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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(Mark One)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 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: 0-7062
NOBLE AFFILIATES, INC.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
Delaware 73-0785597
(STATE OF INCORPORATION) (I.R.S. EMPLOYER IDENTIFICATION NUMBER)
350 Glenborough Drive, Suite 100
Houston, Texas 77067
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
(Registrant's telephone number, including area code)
(281) 872-3100
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of Each Exchange on
Title of Each Class Which Registered
------------------- ----------------
Common Stock, $3.33-1/3 par value New York Stock Exchange, Inc.
Preferred Stock Purchase Rights New York Stock Exchange, Inc.
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 the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /X/
Aggregate market value of Common Stock held by nonaffiliates as of February 15,
2002: $1,747,001,553.
Number of shares of Common Stock outstanding as of February 15, 2002:
57,007,724.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for the 2002 Annual
Meeting of Stockholders to be held on April 23, 2002, which will be filed with
the Securities and Exchange Commission within 120 days after December 31, 2001,
are incorporated by reference into Part III.
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TABLE OF CONTENTS
PART I.
Item 1. Business ............................................................................... 1
General ................................................................................ 3
Oil and Gas ............................................................................ 3
Exploration Activities ............................................................. 4
Production Activities .............................................................. 5
Acquisitions of Oil and Gas Properties, Leases and Concessions...................... 6
Marketing .......................................................................... 6
Regulations and Risks .............................................................. 7
Competition ........................................................................ 8
Unconsolidated Subsidiary .............................................................. 9
Employees .............................................................................. 9
Item 2. Properties ............................................................................. 9
Offices ................................................................................ 9
Oil and Gas ............................................................................ 9
Item 3. Legal Proceedings ...................................................................... 17
Item 4. Submission of Matters to a Vote of Security Holders .................................... 17
Executive Officers of the Registrant ................................................... 17
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters .................. 19
Item 6. Selected Financial Data ................................................................ 21
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations .. 22
Item 7a. Quantitative and Qualitative Disclosures About Market Risk ............................. 28
Item 8. Financial Statements and Supplementary Data ............................................ 31
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .. 58
PART III
Item 10. Directors and Executive Officers of the Registrant ..................................... 59
Item 11. Executive Compensation ................................................................. 59
Item 12. Security Ownership of Certain Beneficial Owners and Management ......................... 59
Item 13. Certain Relationships and Related Transactions ......................................... 59
PART IV
Item 14. Financial Statement Schedules, Exhibits and Reports on Form 8-K ........................ 59
ii
PART I
ITEM 1. BUSINESS.
CAUTIONARY STATEMENT FOR PURPOSES OF THE PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995 AND OTHER FEDERAL SECURITIES LAWS
GENERAL. We are including the following discussion to inform our existing and
potential security holders generally of some of the risks and uncertainties that
can affect the Company and to take advantage of the "safe harbor" protection for
forward-looking statements afforded under federal securities laws. From time to
time, the Company's management or persons acting on our behalf make
forward-looking statements to inform existing and potential security holders
about the Company. These statements may include projections and estimates
concerning the timing and success of specific projects and the Company's future
(1) income, (2) oil and gas production, (3) oil and gas reserves and reserve
replacement and (4) capital spending. Forward-looking statements are generally
accompanied by words such as "estimate," "project," "predict," "believe,"
"expect," "anticipate," "plan," "goal" or other words that convey the
uncertainty of future events or outcomes. Sometimes we will specifically
describe a statement as being a forward-looking statement. In addition, except
for the historical information contained in this Form 10-K, the matters
discussed in this Form 10-K are forward-looking statements. These statements by
their nature are subject to certain risks, uncertainties and assumptions and
will be influenced by various factors. Should any of the assumptions underlying
a forward-looking statement prove incorrect, actual results could vary
materially.
We believe the factors discussed below are important factors that could cause
actual results to differ materially from those expressed in a forward-looking
statement made herein or elsewhere by us or on our behalf. The factors listed
below are not necessarily all of the important factors. Unpredictable or unknown
factors not discussed herein could also have material adverse effects on actual
results of matters that are the subject of forward-looking statements. We do not
intend to update our description of important factors each time a potential
important factor arises. We advise our stockholders that they should (1) be
aware that important factors not described below could affect the accuracy of
our forward-looking statements and (2) use caution and common sense when
analyzing our forward-looking statements in this document or elsewhere. All of
such forward-looking statements are qualified in their entirety by this
cautionary statement.
VOLATILITY AND LEVEL OF HYDROCARBON COMMODITY PRICES. Historically, natural gas
and crude oil prices have been volatile. These prices rise and fall based on
changes in market demand and changes in the political, regulatory and economic
climate and other factors that affect commodities markets generally and are
outside of our control. Some of our projections and estimates are based on
assumptions as to the future prices of natural gas and crude oil. These price
assumptions are used for planning purposes. We expect our assumptions will
change over time and that actual prices in the future may differ from our
estimates. Any substantial or extended decline in the actual prices of natural
gas and/or crude oil could have a material adverse effect on (1) the Company's
financial position and results of operations (including reduced cash flow and
borrowing capacity), (2) the quantities of natural gas and crude oil reserves
that we can economically produce, (3) the quantity of estimated proved reserves
that may be attributed to our properties and (4) our ability to fund our capital
program.
PRODUCTION RATES AND RESERVE REPLACEMENT. Projecting future rates of oil and gas
production is inherently imprecise. Producing oil and gas reservoirs generally
have declining production rates. Production rates depend on a number of factors,
including geological, geophysical and engineering factors, weather, production
curtailments or restrictions, prices for natural gas and crude oil, available
transportation capacity, market demand and the political, economic and
regulatory climate. Another factor affecting production rates is our ability to
replace depleting reservoirs with new reserves through exploration success or
acquisitions. Exploration success is difficult to predict, particularly over the
short term, where results can vary widely from year to year. Moreover, our
ability to replace reserves over an extended period depends not only on the
total volumes found, but also on the cost of finding and developing such
reserves. Depending on the general price environment for natural gas and crude
oil, our finding
1
and development costs may not justify the use of resources to explore for and
develop such reserves. There can be no assurances as to the level or timing of
success, if any, that we will be able to achieve in finding and developing or
acquiring additional reserves. Acquisitions that result in successful
exploration or exploitation projects require assessment of numerous factors,
many of which are beyond our control. There can be no assurance that any
acquisition of property interests by us will be successful and, if unsuccessful,
that such failure will not have an adverse effect on our financial condition,
results of operations and cash flows.
RESERVE ESTIMATES. Our forward-looking statements may be predicated on our
estimates of our oil and gas reserves. All of the reserve data in this Form 10-K
or otherwise made by or on behalf of the Company are estimates. Reservoir
engineering is a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in an exact way. There are numerous
uncertainties inherent in estimating quantities of proved natural gas and oil
reserves. Projecting future rates of production and timing of future development
expenditures is also inexact. Many factors beyond our control affect these
estimates. In addition, the accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Therefore, it is common that estimates made by different engineers
will vary. The results of drilling, testing and production after the date of an
estimate may also require a revision of that estimate, and these revisions may
be material. As a result, reserve estimates are generally different from the
quantities of oil and gas that are ultimately recovered.
LAWS AND REGULATIONS. Our forward-looking statements are generally based on the
assumption that the legal and regulatory environment will remain stable. Changes
in the legal and/or regulatory environment could have a material adverse effect
on our future results of operations and financial condition. Our ability to
economically produce and sell our oil and gas production is affected and could
possibly be restrained by a number of legal and regulatory factors, including
federal, state and local laws and regulations in the U.S. and laws and
regulations of foreign nations, affecting (1) oil and gas production, including
allowable rates of production by well or proration unit, (2) taxes applicable to
the Company and/or our production, (3) the amount of oil and gas available for
sale, (4) the availability of adequate pipeline and other transportation and
processing facilities and (5) the marketing of competitive fuels. Our operations
are also subject to extensive federal, state and local laws and regulations in
the U.S. and laws and regulations of foreign nations relating to the generation,
storage, handling, emission, transportation and discharge of materials into the
environment. These environmental laws and regulations continue to change and may
become more onerous or restrictive in the future. Our forward-looking statements
are generally based upon the expectation that we will not be required in the
near future to expend amounts to comply with environmental laws and regulations
that are material in relation to our total capital expenditures program.
However, inasmuch as such laws and regulations are frequently changed, we are
unable to accurately predict the ultimate cost of such compliance.
DRILLING AND OPERATING RISKS. Our drilling operations are subject to various
risks common in the industry, including cratering, explosions, fires and
uncontrollable flows of oil, gas or well fluids. In addition, a substantial
amount of our operations are currently offshore, domestically and
internationally, and subject to the additional hazards of marine operations,
such as loop currents, capsizing, collision and damage or loss from severe
weather. Our drilling operations are also subject to the risk that no
commercially productive natural gas or oil reserves will be encountered. The
cost of drilling, completing and operating wells is often uncertain, and
drilling operations may be curtailed, delayed or canceled as a result of a
variety of factors, including drilling conditions, pressure or irregularities in
formations, equipment failures or accidents and adverse weather conditions.
COMPETITION. The Company's forward-looking statements are generally based on a
stable competitive environment. Competition in the oil and gas industry is
intense both domestically and internationally. We actively compete for reserve
acquisitions and exploration leases and licenses, as well as in the gathering
and marketing of natural gas and crude oil. Our competitors include the major
oil companies, independent oil and gas concerns, individual producers, natural
gas and crude oil marketers and major pipeline companies, as well as
participants in other industries supplying energy and fuel to industrial,
commercial and individual consumers. To the extent our competitors have greater
financial resources than currently available to us, we may be disadvantaged in
effectively competing for certain reserves, leases and licenses. Recently
announced consolidations in the industry may
2
enhance the financial resources of certain of our competitors. From time to
time, the level of industry activity may result in a tight supply of labor or
equipment required to operate and develop oil and gas properties. The
availability of drilling rigs and other equipment, as well as the level of rates
charged, may have an effect on our ability to compete and achieve success in our
exploration and production activities.
In marketing our production, we compete with other producers and marketers on
such factors as deliverability, price, contract terms and quality of product and
service. Competition for the sale of energy commodities among competing
suppliers is influenced by various factors, including price, availability,
technological advancements, reliability and creditworthiness. In making
projections with respect to natural gas and crude oil marketing, we assume no
material decrease in the availability of natural gas and crude oil for purchase.
We believe that the location of our properties, our expertise in exploration,
drilling and production operations, the experience of our management and the
efforts and expertise of our marketing units generally enable us to compete
effectively. In making projections with respect to numerous aspects of our
business, we generally assume that there will be no material change in
competitive conditions that would adversely affect us.
GENERAL
Noble Affiliates, Inc. is a Delaware corporation organized in 1969, and is
principally engaged, through its subsidiaries, in the exploration, production
and marketing of oil and gas.
In this report, unless otherwise indicated or the context otherwise requires,
the "Company" or the "Registrant" refers to Noble Affiliates, Inc. and its
subsidiaries, "Samedan" refers to Samedan Oil Corporation and its subsidiaries,
"EDC" refers to Energy Development Corporation and its subsidiaries, "NGM"
refers to Noble Gas Marketing, Inc. and its subsidiary and "NTI" refers to Noble
Trading, Inc. Effective December 31, 2001, EDC (but not its subsidiaries) was
merged into Samedan. In this report, quantities of oil or natural gas liquids
are expressed in barrels ("BBLS"), thousands of barrels ("MBBLS") and millions
of barrels ("MMBBLS"); quantities of natural gas are expressed in thousands of
cubic feet ("MCF"), millions of cubic feet ("MMCF"), billions of cubic feet
("BCF"), trillions of cubic feet ("TCF") and million British Thermal Units
("MMBTU"). Equivalent units are expressed in thousand cubic feet of gas
equivalents ("MCFe"), million cubic feet of gas equivalents ("MMCFe"), billion
cubic feet of gas equivalents ("BCFe"), trillion cubic feet of gas equivalents
("TCFe"), converting oil to gas at one barrel of oil equaling six thousand cubic
feet of gas, or barrel of oil equivalents ("BOE"), millions of barrels of oil
equivalents ("MMBOE"), converting gas to oil at six thousand cubic feet of gas
to one barrel of oil.
The Company's wholly-owned subsidiary, NGM, markets the majority of the
Company's natural gas as well as third-party gas. The Company's wholly-owned
subsidiary, NTI, markets a portion of the Company's oil as well as third-party
oil. For more information regarding NGM's operations and NTI's operations, see
"Item 1. Business--Oil and Gas--Marketing" of this Form 10-K.
The Company's unconsolidated subsidiary, Atlantic Methanol Capital Company
("AMCCO"), is a 50 percent owned joint venture that owns an indirect 90 percent
interest in Atlantic Methanol Production Company ("AMPCO"), which completed
construction of a methanol plant in Equatorial Guinea in the second quarter of
2001. Through 2001, AMCCO was accounted for using the equity method within the
Registrant's wholly owned subsidiary, Samedan of North Africa, Inc. For more
information, see "Item 1. Business--Unconsolidated Subsidiary" and "Item 8.
Financial Statements and Supplementary Data--Note 9 - Unconsolidated Subsidiary"
of this Form 10-K.
OIL AND GAS
The Company's wholly-owned subsidiary, Samedan, directly or through various
arrangements with other companies, explores for, develops and produces oil and
gas hydrocarbons. Exploration activities include geophysical and geological
evaluation and exploratory drilling on properties for which the Company has
exploration rights. Samedan has been engaged in the exploration, production and
marketing of oil and gas since 1932. Samedan has exploration, exploitation and
production operations domestically and internationally. The
3
domestic areas consist of: offshore in the Gulf of Mexico and California; the
Gulf Coast Region (Louisiana, New Mexico and Texas); the Mid-Continent Region
(Oklahoma and Southern Kansas); and the Rocky Mountain Region (Colorado,
Montana, North Dakota, Wyoming and California). The international areas of
operations include Argentina, China, Ecuador, Equatorial Guinea, the
Mediterranean Sea, the North Sea and Vietnam. For more information regarding
Samedan's oil and gas properties, see "Item 2. Properties--Oil and Gas" of this
Form 10-K.
EXPLORATION ACTIVITIES
DOMESTIC OFFSHORE. Samedan has been actively engaged in exploration,
exploitation and development of oil and gas properties in the Gulf of Mexico
(offshore Texas, Louisiana, Mississippi and Alabama) and offshore California
since 1968. Generally, offshore properties are characterized by prolific
reservoirs with high production rates, which therefore tend to deplete more
rapidly than the Company's onshore properties. The Company's current offshore
production is derived from 237 wells operated by Samedan and 309 wells operated
by others. During the past 33 years, Samedan has drilled or participated in the
drilling of 1,084 gross wells offshore. At December 31, 2001, the Company held
offshore federal leases covering 995,178 gross developed acres and 690,974 gross
undeveloped acres on which the Company currently intends to conduct future
exploration activities. For more information, see "Item 2. Properties--Oil and
Gas" of this Form 10-K.
DOMESTIC ONSHORE. Samedan has been actively engaged in exploration, exploitation
and development of oil and gas properties in three regions since the 1930's. The
Gulf Coast Region covers onshore Louisiana, New Mexico and Texas. Properties in
the Gulf Coast Region are characterized by gas reservoirs with strong production
rates and oil fields with primary and secondary recovery operations that tend to
deplete more gradually than the Company's offshore properties. The Mid-Continent
Region covers Oklahoma and Southern Kansas. Properties in the Mid-Continent
Region tend to be characterized by stable oil and gas production from primary
and secondary recovery operations and the reservoirs tend to produce for longer
periods compared to the Company's offshore properties. The Rocky Mountain Region
covers Colorado, Montana, North Dakota, Wyoming and California. Reservoirs in
the Rocky Mountain Region are primarily characterized by oil and gas production
from primary and secondary recovery operations.
During the fourth quarter of 2001, the Company acquired all of Aspect Energy's
interests in 110 wells located along the Texas and Louisiana Gulf Coast. Current
production is approximately 1,900 BBLS of oil per day and 57 MMCF of gas per
day. We acquired approximately 59 BCFe of reserves along with working capital
and hedging positions. Also acquired was a 50 percent interest in Aspect's
future drilling prospects in this region. As part of the transaction, the
Company paid $107 million in cash, issued $14 million of common stock previously
held in treasury and assumed a $40 million note payable.
Samedan's current onshore production is derived from 1,743 wells operated by
Samedan and 1,295 wells operated by others. At December 31, 2001, the Company
held 643,260 gross developed acres and 347,628 gross undeveloped acres onshore
on which the Company may conduct future exploration activities. For more
information, see "Item 2. Properties--Oil and Gas" of this Form 10-K.
ARGENTINA. Samedan, through its subsidiary, Energy Development Corporation
(Argentina), Inc., has been actively engaged in exploration, exploitation and
development of oil and gas properties in Argentina since 1996. The Company's
producing properties are located in southern Argentina in the El Tordillo field,
which is characterized by secondary recovery oil production from a 10,000 acre
reservoir. At December 31, 2001, the Company held 28,988 gross developed acres
and 2,398,970 gross undeveloped acres in Argentina on which the Company may
conduct future exploration activities. For more information, see "Item 2.
Properties--Oil and Gas" of this Form 10-K.
