $20.62
=========
53
We had options exercisable of 2,728,494 (weighted average exercise price of
$21.80), 2,361,979 (weighted average exercise price of $23.04) and 2,202,454
(weighted average exercise price of $24.00) at December 31, 2001, 2000 and
1999. Detail of stock options outstanding and options exercisable at December
31, 2001 follows:
Outstanding Exercisable
-------------------------------- -------------------
Weighted- Weighted- Weighted-
Average Average Average
Remaining Exercise Exercise
Range of Exercise Prices Number Life (Years) Price Number Price
------------------------ --------- ------------ --------- --------- ---------
$10.31 to $15.06........ 854,263 8.27 $12.36 576,763 $12.51
$15.50 to $19.63........ 1,453,956 7.28 $16.89 1,202,031 $16.81
$20.38 to $29.88........ 407,700 5.14 $23.27 407,200 $23.27
$34.00 to $47.88........ 542,500 5.69 $41.62 542,500 $41.62
--------- ---------
Total................. 3,258,419 2,728,494
========= =========
The weighted-average fair value of options granted during 2001, 2000 and
1999 was $10.63, $10.87 and $11.38. 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 54.5%, 112% and 55.7% in 2001, 2000 and 1999; risk free interest
of 4%, 5% and 6% in 2001, 2000 and 1999, and average expected option lives of
three years in 2001 and 2000 and five years in 1999. Had compensation expense
for stock-based compensation been determined based on the fair value at the
date of grant, our net income, earnings available to common stockholders and
earnings per share would have been reduced to the pro forma amounts indicated
below.
Year Ended December 31,
-------------------------
2001 2000 1999
-------- ------- -------
(In thousands, except
share data)
Net income (loss).................... As reported $(79,171) $11,635 $31,442
Pro forma (83,177) 6,740 24,673
Earnings (loss) per Common share--
Basic............................... As reported (4.73) 0.67 1.62
Pro forma (4.97) 0.39 1.27
Earnings (loss) per Common share--
Diluted............................. As reported (4.73) 0.64 1.61
Pro forma (4.97) 0.38 1.26
11. Company-Obligated Mandatorily Redeemable Convertible Preferred Securities
of Nuevo Financing I
On December 23, 1996, the Company and Nuevo Financing I, a statutory
business trust formed under the laws of the state of Delaware, (the "Trust"),
closed the offering of 2.3 million TECONS on behalf of the Trust. The price to
the public was $50.00 per TECONS. Distributions began to accumulate from
December 23, 1996, and are payable quarterly on March 15, June 15, September
15, and December 15, at an annual rate of $2.875 per TECONS. Each TECONS is
convertible at any time prior to the close of business on December 15, 2026,
at the option of the holder into shares of common stock at the rate of 0.8421
shares of common stock for each TECONS, subject to adjustment. The sole asset
of the Trust as the obligor on the TECONS is $115.0 million aggregate
principal amount of 5.75% Convertible Subordinated Debentures ("Debentures")
of the Company due December 15, 2026. The Debentures were issued by us to the
Trust to facilitate the offering of the TECONS. The TECONS must be redeemed
for $50.00 per TECON plus accrued and unpaid dividends on December 15, 2026.
54
12. Long-Term Debt
Our long-term debt consisted of the following at December 31:
2001 2000
-------- --------
(In thousands)
9 3/8% Senior Subordinated Notes due 2010................ $150,000 $150,000
9 1/2% Senior Subordinated Notes due 2008................ 257,210 257,310
9 1/2% Senior Subordinated Notes due 2006................ 2,367 2,417
Bank credit facility (at 3.71% on December 31, 2001)..... 41,500 --
-------- --------
Total debt............................................. 451,077 409,727
Interest rate swaps...................................... (633) --
-------- --------
Long-term debt........................................... $450,444 $409,727
======== ========
9 3/8% Notes due 2010
On September 26, 2000, we issued $150.0 million of 9 3/8% Senior
Subordinated Notes due October 1, 2010. Interest accrues at 9 3/8% per annum
and is payable semi-annually in arrears on April 1 and October 1. The Notes
are redeemable, in whole or in part, at our option, on or after October 1,
2005, under certain conditions. We are not required to make mandatory
redemption or sinking fund payments with respect to these Notes. The indenture
contains covenants that, among other things, limit our ability to incur
additional indebtedness, limit restricted payments, limit issuances and sales
of capital stock by restricted subsidiaries, limit dispositions of proceeds
from asset sales, limit dividends and other payment restrictions affecting
restricted subsidiaries, and restrict mergers, consolidations or sales of
assets. If one of our subsidiaries guarantees other subordinated indebtedness
of ours, the subsidiary must also guarantee these Notes. Currently, none of
our subsidiaries guarantee subordinated indebtedness of ours. The Notes are
unsecured general obligations, and are subordinated in right of payment to all
existing and future senior indebtedness. In the event of a defined change in
control, we will be required to make an offer to repurchase all outstanding 9
3/8% Notes at 101% of the principal amount, plus accrued and unpaid interest
to the date of redemption.
9 1/2% Notes due 2008
In July 1999, we authorized a new issuance of $260.0 million of 9 1/2%
Senior Subordinated Notes due June 1, 2008. In August 1999, we exchanged these
Notes for $157.5 million of our 9 1/2% Notes due 2006 and $99.9 million of our
8 7/8% Senior Subordinated Notes due 2008. In connection with the exchange
offers, we solicited consents to proposed amendments to the indentures under
which the exchanged notes were issued. These amendments streamlined our
covenant structure and provided us with additional flexibility to pursue our
operating strategy. The exchange was accounted for as a debt modification and
the consideration we paid to the holders of the exchanged 9 1/2% Notes due
2006 was $4.7 million and was accounted for as deferred financing costs. We
also 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 these Notes accrues at the rate of 9 1/2% per annum and is
payable semi-annually in arrears on June 1 and December 1. These Notes are
redeemable, in whole or in part, at our option, on or after June 1, 2003,
under certain conditions. We are not required to make mandatory redemption or
sinking fund payments on these Notes. The indenture contains covenants that,
among other things, limit the Company's ability to incur additional
indebtedness, limit restricted payments, limit issuances and sales of capital
stock by restricted subsidiaries, limit dispositions of proceeds from asset
sales, limit dividends and other payment restrictions affecting restricted
subsidiaries, and restrict mergers, consolidations or sales of assets. The 9
1/2% Notes are not currently guaranteed by our subsidiaries but are required
to be guaranteed by any subsidiary that guarantees pari passu or subordinated
indebtedness. Currently, none of our subsidiaries guarantees our subordinated
indebtedness. The 9 1/2% Notes are unsecured general obligations, and are
subordinated in right of payment to all of our existing and future senior
indebtedness. In the event of a defined change in control, we will be required
to make an offer to repurchase all outstanding Notes at 101% of the principal
amount, plus accrued and unpaid interest to the date of redemption.
55
9 1/2% Notes due 2006
In April 1996, we issued $160.0 million of 9 1/2% Notes due 2006 and used
the proceeds to pay for a portion of the purchase price of the Unocal
Properties. In August 1999, we exchanged $157.5 million of these notes for our
9 1/2% Notes due 2008. In October 1999, we purchased $0.1 million of the
remaining Notes. No significant costs were incurred in connection with that
early retirement. Interest on these Notes accrues at the rate of 9 1/2% per
annum and is payable semi-annually in arrears on April 15 and October 15 and
were redeemable, in whole or in part, at our option, on or after April 15,
2001, under certain conditions. These Notes had not been redeemed, in whole,
or in part at December 31, 2001. We are not required to make mandatory
redemption or sinking fund payments with respect to these Notes and they are
unsecured general obligations, and are subordinated in right of payment to all
existing and future senior indebtedness.
Interest Rate Swaps
In December 2001, we entered into two interest rate swap agreements with
notional amounts totaling $150 million to hedge the fair value of our 9 1/2%
Notes due 2008 and our 9 3/8% Notes due 2010. These swaps are designated as
fair value hedges and are reflected as a reduction of long-term debt of $0.6
million as of December 31, 2001 with a corresponding increase in long-term
liabilities. Under the terms of the agreements for the 9 3/8% Notes, the
counterparty pays us a weighted average fixed annual rate of 9 3/8% on total
notional amounts of $100 million, and we pay the counterparty a variable
annual rate equal to the six-month London Interbank Offered Rate ("LIBOR")
rate plus a weighted average rate of 3.49%. Under the terms of the agreement
for the 9 1/2% Notes, the counterparty pays us a weighted average fixed annual
rate of 9 1/2% on total notional amounts of $50 million, and we pay the
counterparty a variable annual rate equal to the six-month LIBOR rate plus a
weighted average rate of 3.92%.
Subsequent to December 31, 2001, we entered into an interest rate swap
agreement with a notional amount totaling $50 million to hedge the fair value
of our 9 3/8% Notes. Under the terms of this agreement, the counterparty pays
us a weighted average fixed annual rate of 9 3/8% on the notional amount of
$50 million, and we pay the counterparty a variable annual rate equal to the
three-month LIBOR rate plus a weighted average rate of 3.49%
Bank Credit Facility
Our Third Amended and Restated Credit Agreement ("Credit Agreement"), dated
June 7, 2000, provides for secured revolving credit availability of up to
$410.0 million from a bank group led by Bank of America, N.A., Bank One, NA,
and Bank of Montreal until its expiration on June 7, 2005.
The borrowing base is subject to a semi-annual borrowing base determination
within 60 days following March 1 and August 15 of each year and establishes
the maximum borrowings that may be outstanding under the credit facility. It
is determined by a 60% vote of the banks (two-thirds in the event of an
increase in the borrowing base), each of which bases its judgement on: (i) the
present value of our oil and gas reserves based on their own assumptions
regarding future prices, production, costs, risk factors and discount rates,
and (ii) projected cash flow coverage ratios calculated under varying
scenarios. If amounts outstanding under the credit facility exceed the
borrowing base, as redetermined from time to time, we would be required to
repay such excess over a defined period of time. We have a $225 million
borrowing base under our Credit Facility with $102 million available at
December 31, 2001 and had drawn $41.5 million under the agreement.
Amounts outstanding under the credit facility bear interest at a rate equal
to LIBOR plus an amount which increases as the Indebtedness (as defined in the
Credit Agreement) increases.
Our Credit Agreement has covenants which limit certain restricted payments
and investments, guarantees and indebtedness, prepayments of subordinated and
certain other indebtedness, mergers and consolidations, certain types of
acquisitions and on the issuance of certain securities by subsidiaries, liens,
sales of properties,
56
transactions with affiliates, derivative contracts and debt in subsidiaries.
We are also required to maintain certain financial ratios and conditions,
including without limitation an EBITDAX (earnings before interest, taxes,
depreciation, depletion, amortization and exploration expenses) to fixed
charge coverage ratio and a funded debt to capitalization ratio. At December
31, 2001, we were in compliance with all covenants of the Credit Agreement.
The amount of scheduled debt maturities during the next five years and
thereafter is as follows (amounts in thousands):
2002................................................................ $ --
2003................................................................ --
2004................................................................ --
2005................................................................ 41,500
2006................................................................ 2,367
Thereafter.......................................................... 407,210
--------
Total debt maturities............................................. $451,077
========
Based upon the quoted market price, the fair value of the 9 3/8% Notes was
estimated to be $146.8 million and 150.0 million at December 31, 2001 and
2000; the fair value of the 9 1/2% Notes due 2008 was estimated to be $245.6
million and $260.4 million at December 31, 2001 and 2000, and the fair value
of the 9 1/2% Notes due 2006 was estimated to be $2.4 million and $2.5 million
at December 31, 2001 and 2000. The carrying amount of the credit facility
approximates the fair value of the debt at December 31, 2001.
13. Income Taxes
Income tax (expense) benefit is summarized as follows:
Year Ended December 31,
------------------------
2001 2000 1999
------- ------- -------
(In thousands)
Current
Federal......................................... $ -- $ 371 $(1,012)
State........................................... -- -- (188)
------- ------- -------
-- 371 (1,200)
------- ------- -------
Deferred
Federal......................................... 42,465 (7,102) 8,457
State........................................... 10,492 (1,661) (1,898)
------- ------- -------
52,957 (8,763) 6,559
------- ------- -------
Total income tax (expense) benefit............ $52,957 $(8,392) $ 5,359
======= ======= =======
For the year ended December 31, 2000, we recorded a tax benefit of $0.5
million related to the cumulative effect of a change in accounting principle
(see Note 2). A deferred tax benefit related to the exercise of employee stock
options of approximately $0.8 million and $0.5 million was allocated directly
to additional paid-in capital in 2001 and 2000.
57
Total income tax expense (benefit) differs from the amount computed by
applying the federal income tax rate to income (loss) before income taxes and
cumulative effect. The reasons for these differences are as follows:
Year Ended
December 31,
--------------------
2001 2000 1999
----- ----- -----
Statutory federal income tax rate..................... (35.0)% 35.0% 35.0%
(Decrease) increase in tax rate resulting from:
State income taxes, net of federal benefit.......... (5.2) 5.2 5.2
Decrease in valuation allowance..................... -- -- (60.8)
Nondeductible travel and entertainment and other.... 0.1 0.1 0.1
----- ----- -----
(40.1)% 40.3 % (20.5)%
===== ===== =====
During 1999, we determined that it would be more likely than not that the
deferred tax assets would be realized. At such time, we reduced the valuation
allowance by $15.9 million.
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:
As of December
31,
-----------------
2001 2000
------- --------
(In thousands)
Net operating loss carryforwards.......................... $57,568 $ 51,033
Alternative minimum tax credit carryforwards.............. 1,704 1,704
Property and equipment.................................... 3,261 --
State income taxes........................................ 5,268 --
------- --------
Total deferred income tax assets........................ 67,801 52,737
Less: valuation allowance............................... (1,777) (1,777)
------- --------
Net deferred income tax assets.......................... 66,024 50,960
------- --------
Property and equipment.................................... -- (31,338)
Equity in foreign subsidiaries............................ (1,854) (1,684)
State income taxes........................................ (1,940) (1,656)
------- --------
Total deferred income tax liabilities................... (3,794) (34,678)
------- --------
Net deferred income tax asset............................. $62,230 $ 16,282
======= ========
At December 31, 2001, we had a net operating loss carryforward for regular
tax purposes of approximately $164.5 million, which will begin expiring in
2018. Alternative minimum tax credit carryforwards of $1.7 million does not
expire and may be applied to reduce regular income tax to an amount not less
than the alternative minimum tax payable in any one year. At December 31,
2001, we determined that it was more likely than not that most of the deferred
tax assets would be realized.
58
14. Industry Segment Information
Our operations are concentrated primarily in two segments: exploration and
production of oil and natural gas, and gas plant and other facilities. For
segment reporting purposes, domestic producing areas have been aggregated as
one reportable segment due to similarities in their operations as allowed by
SFAS No. 131, Disclosures About Segments of an Enterprise and Related
Information. Financial information by reportable segment is presented below:
As of and For the Year
Ended
December 31,
-----------------------------
2001 2000 1999
--------- -------- --------
(In thousands)
Sales to unaffiliated customers
Oil and gas--Domestic......................... $ 332,646 $290,774 $211,647
Oil and gas--Foreign.......................... 35,914 40,881 30,627
--------- -------- --------
Total sales................................. 368,560 331,655 242,274
Gain on sale of assets, net............... 882 657 85,294
Interest and other income................. 1,813 4,293 4,667
--------- -------- --------
Total revenues.............................. $ 371,255 $336,605 $332,235
========= ======== ========
Operating profit (loss) before income taxes
Oil and gas--Domestic (/1/)................... $ (17,410) $ 84,747 $ 97,948
Oil and gas--Foreign.......................... (8,444) 14,899 5,208
--------- -------- --------
(25,854) 99,646 103,156
Unallocated corporate expenses................ 56,655 34,738 37,350
Interest expense.............................. 43,006 37,472 33,110
Dividends on TECONS........................... 6,613 6,613 6,613
--------- -------- --------
Operating profit (loss) before income taxes... $(132,128) $ 20,823 $ 26,083
========= ======== ========
Identifiable assets
Oil and gas--Domestic......................... $ 541,688 $613,658 $566,256
Oil and gas--Foreign.......................... 56,404 103,204 82,074
Gas plant and other facilities................ 7,395 11,455 12,297
--------- -------- --------
605,487 728,317 660,627
Corporate assets, investments and other....... 234,325 119,707 99,403
--------- -------- --------
Total....................................... $ 839,812 $848,024 $760,030
========= ======== ========
Capital expenditures (/2/)
Oil and gas--Domestic......................... $ 164,028 $101,773 $106,071
Oil and gas--Foreign.......................... 24,935 11,694 24,570
--------- -------- --------
Total oil and gas expenditures.............. 188,963 113,467 130,641
Less: Geological & geophysical, delay rentals
and other expenses........................... (15,089) (9,047) (4,722)
--------- -------- --------
Additions to oil and gas properties per
Statement of Cash Flows.................... $ 173,874 $104,420 $125,919
========= ======== ========
Gas plant and other facilities................ $ 8,554 $ 3,388 $ 10,247
========= ======== ========
Depreciation, depletion and amortization
Oil and gas--Domestic......................... $ 63,485 $ 57,819 $ 70,024
Oil and gas--Foreign.......................... 10,381 8,085 9,177
Gas plant and other facilities................ 512 512 666
Corporate..................................... 1,776 954 785
--------- -------- --------
Total....................................... $ 76,154 $ 67,370 $ 80,652
========= ======== ========
- --------
(/1/Includes)gain on sale of the East Texas natural gas asset of $80.2 million
in 1999.
(/2/Includes)acquisitions of oil and gas properties.
59
Credit Risks due to Certain Concentrations
In 2001, 2000 and 1999, we had one customer that accounted for 63%, 84%,
and 79% of oil and gas revenues. In 2001, 2000 and 1999, we had another
customer that accounted for 23%, 11% and 12% of oil and gas revenues.
In February 2000, we entered into a 15-year contract, effective January 1,
2000, to sell substantially all of our current and future California crude oil
production to Tosco Corporation. The contract provides pricing based on a
fixed percentage of the NYMEX crude oil price for each type of crude oil that
we produce in California. Therefore, the actual price received as a percentage
of NYMEX will vary with our production mix. Based on the current production
mix, the price we receive for our California production is expected to average
approximately 72% of West Texas Intermediate ("WTI"). While the contract does
not reduce our exposure to price volatility, it does effectively eliminate the
basis differential risk between the NYMEX price and the field price of our
California oil production. The Tosco contract permits us, under certain
circumstances, to separately market up to ten percent of our California crude
production. We exercised this right and, effective January 1, 2001, and
January 1, 2002, began selling 5,000 BOPD of our San Joaquin Valley oil
production to a third party under a one-year contract using NYMEX pricing.