CHINA. Samedan, through its subsidiary, Energy Development Corporation (China),
Inc., has been actively engaged in exploration, exploitation and development of
oil and gas properties in China since 1996. The Company has two concessions in
South Bohai Bay, offshore China. These concessions, Cheng Dao Xi and Cheng Zi
Kou, are contiguous and adjoin non-owned production in the southern portion of
Bohai Bay. At December 31, 2001, the
4
Company held 7,413 gross developed acres and 3,728,198 gross undeveloped acres
in China on which the Company may conduct future exploration activities. For
more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K.
ECUADOR. Samedan, through its subsidiary, EDC Ecuador Ltd., has been actively
engaged in exploration, exploitation and development of oil and gas properties
in Ecuador since 1996. The Company's objective in Ecuador is to develop the gas
market for the Amistad gas field (offshore Ecuador) which was discovered in the
late 1970's. The gas will be used to generate electricity from a power
generation facility, owned 100 percent by the Company, near the city of Machala.
The facility will ultimately be capable of generating 240 megawatts of
electricity into the Ecuadorian power grid. The concession covers 12,355 gross
developed acres and 851,771 gross undeveloped acres encompassing the Amistad
field. For more information, see "Item 2. Properties--Oil and Gas" of this Form
10-K.
EQUATORIAL GUINEA. Samedan, through its subsidiary, Samedan of North Africa,
Inc., has been actively engaged in exploration, exploitation and development of
oil and gas properties offshore Equatorial Guinea (West Africa) since 1990. The
primary offshore Equatorial Guinea production is from the Alba field, which
produces gas and condensate. The gas production is being utilized as feedstock
by a methanol plant, which began production in the second quarter of 2001. The
plant is owned by AMPCO, in which the Company indirectly owns a 45 percent
interest through its 50 percent ownership of AMCCO. For more information on the
methanol plant, see "Item 1. Business--Unconsolidated Subsidiary" of this Form
10-K. Based on reserve estimates, the Alba field can deliver sufficient gas for
the plant to operate for 30 years. At December 31, 2001, the Company held 45,203
gross developed acres and 266,754 gross undeveloped acres offshore Equatorial
Guinea on which the Company may conduct future exploration activities. For more
information, see "Item 2. Properties--Oil and Gas" of this Form 10-K.
NORTH SEA. Samedan, through its subsidiaries, EDC (Europe) Limited, EDC
(Denmark) Inc. and EDC Ireland, has been actively engaged in exploration,
exploitation and development of oil and gas properties in the North Sea since
1996. The Company's current oil and gas production in the North Sea is derived
from 141 wells operated by others. Reservoirs in the North Sea tend to have the
same attributes as Gulf of Mexico reservoirs. At December 31, 2001, the Company
held 202,199 gross developed acres and 805,177 gross undeveloped acres on which
the Company may conduct future exploration activities. For more information, see
"Item 2. Properties--Oil and Gas" of this Form 10-K.
MEDITERRANEAN SEA. The Company, through its subsidiary, Samedan, Mediterranean
Sea, owns a 47 percent interest in 11 licenses, permits or leases. At December
31, 2001, the Company held 123,552 gross developed acres and 1,122,053 gross
undeveloped acres. The acreage is located about 20 miles offshore Israel in
water depths ranging from 700 feet to 5,000 feet. The Company and its partners
expect to provide approximately 170 MMCF of natural gas per day to Israeli
Electric Corporation beginning in early 2004. For more information, see "Item 2.
Properties--Oil and Gas" of this Form 10-K.
VIETNAM. The Company, through its subsidiary, Samedan Vietnam Limited, owns a 60
percent interest in two offshore blocks totaling 1,701,812 gross undeveloped
acres in the Nam Con Son basin. Samedan drilled two exploration wells in 2001.
For more information, see "Item 2. Properties--Oil and Gas" of this Form 10-K.
PRODUCTION ACTIVITIES
OPERATED PROPERTY STATISTICS. The percentage of oil and gas wells operated and
the percentage of sales volume from operated properties are shown in the
following table as of December 31:
2001 2000 1999
------------------------------------------------
(IN PERCENTAGES) OIL GAS OIL GAS OIL GAS
--------------------------------------------------------------------------------
Operated well count basis 24.8 60.6 23.1 66.0 22.8 61.2
Operated sales volume basis 37.2 52.3 48.3 64.5 48.1 59.8
5
NET PRODUCTION. The following table sets forth Samedan's net oil and natural gas
production including royalty, for the three years ended December 31:
2001 2000 1999
--------------------------------------------------------------------------------
Oil Production
(MMBBLS) 11.2 9.4 11.0
Gas Production
(BCF) 154.2 148.7 166.1
OIL AND GAS EQUIVALENTS. The following table sets forth Samedan's net production
stated in oil and gas equivalent volumes, for the three years ended December 31:
2001 2000 1999
--------------------------------------------------------------------------------
Total Oil Equivalents
(MMBOE) 36.9 34.2 38.6
Total Gas Equivalents
(BCFe) 221.3 205.4 231.8
ACQUISITIONS OF OIL AND GAS PROPERTIES, LEASES AND CONCESSIONS
During 2001, Samedan spent approximately $98 million on the purchase of proved
oil and gas properties. Samedan spent approximately $99 million in 2000 and $.1
million in 1999 on proved properties. For more information, see "Item 2.
Properties--Oil and Gas" of this Form 10-K.
During 2001, Samedan spent approximately $81 million on acquisitions of unproved
properties. Samedan spent approximately $17.6 million in 2000 and $7.9 million
in 1999 on acquisitions of unproved properties. These properties were acquired
primarily through various offshore lease sales, domestic onshore lease
acquisitions and international concession negotiations. For more information,
see "Item 2. Properties--Oil and Gas" of this Form 10-K.
MARKETING
NGM seeks opportunities to enhance the value of the Company's gas by marketing
directly to end users and aggregating gas to be sold to gas marketers and
pipelines. During 2001, approximately 70 percent of NGM's total sales were to
end users. NGM is also actively involved in the purchase and sale of gas from
other producers. Such third-party gas may be purchased from non-operators who
own working interests in the Company's wells or from other producers' properties
in which the Company may not own an interest. NGM, through its wholly-owned
subsidiary, Noble Gas Pipeline, Inc., engages in the installation, purchase and
operation of gas gathering systems.
Samedan has short-term gas sales contracts with NGM, whereby Samedan is paid an
index price for all gas sold to NGM. Samedan sold approximately 83 percent of
its natural gas production to NGM in 2001. Sales, including hedging
transactions, are recorded as gathering, marketing and processing revenues. NGM
records the amount paid to Samedan and third parties as cost of sales in
gathering, marketing and processing. All intercompany sales and expenses are
eliminated in the Company's consolidated financial statements. The Company has a
small number of long-term gas contracts representing less than two percent of
its total gas sales.
Oil produced by the Company is sold to purchasers in the United States and
foreign locations at various prices depending on the location and quality of the
oil. The Company has no long-term contracts with purchasers of its oil
production. Crude oil and condensate are distributed through pipelines and by
trucks to gatherers, transportation companies and end users. NTI markets
approximately 38 percent of the Company's oil production as well as certain
third-party oil. The Company records all of NTI's sales as gathering, marketing
and processing revenues and records cost of sales in gathering, marketing and
processing costs. All intercompany sales and expenses are eliminated in the
Company's consolidated financial statements.
Oil prices are affected by a variety of factors that are beyond the control of
the Company. The principal factors influencing the prices received by producers
of domestic crude oil continue to be the pricing and production of the
6
members of the Organization of Petroleum Exporting Countries. The Company's
average oil price decreased $2.21 from $24.37 per BBL in 2000 to $22.16 per BBL
in 2001. Due to the volatility of oil prices, the Company, from time to time,
has used hedging instruments and may do so in the future as a means of
controlling its exposure to price changes. For additional information, see "Item
7a. Quantitative and Qualitative Disclosures About Market Risk" and "Item 8.
Financial Statements and Supplementary Data" of this Form 10-K.
Substantial competition in the natural gas marketplace continued in 2001. Gas
prices, which were once determined largely by governmental regulations, are now
determined by the marketplace. The Company's average gas price increased from
$3.77 per MCF in 2000 to $3.94 per MCF in 2001. Due to the volatility of gas
prices, the Company, from time to time, has used hedging instruments and may do
so in the future as a means of controlling its exposure to price changes. For
additional information, see "Item 7a. Quantitative and Qualitative Disclosures
About Market Risk" and "Item 8. Financial Statements and Supplementary Data" of
this Form 10-K.
The largest single non-affiliated purchaser of the Company's oil production in
2001 accounted for approximately 16 percent of the Company's oil sales,
representing approximately two percent of total revenues. The five largest
purchasers accounted for approximately 37 percent of total oil sales. The
largest single non-affiliated purchaser of the Company's gas production in 2001
accounted for approximately three percent of its gas sales. The five largest
purchasers accounted for approximately 10 percent of total gas sales. The
Company does not believe that its loss of a major oil or gas purchaser would
have a material effect on the Company.
REGULATIONS AND RISKS
GENERAL. Exploration for and production and sale of oil and gas are extensively
regulated at the international, national, state and local levels. Oil and gas
development and production activities are subject to various laws and
regulations (and orders of regulatory bodies pursuant thereto) governing a wide
variety of matters, including allowable rates of production, prevention of waste
and pollution, and protection of the environment. Laws affecting the oil and gas
industry are under constant review for amendment or expansion and frequently
increase the regulatory burden on companies. Our ability to economically produce
and sell our oil and gas production is affected and could possibly be restrained
by a number of legal and regulatory factors, including federal, state and local
laws and regulations in the U.S. and laws and regulations of foreign nations.
Many of these governmental bodies have issued rules and regulations that are
often difficult and costly to comply with, and that carry substantial penalties
for failure to comply. These laws, regulations and orders may restrict the rate
of oil and gas production below the rate that would otherwise exist in the
absence of such laws, regulations and orders. The regulatory burden on the oil
and gas industry increases its costs of doing business and consequently affects
the Company's profitability.
CERTAIN RISKS. In the Company's exploration operations, losses may occur before
any accumulation of oil or gas is found. If oil or gas is discovered, no
assurance can be given that sufficient reserves will be developed to enable the
Company to recover the costs incurred in obtaining the reserves or that reserves
will be developed at a sufficient rate to replace reserves currently being
produced and sold. The Company's international operations are also subject to
certain political, economic and other uncertainties including, among others,
risk of war, expropriation, renegotiation or modification of existing contracts,
taxation policies, foreign exchange restrictions, international monetary
fluctuations and other hazards arising out of foreign governmental sovereignty
over areas in which the Company conducts operations.
ENVIRONMENTAL MATTERS. As a developer, owner and operator of oil and gas
properties, the Company is subject to various federal, state, local and foreign
country laws and regulations relating to the discharge of materials into, and
the protection of, the environment. The unauthorized release or discharge of oil
or certain other regulated substances from the Company's domestic onshore or
offshore facilities could subject the Company to liability under federal laws
and regulations, including the Oil Pollution Act of 1990, the Outer Continental
Shelf Lands Act and the Federal Water Pollution Control Act, as amended. These
laws, among others, impose liability for such a release or discharge for
pollution cleanup costs, damage to natural resources and the environment,
various forms of direct and indirect economic losses, civil or criminal
penalties, and orders or injunctions, including those that can require the
suspension or cessation of operations causing or impacting or potentially
impacting such release or discharge.
7
The liability under these laws for a substantial such release or discharge,
subject to certain specified limitations on liability, may be extraordinarily
large. If any pollution was caused by willful misconduct, willful negligence or
gross negligence within the privity and knowledge of the Company, or was caused
primarily by a violation of federal regulations, the Federal Water Pollution
Control Act provides that such limitations on liability do not apply. Certain of
the Company's facilities are subject to regulations that require the preparation
and implementation of spill prevention control and countermeasure plans relating
to the prevention of, and preparation for, the possible discharge of oil into
navigable waters.
The Comprehensive Environmental Response, Compensation and Liability Act, as
amended ("CERCLA"), also known as "Superfund," imposes liability on certain
classes of persons that generated a hazardous substance that has been released
into the environment or that own or operate facilities or vessels onto or into
which hazardous substances are disposed. The Resource Conservation and Recovery
Act, as amended, ("RCRA") and regulations promulgated thereunder, regulate
hazardous waste, including its generation, treatment, storage and disposal.
CERCLA currently exempts crude oil, and RCRA currently exempts certain oil and
gas exploration and production drilling materials, such as drilling fluids and
produced waters, from the definitions of hazardous substance and hazardous
waste, respectively. The Company's operations, however, may involve the use or
handling of other materials that may be classified as hazardous substances and
hazardous wastes, and therefore, these statutes and regulations promulgated
under them would apply to the Company's generation, handling and disposal of
these materials. In addition, there can be no assurance that such exemptions
will be preserved in future amendments of such acts, if any, or that more
stringent laws and regulations protecting the environment will not be adopted.
Certain of the Company's facilities may also be subject to other federal
environmental laws and regulations, including the Clean Air Act with respect to
emissions of air pollutants.
Certain state or local laws or regulations and common law may impose liabilities
in addition to, or restrictions more stringent than, those described herein.
The environmental laws, rules and regulations of foreign countries are generally
less stringent than those of the United States, and therefore, the requirements
of such jurisdictions do not generally impose an additional compliance burden on
the Company or on its subsidiaries.
The Company has made and will continue to make expenditures in its efforts to
comply with environmental requirements. The Company does not believe that it has
to date expended material amounts in connection with such activities or that
compliance with such requirements will have a material adverse effect upon the
capital expenditures, earnings or competitive position of the Company. Although
such requirements do have a substantial impact upon the energy industry,
generally they do not appear to affect the Company any differently or to any
greater or lesser extent than other companies in the industry.
INSURANCE. The Company has various types of insurance coverages as are customary
in the industry which include, in various degrees, general liability, control of
well, loss of production, pollution, political risks and physical damage
insurance. The Company believes the coverages and types of insurance are
adequate.
COMPETITION
The oil and gas industry is highly competitive. Since many companies and
individuals are engaged in exploring for oil and gas and acquiring oil and gas
properties, a high degree of competition for desirable exploratory and producing
properties exists. A number of the companies with which the Company competes are
larger and have greater financial resources than the Company.
The availability of a ready market for the Company's oil and gas production
depends on numerous factors beyond its control, including the level of consumer
demand, the extent of worldwide oil and gas production, the costs and
availability of alternative fuels, the costs and proximity of pipelines and
other transportation facilities, regulation by state and federal authorities and
the costs of complying with applicable environmental regulations.
8
UNCONSOLIDATED SUBSIDIARY
The Company has an unconsolidated subsidiary, Atlantic Methanol Capital Company
("AMCCO"), a 50 percent owned joint venture that owns an indirect 90 percent
interest in Atlantic Methanol Production Company ("AMPCO"). The Company
accounted for its interest in AMCCO through 2001 using the equity method within
the Company's wholly-owned subsidiary, Samedan of North Africa, Inc. The Company
participated with a 50 percent expense interest (45 percent ownership net of a
five percent government carried interest) in the construction of a methanol
plant in Equatorial Guinea. The total construction costs of the plant and
supporting facilities as of December 31, 2001 were $403 million including
various contingencies, with the Company responsible for $201.5 million. AMPCO
estimates that an additional $32 million will be incurred to complete various
supporting facilities to finalize the project. The Company will be responsible
for $16 million in 2002. The plant is designed to produce 2,500 metric tons of
methanol per day, which equates to approximately 20,000 BBLS per day. At this
level of production, the plant would use approximately 125 MMCF of gas per day
from the 34 percent owned Alba field as feedstock. Reserve estimates indicate
the Alba field can deliver sufficient gas for the plant to operate 30 years. The
methanol plant was completed and on line in the second quarter of 2001. During
1999, AMCCO issued $250 million senior secured notes due 2004 that are not
included in the Company's balance sheet. On January 2, 2002, the Company's
partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a
component of the partner's sale of all of its Equatorial Guinea assets. The
proceeds of the AMPCO sale were used to repay in full AMCCO's $125 million
Series A-1 Notes on January 28, 2002 and to make a distribution to the Company's
partner. Since the Company's partner in AMCCO no longer retains an economic
interest in AMPCO, the Company will consolidate the results of AMCCO, thereby
including the $125 million Series A-2 Notes in the Company's balance sheet. The
terms of the $125 million Series A-2 Notes remain unchanged. For more
information, see "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Item 8. Financial Statements and
Supplementary Data--Note 9 - Unconsolidated Subsidiary" of this Form 10-K.
EMPLOYEES
The total number of employees of the Company increased during the year from 576
at December 31, 2000, to 610 at December 31, 2001.
ITEM 2. PROPERTIES.
OFFICES
The principal executive office of the Registrant is located in Houston, Texas.
The Company maintains offices for international, domestic onshore and domestic
offshore operations in Houston, Texas. The Company also maintains offices in
China, Ecuador, Israel, the United Kingdom and Vietnam. NGM's office and NTI's
office are located in Houston, Texas. The Company also maintains offices in
Ardmore, Oklahoma for centralized accounting, division orders, human resources
and related administrative functions.
OIL AND GAS
The Company, directly or through various arrangements with others, searches for
potential oil and gas properties, seeks to acquire exploration rights in areas
of interest and conducts exploratory activities. These activities include
geophysical and geological evaluation and exploratory drilling, where
appropriate, on properties for which it acquired exploration rights. During
2001, Samedan drilled or participated in the drilling of 293 gross (118.1 net)
wells, comprised of 103 gross (21.3 net) international wells and 190 gross (96.8
net) domestic wells. For more information regarding Samedan's oil and gas
properties, see "Item 1. Business--Oil and Gas" of this Form 10-K.