Our revenues are derived principally from uncollateralized sales to
customers in the oil and gas industry, therefore, customers may be similarly
affected by changes in economic and other conditions within the industry. We
have not experienced significant credit losses in such sales. Sales of oil and
gas to Tosco are similarly uncollateralized.
15. Contingencies and Other Matters
On September 14, 2001, during an annual inspection, we discovered fractures
in the heat affected zone of certain flanges on our pipeline that connects the
Point Pedernales field with onshore processing facilities. We voluntarily
elected to shut-in production in the field while repairs were being made. The
daily net production from this field was approximately 5,000 barrels of crude
oil and 1.2 MMcf of natural gas, representing approximately 11% of our daily
production. We replaced the damaged flanges, as well as others which had not
shown signs of damage. The cost of repair is expected to be partially covered
by insurance. We may have exposure to costs that may not be recoverable from
insurance, including those associated with the repair of undamaged equipment.
Production was back on in January 2002.
On June 15, 2001, we experienced a failure of a carbon dioxide treatment
vessel at the Rincon Onshore Separation Facility ("ROSF") located in Ventura
County, California. There were no injuries associated with this event and the
cause of the failure is under investigation. Crude oil and natural gas
produced from three fields offshore California are transported onshore by
pipeline to the ROSF plant where crude oil and water are separated and
treated, and carbon dioxide is removed from the natural gas stream. The daily
net production associated with these fields is 3,000 barrels of crude oil and
2.4 MMcf of natural gas, representing approximately 6% of our daily
production. Crude oil production resumed in early July and full gas sales
resumed by mid August. The cost of repair, less a $50,000 deductible, is
expected to be covered by insurance. We may have exposure to costs that may
not be recoverable from insurance.
On September 22, 2000, we were named as a defendant in the lawsuit Thomas
Wachtell et al. versus Nuevo Energy Company in the Superior Court of Los
Angeles County, California. We successfully removed this lawsuit to the United
States District Court for the Central District of California. The plaintiffs,
who own certain interests in the Point Pedernales properties, have asserted
numerous causes of action including breach of contract, fraud and conspiracy
in connection with the plaintiff's allegation that: (i) royalties have not
been properly paid to them for production from the Point Pedernales field,
(ii) payments have not been made to them related to production from the Sacate
field, and (iii) we have failed to recognize the plaintiff's interests in the
Tranquillon Ridge project. The plaintiffs have not specified damages. We
intend to vigorously contest these claims.
60
We have been named as a defendant in certain other lawsuits incidental to
our business. However, these actions and claims in the aggregate seek
substantial damages against us and are subject to the inherent uncertainties
in any litigation. We are defending ourselves vigorously in all such matters.
We have reserved an amount that we deem adequate to cover any potential
losses related to the matters discussed above. This amount is reviewed
periodically and changes may be made, as appropriate. Any additional costs
related to these potential losses are not expected to be material to our
operating results, financial condition or liquidity.
In March 1999, we discovered that a non-officer employee had fraudulently
authorized and diverted for personal use Company funds totaling $5.9 million,
$1.6 million in 1999 and the remainder in 1998, that were intended for
international exploration. The Board of Directors engaged a Certified Fraud
Examiner to conduct an in-depth review of the fraudulent transactions. The
investigation confirmed that only one employee was involved in the matter and
that all misappropriated funds were identified. We have reviewed and, where
appropriate, strengthened our internal control procedures. In August 2000, we
recorded $1.5 million of other income for a partial reimbursement of these
previously expensed funds, resulting from the negotiated settlement of a
related legal claim.
In September 1997, there was a spill of crude oil into the Santa Barbara
Channel from a pipeline that connects our Point Pedernales field with shore-
based processing facilities. The volume of the spill was estimated to be 163
barrels of oil. Repairs were completed by the end of 1997, and production
recommenced in December 1997. The costs of the clean up and the cost to repair
the pipeline either have been or are expected to be covered by our insurance,
less a deductible of $120,000. We incurred clean-up and repair costs of $0.3
million, $ 0.3 million and $0.5 million during 2001, 2000 and 1999. As of
December 31, 2001, we had received insurance reimbursements of $4.2 million,
with a remaining insurance receivable of $0.5 million. For amounts not covered
by insurance, including the $0.1 million deductible, we recorded lease
operating expenses of $1.1 million in 2001 and $0.4 million during 1999. No
such expenses were recorded in 2000. We also have exposure to costs that may
not be recoverable from insurance, including certain fines, penalties, and
damages and certain legal fees. Such costs are not quantifiable at this time,
but are not expected to be material to our operating results, financial
condition or liquidity.
Our international investments involve risks typically associated with
investments in emerging markets such as an uncertain political, economic,
legal and tax environment and expropriation and nationalization of assets. In
addition, if a dispute arises in our foreign operations, we may be subject to
the exclusive jurisdiction of foreign courts or may not be successful in
subjecting foreign persons to the jurisdiction of the United States. We
attempt to conduct our business and financial affairs to protect against
political and economic risks applicable to operations in the various countries
where we operate, but there can be no assurance that we will be successful in
so protecting ourselves. A portion of our investment in the Congo is insured
through political risk insurance provided by Overseas Private Investment
Company ("OPIC"). The political risk insurance through OPIC covers up to $25.0
million relating to expropriation and political violence, which is the maximum
coverage available through OPIC. We have no deductible for this insurance.
In connection with our February 1995 acquisitions of two subsidiaries (each
a "Congo subsidiary") owning interests in the Yombo field offshore Congo, we
and a wholly-owned subsidiary of CMS NOMECO Oil & Gas Co. ("CMS") agreed with
the seller of the subsidiaries not to claim certain tax losses ("dual
consolidated losses") incurred by such subsidiaries prior to the acquisitions.
Under the tax law in the Congo, as it existed when this acquisition took
place, if an entity is acquired in its entirety and that entity has certain
tax attributes, for example tax loss carryforwards from operations in the
Republic of Congo, the subsequent owners of that entity can continue to
utilize those losses without restriction. Pursuant to the agreement, we and
CMS may be liable to the seller for the recapture of dual consolidated losses
(net operating losses of any domestic corporation that are subject to an
income tax of a foreign country without regard to the source of its income or
on a residence basis) utilized by the seller in years prior to the
acquisitions if certain triggering events occur, including (i) a
61
disposition by either us or CMS of its respective Congo subsidiary, (ii)
either Congo subsidiary's sale of its interest in the Yombo field, (iii) the
acquisition of us or CMS by another consolidated group or (iv) the failure of
us 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. We and CMS have agreed that the party responsible for the
triggering event shall indemnify the other for any liability to the seller as
a result of such triggering event. Our potential direct liability could be as
much as $38.5 million if a triggering event occurs. Additionally, we believe
that CMS's liability (for which we would be jointly liable with an
indemnification right against CMS) could be as much as $56.2 million. We do
not expect a triggering event to occur with respect to us or CMS and do not
believe the agreement will have a material adverse effect upon us.
During 1997, a new government was established in the Congo. Although the
political situation in the Congo has not to date had a material adverse effect
on our operations in the Congo, no assurances can be made that continued
political unrest in West Africa will not have a material adverse effect on us
or our operations in the Congo in the future.
Our total estimated costs of future dismantlement, abandonment and site
remediation is approximately $113.1 million (net of salvage value) which is
included when calculating depreciation and depletion using the unit-of-
production method. At December 31, 2001, we had recorded $74.2 million as a
component of accumulated depreciation, depletion and amortization.
16. Financial Instruments
We have entered into commodity swaps, put options and interest rate swaps.
The commodity swaps and put options are designated as cash flow hedges and the
interest rate swaps are designated as fair value hedges in accordance with
SFAS 133. Quantities covered by these hedges are based on West Texas
Intermediate ("WTI") barrels. Our production is expected to average 73% of
WTI, therefore, each WTI barrel hedges 1.37 barrels of our production.
Derivative Instruments Designated as Cash Flow Hedges
At December 31, 2001, we had entered into the following cash flow hedges:
WTI Barrels Average
Per Day Strike Price
----------- ------------
Swaps
First quarter 2002................................ 12,500 $25.91
Second quarter 2002............................... 2,000 23.50
Third quarter 2002................................ 6,800 23.20
Fourth quarter 2002............................... 5,000 23.90
Put Options
Second quarter 2002............................... 14,000 $22.00
Third quarter 2002................................ 9,000 22.00
Fourth quarter 2002............................... 9,000 22.00
At December 31, 2001, the fair market value of these hedge positions is
$19.6 million, net of the cost of the options of $3.8 million. All of these
agreements expose us to counterparty credit risk to the extent that the
counterparty is unable to meet its settlement commitments.
62
Derivative Instruments Designated as Fair Value Hedges
In late December 2001, we entered into two interest rate swap agreements
with notional amounts totaling $150 million, to hedge the fair value of our 9
1/2% Notes due 2008 and our 9 3/8% Notes due 2010. These swaps are designated
as fair value hedges and are reflected as a reduction of long-term debt of
$0.6 million as of December 31, 2001, with a corresponding increase in long-
term liabilities. Under the terms of the agreements for the 9 3/8% Notes, the
counterparty pays us a weighted average fixed annual rate of 9 3/8% on total
notional amounts of $100 million, and we pay the counterparty a variable
annual rate equal to the six-month LIBOR rate plus a weighted average rate of
3.49%. Under the terms of the agreement for the 9 1/2% Notes, the counterparty
pays us a weighted average fixed annual rate of 9 1/2% on total notional
amounts of $50 million, and we pay the counterparty a variable annual rate
equal to the six-month LIBOR rate plus a weighted average rate of 3.92%.
Subsequent to December 31, 2001, we entered into an interest rate swap
agreement with a notional amount totaling $50 million to hedge the fair value
of our 9 3/8% Notes. Under the terms of this agreement, the counterparty pays
us a weighted average fixed annual rate of 9 3/8% on the notional amount of
$50 million, and we pay the counterparty a variable annual rate equal to the
three-month LIBOR rate plus a weighted average rate of 3.49%.
Fair Values of Financial Instruments
Fair value for cash, short-term investments, receivables and payables
approximates carrying value. The following table details the carrying values
and approximate fair values of our other investments, derivative financial
instruments and long-term debt at December 31, 2001 and 2000.
December 31, 2001 December 31, 2000
--------------------- --------------------
Carrying Approximate Carrying Approximate
Amount Fair Value Amount Fair Value
-------- ----------- -------- -----------
(In thousands)
Other investments................ $ -- $ -- $ 78 $ 78
Derivative Instruments
Option commodity contracts..... 9,490 9,490 5,595 11,088
Commodity price swaps.......... 10,120 10,120 -- (32,253)
Interest rate swaps............ (633) (633) -- --
Long-term debt (see Note 12)..... 450,444 436,012 409,727 412,823
TECONS........................... 115,000 68,770 115,000 60,950
The fair value of our long-term debt and TECONS were determined based upon
interest rates currently available to us for borrowing with similar terms at
December 31, 2001 and 2000.
Other--Enron Exposure and Call Spreads
In December 2001, Enron Corp. ("Enron") and certain of its affiliates filed
voluntary petitions for reorganization under Chapter 11 of the United States
Bankruptcy Code. As a result, we recorded a $7.6 million charge in the fourth
quarter of 2001: $1.2 million related to the November and December 2001 crude
oil price swaps, $0.9 million related to the Enron call spread (see below),
and $5.5 million related to the fair value of open hedges of second, third and
fourth quarter 2002 crude oil production. Once a deterioration in
creditworthiness creates uncertainty as to whether the future cash flows from
the hedging instrument will be highly effective in offsetting the hedged risk,
the derivative instrument is no longer considered highly effective and no
longer qualifies for hedge accounting treatment. At such time, the fair value
of the derivative asset or liability is adjusted to its new fair value, with
the change in value being charged to current earnings. The net gain or loss of
the derivative instruments previously reported in other comprehensive income
remains in accumulated other comprehensive income and is reclassified into
earnings during the period in which the originally designated hedge items
affect earnings. At December 31, 2001, a deferred gain of $2.2 million remains
in accumulated other comprehensive income related to the outstanding Enron
options, which will be reclassified into earnings when the hedged production
occurs, in the next 12 months.
63
In 2001 and 2000, we entered into call spreads with the anticipation of
using the proceeds to offset the Unocal Contingent payment. (See Note 17).
Subsequent to entering into the call spreads, the market fell and as a result,
offsetting call spreads were purchased to economically nullify the trade. All
of our existing call spreads had been offset through the purchase of a mirror
spread, however, the call spread with Enron was cancelled. (See above
discussion). The remaining mirror call spread is not designated as a hedge
instrument and is marked-to-market with changes in fair value recognized in
earnings. At December 31, 2001, $1.1 million is reflected in long-term
liabilities.
17. Contingent Payment and Price Sharing Agreements
In connection with the acquisition from Unocal in 1996 of the properties
located in California, we are obligated to make a contingent payment for the
years 1998 through 2004 if oil prices exceed thresholds set forth in the
agreement with Unocal. Any contingent payment will be accounted for as a
purchase price adjustment to oil and gas properties. The contingent payment
will equal 50% of the difference between the actual average annual price
received on a field-by-field basis (capped by a maximum price) and a minimum
price, less ad valorem and production taxes, multiplied by the actual number
of barrels of oil sold that are produced from the properties acquired from
Unocal during the respective year. The minimum price of $17.75 per Bbl under
the agreement (determined based on the near month delivery of WTI crude oil on
the NYMEX) is escalated at 3% per year and the maximum price of $21.75 per Bbl
on the NYMEX is escalated at 3% per year. Minimum and maximum prices are
reduced to reflect the field level price by subtracting a fixed differential
established for each field. The reduction was established at approximately the
differential between actual sales prices and NYMEX prices in effect in 1995
($4.34 per Bbl weighted average for all the properties acquired from Unocal).
We accumulate credits to offset the contingent payment when prices are $.50
per Bbl or more below the minimum price. We paid $10.8 million to Unocal under
this agreement on March 15, 2002.
In connection with the acquisition of the Congo properties in 1995, we
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, we are
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 was $15.78 per Bbl for 2001, $15.19 per Bbl
for 2000 and $14.79 per Bbl for 1999. The benchmark price increases each year,
based on the increase in the Consumer Price Index. For 2001, the effect of
this agreement was that we only owned upside above $15.78 per Bbl on
approximately 56% of our Congo production. We were obligated to pay the seller
$3.4 million in 2001 and $5.4 million in 2000 under this price sharing
agreement. This obligation was accounted for as a reduction in oil revenues.
No payment was due in 1999.
We acquired a 12% working interest in the Point Pedernales oil field from
Unocal in 1994 and the remainder of its 80.3 % working interest from Torch in
1996. We are entitled to all revenue proceeds up to $9.00 per Bbl, with the
excess revenue over $9.00 per Bbl, if any, we share with the original owners
from whom Torch acquired its interest. We own amounts below $9.00 per Bbl with
the other working interest owners based on their respective ownership
interests. For 2001, the effect of this agreement is we were entitled to
receive the pricing upside above $9.00 per Bbl on approximately 73% of the
gross Point Pedernales production. As of December 31, 2001, we had $0.2
million accrued as our obligation under this agreement. As of December 31,
2000, we had $0.6 million accrued as our obligation under this agreement. As
of December 31, 1999, we had $5.1 million accrued as our obligation under this
agreement.
18. 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,
64
2001, and for previous years, are based primarily on reserve reports prepared
by the independent petroleum engineering firm of Ryder Scott Company. These
estimates are inherently imprecise and subject to substantial revision.
Estimates of future net cash flows from proved reserves of gas, oil,
condensate and natural gas liquids ("NGL") were made in accordance with SFAS
No. 69, Disclosures about Oil and Gas Producing Activities. The estimates are
based on NYMEX prices at year-end 2001, of $19.84 per Bbl and $2.57 per MMbtu,
and are adjusted for the effects of contractual agreements with Unocal and
Amoco in connection with the California and Congo property acquisitions (see
Note 17).
Estimated future cash inflows are reduced by estimated future development
and production costs based on year-end cost levels, assuming continuation of
existing economic conditions, and by estimated future income tax expense. Tax
expense is calculated by applying the existing statutory tax rates, including
any known future changes, to the pre-tax net cash flows, less depreciation of
the tax basis of the properties and depletion allowances applicable to the
gas, oil, condensate and NGL production. Because the disclosure requirements
are standardized, significant changes can occur in these estimates based upon
oil and gas prices currently in effect. The results of these disclosures
should not be construed to represent the fair market value of our oil and gas
properties. A market value determination would include many additional factors
including: (i) anticipated future increases or decreases in oil and gas prices
and production and development costs; (ii) an allowance for return on
investment; (iii) the value of additional reserves, not considered proved at
the present, which may be recovered as a result of further exploration and
development activities; and (iv) other business risks.
65
Costs incurred
The following table sets forth the costs incurred in property acquisition
and development activities:
Year Ended December 31,
--------------------------
2001 2000 1999
-------- -------- --------
(In thousands)
Domestic
Property acquisition
Proved properties............................ $ 41,135 $ -- $ 62,300
Unproved properties (/1/).................... 6,131 4,892 520
Exploration.................................... 16,004 5,591 4,973
Development
Proved reserves.............................. 95,005 79,857 35,372
Unproved reserves............................ 5,716 11,433 2,906
-------- -------- --------
$163,991 $101,773 $106,071
======== ======== ========
Foreign
Property acquisition
Proved properties............................ $ -- $ -- $ --
Unproved properties (/1/).................... 47 479 424
Exploration.................................... 4,703 6,467 3,742
Development
Proved reserves.............................. 20,222 4,406 20,404
Unproved reserves............................ -- 342 --
-------- -------- --------
$ 24,972 $ 11,694 $ 24,570
======== ======== ========
Total
Property acquisition
Proved properties............................ $ 41,135 $ -- $ 62,300
Unproved properties (/1/).................... 6,178 5,371 944
Exploration.................................... 20,707 12,058 8,715
Development
Proved reserves.............................. 115,227 84,263 55,776
Unproved reserves............................ 5,716 11,775 2,906
-------- -------- --------
$188,963 $113,467 $130,641
======== ======== ========
- --------
(/1/Includes)capitalized interest directly related to development activities of
$2.5 million and $0.3 million in 2001 and 1999.