DOMESTIC OFFSHORE. The Lost Ark prospect on East Breaks 421 is the Company's
first operated commercial deepwater discovery in the Gulf of Mexico. The East
Breaks 421 #1 well was drilled to a total depth of 7,700 feet
9
in 2,700 feet of water. The well, in which the Company owns a 48 percent working
interest, encountered a gross gas pay section from 6,695 feet to 6,805 feet,
with high porosity and permeability.
Other deepwater gas discoveries include Mississippi Canyon 278 and 837, in which
Samedan owns a 30 percent and a 40 percent working interest, respectively;
Garden Banks 240, in which Samedan owns a 100 percent working interest; and
Green Canyon 136, in which Samedan owns a 25 percent working interest.
Deepwater oil discoveries include Green Canyon 282, in which Samedan owns a 25
percent working interest, and Viosca Knoll 917/962, in which Samedan owns a 20
percent working interest.
The Mound Point prospect, located offshore Louisiana on State Lease 340, was
drilled to 18,704 feet, logging two potential pay sections. Production casing
has been run and a completion and testing program is being designed. The Company
owns a 25 percent working interest.
Samedan was the successful bidder, alone or with partners, on 33 lease blocks at
the Central Gulf of Mexico Outer Continental Shelf Sale 178. The high bids
totaled approximately $27.5 million net to the Company's interest. Nineteen of
the high bids were on blocks in deepwater and 14 were on blocks located on the
shelf. Samedan will be the designated operator on 19 of the blocks.
DOMESTIC ONSHORE. During the fourth quarter of 2001, the Company acquired all of
Aspect Energy's interests in 110 wells located along the Texas and Louisiana
Gulf Coast. Current production is approximately 1,900 BBLS of oil per day and 57
MMCF of gas per day. We acquired approximately 59 BCFe of reserves along with
working capital and hedging positions. Also acquired was a 50 percent interest
in Aspect's future drilling prospects in this region. As part of the
transaction, the Company paid $107 million in cash, issued $14 million of common
stock previously held in treasury and assumed a $40 million note payable.
Key domestic onshore exploration projects in 2001 included the exploitation of
the Miogyp Trend in southwest Louisiana. Discoveries in this trend include the
Thompson #1, which was tested at a rate of 10 MMCF of gas per day and 52 BBLS of
condensate per day, and the McConnell #4, which tested at a rate of 15 MMCF of
gas per day and 62 BBLS of condensate per day. Samedan owns a 63 percent and a
20 percent working interest, respectively.
The Runnells #5 in Matagorda County, Texas was completed and tested at a rate of
21 MMCF of gas per day and 710 BBLS of condensate per day. The Runnells #5 is a
follow-up to the Runnells #3 discovery. The Company owns a 23 percent working
interest in both wells.
ARGENTINA. The Company's wholly-owned subsidiary, Energy Development Corporation
(Argentina), Inc., participated with a 13 percent working interest in 70
exploitation wells in the El Tordillo field during 2001. The Company is awaiting
government approval on an oil and gas exploration permit of approximately 1.2
million acres. The permit is located in the Cuyo Basin of Mendoza Province in
western Argentina. The Company was the successful bidder on an adjacent permit
of approximately 1.1 million acres.
CHINA. The Company's wholly-owned subsidiary, Energy Development Corporation
(China), Inc., entered into an agreement to acquire a 50 percent working
interest in South China Sea blocks 16/02, 16/05 and 26/35. The blocks encompass
approximately two million acres in the Pearl River Mouth Basin. The HuizhouSag
block 16/02 tested 1,581 BBLS of oil per day and 2 MMCF of natural gas per day.
ECUADOR. EDC Ecuador Ltd. completed the successful testing of a well located
offshore Ecuador in the Gulf of Guayaquil block 3. The Amistad #7 is an
exploratory well that is part of a four-well work program on the block. The well
was drilled from a platform located 30 miles offshore in 134 feet of water. The
well tested 19.4 MMCF of gas per day from 172 feet of perforations on a
32/64-inch choke with 3,208 pounds per square inch of flowing tubing pressure at
the wellhead. It logged 472 feet of gross sand thickness in the Miocene Age
Progreso formation. The Company owns a 100 percent working interest in the
field.
The gas will be used to generate electricity from a power generating facility,
owned 100 percent by the Company, near the city of Machala. The facility will
ultimately be capable of generating 240 megawatts of electricity into the
Ecuadorian power grid.
10
EQUATORIAL GUINEA. The Alba #9 was successfully completed and tested as a major
natural gas and condensate well in the Alba field offshore Equatorial Guinea.
The well is located 2.4 miles from the nearest producing well in the Alba field,
which is located 18 miles offshore, northwest of Bioko Island. The well tested
at a rate of 37.5 MMCF of gas per day and 2,400 BBLS of condensate per day from
120 feet of perforations on a one-inch choke at 2,473 pounds per square inch
flowing tubing pressure. Estimated proven and probable reserves for the Alba
field now total more than 300 MMBBLS of liquid hydrocarbons associated with 1.6
TCF of natural gas. The Company owns a 34 percent working interest in the field.
The Estrella #1, in which the Company owns a 34 percent working interest, was
drilled to a depth of 10,324 feet in approximately 200 feet of water 22 miles
northwest of Bioko Island. The well flow tested at a combined stabilized rate of
6,780 BBLS of condensate and 47 MMCF of natural gas per day from two intervals
between 6,950 feet and 7,200 feet. The well results are currently being
evaluated for possible early production. The Alba field "A" platform is located
approximately five miles south of the Estrella well. Further drilling to
determine the ultimate size of the Estrella accumulation is being evaluated.
The Company's unconsolidated subsidiary, AMCCO, is a 50 percent owned joint
venture that owns an indirect 90 percent interest in AMPCO, which completed
construction of a methanol plant in Equatorial Guinea in the second quarter of
2001. The plant construction started during 1998 and initial production of
commercial grade methanol commenced May 2, 2001. Operating at full capacity, the
facility converts approximately 125 MMCF of gas per day into approximately 2,500
metric tons (20,000 BBLS) of methanol per day for commercial markets. During
2001, 12 shipments of methanol were delivered, five to European markets and
seven to markets in the United States.
ISRAEL. The Company's wholly-owned subsidiary, Samedan, Mediterranean Sea, and
its partners expect to provide approximately 170 MMCF of natural gas per day to
Israeli Electric Corporation beginning in early 2004, for use in IEC's power
plants. The gas will be produced from the Mari-B and Noa prospects, which had
discovery wells drilled in 2000 and 1999, respectively, offshore Israel and
production is anticipated to begin in 2004.
NORTH SEA. The Company's wholly-owned subsidiary, EDC (Europe) Limited, received
United Kingdom approval for a $50 million development of the Hannay oil field.
The Hannay field is located in the UK sector of the North Sea in block 20/5c.
The operator has estimated reserves of eight MMBBLS of oil equivalent with a
field life of eight years. The Company owns a 15 percent working interest in the
field.
Oil production commenced in August from the Hanze field in the North Sea, off
the coast of the Netherlands. Production started at a rate of 11,000 BBLS of oil
per day in August 2001 and by year-end the block was producing approximately
30,000 BBLS of oil per day. The Company owns a 15 percent working interest in
the field which is located in block F2a and is the first offshore oil chalk
reservoir ever developed in the Netherlands.
VIETNAM. The Company's wholly-owned subsidiary, Samedan Vietnam Limited,
successfully tested a discovery well in the Swan prospect, which is located in
block 12W offshore Vietnam. The well, 12W-TN-1X, is located approximately 230
miles southeast of Ho Chi Minh City in the Nam Con Son Basin in 260 feet of
water. It was drilled to a total depth of 14,626 feet and tested natural gas at
a stabilized flow rate of 20 MMCF of gas per day with 150 BBLS of condensate per
day from a perforated interval of 131 feet during a drill stem test at 12,884
feet in the Upper Oligocene Cau formation. Further evaluation, including a 3D
seismic survey and a confirmation well, will be needed to determine the
commercial significance of the discovery. The Company owns a 60 percent working
interest in the 567,000 acre block.
The Lark prospect, located offshore Vietnam in block 12E, was non-commercial.
11
NET EXPLORATORY AND DEVELOPMENTAL WELLS. The following table sets forth, for
each of the last three years, the number of net exploratory and development
wells drilled by or on behalf of Samedan. An exploratory well is a well drilled
to find and produce oil or gas in an unproved area, to find a new reservoir in a
field previously found to be productive of oil or gas in another reservoir, or
to extend a known reservoir. A development well, for purposes of the following
table and as defined in the rules and regulations of the Securities and Exchange
Commission, is a well drilled within the proved area of an oil or gas reservoir
to the depth of a stratigraphic horizon known to be productive. The number of
wells drilled refers to the number of wells completed at any time during the
respective year, regardless of when drilling was initiated. Completion refers to
the installation of permanent equipment for the production of oil or gas, or in
the case of a dry hole, to the reporting of abandonment to the appropriate
agency.
NET EXPLORATORY WELLS NET DEVELOPMENT WELLS
--------------------------- ----------------------------
PRODUCTIVE(1) DRY(2) PRODUCTIVE(1) DRY(2)
--------------------------- ----------------------------
YEAR ENDED
DECEMBER 31, U.S. INT'L U.S. INT'L U.S. INT'L U.S. INT'L
---------------------------------------------------------------------------
2001 4.87 .63 10.79 5.41 68.30 13.67 12.88 1.62
2000 17.86 3.94 10.59 1.00 101.89 5.99 4.17 .57
1999 6.97 2.00 6.14 .55 26.10 4.82 2.42 .01
----------
(1) A productive well is an exploratory or a development well that is not a
dry hole.
(2) A dry hole is an exploratory or development well found to be incapable
of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.
At January 31, 2002, Samedan was drilling 6 gross (2.7 net) exploratory wells
and 11 gross (4.0 net) development wells. These wells are located onshore in
Texas, Colorado, Argentina, and offshore in the Gulf of Mexico, China,
Equatorial Guinea and the North Sea. These wells have objectives ranging from
approximately 2,600 feet to 16,900 feet. The drilling cost to Samedan of these
wells is approximately $21 million if all are dry and approximately $31 million
if all are completed as producing wells.
12
OIL AND GAS WELLS. The number of productive oil and gas wells in which Samedan
held an interest as of December 31 follows:
2001(1)(3) 2000(1)(3) 1999(1)(2)(3)
------------------------------------------------------------------
GROSS NET GROSS NET GROSS NET
----------------------------------------------------------------------------------------------------
OIL WELLS
United States - Onshore 1,364.5 573.6 1,341.5 564.0 1,512.5 683.2
United States - Offshore 212.5 120.0 210.5 119.2 254.5 128.2
INTERNATIONAL 670.0 75.7 604.0 66.2 1,041.0 122.9
----------------------------------------------------------------------------------------------------
TOTAL 2,247.0 769.3 2,156.0 749.4 2,808.0 934.3
----------------------------------------------------------------------------------------------------
GAS WELLS
United States - Onshore 1,673.5 1,025.7 1,532.5 947.1 1,435.5 873.9
United States - Offshore 333.5 143.3 300.5 133.4 406.5 150.4
INTERNATIONAL 38.0 8.4 31.0 3.5 27.0 2.5
----------------------------------------------------------------------------------------------------
TOTAL 2,045.0 1,177.4 1,864.0 1,084.0 1,869.0 1,026.8
----------------------------------------------------------------------------------------------------
(1) Productive wells are producing wells and wells capable of production. A
gross well is a well in which a working interest is owned. The number of
gross wells is the total number of wells in which a working interest is
owned. A net well is deemed to exist when the sum of fractional
ownership working interests in gross wells equals one. The number of net
wells is the sum of the fractional working interests owned in gross
wells expressed as whole numbers and fractions thereof.
(2) During 1999, the Company sold 250 net non-strategic wells.
(3) One or more completions in the same bore hole are counted as one well in
this table.
The following table summarizes multiple completions and non-producing wells as
of December 31 for the years shown. Included in wells not producing are
productive wells awaiting additional action, pipeline connections or shut-in for
various reasons.
2001 2000 1999
-------------------------------------------------------------------
GROSS NET GROSS NET GROSS NET
-----------------------------------------------------------------------------------------------------
MULTIPLE COMPLETIONS
Oil 13.5 6.9 13.5 6.9 14.0 9.2
Gas 36.5 14.0 36.5 14.0 49.0 23.2
NOT PRODUCING (SHUT-IN)
Oil 391.0 179.2 386.0 177.5 857.0 233.5
Gas 100.0 36.3 62.0 20.6 33.0 4.5
At year-end 2001, Samedan had less than two percent of its oil and gas sales
volumes committed to long-term supply contracts and had no similar agreements
with foreign governments or authorities in which Samedan acts as producer.
Since January 1, 2001, no oil or gas reserve information has been filed with, or
included in any report to any federal authority or agency other than the
Securities and Exchange Commission and the Energy Information Administration
("EIA"). Samedan files Form 23, including reserve and other information, with
the EIA.
13
AVERAGE SALES PRICE. The following table sets forth, for each of the last three
years, the average sales price per unit of oil produced and per unit of natural
gas produced, and the average production cost per unit.
YEAR ENDED DECEMBER 31,
-------------------------------
2001 2000 1999
-----------------------------------------------------------------------------------------------------
Average sales price per BBL of oil (1):
United States $ 22.88 $ 23.75 $ 16.37
International $ 21.06 $ 26.09 $ 16.01
Combined (2) $ 22.16 $ 24.37 $ 16.29
Average sales price per MCF of natural gas (1):
United States $ 4.24 $ 3.90 $ 2.30
International $ 1.40 $ 2.08 $ 1.38
Combined (3) $ 3.94 $ 3.77 $ 2.23
Average production (lifting) cost per unit of oil and natural gas production,
excluding depreciation (MCFe) (4):
United States $ .66 $ .59 $ .51
International $ .46 $ .64 $ .49
Combined $ .60 $ .59 $ .50
----------
(1) Net production amounts used in this calculation include royalties.
(2) Reflects a reduction of $2.92 per BBL in 2000 from hedging in the United
States.
(3) Reflects an increase of $.03 per MCF in 2001 from hedging in the United
States.
(4) Oil production is converted to gas equivalents (MCFe) based on one BBL
of oil equals six MCF of gas.
14
[MAP OF FACILITY]
NET WORKING
BLOCK INTEREST (%)
----------------------------
EAST BREAKS
279 33
464* 48
465* 48
475* 100
510* 33
519* 100
563* 100
GREEN CANYON
23* 50
24* 43
25* 43
27* 43
85* 50
227* 50
228* 50
303* 40
507* 50
723* 100
724* 100
768* 100
955* 7
958* 25
WEST CAMERON
136 40
392 100
393 100
400 100
419 100
422 50
438 100
443 100
446 100
MUSTANG ISLAND
829 80
830 80
831 100
VERMILION
195 25
207 25
208 25
232 50
278 100
280 50
285 100
293 50
300 50
310 50
353 100
360 67
361 67
365 50
377 100
391 100
GARDEN BANKS
25 50
35 100
116 100
122 100
154 100
326* 100
751* 100
795* 100
841* 39
MAIN PASS
107 25
109 25
110 25
192 100
293 100
EAST CAMERON
342 67
355 100
SOUTH TIMBALIER
98 50
156 67
201 100
316 40
GALVESTON
249-L 50
250-L 50
274-L 50
275-L 50
277-L 50
340-S 50
341-S 50
SOUTH MARSH ISLAND
38 100
62 67
63 67
64 67
65 67
70 50
104 100
145 100
167 100
195 50
MISSISSIPPI CANYON
26* 75
70* 75
71* 75
123* 75
159* 75
524* 50
583* 50
595* 24
602* 75
639* 24
661 25
665* 50
837* 40
849* 48
855* 40
857* 40
900* 40
901* 40
911* 40
999* 30
1000* 30
SHIP SHOAL
73 50
BRAZOS
308-L 50
336-L 50
337-L 50
543 100
EWING BANK
833* 14
834* 14
879* 40
949 97
993 48
995 43
996 43
EUGENE ISLAND
96 25
97 25
109 25
317 67
HIGH ISLAND
A-218 100
A-230 100
A-426 33
A-435 33
A-516 100
VIOSCA KNOLL
23 100
344 100
697 50
820 50
864* 35
908* 100
ATWATER VALLEY
10* 100
11* 100
23* 100
67* 100
327* 39
533* 40
*Located in water deeper than 1,000 feet.