66
Capitalized costs
The following table sets forth the capitalized costs relating to oil and gas
activities and the associated accumulated depreciation, depletion and
amortization:
As of December 31,
----------------------------------
2001 2000 1999
---------- ---------- ----------
(In thousands)
Domestic
Proved properties........................ $ 893,215 $ 986,889 $ 898,032
Unproved properties...................... 27,117 25,341 21,755
---------- ---------- ----------
Total capitalized costs................ 920,332 1,012,230 919,787
Accumulated depreciation, depletion and
amortization.......................... (378,644) (461,225) (403,727)
---------- ---------- ----------
Net capitalized costs................ $ 541,688 $ 551,005 $ 516,060
========== ========== ==========
Foreign
Proved properties........................ $ 91,437 $ 84,558 $ 80,374
Unproved properties...................... 2,660 5,445 2,618
---------- ---------- ----------
Total capitalized costs................ 94,097 90,003 82,992
Accumulated depreciation, depletion and
amortization.......................... (37,693) (29,008) (20,901)
---------- ---------- ----------
Net capitalized costs................ $ 56,404 $ 60,995 $ 62,091
========== ========== ==========
Total
Proved properties........................ $ 984,652 $1,071,447 $ 978,406
Unproved properties...................... 29,777 30,786 24,373
---------- ---------- ----------
Total capitalized costs................ 1,014,429 1,102,233 1,002,779
Accumulated depreciation, depletion and
amortization.......................... (416,337) (490,233) (424,628)
---------- ---------- ----------
Net capitalized costs................ $ 598,092 $ 612,000 $ 578,151
========== ========== ==========
67
Results of operations for producing activities
Year Ended December 31,
-------------------------------
2001 2000 1999
--------- --------- ---------
(In thousands)
Domestic
Revenues from oil and gas producing
activities................................. $ 332,646 $ 290,774 $ 211,647
Production costs............................ (177,862) (142,850) (117,680)
Exploration costs........................... (16,170) (5,503) (10,643)
Depreciation, depletion and amortization.... (63,485) (57,819) (70,024)
Provision for impairment of oil and gas
properties................................. (89,466) -- --
Income tax (provision) benefit.............. 5,750 (34,096) (2,727)
--------- --------- ---------
Results of operations from producing
activities (excluding corporate overhead
and interest costs)...................... $ (8,587) $ 50,506 $ 10,573
========= ========= =========
Foreign
Revenues from oil and gas producing
activities................................. $ 35,914 $ 40,881 $ 30,627
Production costs............................ (14,015) (13,626) (12,869)
Exploration costs........................... (5,888) (4,271) (3,374)
Depreciation, depletion and amortization.... (10,381) (8,085) (9,177)
Provision for impairment of oil and gas
properties................................. (14,024) -- --
Income tax (provision) benefit.............. 3,366 (6,005) (1,067)
--------- --------- ---------
Results of operations from producing
activities (excluding corporate overhead
and interest costs)...................... $ (5,028) $ 8,894 $ 4,140
========= ========= =========
Total
Revenues from oil and gas producing
activities................................. $ 368,560 $ 331,655 $ 242,274
Production costs............................ (191,877) (156,476) (130,549)
Exploration costs........................... (22,058) (9,774) (14,017)
Depreciation, depletion and amortization.... (73,866) (65,904) (79,201)
Provision for impairment of oil and gas
properties................................. (103,490) -- --
Income tax (provision) benefit.............. 9,116 (40,101) (3,794)
--------- --------- ---------
Results of operations from producing
activities (excluding corporate overhead
and interest costs)...................... $ (13,615) $ 59,400 $ 14,713
========= ========= =========
68
Our estimated total proved and proved developed reserves of oil and gas are
as follows:
Year Ended December 31,
--------------------------------------------------------
2001 2000 1999
----------------- ----------------- ------------------
Oil(/1/) Gas Oil(/1/) Gas Oil(/1/) Gas
(MBbl) (MMcf) (MBbl) (MMcf) (MBbl) (MMcf)
-------- ------- -------- ------- -------- --------
Domestic
Proved reserves at
beginning of year.... 196,692 165,977 239,190 145,125 164,300 403,256
Revisions of previous
estimates............ 15,164 (55,422) (40,340) 20,740 61,168 56,097
Extensions and
discoveries.......... 311 578 15,945 17,678 10,795 11,800
Production............ (14,536) (12,750) (15,591) (15,215) (15,892) (17,620)
Sales of reserves in-
place................ -- -- (2,512) (2,351) (10,270) (335,927)
Purchase of reserves
in-place............. 1,383 12,980 -- -- 29,089 27,519
------- ------- ------- ------- ------- --------
Proved reserves at end
of year.............. 199,014 111,363 196,692 165,977 239,190 145,125
======= ======= ======= ======= ======= ========
Proved developed
reserves
Beginning of year... 160,039 122,500 174,846 112,204 123,077 308,667
======= ======= ======= ======= ======= ========
End of year......... 169,507 92,890 160,039 122,500 174,846 112,204
======= ======= ======= ======= ======= ========
Foreign
Proved reserves at
beginning of year.... 23,202 -- 26,048 -- 25,841 --
Revisions of previous
estimates............ (5,478) -- (1,003) -- 2,042 --
Extensions and
discoveries.......... -- 1,129 -- -- -- --
Production............ (1,880) -- (1,843) -- (1,835) --
Sales of reserves in-
place................ -- -- -- -- -- --
Purchase of reserves
in-place............. -- -- -- -- -- --
------- ------- ------- ------- ------- --------
Proved reserves at end
of year.............. 15,844 1,129 23,202 -- 26,048 --
======= ======= ======= ======= ======= ========
Proved developed
reserves
Beginning of year... 11,013 -- 13,749 -- 10,242 --
======= ======= ======= ======= ======= ========
End of year......... 15,844 1,129 11,013 -- 13,749 --
======= ======= ======= ======= ======= ========
Total
Proved reserves at
beginning of year.... 219,894 165,977 265,238 145,125 190,141 403,256
Revisions of previous
estimates............ 9,686 (55,422) (41,343) 20,740 63,210 56,097
Extensions and
discoveries.......... 311 1,707 15,945 17,678 10,795 11,800
Production............ (16,416) (12,750) (17,434) (15,215) (17,727) (17,620)
Sales of reserves in-
place................ -- -- (2,512) (2,351) (10,270) (335,927)
Purchase of reserves
in-place............. 1,383 12,980 -- -- 29,089 27,519
------- ------- ------- ------- ------- --------
Proved reserves at end
of year.............. 214,858 112,492 219,894 165,977 265,238 145,125
======= ======= ======= ======= ======= ========
Proved developed
reserves
Beginning of year... 171,052 122,500 188,595 112,204 133,319 308,667
======= ======= ======= ======= ======= ========
End of year......... 185,351 94,019 171,052 122,500 188,595 112,204
======= ======= ======= ======= ======= ========
- --------
(/1/Includes)estimated NGL reserves.
69
Discounted future net cash flows
The standardized measure of discounted future net cash flows and changes
therein are shown below:
Year Ended December 31,
-------------------------------------
2001 2000 1999
----------- ----------- -----------
(In thousands)
Domestic
Future cash inflows................... $ 3,182,420 $ 6,168,033 $ 4,823,952
Future production costs............... (1,773,397) (2,968,448) (2,132,655)
Future development costs.............. (382,412) (349,150) (357,708)
----------- ----------- -----------
Future net inflows before income tax.. 1,026,611 2,850,435 2,333,589
Future income taxes................... (149,564) (896,974) (704,236)
----------- ----------- -----------
Future net cash flows................. 877,047 1,953,461 1,629,353
10% discount factor................... (366,050) (803,899) (739,181)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows................ $ 510,997 $ 1,149,562 $ 890,172
=========== =========== ===========
Foreign
Future cash inflows................... $ 248,569 $ 521,831 $ 469,327
Future production costs............... (123,628) (235,825) (177,150)
Future development costs.............. (6,863) (54,475) (46,750)
----------- ----------- -----------
Future net inflows before income tax.. 118,078 231,531 245,427
Future income taxes................... (25,237) (70,452) (66,971)
----------- ----------- -----------
Future net cash flows................. 92,841 161,079 178,456
10% discount factor................... (24,152) (55,752) (61,455)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows................ $ 68,689 $ 105,327 $ 117,001
=========== =========== ===========
Total
Future cash inflows................... $ 3,430,989 $ 6,689,864 $ 5,293,279
Future production costs............... (1,897,025) (3,204,273) (2,309,805)
Future development costs.............. (389,275) (403,625) (404,458)
----------- ----------- -----------
Future net inflows before income tax.. 1,144,689 3,081,966 2,579,016
Future income taxes................... (174,801) (967,426) (771,207)
----------- ----------- -----------
Future net cash flows................. 969,888 2,114,540 1,807,809
10% discount factor................... (390,202) (859,651) (800,636)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows................ $ 579,686 $ 1,254,889 $ 1,007,173
=========== =========== ===========
- --------
* In addition to the information presented in the above table, we entered into
swap and option arrangements on a portion of our future crude production as
of December 31, 2001 (see Note 16). The effects of these hedges would
increase the present value of future net cash flows discounted at a 10% rate
("PV-10") by approximately $17.8 million as of December 31, 2001.