15
The developed and undeveloped acreage (including both leases and concessions)
that Samedan held as of December 31, 2001, is as follows:
DEVELOPED ACREAGE (1)(2) UNDEVELOPED ACREAGE (2)(3)(4)
----------------------------- -----------------------------
LOCATION GROSS ACRES NET ACRES GROSS ACRES NET ACRES
-------------------------------------------------------------------------------------------------------------------
United States Onshore
Alabama 2,396 506
California 5,170 2,109 4,899 3,712
Colorado 61,678 59,105 20,380 15,599
Kansas 92,281 52,833 17,803 11,907
Louisiana 28,188 8,563 27,590 9,420
Michigan 1,876 427
Mississippi 878 34 1,884 51
Montana 172,683 119,113 8,292 2,064
New Mexico 3,117 1,766 1,520 933
North Dakota 1,932 1,554 4,431 2,061
Oklahoma 141,603 54,915 31,869 11,142
Texas 99,348 43,316 154,331 65,984
Utah 5,160 2,433 1,832 1,556
Wyoming 31,222 18,682 68,525 44,750
-------------------------------------------------------------------------------------------------------------------
Total United States Onshore 643,260 364,423 347,628 170,112
-------------------------------------------------------------------------------------------------------------------
United States Offshore (Federal Waters)
Alabama 80,640 39,168 31,363 19,425
California 38,834 12,039 52,364 9,422
Florida 11,520 2,304
Louisiana 618,006 261,285 372,160 218,784
Mississippi 22,411 10,141 34,560 14,216
Texas 235,287 98,672 189,007 124,623
-------------------------------------------------------------------------------------------------------------------
Total United States Offshore (Federal Waters) 995,178 421,305 690,974 388,774
-------------------------------------------------------------------------------------------------------------------
International
Argentina 28,988 3,977 2,398,970 2,326,204
China 7,413 4,225 3,728,198 1,927,547
Denmark 80,902 32,361
Ecuador 12,355 12,355 851,771 851,771
Equatorial Guinea 45,203 15,727 266,754 92,808
Ireland 263,803 105,521
Israel 123,552 58,142 1,122,053 382,671
Netherlands 70,672 10,601 97,952 39,181
United Kingdom 131,527 4,566 362,520 104,603
Vietnam 1,701,812 1,021,087
-------------------------------------------------------------------------------------------------------------------
Total International 419,710 109,593 10,874,735 6,883,754
-------------------------------------------------------------------------------------------------------------------
Total 2,058,148 895,321 11,913,337 7,442,640
-------------------------------------------------------------------------------------------------------------------
(1) Developed acreage is acreage spaced or assignable to productive wells.
(2) A gross acre is an acre in which a working interest is owned. A net acre
is deemed to exist when the sum of fractional ownership working
interests in gross acres equals one. The number of net acres is the sum
of the fractional working interests owned in gross acres expressed as
whole numbers and fractions thereof.
(3) 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. Included within
undeveloped acreage are those leased acres (held by production under the
terms of a lease) that are not within the spacing unit containing, or
acreage assigned to, the productive well so holding such lease.
(4) The Argentina acreage includes two concessions totaling 2,314,633 acres
subject to final regulatory approval.
16
ITEM 3. LEGAL PROCEEDINGS.
The Company has various lawsuits pending but does not believe the outcome of the
lawsuits, individually or collectively, will materially impair the Company's
financial and operational condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the fourth
quarter of 2001.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information, as of March 11, 2002, with
respect to the executive officers of the Registrant.
Name Age Position
----------------------------------------------------------------------------------------------------------------
Charles D. Davidson (1) 52 Chairman of the Board, President, Chief Executive Officer and Director
Alan R. Bullington (2) 50 Vice President, International
Robert K. Burleson (3) 44 Vice President, Business Administration and President, Noble Gas
Marketing, Inc.
Susan M. Cunningham (4) 46 Senior Vice President, Exploration
Albert D. Hoppe (5) 57 Senior Vice President, General Counsel and Secretary
James L. McElvany (6) 48 Vice President, Chief Financial Officer, Treasurer and Assistant
Secretary
Richard A. Peneguy, Jr. (7) 51 Vice President, Offshore
William A. Poillion, Jr. (8) 52 Senior Vice President, Production and Drilling
Ted A. Price (9) 42 Vice President, Onshore
Kenneth P. Wiley (10) 49 Vice President, Information Systems
----------
(1) Charles D. Davidson was elected Chairman of the Board on April 24, 2001
and President and Chief Executive Officer of the Company on October 2,
2000. Prior to October 2000, he served as President and Chief Executive
Officer of Vastar Resources, Inc. from March 1997 to September 2000
(Chairman from April 2000) and was a Vastar Director from March 1994 to
September 2000. From September 1993 to March 1997, he served as a Senior
Vice President of Vastar.
(2) Alan R. Bullington was promoted to Vice President, International of
Noble Affiliates, Inc. effective April 24, 2001 and to Vice President
and General Manager, International Division of Samedan on January 1,
1998. Prior thereto, he served as Manager-International Operations and
Exploration and as Manager-International Operations. Prior to his
employment with Samedan in 1990, he held various management positions
within the exploration and production division of Texas Eastern
Transmission Company.
17
3) Robert K. Burleson was appointed Vice President, Business Administration
of Noble Affiliates, Inc. on January 29, 2002. Prior thereto, he was
promoted to Vice President of Noble Affiliates, Inc. effective April 24,
2001 and has served as President of Noble Gas Marketing, Inc. since June
14, 1995. Prior to June 1995, he served as Vice President-Marketing for
Noble Gas Marketing since its inception in 1994. Previous to his
employment with the Company, he was employed by Reliant Energy as
Director of Business Development for their interstate pipeline, Reliant
Gas Transmission.
(4) Susan M. Cunningham joined Noble Affiliates, Inc. in March 2001 as
Senior Vice President, Exploration. Previous to her employment with the
Company, she was employed by Texaco as Vice President - Worldwide
Exploration. Prior thereto, she held senior exploration management
positions with Statoil and Amoco.
(5) Albert D. Hoppe was elected Senior Vice President, General Counsel and
Secretary of Noble Affiliates, Inc. on December 5, 2000. Prior thereto,
he served as Vice President, General Counsel and Secretary of Vastar
Resources, Inc. from 1994 through 2000.
(6) James L. McElvany has served as Vice President, Chief Financial Officer,
Treasurer and Assistant Secretary of Noble Affiliates, Inc. since July
1, 1999. Prior to July 1999, he had served as Vice President-Controller
since December 1997. Prior thereto, he served as Controller since
December 1983.
(7) Richard A. Peneguy, Jr. was promoted to Vice President, Offshore of
Noble Affiliates, Inc. on January 29, 2002. Prior thereto, he was
promoted to Vice President of Noble Affiliates, Inc. effective April 24,
2001. Prior to April 2001, he served as Vice President and General
Manager, Onshore Division of Samedan since January 1, 2000 and he had
served as General Manager, Onshore Division of Samedan since January 1,
1991.
(8) William A. Poillion, Jr. was promoted to Senior Vice President,
Production and Drilling of Noble Affiliates, Inc. on January 1, 1998.
Prior thereto, he had served as Vice President-Production and Drilling
of Samedan since November 1990. From March 1, 1985 to October 31, 1990,
he served as Manager of Offshore Production and Drilling for Samedan.
(9) Ted A. Price was promoted to Vice President, Onshore of Noble
Affiliates, Inc. on January 29, 2002. Prior thereto, he served as
Manager of Onshore Exploration since 1999. He had served as Onshore
Region Geologist since March 1994 and as a Staff Geologist for Samedan
since May 1981.
(10) Kenneth P. Wiley has served as Vice President, Information Systems of
Noble Affiliates, Inc. since July 1998. Prior thereto, he served as
Manager-Information Systems for Samedan since November 1994.
The terms of office for the officers of the Registrant continue until their
successors are chosen and qualified. No officer or executive officer of the
Registrant currently has an employment agreement with the Registrant or any of
its subsidiaries, although Mr. Davidson had an employment agreement with the
Registrant until February 1, 2002. There are no family relationships between any
of the Registrant's officers.
18
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
COMMON STOCK. The Registrant's Common Stock, $3.33 1/3 par value ("Common
Stock"), is listed and traded on the New York Stock Exchange under the symbol
"NBL." The declaration and payment of dividends are at the discretion of the
Board of Directors of the Registrant and the amount thereof will depend on the
Registrant's results of operations, financial condition, contractual
restrictions, cash requirements, future prospects and other factors deemed
relevant by the Board of Directors.
STOCK PRICES AND DIVIDENDS BY QUARTERS. The following table sets forth, for the
periods indicated, the high and low sales price per share of Common Stock on the
New York Stock Exchange and quarterly dividends paid per share.
DIVIDENDS
HIGH LOW PER SHARE
-------------------------------------------------------------------------
2001
----
First quarter $ 51.09 $ 39.63 $ .04
Second quarter $ 45.20 $ 34.26 $ .04
Third quarter $ 38.19 $ 27.50 $ .04
Fourth quarter $ 40.00 $ 30.00 $ .04
2000
----
First quarter $ 33.63 $ 19.19 $ .04
Second quarter $ 42.38 $ 29.13 $ .04
Third quarter $ 41.50 $ 28.88 $ .04
Fourth quarter $ 48.38 $ 34.69 $ .04
TRANSFER AGENT AND REGISTRAR. The transfer agent and registrar for the Common
Stock is First Union National Bank, NC1153, 1525 West W. T. Harris Blvd., 3C3,
Charlotte, North Carolina 28262-1153.
STOCKHOLDERS' PROFILE. As of December 31, 2001, the number of holders of record
of Common Stock was 1,125. The following chart indicates the common stockholders
by category.
SHARES
DECEMBER 31, 2001 OUTSTANDING
----------------------------------------------------------------------
Individuals 682,804
Joint accounts 56,176
Fiduciaries 121,177
Institutions 2,513,452
Nominees 53,623,611
Foreign 8,581
----------------------------------------------------------------------
Total-excluding Treasury Shares 57,005,801
----------------------------------------------------------------------
SALES OF UNREGISTERED SECURITIES. The Company's unconsolidated subsidiary,
AMCCO, is a 50 percent owned joint venture that owns an indirect 90 percent
interest in AMPCO, which completed construction of a methanol plant in
Equatorial Guinea in the second quarter of 2001. On November 10, 1999, AMCCO
issued $125 million of 10.875% Series A-1 Senior Secured Notes ("Series A-1
Notes") and $125 million of 8.95% Series A-2 Senior Secured Notes ("Series A-2
Notes") due 2004, which are not included in the Company's balance sheet, to fund
the Company's portion of the construction payments. For more information, see
"Item 8. Financial Statements and Supplementary Data--Note 9 - Unconsolidated
Subsidiary" of this Form 10-K.
On January 2, 2002, the Company's partner in AMCCO directed AMCCO to sell 50
percent of its interest in AMPCO as a component of the partner's sale of all of
its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay
in full AMCCO's $125 million Series A-1 Notes on January 28, 2002 and to make a
distribution to the Company's partner. Since the Company's partner in AMCCO no
longer retains an economic interest in AMPCO, the Company will consolidate the
results of AMCCO, thereby including the $125 million Series A-2 Notes in the
Company's balance sheet. The terms of the $125 million Series A-2 Notes remain
unchanged.
19
At the same time the Series A-2 Notes were issued, the Company guaranteed the
payment of interest on the Series A-2 Notes and issued, in a private placement
pursuant to Section 4(2) of the Securities Act, 125,000 shares of its Series B
Mandatorily Convertible Preferred Stock, par value $1.00 per share (the "Series
B Preferred") to Noble Share Trust, which is a Delaware statutory business
trust, in exchange for all of the beneficial ownership interests in the Noble
Share Trust.
Noble Share Trust holds the 125,000 shares of Series B Preferred for the benefit
of the holders of the Series A-2 Notes. The Series A-2 indenture trustee, and
the holders of 25 percent of the outstanding principal amount of the Series A-2
Notes, would have the right to require a public offering of the Series B
Preferred to generate proceeds sufficient to repay the Series A-2 Notes, upon
the occurrence of certain events ("Trigger Dates"), including (i) defaults under
the Indenture governing the Series A-2 Notes, (ii) a default and acceleration of
the Company's debt exceeding five percent of the Company's consolidated net
tangible assets, and (iii) the simultaneous occurrence of a downgrade of the
Company's unsecured senior debt rating to "Ba1" or below by Moody's or "BB+" or
below by Standard & Poor's and a decline in the closing price of the Company's
common stock for three consecutive trading days to below $17.50. The exercise of
this mandatory remarketing right is subject to certain forbearance provisions
that would allow the Company the opportunity to obtain funds for the repayment
of the Series A-2 Notes by alternative means for a specified period of time.
The terms of the Series B Preferred, including dividend and conversion features,
would be reset at the time of the remarketing, based on the recommendation of
Credit Suisse First Boston, as Remarketing Agent, as to the terms necessary to
generate proceeds to repay the Series A-2 Notes. If the Remarketing Agent is not
able to complete a registered public offering of the Series B Preferred, it may
under certain circumstances conduct a private placement of such stock. If it is
impossible for legal reasons to remarket the Series B Preferred, the Company
would be obligated to repay the Series A-2 Notes.
The Series B Preferred stock would be mandatorily convertible into the Company's
common stock three years after remarketing (or failed remarketing). Generally,
each share of Series B Preferred would then be mandatorily convertible at the
"Mandatory Conversion Rate," which is equal to the following number of shares of
the Company's common stock:
(a) if the Mandatory Conversion Date Market Price is greater than or equal
to the Threshold Appreciation Price, the quotient of (i) $1,000 divided by
(ii) the Threshold Appreciation Price;
(b) if the Mandatory Conversion Date Market Price is less than the
Threshold Appreciation Price but is greater than the Reset Price, the
quotient of $1,000 divided by the Mandatory Conversion Date Market Price;
and
(c) if the Mandatory Conversion Date Market Price is less than or equal to
the Reset Price, the quotient of $1,000 divided by the Reset Price.
"Mandatory Conversion Date Market Price" means the average closing price per
share of the Company's common stock for the 20 consecutive trading days
immediately prior to, but not including, the mandatory conversion date.
"Threshold Appreciation Price" means the product of (i) the Reset Price (as the
same may be adjusted from time to time) and (ii) 110 percent.
"Reset Price" means the higher of (i) the closing price of a share of the
Company's common stock on the Trigger Date or (ii) the quotient (rounded up to
the nearest cent) of $125,000,000 divided by the number, as of the Trigger Date,
of the authorized but unissued shares of common stock that have not been
reserved as of the Trigger Date by the Company's Board of Directors for other
purposes.
In addition to the mandatory conversion discussed above, each share of the
Series B Preferred is generally convertible, at the option of the holder thereof
at any time before the mandatory conversion date, into 36.364 shares of the
Company's common stock (the "Optional Conversion Rate"); provided, however, that
the Optional Conversion Rate shall adjust, as of the earlier to occur of
remarketing or failed remarketing, to the quotient of (i) $1,000 divided by (ii)
the Threshold Appreciation Price.
20
ITEM 6. SELECTED FINANCIAL DATA.
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS) 2001 2000 1999 1998 1997
-------------------------------------------------------------------------------------------------------------------------
REVENUES AND INCOME
Revenues $ 1,572,263 $ 1,393,591 $ 909,842 $ 911,616 $ 1,116,623
Net cash provided by operating activities 635,772 570,334 343,100 382,010 492,473
Net income (loss) 133,575 191,597 49,461 (164,025) 99,278
PER SHARE DATA
Basic earnings (loss) per share $ 2.36 $ 3.42 $ .87 $ (2.88) $ 1.75
Cash dividends $ .16 $ .16 $ .16 $ .16 $ .16
Year-end stock price $ 35.29 $ 46.00 $ 21.44 $ 24.63 $ 35.25
Basic weighted average shares outstanding 56,549 55,999 57,005 56,955 56,872
FINANCIAL POSITION (at year end)
Property, plant and equipment, net:
Oil and gas mineral interests,
equipment and facilities $ 1,953,211 $ 1,485,123 $ 1,242,370 $ 1,429,667 $ 1,546,426
Total assets 2,479,848 1,879,280 1,420,351 1,686,080 1,852,782
Long-term obligations:
Long-term debt, net of current portion 837,177 525,494 445,319 745,143 644,967
Deferred income taxes 176,259 117,048 83,075 106,823 144,083
Other 75,629 61,639 53,877 52,868 56,425
Shareholders' equity 1,010,198 849,682 683,609 642,080 812,989
Ratio of debt to book capital .45 .38 .39 .54 .44
CAPITAL EXPENDITURES
Oil and gas mineral interests,
equipment and facilities $ 765,291 $ 502,430 $ 121,077 $ 445,910 $ 320,561
Methanol and power projects 95,716 98,737 89,728 25,131
Other 1,932 4,430 1,410 2,733 8,499
-------------------------------------------------------------------------------------------------------------------------
Total Capital Expenditures $ 862,939 $ 605,597 $ 212,215 $ 473,774 $ 329,060
-------------------------------------------------------------------------------------------------------------------------
For additional information, see "Item 8. Financial Statements and Supplementary
Data" of this Form 10-K.
OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
------------------------------------------------------------------------------------------------------
GAS
Sales (in millions) $ 592.3 $ 549.9 $ 359.8 $ 441.8 $ 499.4
Production (MMCF per day) 422.4 406.3 455.1 566.6 565.4
Average price (per MCF) $ 3.94 $ 3.77 $ 2.23 2.18 $ 2.48
OIL
Sales (in millions) $ 242.6 $ 224.2 $ 174.9 $ 154.3 $ 243.6
Production (BBLS per day) 30,661 25,805 30,003 37,217 38,345
Average price (per BBL) $ 22.16 $ 24.37 $ 16.29 $ 11.66 $ 17.86
Royalty sales (in millions) $ 20.9 $ 17.3 $ 14.0 $ 13.1 $ 18.1
21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
CRITICAL ACCOUNTING POLICIES AND PRACTICES
The use of estimates is necessary in the preparation of the Company's financial
statements. The circumstances that make these judgments difficult, subjective
and complex have to do with the need to make estimates about the effect of
matters that are inherently uncertain. The use of estimates and assumptions
affects the reported amounts of assets and liabilities. Such estimates and
assumptions also affect the disclosure of legal reserves, platform abandonment
reserves, oil and gas reserves, income taxes and other contingent assets and
liabilities at the date of the financial statements, as well as amounts of
revenues and expenses recognized during the reporting period. Of the estimates
and assumptions that affect reported results, estimates of the Company's oil and
gas reserves are the most significant. Changes in oil and gas reserve estimates
impact the Company's calculation of depletion and abandonment expense and is
critical in the Company's assessment of asset impairments. Management believes
it is necessary to understand the Company's significant accounting policies,
"Item 8. Financial Statements and Supplementary Data--Note 1 - Summary of
Significant Accounting Policies" of this Form 10-K, in order to understand the
Company's financial condition, changes in financial condition and results of
operations.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY
The Company's net cash provided from operations in 2001 was higher than 2000 due
to higher natural gas prices during the first half of 2001 and increased oil and
gas production volumes.
The oil price received by the Company in 2001 decreased nine percent from 2000
and the natural gas price received by the Company increased five percent in 2001
over the price received in 2000. In 2000, the Company's oil price increased 50
percent and the natural gas price increased 69 percent compared to 1999.
CASH PROVIDED FROM OPERATIONS
[CHART OF CASH PROVIDED FROM OPERATIONS]
[CHART OF CASH PROVIDED FROM OPERATIONS]
The Company's unconsolidated subsidiary, AMCCO, is a 50 percent owned joint
venture that owns an indirect 90 percent interest in AMPCO, which completed
construction of a methanol plant in Equatorial Guinea in the second quarter of
2001. During 1999, AMCCO issued $250 million senior secured notes due 2004,
which are not included in the Company's balance sheet at December 31, 2001. On
January 2, 2002, the Company's partner in AMCCO directed AMCCO to sell 50
percent of its interest in AMPCO as a component of the partner's sale of all of
its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay
in full AMCCO's $125 million Series A-1 Notes on January 28, 2002 and to make a
distribution to the Company's partner. Since the Company's partner in AMCCO no
longer retains an economic interest in AMPCO, the Company will consolidate the
results of AMCCO, thereby including the $125 million Series A-2 Notes in the
Company's balance sheet. The terms of the $125 million Series A-2 Notes remain
unchanged.
The plant construction started during 1998 and commercial production began on
May 2, 2001. The total construction costs of the plant and supporting facilities
as of December 31, 2001 were $403 million including various
22
contingencies, with the Company responsible for $201.5 million. AMPCO estimates
that an additional $32 million will be incurred to complete various supporting
facilities to finalize the project. The Company will be responsible for $16
million in 2002. During 2001, the Company recorded costs of $49 million toward
the project.
During 2001, $765 million was spent on acquisition, exploration and development
projects, $49 million on the methanol project and $47 million on the Machala
power project in Ecuador for total expenditures of $861 million. The 2002
exploration and development budget is approximately $520 million, including $20
million on the Machala power project.
During the fourth quarter of 2001, the Company acquired all of Aspect Energy's
interests in 110 wells located along the Texas and Louisiana Gulf Coast. Current
production is approximately 1,900 BBLS of oil per day and 57 MMCF of gas per
day. We acquired approximately 59 BCFe of reserves along with working capital
and hedging positions. Also acquired was a 50 percent interest in Aspect's
future drilling prospects in this region. As part of the transaction, the
Company paid $107 million in cash, issued $14 million of common stock previously
held in treasury and assumed a $40 million note payable.
The Company's current ratio (current assets divided by current liabilities) was
..92:1 at December 31, 2001, compared with .83:1 at December 31, 2000. The
increase in the current ratio was primarily due to an increase in cash and
short-term investments along with a $43.5 million increase in other current
assets primarily composed of various prepaid foreign income taxes, value added
taxes and miscellaneous receivables. The Company's cash and short-term
investments increased from $23.2 million at December 31, 2000, to $73.2 million
at December 31, 2001.
FINANCING
The Company's total long-term debt, net of unamortized discount, at December 31,
2001, was $837 million compared to $525 million at December 31, 2000. The ratio
of debt to book capital (defined as the Company's debt plus its equity) was 45
percent at December 31, 2001, compared with 38 percent at December 31, 2000.
The Company's long-term debt, net of current portion, is comprised of: $100
million of 7 1/4% Notes Due 2023, $250 million of 8% Senior Notes Due 2027, $100
million of 7 1/4% Senior Debentures Due 2097, $11 million on the note obtained
in the acquisition and the outstanding balance of $380 million on a $400 million
five-year credit facility. Payments of $11 million on the note obtained in the
acquisition will be made as follows: 2003, $4 million and 2004, $7 million. The
$380 million due on the credit facility that matures November 30, 2006 is the
only other amount due on long-term debt during the next five years. There are no
scheduled payments prior to maturity. In addition, $19.5 million of the current
installment of long-term debt obtained in the acquisition will be repaid during
2002.
The Company had a $300 million credit agreement that exposed the Company to the
risk of earnings or cash flow loss due to changes in market interest rates. The
interest rate was based upon a Eurodollar rate plus a range of 17.5 to 50 basis
points. There was an outstanding balance of $250 million on this credit
agreement which was repaid on November 30, 2001. At year-end 2000, the Company
had $80 million outstanding on this credit facility. For more information, see
"Item 8. Financial Statements and Supplementary Data--Note 3 - Debt" of this
Form 10-K.
The Company entered into a new $400 million five-year credit agreement on
November 30, 2001 with certain commercial lending institutions which exposes the
Company to the risk of earnings or cash flow loss due to changes in market
interest rates. The interest rate is based upon a Eurodollar rate plus a range
of 60 to 145 basis points depending upon the percentage of utilization and
credit rating. At December 31, 2001, there was $380 million borrowed against
this credit agreement, which has a maturity date of November 30, 2006. For more
information, see "Item 8. Financial Statements and Supplementary Data--Note 3 -
Debt" of this Form 10-K.
The Company also entered into a new $200 million 364-day credit agreement on
November 30, 2001 with certain commercial lending institutions which exposes the
Company to the risk of earnings or cash flow loss due to changes in market
interest rates. The interest rate is based upon a Eurodollar rate plus a range
of 62.5 to 150 basis points
23
depending upon the percentage of utilization and credit rating. At December 31,
2001, there were no amounts outstanding under this credit agreement, which has a
maturity date of November 27, 2002 for the revolving commitment and a maturity
date of November 27, 2003 for the term commitment which includes any balance
remaining after the revolving commitment matures. For more information, see
"Item 8. Financial Statements and Supplementary Data--Note 3 - Debt" of this
Form 10-K.
The Company had a $25 million short-term note payable outstanding December 31,
2001, which was repaid January 28, 2002. The note was an uncommitted facility
with an interest rate of 3.25 percent for the period December 28, 2001 to
January 28, 2002.
On January 2, 2002, the Company's partner in AMCCO directed AMCCO to sell 50
percent of its interest in AMPCO as a component of the partner's sale of all of
its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay
in full AMCCO's $125 million Series A-1 Notes on January 28, 2002 and to make a
distribution to the Company's partner. Since the Company's partner in AMCCO no
longer retains an economic interest in AMPCO, the Company will consolidate the
results of AMCCO, thereby including the $125 million Series A-2 Notes in the
Company's balance sheet. The terms of the $125 million Series A-2 Notes remain
unchanged.
OTHER
The Company has paid quarterly cash dividends of $.04 per share since 1989, and
currently anticipates it will continue to pay quarterly dividends of $.04 per
share.
The Company's Board of Directors, in February 2000, authorized a repurchase of
up to $50 million in the Company's common stock. Under the original $50 million
authorization, the Company repurchased approximately $30 million of common stock
in the first quarter of 2000. The 2000 repurchase of 1,386,400 shares at an
average cost of $21.84 per share was funded from the Company's current cash
flow. On September 17, 2001 the Company's Board of Directors approved an
expansion of the original repurchase program from $50 million to $100 million.
During the fourth quarter of 2001, the Board approved a stock repurchase forward
program. In January 2002, one of the Company's banks purchased $35 million of
the Company's stock or 1,044,454 shares to be settled in early 2003.
The Company has sold a number of non-strategic oil and gas properties over the
past three years. Total amounts of oil and gas reserves associated with the 2000
and 1999 dispositions were 1.2 MMBBLS of oil and 4.8 BCF of gas and 5.1 MMBBLS
of oil and 34.2 BCF of gas, respectively. There were no significant sales of oil
or gas properties in 2001. The Company believes the disposition of non-strategic
properties furthers the goal of concentrating its efforts on strategic
properties.
The Financial Accounting Standards Board ("FASB") issued Statement of Financial
Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and
Hedging Activities," in June 1998. The Statement established accounting and
reporting standards requiring every derivative instrument (including certain
derivative instruments embedded in other contracts) to be recorded in the
balance sheet as either an asset or liability measured at its fair value. The
Statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met wherein
gains and losses are reflected in shareholders' equity as other comprehensive
income until the hedged item is recognized. Special accounting for qualifying
hedges allows a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that a company formally
document, designate and assess the effectiveness of transactions that receive
hedge accounting.
The Company adopted SFAS No. 133 effective January 1, 2001. The adoption of this
statement did not have a material impact on the Company's results of operations
or financial position.
24
RESULTS OF OPERATIONS
NET INCOME AND REVENUES
The Company's net income for 2001 was $133.6 million, a decrease of $58 million
from 2000. The decrease was due primarily to a $61.2 million increase in dry
hole expense, offset by a $3.8 million decrease in abandoned asset expense. The
increase in net income for 2000 compared to 1999, is primarily due to
significantly higher oil and gas prices, 50 percent and 69 percent,
respectively, received during 2000.
NATURAL GAS INFORMATION
Natural gas revenues increased eight percent in 2001, due to a four percent
increase in average daily production coupled with a five percent increase in the
average price. Gas production increased primarily due to the Aspect acquisition
in the fourth quarter of 2001 coupled with the startup of the methanol plant in
Equatorial Guinea. Natural gas accounted for 71 percent of the Company's total
gas and oil revenues in 2001. Gas sales for 2000 increased 53 percent, due
primarily to a 69 percent increase in average gas price offset by an 11 percent
decrease in the average daily gas production compared to 1999. The table below
depicts daily natural gas production in MMCF by area for the last three years.
2001 2000 1999
--------------------------------------------------------------------------------
Offshore 264.8 291.3 304.9
Onshore 113.6 86.9 116.9
INTERNATIONAL 44.0 28.1 33.3
--------------------------------------------------------------------------------
TOTAL 422.4 406.3 455.1
--------------------------------------------------------------------------------
Natural gas production during 2001 ranged from a low of 372.0 MMCF per day in
October, to a high of 437.7 MMCF per day in May.
2001 DAILY PRODUCTION BY QUARTER
[CHART OF 2001 DAILY PRODUCTION BY QUARTER]
[CHART OF 2001 DAILY PRODUCTION BY QUARTER]
CRUDE OIL INFORMATION
Crude oil revenues increased eight percent during 2001, due to a 19 percent
increase in average daily production. The increase in average daily production
for the Company's oil offset a decline of nine percent in the average price
received for 2001. Crude oil accounted for 29 percent of the Company's total oil
and gas revenues in 2001. Oil sales increased 28 percent and average daily
production decreased 14 percent in 2000, compared to 1999.
25
The table below depicts daily oil production in BBLS by area for the last three
years.
2001 2000 1999
----------------------------------------------------------------------
Offshore 11,393 12,077 13,501
Onshore 7,219 6,942 9,901
International 12,049 6,786 6,601
----------------------------------------------------------------------
Total 30,661 25,805 30,003
----------------------------------------------------------------------
Crude oil production during 2001 ranged from a low of 27,858 BBLS per day in
February, to a high of 35,105 BBLS per day in December.
HEDGING ACTIVITY
The Company, through its subsidiaries, from time to time, uses various hedging
arrangements in connection with anticipated crude oil and natural gas sales to
minimize the impact of product price fluctuations. Such arrangements include
fixed price hedges, costless collars and other contractual arrangements.
Although these hedging arrangements expose the Company to credit risk, the
Company monitors the creditworthiness of its counterparties, which generally are
major financial institutions, and believes that losses from nonperformance are
unlikely to occur. Hedging gains and losses related to the Company's oil and gas
production are recorded in oil and gas sales and royalties. For more
information, see "Item 7a. Quantitative and Qualitative Disclosures About Market
Risk" of this Form 10-K.
COSTS AND EXPENSES
Oil and gas operations expense, consisting of lease operating expense, workover
expenses, production taxes and other related lifting costs increased 10 percent
in 2001 from 2000, due to higher daily production volumes and increased four
percent in 2000 from 1999. Included in operations expense were workover costs of
$15.1 million, $21.1 million and $5.7 million for 2001, 2000 and 1999,
respectively. The workovers, which enhanced production during 2001 and 2000,
increased operations expense by $.07 and $.10 per MCFe, respectively. Workover
costs for 1999 were held to a minimum due to low product prices.
[CHART OF OPERATING EXPENSES]
[CHART OF DD&A EXPENSES]
In 2001, depreciation, depletion and amortization ("DD&A") expense increased 23
percent, compared to 2000. The unit rate of DD&A per BOE was $7.70 in 2001,
compared to $6.75 in 2000. The increase in the unit rate per BOE is due
primarily to increased development costs incurred in the Gulf of Mexico to
stabilize the Company's oil and gas production volumes, which are being
amortized in the current and subsequent periods.
The Company provides for the cost of future liabilities related to restoration
and dismantlement costs for offshore facilities. This provision is based on the
Company's best estimate of such costs to be incurred in future years based on
information from the Company's engineers. These estimated costs are provided
through charging DD&A expense using a ratio of production divided by reserves
multiplied by the estimated costs to dismantle and restore. The
26
Company's accumulated provision for future dismantlement and restoration cost
was $80.0 million at December 31, 2001, $79.7 million at December 31, 2000 and
$83.0 million at December 31, 1999. Total estimated future dismantlement and
restoration costs of $168.2 million are included in future production and
development costs for purposes of estimating the future net revenues relating to
the Company's proved reserves.
Oil and gas exploration expense consists of dry hole expense, undeveloped lease
amortization, abandoned assets, seismic and other miscellaneous exploration
expense. The table below depicts the exploration expense for the last three
years.
(IN THOUSANDS) 2001 2000 1999
-------------------------------------------------------------------------------------
Dry hole expense $ 99,684 $ 38,463 $ 19,204
Undeveloped lease amortization 17,213 16,075 9,645
Abandoned assets (415) 3,375 2,483
Seismic 15,607 18,738 7,797
Other 19,592 11,592 7,655
-------------------------------------------------------------------------------------
Total Exploration Expense $ 151,681 $ 88,243 $ 46,784
-------------------------------------------------------------------------------------
IMPAIRMENT OF OPERATING ASSETS
Developed oil and gas properties and other long-lived assets are periodically
assessed to determine if circumstances indicate that the carrying amount of an
asset may not be recoverable. The Company performs this review of recoverability
by estimating future cash flows. If the sum of the expected future cash flows is
less than the carrying amount of the asset, an impairment is recognized based on
the discounted amount of such cash flows. The Company recorded no operating
asset impairments during 2001, 2000 or 1999. Individually significant
undeveloped oil and gas properties are periodically assessed for impairment of
value and a loss is recognized at the time of impairment by providing an
impairment allowance.
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES ("SG&A")
SG&A expenses decreased $3.1 million in 2001 compared to 2000 and $.6 million in
2000 compared to 1999. The decreases reflect the Company's effort to reduce SG&A
through efficiencies and other cost reduction measures.
GATHERING, MARKETING AND PROCESSING
NGM markets the majority of the Company's natural gas, as well as certain
third-party gas. NGM sells gas directly to end-users, gas marketers, industrial
users, interstate and intrastate pipelines, and local distribution companies.
NTI markets a portion of the Company's oil, as well as certain third-party oil.
The Company records all of NGM's and NTI's sales and expenses as gathering,
marketing and processing revenues and expenses. All intercompany sales and
expenses have been eliminated in the Company's consolidated financial
statements.
The gathering, marketing and processing revenues less expenses for both NGM and
NTI are reflected in the table below.
(IN THOUSANDS) 2001 2000 1999
----------------------------- -------------------------- ---------------------------
(AMOUNTS INCLUDE INTER-
COMPANY ELIMINATIONS) NTI NGM NTI NGM NTI NGM
----------------------------------------------------------------------------------------------------------------------
Revenues $ 75,550 $ 645,400 $ 91,204 $ 498,729 $ 62,671 $ 275,375
Expenses
Cost of goods sold 49,191 607,170 63,005 464,600 35,974 237,475
Transportation 19,739 27,779 19,455 24,014 19,128 27,816
General and administrative 199 3,176 190 3,002 180 2,742
----------------------------------------------------------------------------------------------------------------------
Total Expenses $ 69,129 $ 638,125 $ 82,650 $ 491,616 $ 55,282 $ 268,033
----------------------------------------------------------------------------------------------------------------------
Gross Margin $ 6,421 $ 7,275 $ 8,554 $ 7,113 $ 7,389 $ 7,342
----------------------------------------------------------------------------------------------------------------------
The margins for NGM on a per MMBTU basis were $.035 for 2001, $.027 for 2000 and
$.026 for 1999. The increase in NGM's margin on a per MMBTU basis for 2001
compared to 2000, and 2000 compared to 1999, was due primarily to the
improvement in gas prices. The margins for NTI on a per BBL basis were $.95 for
2001, $1.28 for
27
2000 and $.87 for 1999. The decrease in NTI's margin for 2001 compared to 2000
was due primarily to lower crude oil prices. The increase in the 2000 margin
compared to 1999 was due to improved crude oil prices coupled with lower
transportation costs.