70
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
Year Ended December 31,
----------------------------------
2001 2000 1999
---------- ---------- ----------
Domestic
Standardized measure--beginning of year.. $1,149,562 $ 890,172 $ 277,963
Sales, net of production costs........... (154,785) (147,924) (94,384)
Purchases of reserves in-place........... 13,759 -- 224,251
Net change in prices and production
costs................................... (904,288) 387,009 439,615
Extensions, discoveries and improved
recovery, net of future production and
development costs....................... 2,750 181,885 59,873
Changes in estimated future development
costs................................... (61,735) (8,806) (12,375)
Development costs incurred............... 62,562 79,857 32,380
Revisions of quantity estimates.......... 20,906 (233,132) 276,965
Accretion of discount.................... 151,060 110,162 27,796
Net change in income taxes............... 211,477 (149,592) (211,448)
Sales of reserves in-place............... -- (9,242) (151,348)
Changes in production rates and other.... 19,729 49,173 20,884
---------- ---------- ----------
Standardized measure--end of year........ $ 510,997 $1,149,562 $ 890,172
========== ========== ==========
Foreign
Standardized measure--beginning of year.. $ 105,327 $ 117,001 $ 21,970
Sales, net of production costs........... (21,899) (27,255) (17,759)
Purchases of reserves in-place........... -- -- --
Net change in prices and production
costs................................... (56,360) 19,595 59,641
Extensions, discoveries and improved
recovery, net of future production and
development costs....................... 114 -- --
Changes in estimated future development
costs................................... 16,455 (7,167) 12,711
Development costs incurred............... 16,100 4,406 7,175
Revisions of quantity estimates.......... (25,804) (7,204) 8,479
Accretion of discount.................... 13,861 14,300 2,197
Net change in income taxes............... 24,150 (7,284) (26,001)
Sales reserves in-place.................. -- -- --
Changes in production rates and other.... (3,255) (1,065) 48,588
---------- ---------- ----------
Standardized measure--end of year........ $ 68,689 $ 105,327 $ 117,001
========== ========== ==========
Total
Standardized measure--beginning of year.. $1,254,889 $1,007,173 $ 299,933
Sales, net of production costs........... (176,684) (175,179) (112,143)
Purchases of reserves in-place........... 13,759 -- 224,251
Net change in prices and production
costs................................... (960,648) 406,604 499,256
Extensions, discoveries and improved
recovery, net of future production and
development costs....................... 2,864 181,885 59,873
Changes in estimated future development
costs................................... (45,280) (15,973) 336
Development costs incurred............... 78,662 84,263 39,555
Revisions of quantity estimates.......... (4,898) (240,336) 285,444
Accretion of discount.................... 164,921 124,462 29,993
Net change in income taxes............... 235,627 (156,876) (237,449)
Sales of reserves in-place............... -- (9,242) (151,348)
Changes in production rates and other.... 16,474 48,108 69,472
---------- ---------- ----------
Standardized measure--end of year........ $ 579,686 $1,254,889 $1,007,173
========== ========== ==========
- --------
* In addition to the information presented in the above table, the Company had
entered into swap and option arrangements on a portion of its future crude
production as of December 31, 2001 (see Note 16). The effects of these
hedges would increase the PV-10 by approximately $17.8 million as of
December 31, 2001.
71
19. Selected Quarterly Financial Data (Unaudited)
Quarter Ended(/1/)
--------------------------------------------
March
31, June 30, September 30, December 31,
2001 2001 2001 2001
-------- -------- ------------- ------------
(In thousands, except share data)
Revenues.......................... $117,522 $100,696 $83,146 $ 69,891
Operating earnings (loss)......... 28,505 16,109 7,843 (134,167)
Net income (loss)................. 9,603 2,659 (2,383) (89,050)
Earnings (loss) per Common share--
Basic............................ 0.58 0.16 (0.14) (5.28)
Earnings (loss) per Common share--
Diluted.......................... 0.57 0.14 (0.14) (5.28)
Quarter Ended(/1/)(/2/)
--------------------------------------------
March
31, June 30, September 30, December 31,
2000 2000 2000 2000
-------- -------- ------------- ------------
(In thousands, except share data)
Revenues.......................... $ 71,505 $ 72,171 $91,274 $ 101,655
Operating earnings................ 20,372 20,505 32,689 25,424
Net income........................ 651 263 8,850 1,871
Earnings per Common share before
cumulative
effect--Basic.................... 0.08 0.02 0.51 0.11
Earnings per Common share before
cumulative
effect--Diluted.................. 0.08 0.00 0.49 0.10
Earnings per Common share--Basic.. 0.04 0.02 0.51 0.11
Earnings per Common share--
Diluted.......................... 0.04 0.00 0.49 0.10
- --------
(/1/The)sum of the individual quarterly net income (loss) per common share may
not agree with year-to-date net income (loss) per common share as each
quarterly computation is based on the weighted average number of common
shares outstanding during that period.
(/2/Results)for the 2000 quarters were revised due to a change in accounting
for processed fuel oil and natural gas liquids inventories (see Note 2).
72
SCHEDULE II
NUEVO ENERGY COMPANY
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2001, 2000 and 1999
(In thousands)
Additions
--------------------------------
Balance at Charged to Charged Balance
Beginning Costs to Other at End
of Period and Expenses Accounts Deductions of Period
---------- ------------ -------- ---------- ---------
2001
Allowance for doubtful
accounts.............. $ 766 $1,314 $ -- $ 800 $1,280
Valuation allowance on
deferred taxes........ 1,777 -- -- -- 1,777
Legal reserves......... 807 4,000 -- -- 4,807
Environmental
reserves.............. 4,479 -- 613 -- 5,092
2000
Allowance for doubtful
accounts.............. -- -- 766 -- 766
Valuation allowance on
deferred taxes........ 1,777 -- -- -- 1,777
Legal reserves......... 1,951 -- -- 1,144 807
Environmental
reserves.............. 4,500 -- -- 21 4,479
1999
Valuation allowance on
deferred taxes........ 17,646 -- -- 15,869 1,777
Legal reserves......... 1,515 236 200 -- 1,951
Environmental
reserves.............. -- -- 4,500 -- 4,500
73
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
On March 9, 2001, we notified KPMG LLP ("KPMG") that their engagement as
our independent accountants would be terminated following the issuance of
their report on our consolidated financial statements for the fiscal year
ended December 31, 2000. On March 9, 2001, our Board of Directors, on the
recommendation of the Audit Committee, appointed Arthur Andersen LLP as our
independent accountants to audit our consolidated financial statements for the
year ending December 31, 2001.
We and KPMG have not, in connection with the audit of our consolidated
financial statements for each of the prior two years ended December 31, 2000
and December 31, 1999, or for any subsequent or interim period prior to and
including March 9, 2001, had any disagreement on any matter of accounting
principles or practice, financial statement disclosure, or auditing scope or
procedure, which disagreement, if not resolved to KPMG's satisfaction, would
have caused KPMG to make reference to the subject matter of the disagreement
in connection with its reports.
The reports of KPMG on our financial statements for the past two fiscal
years did not contain an adverse opinion or a disclaimer of opinion and were
not qualified or modified as to uncertainty or audit scope.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item will be included in our definitive
proxy statement, which will be filed not later than 120 days after December
31, 2001, and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item will be included in our definitive
proxy statement, which will be filed not later than 120 days after December
31, 2001, and 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 our definitive
proxy statement, which will be filed not later than 120 days after December
31, 2001, and 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, which will be filed not later than 120 days after December
31, 2001, and is incorporated herein by reference.
74
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements.
Our consolidated financial statements are included in Part II, Item 8 of
this report:
Report of Independent Public Accountants--2001....................... 37
Independent Auditors Report--2000 and 1999........................... 38
Consolidated Statements of Income.................................... 39
Consolidated Balance Sheets.......................................... 40
Consolidated Statements of Cash Flows................................ 41
Consolidated Statements of Stockholder's Equity...................... 42
Consolidated Statements of Comprehensive Income and Changes in
Accumulated Other Comprehensive Income.............................. 43
Notes to the Consolidated Financial Statements....................... 44
2. Financial statement schedules and supplementary information required
to be submitted.
Schedule II--Valuation and qualifying accounts .................... 73
Schedules other than that listed above are omitted because they are
not applicable.
3. Exhibit List......................................................76
(b) Reports on Form 8-K:
. We filed a Current Report on Form 8-K, dated November 9, 2001,
reporting Item 9. Regulation FD Disclosure.
. We filed a Current Report on Form 8-K, dated January 22, 2002,
reporting Item 9. Regulation FD Disclosure.
75
NUEVO ENERGY COMPANY
EXHIBIT LIST
December 31, 2001
Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by and asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" constitute a management
contract or compensatory plan or arrangement required to be filed as an exhibit
to this report pursuant to Item 14 (c) of Form 10-K.
(3) Articles of Incorporation and bylaws.
3.1 Certificate of Incorporation of Nuevo Energy Company (Exhibit 3.1 to our
1999 Second Quarter Form 10-Q).
3.2 Certificate of Amendment to the Certificate of Incorporation of Nuevo
Energy Company (Exhibit 3.2 to our 1999 Second Quarter Form 10-Q).
3.3 Bylaws of Nuevo Energy Company (Exhibit 3.3 to our 1999 Second Quarter
Form 10-Q).
3.4 Amendment to section 3.1 of the Bylaws of Nuevo Energy Company (Exhibit
3.4 to our 1999 Second Quarter Form 10-Q).
(4) Instruments defining the rights of security holders, including indentures.
4.1 Specimen Stock Certificate (Exhibit 4.1 to our Form S-4 (No. 33-33873)
filed under the Securities Act of 1933).
4.2 Indenture dated April 1, 1996 among Nuevo Energy Company as Issuer,
various Subsidiaries as the Guarantors, and State Street Bank and Trust
Company as the Trustee--9 1/2% Senior Subordinated Notes due 2006.
(Incorporated by reference from Form S-3 (No. 333-1504).