FUTURE TRENDS
The Company expects oil and gas production to increase in 2002 and 2003 compared
to 2001. The increase in 2002 will be due primarily to a full year of production
from the expansion of the Alba field in Equatorial Guinea and the Hanze field in
the North Sea. The increase in 2003 will be due primarily to a full year of
production in China and Ecuador.
The Company recently set its 2002 exploration and development budget at
approximately $520 million. Such expenditures are planned to be funded through
internally generated cash flows. The Company believes that it has the capital
structure to take advantage of strategic acquisitions, as they become available,
through internally generated cash flows or borrowings.
On January 2, 2002, the Company's partner in AMCCO directed AMCCO to sell 50
percent of its interest in AMPCO as a component of the partner's sale of all of
its Equatorial Guinea assets. The proceeds of the AMPCO sale were used to repay
in full AMCCO's $125 million Series A-1 Notes on January 28, 2002 and to make a
distribution to the Company's partner. Since the Company's partner in AMCCO no
longer retains an economic interest in AMPCO, the Company will consolidate the
results of AMCCO, thereby including the $125 million Series A-2 Notes in the
Company's balance sheet. The terms of the $125 million Series A-2 Notes remain
unchanged.
The Company's total long-term debt at December 31, 2001 was $837 million and the
ratio of debt to book capital (defined as the Company's debt plus its equity)
was 45 percent. If the $125 million off balance sheet financing were included,
the long-term debt would be $962 million with a ratio of debt to book capital of
48 percent.
Management believes that the Company is well positioned with its balanced
reserves of oil and gas and downstream projects. The uncertainty of commodity
prices continues to affect the oil, gas and methanol industries. The Company
cannot predict the extent to which its revenues will be affected by inflation,
government regulation or changing prices.
ITEM 7a. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company is exposed to market risk in the normal course of its business
operations. Management believes that the Company is well positioned with its mix
of oil and gas reserves to take advantage of future price increases that may
occur. However, the uncertainty of oil and gas prices continues to impact the
oil and gas industry. Due to the volatility of oil and gas prices, the Company,
from time to time, has used derivative hedging instruments and may do so in the
future as a means of controlling its exposure to price changes.
On August 16, 2001, the Company (floating price payor) entered into a total of
three natural gas costless collar contracts related to its production. The first
contract, for the fourth quarter of 2001, for 50,000 MMBTU of gas per day, had a
floor price of $3.25 per MMBTU and a ceiling price of $4.60 per MMBTU. The net
effect of this fourth quarter 2001 hedge was a $.02 per MCF increase in the
average natural gas price for the year 2001. The other two contracts, for
calendar year 2002, each for 25,000 MMBTU of gas per day, have a floor price of
$3.25 per MMBTU and ceiling prices ranging from $5.05 to $5.10 per MMBTU. These
contracts entitle the Company to receive settlement from the counterparty (fixed
price payor) on a calendar quarterly basis, in amounts, if any, by which the
average settlement price for the last scheduled NYMEX trading day applicable for
each month, per calendar quarter, is less than the floor price. The Company
would pay the counterparty if the average settlement price for the last
scheduled NYMEX trading day applicable for each month, per calendar quarter, is
more than the ceiling price. The amount payable by the floating price payor, if
the floating price is above the ceiling price, is the product of the notional
quantity per calculation period and the excess, if any, of the floating price
over the ceiling price in respect of each calendar quarter. The amount payable
by the fixed price payor, if the floating price is below the floor price, is the
product of the notional quantity per calculation period and the excess, if any,
of the floor price over the floating price in respect of each calendar quarter.
Of the 50,000 MMBTU per day of costless collars mentioned in this
28
paragraph, 25,000 MMBTU per day were terminated and, as a result, the Company
will recognize an additional $.70 per MMBTU on 25,000 MMBTU per day in 2002.
In addition, the Company has entered into a number of costless collar hedges for
2002 and 2003. For the period January to March 2002, the Company has entered
into collars for 25,000 MMBTU of natural gas production per day with a floor
price of $2.75 per MMBTU and a ceiling price of $3.50 per MMBTU. For the period
February to March 2002, the Company has entered into collars of 100,000 MMBTU of
natural gas production per day with an average floor price of $2.04 per MMBTU
and an average ceiling price of $2.54 per MMBTU. For the period April to June
2002, the Company has entered into collars for 30,000 MMBTU of natural gas
production per day with a floor price of $2.75 per MMBTU and a ceiling price of
$3.50 per MMBTU. Subsequent to December 31, 2001, the Company entered into
collars for April to June 2002, for 50,000 MMBTU of natural gas production per
day with an average floor price of $2.00 per MMBTU and an average ceiling price
of $3.09 per MMBTU. The collars for April to June with a floor of $2.00 per
MMBTU have a knockout price of $1.70 per MMBTU. For the third quarter of 2002,
the Company has collars for 35,000 MMBTU of natural gas production per day with
a floor price of $2.75 per MMBTU and a ceiling price of $3.50 per MMBTU. For the
fourth quarter of 2002, the Company has collars for 40,000 MMBTU of natural gas
production per day with a floor price of $3.00 per MMBTU and a ceiling price of
$3.75 per MMBTU.
The Company has collars related to calendar year 2003, for 45,000 MMBTU of
natural gas production per day with a floor price of $3.25 per MMBTU and a
ceiling price of $4.00 per MMBTU.
The Company purchased collars and swaps related to the Aspect transaction that
cover the period October 2001 through March 2004 for 6,337 MMBTU of natural gas
production per day and 162 BBLS of oil production per day . Based on the cost of
these collars and swaps, the Company will realize prices of approximately $3.20
per MMBTU and $22.00 per BBL for this time period related to these hedged
volumes. The net effect of this fourth quarter 2001 purchased hedge was a $.01
per MCF increase in the average natural gas price for the year 2001.
The Company adopted SFAS No. 133 effective January 1, 2001. The adoption of this
statement did not have a material impact on the Company's results of operations
or financial position, as of the date of adoption. At December 31, 2001, the
Company recorded oil and gas hedge receivables of $33.4 million, oil and gas
hedge liabilities of $25.4 million and other comprehensive income, net of tax,
of $5.1 million related to the Company's hedging contracts. The Company
estimates that during the next 12 months, $4.4 million of the $5.1 million
stated above, is expected to be reclassified into earnings.
The Company entered into three crude oil premium swap contracts related to its
production for calendar year 2000. Two of the contracts provided for payments
based on daily NYMEX settlement prices. These contracts related to 2,500 BBLS
per day and 2,000 BBLS per day and had trigger prices of $21.73 per BBL and
$22.45 per BBL, respectively, and both had knockout prices of $17.00 per BBL.
These two contracts entitled the Company to receive settlements from the
counterparties in amounts, if any, by which the settlement price for each NYMEX
trading day was less than the trigger price, provided the NYMEX price was also
greater than the $17.00 per BBL knockout price. If a daily settlement price was
$17.00 per BBL or less, then neither party had any liability to the other for
that day. If a daily settlement price was above the applicable trigger price,
then the Company would owe the counterparty for the excess of the settlement
price over the trigger price for that day. Payment was made monthly under each
of these contracts, in an amount equal to the net amount due to either party
based on the sum of the daily amounts determined as described in this paragraph
for that month.
The third contract related to 2,500 BBLS per day and provided for payments based
on monthly average NYMEX settlement prices. The contract entitled the Company to
receive monthly settlements from the counterparty in an amount, if any, by which
the arithmetic average of the daily NYMEX settlement prices for the month was
less than the trigger price, which was $21.73 per BBL, multiplied by the number
of days in the month, provided such average NYMEX price was also greater than
the $17.00 per BBL knockout price. If the average NYMEX settlement price for the
month was $17.00 per BBL or less, then neither party would have any liability to
the other for that month. If the average NYMEX settlement price for the month
was above the trigger price, then the Company would pay the
29
counterparty an amount equal to the excess of the average settlement price over
the trigger price, multiplied by the number of days in the month.
The net effect of these premium swap contracts was a $2.87 per BBL reduction in
the average crude oil price realized by the Company in 2000.
The Company has treated the swap component of these contracts as a hedge (for
accounting purposes only), at swap prices ranging from $19.40 per BBL to $20.20
per BBL, which existed at the dates it entered into these contracts. In
addition, the Company has separately accounted for the premium component of
these contracts by marking them to market, resulting in a gain of $2,921,000
recorded in other income for the year ended December 31, 2000.
In addition to the premium swap crude oil hedging contracts, the Company entered
into crude oil costless collar hedges from January 1, 2000 to April 30, 2000 for
volumes of 2,000 BBLS per day. These costless collars had a floor price ranging
from $21.53 per BBL to $23.27 per BBL and a cap price ranging from $25.83 per
BBL to $27.31 per BBL. These costless collar contracts entitled the Company to
receive settlements from the counterparties in amounts, if any, by which the
monthly average settlement price for each NYMEX trading day during a contract
month was less than the floor price. If the monthly average settlement price was
above the applicable cap price, then the Company would owe the counterparties
for the excess of the monthly average settlement price over the applicable cap
price. If the monthly average settlement price fell between the applicable floor
and cap price, then neither party would have any liability to the other party
for that month. Payment, if any, was made monthly under each of the contracts in
an amount equal to the net amount due either party based on the volumes per day
multiplied by the difference between the NYMEX average price and the cap, if the
NYMEX average price exceeded the cap price, or if the NYMEX average price was
less than the floor price, then the volumes per day multiplied by the difference
between the floor price and the NYMEX average price.
The net effect of these costless collar hedges was a $.05 per BBL reduction in
the average crude oil price realized by the Company in 2000.
During 1999, the Company had no oil or gas hedging transactions for its
production.
NGM, from time to time, employs hedging arrangements in connection with its
purchases and sales of production. While most of NGM's purchases are made for an
index-based price, NGM's customers often require prices that are either fixed or
related to NYMEX. In order to establish a fixed margin and mitigate the risk of
price volatility, NGM may convert a fixed or NYMEX sale to an index-based sales
price (such as by purchasing an index-based futures contract obligating NGM for
delivery of production). Due to the size of such transactions and certain
restraints imposed by contract and by Company guidelines, as of December 31,
2001, the Company had no material market risk exposure from NGM's hedging
activity.
The Company has a $400 million credit agreement that exposes the Company to the
risk of earnings or cash flow loss due to changes in market interest rates. The
interest rate is based upon a Eurodollar rate plus a range of 60 to 145 basis
points depending upon the percentage of utilization and credit rating. At
December 31, 2001, there was $380 million borrowed against this credit
agreement, which has a maturity date of November 30, 2006. All other Company
long-term debt is fixed-rate and, therefore, does not expose the Company to the
risk of earnings or cash flow loss due to changes in market interest rates. For
more information, see "Item 8. Financial Statements and Supplementary Data--Note
3 - Debt" of this Form 10-K.
The Company does not invest in foreign currency derivatives. The U.S. dollar is
considered the primary currency for each of the Company's international
operations. Transactions that are completed in a foreign currency are translated
into U.S. dollars and recorded in the financial statements. Translation gains or
losses were not material in any of the periods presented and the Company does
not believe it is currently exposed to any material risk of loss on this basis.
Such gains or losses are included in other expense on the income statement.
However, certain sales transactions are concluded in foreign currencies and the
Company, therefore, is exposed to potential risk of loss based on fluctuation in
exchange rates from time to time.
30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants................................................................ 32
Consolidated Balance Sheet as of December 31, 2001 and 2000............................................. 33
Consolidated Statement of Operations for each of the three years in the period ended
December 31, 2001..................................................................................... 34
Consolidated Statement of Cash Flows for each of the three years in the period ended
December 31, 2001..................................................................................... 35
Consolidated Statement of Shareholders' Equity and Other Comprehensive Income
for each of the three years in the period ended December 31, 2001..................................... 36
Notes to Consolidated Financial Statements.............................................................. 37
Supplemental Oil and Gas Information (Unaudited)........................................................ 52
Interim Financial Information (Unaudited)............................................................... 58
All other financial statement schedules have been omitted because the required
information is not present or is not present in amounts sufficient to require
submission of the schedule or because the information required is included in
the financial statements, including the notes thereto.
31
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Noble Affiliates, Inc.:
We have audited the accompanying consolidated balance sheet of Noble
Affiliates, Inc. (a Delaware corporation) and subsidiaries as of December 31,
2001 and 2000, and the related consolidated statements of operations,
shareholders' equity and other comprehensive income and cash flows for each of
the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits 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 audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Noble Affiliates, Inc. and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma
January 24, 2002
32
CONSOLIDATED BALANCE SHEET
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
DECEMBER 31,
-----------------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT SHARE AMOUNTS) 2001 2000
-----------------------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS:
Cash and short-term investments $ 73,237 $ 23,152
Accounts receivable - trade 182,979 235,843
Oil and gas hedges receivable 33,424
Materials and supplies inventories 10,828 4,645
Other current assets 51,103 7,621
-----------------------------------------------------------------------------------------------------------------------------------
Total current assets 351,571 271,261
-----------------------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas mineral interests, equipment and facilities
(successful efforts method of accounting) 3,929,226 3,213,223
Other 45,528 43,244
-----------------------------------------------------------------------------------------------------------------------------------
3,974,754 3,256,467
Accumulated depreciation, depletion and amortization (2,021,543) (1,771,344)
-----------------------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment, net 1,953,211 1,485,123
-----------------------------------------------------------------------------------------------------------------------------------
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY 117,735 74,159
-----------------------------------------------------------------------------------------------------------------------------------
OTHER ASSETS 57,331 48,737
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 2,479,848 $ 1,879,280
-----------------------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - trade $ 270,091 $ 279,379
Short-term note payable 25,000
Current installments of long-term debt 19,507
Oil and gas hedges payable 25,363
Other current liabilities 40,624 30,730
Income taxes - current 15,308
-----------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 380,585 325,417
-----------------------------------------------------------------------------------------------------------------------------------
DEFERRED INCOME TAXES 176,259 117,048
-----------------------------------------------------------------------------------------------------------------------------------
OTHER DEFERRED CREDITS AND NONCURRENT LIABILITIES 75,629 61,639
-----------------------------------------------------------------------------------------------------------------------------------
LONG-TERM DEPT 837,177 525,494
-----------------------------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY:
Preferred stoc$1.00; 4,000,000 shares authorized, none issued Common stock -
par value $3.33 1/3; 100,000,000 shares authorized;
59,511,323 and 59,002,162 shares issued in 2001 and 2000, respectively 198,369 196,672
Capital in excess of par value 396,104 373,259
Accumulated other comprehensive income 5,070
Retained earnings 449,985 325,452
-----------------------------------------------------------------------------------------------------------------------------------
1,049,528 895,383
Less common stock in treasury at cost
(December 31, 2001, 2,505,522 shares and
December 31, 2000, 2,911,300 shares) (39,330) (45,701)
-----------------------------------------------------------------------------------------------------------------------------------
Total shareholders' equity 1,010,198 849,682
-----------------------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 2,479,848 $ 1,879,280
-----------------------------------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
33
CONSOLIDATED STATEMENT OF OPERATIONS
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 2001 2000 1999
-----------------------------------------------------------------------------------------------------------------------------------
REVENUES:
Oil and gas sales and royalties $ 855,800 $ 791,353 $ 548,733
Gathering, marketing and processing 721,000 589,933 338,046
Other income 538 10,816 23,100
Income (loss) from investment in unconsolidated subsidiary (5,075) 1,489 (37)
-----------------------------------------------------------------------------------------------------------------------------------
Total Revenue 1,572,263 1,393,591 909,842
-----------------------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES:
Oil and gas exploration 151,681 88,243 46,784
Oil and gas operations 133,549 121,866 116,698
Gathering, marketing and processing 708,292 574,266 323,314
Depreciation, depletion and amortization 284,016 230,800 254,515
Selling, general and administrative 44,164 47,291 47,859
Interest 41,904 37,968 48,935
Interest capitalized (15,953) (6,326) (5,894)
-----------------------------------------------------------------------------------------------------------------------------------
Total Expenses 1,347,653 1,094,108 832,211
-----------------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE TAXES 224,610 299,483 77,631
-----------------------------------------------------------------------------------------------------------------------------------
INCOME TAX PROVISION:
Current 31,595 74,616 24,508
Deferred 59,440 33,270 3,662
-----------------------------------------------------------------------------------------------------------------------------------
Total Tax Provision 91,035 107,886 28,170
-----------------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 133,575 $ 191,597 $ 49,461
-----------------------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS PER SHARE $ 2.36 $ 3.42 $ .87
-----------------------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS PER SHARE $ 2.33 $ 3.38 $ .86
-----------------------------------------------------------------------------------------------------------------------------------
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic 56,549 55,999 57,005
Diluted 57,303 56,755 57,349
-----------------------------------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
34
CONSOLIDATED STATEMENT OF CASH FLOWS
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS) 2001 2000 1999
------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 133,575 $ 191,597 $ 49,461
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 284,016 230,800 254,515
Dry hole 99,684 38,463 19,204
Amortization of undeveloped leasehold costs, net 17,213 16,075 9,645
(Gain) loss on disposal of assets (2,098) (3,799) (12,079)
Noncurrent deferred income taxes 59,212 33,973 (23,749)
(Income) loss from unconsolidated subsidiary 5,075 (1,489) 37
Increase (decrease) in other deferred credits 13,990 7,762 1,011
(Increase) decrease in other (2,224) (3,747) (1,295)
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable 57,973 (137,049) 7,719
(Increase) decrease in other current assets (64,951) 3,557 16,571
Increase (decrease) in accounts payable (17,960) 198,871 (4,785)
Increase (decrease) in other current liabilities 52,267 (4,680) 26,845
------------------------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 635,772 570,334 343,100
------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (738,706) (536,901) (142,124)
Investment in unconsolidated subsidiary (48,651) (57,045) (51,962)
Proceeds from the transfer of our interest
to unconsolidated subsidiary 61,987
Proceeds from sale of property, plant and equipment 1,434 12,608 58,137
Aspect acquisition (107,078)
Cash obtained in acquisition 9,286
------------------------------------------------------------------------------------------------------------------------------------
NET CASH USED IN INVESTING ACTIVITIES (883,715) (581,338) (73,962)
------------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Exercise of stock options 16,675 13,717 1,188
Cash dividends paid (9,042) (8,958) (9,120)
Proceeds from bank debt 675,000 137,000
Repayment of bank debt (375,000) (57,000) (300,000)
Repayment of notes payable - unconsolidated subsidiary (23,245) (38,101)
Proceeds from notes payable - unconsolidated subsidiary 60,720
Repayment of note payable obtained in acquisition (9,605)
Purchase of treasury stock (30,283)
------------------------------------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 298,028 31,231 (285,313)
------------------------------------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM CASH INVESTMENTS 50,085 20,227 (16,175)
CASH AND SHORT-TERM CASH INVESTMENTS AT BEGINNING OF YEAR 23,152 2,925 19,100
------------------------------------------------------------------------------------------------------------------------------------
CASH AND SHORT-TERM CASH INVESTMENTS AT END OF YEAR $ 73,237 $ 23,152 $ 2,925
------------------------------------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amount capitalized) $ 26,590 $ 32,976 $ 44,845
Income taxes $ 66,131 $ 56,890 $ 30,000
Non-cash financing and investing activities:
Issuance of treasury stock for acquisition $ 14,238
Debt assumed in acquisition $ 40,043
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
35
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY AND
OTHER COMPREHENSIVE INCOME
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
ACCUMULATED
OTHER CAPITAL IN OTHER TREASURY TOTAL
COMPREHENSIVE COMMON EXCESS OF RETAINED COMPREHENSIVE STOCK SHAREHOLDERS'
(IN THOUSANDS) INCOME STOCK PAR VALUE EARNINGS INCOME AT COST EQUITY
-----------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998 $ 195,018 $ 360,008 $ 102,472 $ (15,418) $ 642,080
----------------------------------------------------------------------------------------
Net Income 49,461 49,461
Exercise of stock options 213 975 1,188
Cash dividends
($.16 per share) (9,120) (9,120)
----------------------------------------------------------------------------------------
DECEMBER 31, 1999 $ 195,231 $ 360,983 $ 142,813 $ (15,418) $ 683,609
----------------------------------------------------------------------------------------
Net Income 191,597 191,597
Purchase of treasury stock (30,283) (30,283)
Exercise of stock options 1,441 12,276 13,717
Cash dividends
($.16 per share) (8,958) (8,958)
----------------------------------------------------------------------------------------
DECEMBER 31, 2000 $ 196,672 $ 373,259 $ 325,452 $ (45,701) $ 849,682
----------------------------------------------------------------------------------------
Net Income $ 133,575 133,575 133,575
Hedge derivatives marked
to market 5,070 5,070 5,070
Treasury stock issued
for acquisition 7,867 6,371 14,238
Exercise of stock options 1,697 14,978 16,675
Cash dividends
($.16 per share) (9,042) (9,042)
-----------------------------------------------------------------------------------------------------
Total $ 138,645
----------
DECEMBER 31, 2001 $ 198,369 $ 396,104 $ 449,985 $ 5,070 $ (39,330) $1,010,198
----------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DOLLAR AMOUNTS IN TABLES, UNLESS OTHERWISE INDICATED, ARE IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION
The consolidated accounts include Noble Affiliates, Inc. (the "Company") and the
consolidated accounts of its wholly-owned subsidiaries: Noble Gas Marketing,
Inc. ("NGM"); Noble Trading, Inc. ("NTI"); NPM, Inc.; and Samedan Oil
Corporation ("Samedan"). Effective December 31, 2001, Energy Development
Corporation, a previously wholly-owned subsidiary of Samedan, was merged into
Samedan. Listed below are consolidated entities at December 31, 2001.
NOBLE AFFILIATES, INC.
LaTex Resources Inc.
Noble Gas Marketing, Inc.
Noble Gas Pipeline, Inc.
Noble Trading, Inc.
NPM, Inc.
Samedan Oil Corporation
Samedan North Sea, Inc.
Samedan of North Africa, Inc.
EDC Ireland
Samedan International
Machalapower Cia. Ltda.
Samedan, Mediterranean Sea
Samedan Transfer Sub
Samedan Vietnam Limited
Samedan, Mediterranean Sea, Inc.
Samedan of Tunisia, Inc.
Samedan Oil of Canada, Inc.
Samedan Oil of Indonesia, Inc.
Samedan Pipe Line Corporation
Samedan Royalty Corporation
EDC Australia, Ltd.
EDC Ecuador Ltd.
EDC Ecuador Limited
EDC Portugal Ltd.
EDC (UK) Limited
EDC (Denmark) Inc.
EDC (Europe) Limited
EDC (ISE) Limited
EDC (Oilex) Limited
Brabant Oil Limited
Energy Development Corporation (Argentina), Inc.
Energy Development Corporation (China), Inc.
Energy Development Corporation (HIPS), Inc.
Gasdel Pipeline System Incorporated
HGC, Inc.
Producers Service, Inc.
37
NATURE OF OPERATIONS
The Company is an independent energy company engaged through its subsidiaries in
the exploration, development, production and marketing of oil and gas. Samedan
operates throughout the major basins in the United States, including the Gulf of
Mexico, as well as international operations in Argentina, China, Ecuador,
Equatorial Guinea, the Mediterranean Sea, the North Sea and Vietnam. The Company
markets its oil and gas production through NGM, NTI and Samedan.
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities. Such estimates and
assumptions also affect the disclosure of contingent assets and liabilities at
the date of the financial statements as well as amounts of revenues and expenses
recognized during the reporting period. Of the estimates and assumptions that
affect reported results, the estimate of the Company's oil and gas reserves is
the most significant.
FOREIGN CURRENCY TRANSLATION
The U.S. dollar is considered the primary currency for each of the Company's
international operations. Transactions that are completed in a foreign currency
are translated into U.S. dollars and recorded in the financial statements.
Translation gains or losses were not material in any of the periods presented
and are included in other expense on the income statement.
INVENTORIES
Materials and supplies inventories, consisting principally of tubular goods and
production equipment, are stated at the lower of cost or market, with cost being
determined by the first-in, first-out method.
PROPERTY, PLANT AND EQUIPMENT
The Company accounts for its oil and gas properties under the successful efforts
method of accounting. Under this method, costs to acquire mineral interests in
oil and gas properties, to drill and equip exploratory wells that find proved
reserves and to drill and equip development wells are capitalized. Capitalized
costs of producing oil and gas properties are amortized to operations by the
unit-of-production method based on proved developed oil and gas reserves on a
property-by-property basis as estimated by Company engineers. Estimated future
restoration and abandonment costs are recorded by charges to depreciation,
depletion and amortization ("DD&A") expense over the productive lives of the
related properties. The Company has provided $80.0 million for such future costs
classified with accumulated DD&A in the December 31, 2001 balance sheet. The
total estimated future dismantlement and restoration costs of $168.2 million are
included in future production and development costs for purposes of estimating
the future net revenues relating to the Company's proved reserves. Upon sale or
retirement of depreciable or depletable property, the cost and related
accumulated DD&A are eliminated from the accounts and the resulting gain or loss
is recognized.
Individually significant undeveloped oil and gas properties are periodically
assessed for impairment of value and a loss is recognized at the time of
impairment by providing an impairment allowance. Other undeveloped properties
are amortized on a composite method based on the Company's experience of
successful drilling and average holding period. Geological and geophysical
costs, delay rentals and costs to drill exploratory wells which do not find
proved reserves are expensed. Repairs and maintenance are charged to expense as
incurred.
Developed oil and gas properties and other long-lived assets are periodically
assessed to determine if circumstances indicate that the carrying amount of an
asset may not be recoverable. The Company performs this review of recoverability
by estimating future cash flows. If the sum of the expected future cash flows is
less than the carrying amount of the asset, an impairment is recognized based on
the discounted amount of such cash flows.
38
INCOME TAXES
The Company files a consolidated federal income tax return. Deferred income
taxes are provided for temporary differences between the financial reporting and
tax bases of the Company's assets and liabilities.
CAPITALIZATION OF INTEREST
The Company capitalizes interest costs associated with the development and
construction of significant properties or projects.
STATEMENT OF CASH FLOWS
For purposes of reporting cash flows, cash and short-term investments include
cash on hand and investments purchased with original maturities of three months
or less.
BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE
Basic income per share of common stock has been computed on the basis of the
weighted average number of shares outstanding during each period. The diluted
net income per share of common stock includes the effect of outstanding stock
options. The following table summarizes the calculation of basic earnings per
share ("EPS") and diluted EPS components as of December 31:
2001 2000 1999
--------------------------- -------------------------- ---------------------------
(IN THOUSANDS INCOME SHARES INCOME SHARES INCOME SHARES
EXCEPT PER SHARE AMOUNTS) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR)
---------------------------------------------------------------------------------------------------------------------
Net income/shares $133,575 56,549 $191,597 55,999 $49,461 57,005
---------------------------------------------------------------------------------------------------------------------
BASIC EPS $2.36 $3.42 $.87
---------------------------------------------------------------------------------------------------------------------
Net income/shares $133,575 56,549 $191,597 55,999 $49,461 57,005
Effect of Dilutive Securities
Stock options 754 756 344
---------------------------------------------------------------------------------------------------------------------
Adjusted net income
and shares $133,575 57,303 $191,597 56,755 $49,461 57,349
---------------------------------------------------------------------------------------------------------------------
DILUTED EPS $2.33 $3.38 $.86
---------------------------------------------------------------------------------------------------------------------
REVENUE RECOGNITION AND GAS IMBALANCES
Samedan has gas sales contracts with NGM, whereby Samedan is paid an index price
for all gas sold to NGM. NGM records sales, including hedging transactions, as
gathering, marketing and processing revenues. NGM records the amount paid to
Samedan and third parties as cost of sales in gathering, marketing and
processing. All intercompany sales and costs have been eliminated.
The Company follows an entitlements method of accounting for its gas imbalances.
Gas imbalances occur when the Company sells more or less gas than its entitled
ownership percentage of total gas production. Any excess amount received above
the Company's share is treated as a liability. If less than the Company's
entitlement is received, the underproduction is recorded as a receivable. The
Company records the noncurrent liability in Other Deferred Credits and
Noncurrent Liabilities, and the current liability in Other Current Liabilities.
The Company's gas imbalance liabilities were $15.5 million and $14.2 million for
2001 and 2000, respectively. The Company records the noncurrent receivable in
Other Assets, and the current receivable in Other Current Assets. The Company's
gas imbalance receivables were $20.9 million and $18.5 million for 2001 and
2000, respectively, and are valued at the amount which is expected to be
received.
39
TAKE-OR-PAY SETTLEMENTS
The Company records gas contract settlements which are not subject to recoupment
in Other Income when the settlement is received.
TRADING AND HEDGING ACTIVITIES
The Company, through its subsidiaries, from time to time, uses various hedging
arrangements in connection with anticipated crude oil and natural gas sales to
minimize the impact of product price fluctuations. Such arrangements include
fixed price hedges, costless collars, and other contractual arrangements.
Although these hedging arrangements expose the Company to credit risk, the
Company monitors the creditworthiness of its counterparties, which generally are
major financial institutions, and believes that losses from nonperformance are
unlikely to occur. Hedging gains and losses related to the Company's oil and gas
production are recorded in oil and gas sales and royalties.
On August 16, 2001, the Company (floating price payor) entered into a total of
three natural gas costless collar contracts related to its production. The first
contract, for the fourth quarter of 2001, for 50,000 MMBTU of gas per day, had a
floor price of $3.25 per MMBTU and a ceiling price of $4.60 per MMBTU. The net
effect of this fourth quarter 2001 hedge was a $.02 per MCF increase in the
average natural gas price for the year 2001. The other two contracts, for
calendar year 2002, each for 25,000 MMBTU of gas per day, have a floor price of
$3.25 per MMBTU and ceiling prices ranging from $5.05 to $5.10 per MMBTU. These
contracts entitle the Company to receive settlement from the counterparty (fixed
price payor) on a calendar quarterly basis, in amounts, if any, by which the
average settlement price for the last scheduled NYMEX trading day applicable for
each month, per calendar quarter, is less than the floor price. The Company
would pay the counterparty if the average settlement price for the last
scheduled NYMEX trading day applicable for each month, per calendar quarter, is
more than the ceiling price. The amount payable by the floating price payor, if
the floating price is above the ceiling price, is the product of the notional
quantity per calculation period and the excess, if any, of the floating price
over the ceiling price in respect of each calendar quarter. The amount payable
by the fixed price payor, if the floating price is below the floor price, is the
product of the notional quantity per calculation period and the excess, if any,
of the floor price over the floating price in respect of each calendar quarter.
Of the 50,000 MMBTU per day of costless collars mentioned in this paragraph,
25,000 MMBTU per day were terminated and, as a result, the Company will
recognize an additional $.70 per MMBTU on 25,000 MMBTU per day in 2002.
In addition, the Company has entered into a number of costless collar hedges for
2002 and 2003. For the period January to March 2002, the Company has entered
into collars for 25,000 MMBTU of natural gas production per day with a floor
price of $2.75 per MMBTU and a ceiling price of $3.50 per MMBTU. For the period
February to March 2002, the Company has entered into collars of 100,000 MMBTU of
natural gas production per day with an average floor price of $2.04 per MMBTU
and an average ceiling price of $2.54 per MMBTU. For the period April to June
2002, the Company has entered into collars for 30,000 MMBTU of natural gas
production per day with a floor price of $2.75 per MMBTU and a ceiling price of
$3.50 per MMBTU. Subsequent to December 31, 2001, the Company entered into
collars for April to June 2002, for 50,000 MMBTU of natural gas production per
day with an average floor price of $2.00 per MMBTU and an average ceiling price
of $3.09 per MMBTU. The collars for April to June with a floor of $2.00 per
MMBTU have a knockout price of $1.70 per MMBTU. For the third quarter of 2002,
the Company has collars for 35,000 MMBTU of natural gas production per day with
a floor price of $2.75 per MMBTU and a ceiling price of $3.50 per MMBTU. For the
fourth quarter of 2002, the Company has collars for 40,000 MMBTU of natural gas
production per day with a floor price of $3.00 per MMBTU and a ceiling price of
$3.75 per MMBTU.
The Company has collars related to calendar year 2003, for 45,000 MMBTU of
natural gas production per day with a floor price of $3.25 per MMBTU and a
ceiling price of $4.00 per MMBTU.
The Company purchased collars and swaps related to the Aspect transaction that
cover the period October 2001 through March 2004 for 6,337 MMBTU of natural gas
production per day and 162 BBLS of oil production per day.
40
Based on the cost of these collars and swaps, the Company will realize prices of
approximately $3.20 per MMBTU and $22.00 per BBL for this time period related to
these hedged volumes. The net effect of this fourth quarter 2001 purchased hedge
was a $.01 per MCF increase in the average natural gas price for the year 2001.
The Company adopted SFAS No. 133 effective January 1, 2001. The adoption of this
statement did not have a material impact on the Company's results of operations
or financial position, as of the date of adoption. At December 31, 2001, the
Company recorded oil and gas hedge receivables of $33.4 million, oil and gas
hedge liabilities of $25.4 million and other comprehensive income, net of tax,
of $5.1 million related to the Company's hedging contracts. The Company
estimates that during the next 12 months, $4.4 million of the $5.1 million
stated above, is expected to be reclassified into earnings.
The Company entered into three crude oil premium swap contracts related to its
production for calendar year 2000. Two of the contracts provided for payments
based on daily NYMEX settlement prices. These contracts related to 2,500 BBLS
per day and 2,000 BBLS per day and had trigger prices of $21.73 per BBL and
$22.45 per BBL, respectively, and both had knockout prices of $17.00 per BBL.
These two contracts entitled the Company to receive settlements from the
counterparties in amounts, if any, by which the settlement price for each NYMEX
trading day was less than the trigger price, provided the NYMEX price was also
greater than the $17.00 per BBL knockout price. If a daily settlement price was
$17.00 per BBL or less, then neither party had any liability to the other for
that day. If a daily settlement price was above the applicable trigger price,
then the Company would owe the counterparty for the excess of the settlement
price over the trigger price for that day. Payment was made monthly under each
of these contracts, in an amount equal to the net amount due to either party
based on the sum of the daily amounts determined as described in this paragraph
for that month.
The third contract related to 2,500 BBLS per day and provided for payments based
on monthly average NYMEX settlement prices. The contract entitled the Company to
receive monthly settlements from the counterparty in an amount, if any, by which
the arithmetic average of the daily NYMEX settlement prices for the month was
less than the trigger price, which was $21.73 per BBL, multiplied by the number
of days in the month, provided such average NYMEX price was also greater than
the $17.00 per BBL knockout price. If the average NYMEX settlement price for the
month was $17.00 per BBL or less, then neither party would have any liability to
the other for that month. If the average NYMEX settlement price for the month
was above the trigger price, then the Company would pay the counterparty an
amount equal to the excess of the average settlement price over the trigger
price, multiplied by the number of days in the month.