4.3 Form of Amended and Restated Declaration of Trust dated December 23,
1996, among the Company, as Sponsor, Wilmington Trust Company, as
Institutional Trustee and Delaware Trustee, and Michael D. Watford,
Robert L. Gerry, III and Robert M. King, as Regular Trustees. (Exhibit
4.1 to our Form 8-K filed on December 23, 1996).
4.4 Form of Subordinated Indenture dated as of November 25, 1996, between
the Company and Wilmington Trust Company, as Indenture Trustee.
(Exhibit 4.2 to Form 8-K filed on December 23, 1996).
4.5 Form of First Supplemental Indenture dated December 23, 1996, between
the Company and Wilmington Trust Company, as Indenture Trustee.
(Exhibit 4.3 to Form 8-K filed on December 23, 1996).
4.6 Form of Preferred Securities Guarantee Agreement dated as of December
23, 1996, between the Company and Wilmington Trust Company, as
Guarantee Trustee. (Exhibit 4.4 to Form 8-K filed on December 23,
1996).
4.7 Form of Certificate representing TECONS. (Exhibit 4.5 to Form 8-K filed
on December 23, 1996).
4.8 Shareholder Rights Plan, dated March 5, 1997, between Nuevo Energy
Company and American Stock Transfer & Trust Company, as Rights Agent
(Exhibit 1 to our Form 8-A filed on April 1, 1997).
4.9 Release and Termination of Subsidiary Guarantees with respect to the 9
% Senior Subordinated Notes due 2006. (Exhibit 4.11 to our 1997 Form
10-K)
4.10 Second Supplemental Indenture to the Indenture dated April 1, 1996,
dated August 9, 1999 between Nuevo Energy Company and State Street Bank
and Trust Company--9 1/2% Senior Subordinated Notes due 2006 (Exhibit
4.10 to our Form S-4 (No. 333-90235) filed on November 3, 1999).
76
4.11 Indenture dated as of August 20, 1999, between Nuevo Energy Company and
State Street Bank Trust Company, as Trustee (Exhibit 4.11 to our Form
S-4 (No. 333-90235) filed on November 3, 1999).
4.12 Registration Agreement dated August 20, 1999, between Nuevo Energy
Company, Banc of America Securities LLC and Salomon Smith Barney Inc.
(Exhibit 4.12 to our Form S-4 (No. 333-90235) filed on November 3,
1999).
4.13 Indenture dated September 26, 2000, between Nuevo Energy Company and
State Street Bank and Trust Company as the Trustee--9 3/8% Senior
subordinated Notes due 2010 (Exhibit 4.12 to our 2000 Third Quarter
Form 10-Q).
4.14 Registration Agreement dated September 26, 2000, between Nuevo Energy
Company and Banc of America Securities LLC, Banc One Capital Markets,
Inc. and J.P. Morgan & Co. (Exhibit 4.13 to our 2000 Third Quarter Form
10-Q).
(10) Material Contracts.
10.1 Third Restated Credit Agreement dated June 7, 2000, between Nuevo
Energy Company (Borrower) and Bank of America N.A. (Administrative
Agent), Bank One, NA (Syndication Agent), Bank of Montreal
(Documentation Agent) and certain lenders (Exhibit 10.1 to our 2000
Second Quarter Form 10-Q).
10.2 1990 Stock Option Plan, as amended (Exhibit 10.8 to our Form S-1 dated
July 13, 1992).
10.3 1993 Stock Incentive Plan, as amended (Exhibit 4.2 to our Form S-8
(No. 333-21063) filed on February 4, 1997.)
10.4 1999 Stock Incentive Plan (Exhibit 99.1 to our Form S-8 (No. 333-
87899) filed on September 28, 1999).
10.5 Nuevo Energy Company Deferred Compensation Plan (Exhibit 99 to our
Form S-8 (No. 333-51217) filed on April 28, 1998).
10.6 Stock Purchase Agreement, dated as of June 30, 1994, among Amoco
Production Company ("APC"), Walter International Inc. ("Walter"),
Walter Congo Holdings, Inc. ("Walter Holdings"), Walter International
Congo, Inc. (before the merger "Walter Congo" and after the merger
"Old Walter Congo"), Nuevo, Nuevo Holding and The Nuevo Congo Company
(before the merger, "Nuevo Congo" and after the merger, "Old Nuevo
Congo"). (Exhibit 2.1 to Form 8-K dated March 10, 1995).
10.7 Amendment to Stock Purchase Agreement dated as of September 19, 1994,
among APC, Walter Congo, Nuevo Congo, Walter Holdings, Nuevo Holding,
Walter and Nuevo. (Exhibit 2.2 to Form 8-K dated March 10, 1995).
10.8 Second Amendment to Stock Purchase Agreement dated as of October 15,
1994, among APC, Walter Congo, Nuevo Congo, Walter Holdings, Nuevo
Holding, Walter and Nuevo. (Exhibit 2.3 to Form 8-K dated March 10,
1995).
10.9 Third Amendment to Stock Purchase Agreement dated as of December 2,
1994, among APC, Walter Congo, Nuevo Congo, Walter Holdings, Nuevo
Holding, Walter and Nuevo. (Exhibit 2.4 to Form 8-K dated March 10,
1995.)
10.10 Fourth Amendment to Stock Purchase Agreement dated as of February 23,
1995, among APC, Walter Congo, Nuevo Congo, Walter Holdings, Nuevo
Holding, Walter and Nuevo. (Exhibit 2.5 to Form 8-K dated March 10,
1995).
10.11 Tax Agreement dated as of February 23, 1995, executed by APC, Amoco
Congo Exploration Company ("ACEC"), Amoco Congo Production Company
("ACPC"), Walter, Walter Holdings, Walter Congo, Nuevo, Nuevo Holding
and Nuevo Congo. (Exhibit 2.6 to Form 8-K dated March 10, 1995).
77
10.12 Agreement and Plan of Merger executed by Nuevo Congo, Nuevo Holding
and APC dated February 24, 1995. (Exhibit 2.7 to Form 8-K dated March
10, 1995).
10.13 Finance Agreement dated as of December 28, 1994, among Nuevo Holding,
Nuevo Congo and The Overseas Private Investment Corporation ("OPIC").
(Exhibit 2.8 to Form 8-K dated March 10, 1995).
10.14 Subordination Agreement dated December 28, 1994, among Nuevo Congo,
Nuevo Holding, Walter Congo, Walter Holdings and APC. (Exhibit 2.9 to
Form 8-K dated March 10, 1995).
10.15 Guaranty covering the obligations of Nuevo Congo and Walter Congo
under the Stock Purchase Agreement dated February 24, 1995, executed
by Walter and Nuevo. (Exhibit 2.10 to Form 8-K dated March 10, 1995).
10.16 Inter-Purchaser Agreement dated as of December 28, 1994, among Walter,
Old Walter Congo, Walter Holdings, Nuevo, Old Nuevo Congo and Nuevo
Holding. (Exhibit 2.11 to Form 8-K dated March 10, 1995).
10.17 Latent ORRI Contract dated February 25, 1995, among Walter, Walter
Holdings, Walter Congo, Nuevo, Nuevo Holding and Nuevo Congo. (Exhibit
2.12 to Form 8-K dated March 10, 1995).
10.18 Latent Working Interest Contract dated February 25, 1995, among
Walter, Walter Holdings, Walter Congo, Nuevo, Nuevo Holding and Nuevo
Congo. (Exhibit 2.13 to Form 8-K dated March 10, 1995).
10.19 Asset Purchase Agreement dated as of February 16, 1996 between Nuevo
Energy Company, the Purchaser, and Union Oil Company of California as
Seller. (Exhibit 2.1 to Form S-3 (No. 333-1504).
10.20 Asset Purchase Agreement dated as of April 4, 1997, by and among Torch
California Company and Express Acquisition Company, as Sellers, and
Nuevo Energy Company, as Purchaser. (Exhibit 2.2 to Form S-3 (No. 333-
1504)).
10.21 Employment Agreement with Douglas L. Foshee. (Exhibit 10.23 to our
1997 Form 10-K)
10.22 Employment Agreement with Robert M. King. (Exhibit 10.24 to our 1998
Form 10-K).
10.23 Employment Agreement with Dennis Hammond. (Exhibit 10.26 to our 1997
Form 10-K)
10.24 Employment Agreement with Michael P. Darden. (Exhibit 10.1 to our 1998
Third Quarter Form 10-Q).
10.25 Purchase and sale agreement dated October 16, 1998 between Nuevo
Energy Company (Seller) and Samson Lone Star Limited Partnership
(Buyer). (Exhibit 10.28 to our 1998 Form 10-K).
10.26 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. (Exhibit 10.29 to our 1998
Form 10-K).
10.27 Employment Agreement with Bruce Murchison dated June 1, 1999. (Exhibit
10.27 to our 1999 Third Quarter Form 10-Q).
10.28 Employment Agreement with John P. McGinnis dated July 15, 1999.
(Exhibit 10.28 to our 1999 Third Quarter Form 10-Q).
10.29 Crude Oil Purchase Agreement dated February 4, 2000 between Nuevo
Energy Company and Tosco Corporation. (Exhibit 10.1 to Form 8-K dated
March 23, 2000).
10.30 Employment Agreement with Phillip Gobe dated February 26, 2001.
(Exhibit 10.30 to our 2000 Form 10-K).
10.31 Severance Protection Agreement dated March 25, 2001. (Exhibit 10.31 to
our 2000 Form 10-K).
10.32 Amendment to 1999 Stock Incentive Plan (Exhibit 99.1 to our Form S-8,
filed on October 21, 2001).
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10.33 2001 Stock Incentive Plan (Exhibit 99.1 to our Form S-8, filed on
October 21, 2001).
10.34 Employment Agreement with James L. Payne dated October 15, 2001.
(Exhibit 10.1 to our 2001 Third Quarter Form 10-Q).
+10.35 Janet F. Clark Stock Option Plan
+10.36 George B. Nilsen Stock Option Plan
+10.37 Resignation Agreement with Robert M. King November 30, 2001.
+10.38 Resignation Agreement with Dennis Hammond dated January 9, 2002.
+10.39 Resignation Agreement with Michael P. Darden dated January 11, 2002.
(21) Subsidiaries of the Registrant
(23) Consents of experts and counsel
*23.1 Consent of ARTHUR ANDERSEN LLP
*23.2 Consent of KPMG LLP
(99) Additional Exhibits
*99.1 Management's representation regarding Arthur Andersen LLP
79
GLOSSARY OF OIL AND GAS TERMS
Terms used to describe quantities of oil and natural gas
. Bbl--One stock tank barrel, or 42 US gallons liquid volume, of crude oil
or other liquid hydrocarbons.
. Bcf--One billion cubic feet of natural gas.
. Bcfe--One billion cubic feet of natural gas equivalent.
. BOE--One barrel of oil equivalent, converting gas to oil at the ratio of
6 Mcf of gas to 1 Bbl of oil.
. BOPD--One barrel of oil per day.
. MBbl--One thousand Bbls.
. Mcf--One thousand cubic feet of natural gas.
. MMBbl--One million Bbls of oil or other liquid hydrocarbons.
. MMcf--One million cubic feet of natural gas.
. MBOE--One thousand BOE.
. MMBOE--One million BOE.
Terms used to describe the Company's interests in wells and acreage
. Gross oil and gas wells or acres--The Company's gross wells or gross
acres represent the total number of wells or acres in which the Company
owns a working interest.
. Net oil and gas wells or acres--Determined by multiplying "gross" oil
and natural gas wells or acres by the working interest that the Company
owns in such wells or acres represented by the underlying properties.
Terms used to assign a present value to the Company's reserves
. Standard measure of proved reserves--The present value, discounted at
10%, of the pre-tax future net cash flows attributable to estimated net
proved reserves. The Company calculates this amount by assuming that it
will sell the oil and gas production attributable to the proved reserves
estimated in its independent engineer's reserve report for the prices it
received for the production on the date of the report, unless it had a
contractual arrangement specific to a property to sell the production
for a different price. The Company also assumes that the cost to produce
the reserves will remain constant at the costs prevailing on the date of
the report. The assumed costs are subtracted from the assumed revenues
resulting in a stream of future net cash flows. Estimated future income
taxes using rates in effect on the date of the report are deducted from
the net cash flow stream. The after-tax cash flows are discounted at 10%
to result in the standardized measure of the Company's proved reserves.
The standardized measure of the Company's proved reserves is disclosed
in the Company's audited financial statements in Note 14.
. Pre-tax discounted present value--The discounted present value of proved
reserves is identical to the standardized measure, except that estimated
future income taxes are not deducted in calculating future net cash
flows. The Company discloses the discounted present value without
deducting estimated income taxes to provide what it believes is a better
basis for comparison of its reserves to the producers who may have
different tax rates.
Terms used to classify our reserve quantities
. Proved reserves--The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering
data, appear with reasonable certainty to be recoverable in the future
from known oil and natural gas reservoirs under existing economic and
operating conditions.
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The SEC definition of proved oil and gas reserves, per Article 4-10(a)(2)
of Regulation S-X, is as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e., prices and costs as of the date
the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalations
based upon future conditions.
(a) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion delineated
by drilling and defined by gas-oil and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
(b) Reserves which can be produced economically through application of
improved recovery, techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.
(c) Estimates of proved reserves do not include the following: (1) oil
that may become available from known reservoirs, but is classified
separately as "indicated additional reserves"; (2) crude oil, natural gas,
and natural gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir characteristics, or
economic factors; (3) crude oil, natural gas, and natural gas liquids, that
may occur in undrilled prospects; and (4) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales, coal, gilsonite
and other such sources.
. Proved developed reserves--Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
. Proved undeveloped reserves--Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required.
Terms which describe the cost to acquire the Company's reserves
. Finding costs--The Company's finding costs compare the amount the
Company spent to acquire, explore and develop its oil and gas
properties, explore for oil and gas and to drill and complete wells
during a period, with the increases in reserves during the period. This
amount is calculated by dividing the net change in the Company's
evaluated oil and property costs during a period by the change in proved
reserves plus production over the same period. The Company's finding
costs as of December 31 of any year represent the average finding costs
over the three-year period ending December 31 of that year.
Terms which describe the productive life of a property or group of properties
. Reserve life index--A measure of the productive life of an oil and gas
property or a group of oil and gas properties, expressed in years.
Reserve life index for the years ended December 31, 2000, 1999 or 1998
equal the estimated net proved reserves attributable to a property or
group of properties divided by production from the property or group of
properties for the four fiscal quarters preceding the date as of which
the proved reserves were estimated.
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,
81
a specific portion of oil and natural gas produced, without any deduction
for the costs to explore for, develop or produce the oil and natural gas.
A royalty interest owner has no right to consent to or approve the
operation and development of the property, while the owners of the
working interests have the exclusive right to exploit the mineral on the
land.
. Working interest--A real property interest entitling the owner to
receive a specified percentage of the proceeds of the sale of oil and
natural gas production or a percentage of the production, but requiring
the owner of the working interest to bear the cost to explore for,
develop and produce such oil and natural gas. A working interest owner
who owns a portion of the working interest may participate either as
operator or by voting his percentage interest to approve or disapprove
the appointment of an operator and drilling and other major activities
in connection with the development and operation of a property.
. Net revenue interest--A real property interest entitling the owner to
receive a specified percentage of the proceeds of the sale of oil and
natural gas production or a percentage of the production, net of royalty
interests and costs to explore for, develop and produce such oil and
natural gas.
Terms used to describe seismic operations
. Seismic data--Oil and gas companies use seismic data as their principal
source of information to locate oil and gas deposits, both to aid in
exploration for new deposits and to manage or enhance production from
known reservoirs. To gather seismic data, an energy source is used to
send sound waves into the subsurface strata. These waves are reflected
back to the surface by underground formations, where they are detected
by geophones which digitize and record the reflected waves. Computers
are then used to process the raw data to develop an image of underground
formations.
. 2-D seismic data--2-D seismic survey data has been the standard
acquisition technique used to image geologic formations over a broad
area. 2-D seismic data is collected by a single line of energy sources
which reflect seismic waves to a single line of geophones. When
processed, 2-D seismic data produces an image of a single vertical plane
of sub-surface data.
. 3-D seismic--3-D seismic data is collected using a grid of energy
sources, which are generally spread over several miles. A 3-D survey
produces a three dimensional image of the subsurface geology by
collecting seismic data along parallel lines and creating a cube of
information that can be divided into various planes, thus improving
visualization. Consequently, 3-D seismic data is a more reliable
indicator of potential oil and natural gas reservoirs in the area
evaluated than 2-D seismic data.
The Company's miscellaneous definitions
. Infill drilling--Infill drilling is the drilling of an additional well
or additional wells in excess of those provided for by a spacing order
in order to more adequately drain a reservoir.
. No. 6 fuel oil (Bunker)--No. 6 fuel oil is a heavy residual fuel oil
used by ships, industry, and for large-scale heating installations.
. Upstream oil and gas properties--Upstream is a term used in describing
operations performed before those at a point of reference. Production is
an upstream operation and marketing is a downstream operation when the
refinery is used as a point of reference. On a gas pipeline, gathering
activities are considered to have ended when gas reaches a central point
for delivery into a single line, and facilities used before this point
of reference are upstream facilities used in gathering, whereas
facilities employed after commingling at the central point and employed
to make ultimate delivery of the gas are downstream facilities.
82
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: April 1, 2002 /s/ James L. Payne
By: _________________________________
James L. Payne
Chairman, President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report is signed below by the following persons on behalf of the registrant
and in the capacities and on the dates indicated.
Signature Date
--------- ----
/s/ James L. Payne April 1, 2002
*By: _________________________________
James L. Payne
Chairman, President and Chief
Executive Officer (Principal Executive
Officer)
/s/ Janet f. Clark April 1, 2002
*By: _________________________________
Janet F. Clark
Senior Vice President and Chief
Financial Officer (Principal Financial
and Accounting Officer)
/s/ Isaac Arnold, Jr. April 1, 2002
*By: _________________________________
Isaac Arnold, Jr.
Director
/s/ David H. Batchelder April 1, 2002
*By: _________________________________
David H. Batchelder
Director
/s/ Charles M. Elson April 1, 2002
*By: _________________________________
Charles M. Elson
Director
/s/ Robert L. Gerry III April 1, 2002
*By: _________________________________
Robert L. Gerry III
Director
/s/ James T. Jongebloed April 1, 2002
*By: _________________________________
James T. Jongebloed
Director
/s/ Gary R. Peterson April 1, 2002
*By: _________________________________
Gary R. Peterson
Director
/s/ David Ross April 1, 2002
*By: _________________________________
David Ross
Director
/s/ Robert W. Shower April 1, 2002
*By: _________________________________
Robert W. Shower
Director
83