The net effect of these premium swap contracts was a $2.87 per BBL reduction in
the average crude oil price realized by the Company in 2000.
The Company has treated the swap component of these contracts as a hedge (for
accounting purposes only), at swap prices ranging from $19.40 per BBL to $20.20
per BBL, which existed at the dates it entered into these contracts. In
addition, the Company has separately accounted for the premium component of
these contracts by marking them to market, resulting in a gain of $2,921,000
recorded in other income for the year ended December 31, 2000.
In addition to the premium swap crude oil hedging contracts, the Company entered
into crude oil costless collar hedges from January 1, 2000 to April 30, 2000 for
volumes of 2,000 BBLS per day. These costless collars had a floor price ranging
from $21.53 per BBL to $23.27 per BBL and a cap price ranging from $25.83 per
BBL to $27.31 per BBL. These costless collar contracts entitled the Company to
receive settlements from the counterparties in amounts, if any, by which the
monthly average settlement price for each NYMEX trading day during a contract
month was less than the floor price. If the monthly average settlement price was
above the applicable cap price, then the Company would owe the counterparties
for the excess of the monthly average settlement price over the applicable cap
price. If the monthly average settlement price fell between the applicable floor
and cap price, then neither party would have any liability to the other party
for that month. Payment, if any, was made monthly under each of the contracts in
an amount equal to the net amount due either party based on the volumes per day
multiplied by the difference between the NYMEX average price and the cap, if the
NYMEX average price exceeded the cap price, or if the NYMEX
41
average price was less than the floor price, then the volumes per day multiplied
by the difference between the floor price and the NYMEX average price.
The net effect of these costless collar hedges was a $.05 per BBL reduction in
the average crude oil price realized by the Company in 2000.
During 1999, the Company had no oil or gas hedging transactions for its
production.
In addition to the hedging arrangements pertaining to the Company's production
as described above, NGM employs various hedging arrangements in connection with
its purchases and sales of third party production to lock in profits or limit
exposure to gas price risk. Most of the purchases made by NGM are on an index
basis; however, purchasers in the markets in which NGM sells often require fixed
or NYMEX related pricing. NGM may use a hedge to convert the fixed or NYMEX sale
to an index basis thereby determining the margin and minimizing the risk of
price volatility. During 2001, NGM had hedging transactions with broker-dealers
that ranged from 1,157,000 MMBTU to 1,388,000 MMBTU of gas per day. At December
31, 2001, NGM had in place hedges ranging from approximately 20,000 MMBTU to
1,439,000 MMBTU of gas per day for January 2002 to May 2006 for future physical
transactions.
In 2000, NGM had hedging transactions with broker-dealers that ranged from
423,000 MMBTU to 1,023,000 MMBTU of gas per day. During 1999, NGM had hedging
transactions with broker-dealers that ranged from 146,000 MMBTU to 815,000 MMBTU
of gas per day. NGM records hedging gains or losses relating to fixed term sales
as gathering, marketing and processing revenues in the periods in which the
related contract is completed.
SELF-INSURANCE
The Company self-insures the medical and dental coverage provided to certain of
its employees, certain workers' compensation and the first $250,000 of its
general liability coverage.
A provision for self-insured claims is recorded when sufficient information is
available to reasonably estimate the amount of the loss.
UNCONSOLIDATED SUBSIDIARY
The Company has an unconsolidated subsidiary, Atlantic Methanol Capital Company
("AMCCO"), a 50 percent owned joint venture that owns an indirect 90 percent
interest in Atlantic Methanol Production Company ("AMPCO"). The Company
accounted for its interest in AMCCO through 2001 using the equity method within
the Company's wholly-owned subsidiary, Samedan of North Africa, Inc. The Company
participated with a 50 percent expense interest (45 percent ownership net of a
five percent government carried interest) in the construction of a methanol
plant in Equatorial Guinea. For more information, see "Note 9 - Unconsolidated
Subsidiary" of this Form 10-K.
RECLASSIFICATION
Certain reclassifications have been made to the 1999 consolidated financial
statements to conform to the 2001 presentation.
RECENTLY ISSUED PRONOUNCEMENTS
The Financial Accounting Standards Board ("FASB") issued Statement of Financial
Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and
Hedging Activities," in June 1998. The Statement established accounting and
reporting standards requiring every derivative instrument (including certain
derivative instruments embedded in other contracts) to be recorded in the
balance sheet as either an asset or liability measured at its fair value. The
Statement requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met wherein
gains and losses are reflected in shareholders' equity as other
42
comprehensive income until the hedged item is recognized. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement, and requires that a company
formally document, designate and assess the effectiveness of transactions that
receive hedge accounting.
The Company adopted SFAS No. 133 effective January 1, 2001. The adoption of this
statement did not have a material impact on the Company's results of operations
or financial position, as of the date of adoption. At December 31, 2001, the
Company recorded oil and gas hedge receivables of $33.4 million, oil and gas
hedge liabilities of $25.4 million and other comprehensive income, net of tax,
of $5.1 million related to the Company's hedging contracts.
SFAS No. 143, "Accounting for Asset Retirement Obligations," was issued in June
2001. This statement addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. This statement requires that the fair value
of a liability for an asset retirement obligation be recognized in the period in
which it is incurred. The associated asset retirement costs are capitalized as
part of the carrying cost of the asset. The Company has not quantified the
impact of adopting SFAS No. 143, but plans to adopt the statement by January 1,
2003.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets,"
was issued in August 2001. This statement addresses financial accounting and
reporting for the impairment or disposal of long-lived assets. This statement
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of." This statement requires (a)
recognition of an impairment loss only if the carrying amount of a long-lived
asset is not recoverable from its undiscounted cash flows and (b) measurement of
an impairment loss as the difference between the carrying amount and fair value
of the asset. The Company adopted the statement January 1, 2002 with no material
impact on the Company's results of operations or financial position.
NOTE 2 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of
each class of financial instruments.
CASH AND SHORT-TERM INVESTMENTS
The carrying amount approximates fair value due to the short maturity of the
instruments.
OIL AND GAS PRICE HEDGE AGREEMENTS
The fair value of oil and gas price hedges is the estimated amount the Company
would receive or pay to terminate the hedge agreements at the reporting date
taking into account creditworthiness of the hedging parties.
LONG-TERM DEBT
The fair value of the Company's long-term debt is estimated based on the quoted
market prices for the same or similar issues or on the current rates offered to
the Company for debt of the same remaining maturities.
The carrying amounts and estimated fair values of the Company's financial
instruments as of December 31, for each of the years are as follows:
2001 2000
---------------------------- ---------------------------
CARRYING FAIR CARRYING FAIR
(IN THOUSANDS) AMOUNT VALUE AMOUNT VALUE
--------------------------------------------------------------------------------------------------------------------
Cash and short-term investments $ 73,237 $ 73,237 $ 23,152 $ 23,152
Long-term debt $ 837,177 $ 852,033 $ 525,494 $ 539,375
43
NOTE 3 - DEBT
A summary of debt at December 31 follows:
(IN THOUSANDS) 2001 2000
--------------------------------------------------------------------------------------------------------------------
$400 million Credit Agreement $ 380,000 $
$300 million Credit Agreement 80,000
Note obtained in acquisition 31,015
7 1/4% Notes Due 2023 100,000 100,000
8% Senior Notes Due 2027 250,000 250,000
7 1/4% SENIOR DEBENTURES DUE 2097 100,000 100,000
--------------------------------------------------------------------------------------------------------------------
Outstanding Debt 861,015 530,000
--------------------------------------------------------------------------------------------------------------------
Less: unamortized discount 4,331 4,506
Current Installment of Long-term Debt Obtained in Acquisition 19,507
--------------------------------------------------------------------------------------------------------------------
Long-term Debt $ 837,177 $ 525,494
--------------------------------------------------------------------------------------------------------------------
The Company's total long-term debt, net of unamortized discount, at December 31,
2001, was $837 million compared to $525 million at December 31, 2000. The ratio
of debt to book capital (defined as the Company's debt plus its equity) was 45
percent at December 31, 2001, compared with 38 percent at December 31, 2000.
The Company's long-term debt, net of current portion, is comprised of: $100
million of 7 1/4% Notes Due 2023, $250 million of 8% Senior Notes Due 2027, $100
million of 7 1/4% Senior Debentures Due 2097, $11 million on the note obtained
in the acquisition and the outstanding balance of $380 million on a $400 million
five-year credit facility. Payments of $11 million on the note obtained in the
acquisition will be made as follows: 2003, $4 million and 2004, $7 million. The
$380 million due on the credit facility that matures November 30, 2006 is the
only other amount due on long-term debt during the next five years. There are no
scheduled payments prior to maturity. In addition, $19.5 million of the current
installment of the long-term debt obtained in the acquisition will be repaid
during 2002.
The Company had a $300 million credit agreement that exposed the Company to the
risk of earnings or cash flow loss due to changes in market interest rates. The
interest rate was based upon a Eurodollar rate plus a range of 17.5 to 50 basis
points. There was an outstanding balance of $250 million on this credit
agreement which was repaid on November 30, 2001. At year-end 2000, the Company
had $80 million outstanding on this credit facility.
The Company entered into a new $400 million five-year credit agreement on
November 30, 2001 with certain commercial lending institutions which exposes the
Company to the risk of earnings or cash flow loss due to changes in market
interest rates. The interest rate is based upon a Eurodollar rate plus a range
of 60 to 145 basis points depending upon the percentage of utilization and
credit rating. At December 31, 2001, there was $380 million borrowed against
this credit agreement, which has a maturity date of November 30, 2006.
The Company also entered into a new $200 million 364-day credit agreement on
November 30, 2001 with certain commercial lending institutions which exposes the
Company to the risk of earnings or cash flow loss due to changes in market
interest rates. The interest rate is based upon a Eurodollar rate plus a range
of 62.5 to 150 basis points depending upon the percentage of utilization and
credit rating. At December 31, 2001, there were no amounts outstanding under
this credit agreement, which has a maturity date of November 27, 2002 for the
revolving commitment and a maturity date of November 27, 2003 for the term
commitment which includes any balance remaining after the revolving commitment
matures.
The Company had a $25 million short-term note payable outstanding December 31,
2001, which was repaid January 28, 2002. The note was an uncommitted facility
with an interest rate of 3.25 percent for the period December 28, 2001 to
January 28, 2002.
44
NOTE 4 - INCOME TAXES
The following table details the difference between the federal statutory tax
rate and the effective tax rate for the years ended December 31:
(AMOUNTS EXPRESSED IN PERCENTAGES) 2001 2000 1999
---------------------------------------------------------------------------------------------------------------------
Statutory rate (benefit) 35.0 35.0 35.0
Effect of:
State taxes, net of federal benefit .3 .3
Difference between U.S. and foreign rates 4.9 .2 3.1
OTHER, NET .4 .5 (1.8)
---------------------------------------------------------------------------------------------------------------------
Effective Rate 40.6 36.0 36.3
---------------------------------------------------------------------------------------------------------------------
The net current deferred tax asset (liability) in the following table is
classified as Other Current Assets in the Consolidated Balance Sheet. The tax
effects of temporary differences which gave rise to deferred tax assets and
liabilities as of December 31 were:
(IN THOUSANDS) 2001 2000
---------------------------------------------------------------------------------------------------------------------
U.S. and State Current Deferred Tax Assets (Liabilities):
Accrued expenses $ 15 $ 1,061
Deferred income 626 (186)
Allowance for doubtful accounts 226 225
Mark to market - hedging contracts (2,730)
OTHER (17) (21)
---------------------------------------------------------------------------------------------------------------------
Net Current Deferred Tax Asset (Liability) (1,880) 1,079
---------------------------------------------------------------------------------------------------------------------
U.S. and State Non-current Deferred Tax Assets (Liabilities):
Property, plant and equipment, principally due to
differences in depreciation, amortization, lease
impairment and abandonments (177,382) (121,799)
Accrued expenses 7,125 9,309
Deferred income 6,029 3,303
Allowance for doubtful accounts 5,767 5,779
Foreign and state income tax accruals 11,627 9,579
OTHER 2,244 2,962
---------------------------------------------------------------------------------------------------------------------
Net non-current deferred asset (liability) (144,590) (90,867)
---------------------------------------------------------------------------------------------------------------------
U.S. and state net deferred tax asset (liability) (146,470) (89,788)
---------------------------------------------------------------------------------------------------------------------
Foreign Deferred Tax Assets (Liabilities):
Property, plant and equipment of
FOREIGN OPERATIONS (31,669) (26,181)
---------------------------------------------------------------------------------------------------------------------
Deferred tax liability (31,669) (26,181)
---------------------------------------------------------------------------------------------------------------------
Total net deferred tax liability $ (178,139) $ (115,969)
---------------------------------------------------------------------------------------------------------------------
The components of income from operations before income taxes as of December 31
for each year are as follows:
(IN THOUSANDS) 2001 2000 1999
---------------------------------------------------------------------------------------------------------------------
Domestic $241,479 $268,489 $83,439
Foreign (16,869) 30,994 (5,808)
---------------------------------------------------------------------------------------------------------------------
TOtal $224,610 $299,483 $77,631
---------------------------------------------------------------------------------------------------------------------
45
The income tax provision (benefit) relating to operations consists of the
following for the years ended December 31:
(IN THOUSANDS) 2001 2000 1999
---------------------------------------------------------------------------------------------------------------------
U.S. current $ 24,743 $ 65,358 $ 18,963
U.S. deferred 53,591 32,311 7,150
State current 651 917 313
State deferred 360 334 (313)
Foreign current 6,200 8,341 5,232
Foreign deferred 5,490 625 (3,175)
---------------------------------------------------------------------------------------------------------------------
Total $ 91,035 $ 107,886 $ 28,170
---------------------------------------------------------------------------------------------------------------------
Note 5 - Common Stock, Stock Options and Stockholder Rights
The Company has two stock option plans, the 1992 Stock Option and Restricted
Stock Plan ("1992 Plan") and the 1988 Non-Employee Director Stock Option Plan
("1988 Plan"). The Company accounts for these plans under APB Opinion No. 25.
Under the Company's 1992 Plan, the Board of Directors may grant stock options
and award restricted stock. No restricted stock has been issued under the 1992
Plan. Since the adoption of the 1992 Plan, stock options have been issued at the
market price on the date of grant. The earliest the granted options may be
exercised is over a three year period at the rate of 33 1/3% each year
commencing on the first anniversary of the grant date. The options expire ten
years from the grant date. The 1992 Plan was amended in 2000, by a vote of the
shareholders, to increase the maximum number of shares of common stock that may
be issued under the 1992 Plan to 6,500,000 shares. At December 31, 2001, the
Company had reserved 5,384,498 shares of common stock for issuance, including
1,732,030 shares available for grant, under its 1992 Plan.
The Company's 1988 Plan allows stock options to be issued to certain
non-employee directors at the market price on the date of grant. The options may
be exercised one year after issue and expire ten years from the grant date. The
1988 Plan provides for the grant of options to purchase a maximum of 550,000
shares of the Company's authorized but unissued common stock. The 1988 Plan was
amended at the shareholders' annual meeting on April 24, 2001 to provide for the
granting of a consistent number of stock options to each non-employee director
annually (10,000 stock options for the first year of service and 5,000 stock
options for each year thereafter) and to change the annual grant date to
February 1, commencing February 1, 2002. At December 31, 2001, the Company had
reserved 335,857 shares of common stock for issuance, including 139,786 shares
available for grant, under its 1988 Plan.
The Company adopted a stockholder rights plan on August 27, 1997, designed to
assure that the Company's stockholders receive fair and equal treatment in the
event of any proposed takeover of the Company and to guard against partial
tender offers and other abusive takeover tactics to gain control of the Company
without paying all stockholders a fair price. The rights plan was not adopted in
response to any specific takeover proposal. Under the rights plan, the Company
declared a dividend of one right ("Right") on each share of Noble Affiliates,
Inc. common stock. Each Right will entitle the holder to purchase one
one-hundredth of a share of a new Series A Junior Participating Preferred Stock,
par value $1.00 per share, at an exercise price of $150.00. The Rights are not
currently exercisable and will become exercisable only in the event a person or
group acquires beneficial ownership of 15 percent or more of Noble Affiliates,
Inc. common stock. The dividend distribution was made on September 8, 1997, to
stockholders of record at the close of business on that date. The Rights will
expire on September 8, 2007.
46
Stock options outstanding under the plans mentioned above and one previously
terminated plan are presented for the periods indicated.
NUMBER OPTION
OF SHARES PRICE RANGE
---------------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1998 2,817,242 $ 13.38-$40.38
---------------------------------------------------------------------------------------------------------------------
Granted 810,895 $ 20.06-$27.50
Exercised (64,055) $ 13.38-$24.25
CANCELED (85,812) $ 20.06-$40.38
---------------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1999 3,478,270 $ 13.50-$40.38
---------------------------------------------------------------------------------------------------------------------
Granted 774,343 $ 20.06-$38.88
Exercised (432,199) $ 13.50-$40.38
CANCELED (109,404) $ 20.06-$40.38
---------------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 2000 3,711,010 $ 13.50-$40.38
---------------------------------------------------------------------------------------------------------------------
Granted 723,400 $ 34.79-$43.21
Exercised (509,161) $ 13.50-$40.38
CANCELED (81,267) $ 20.06-$43.21
---------------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 2001 3,843,982 $ 15.00-$43.21
---------------------------------------------------------------------------------------------------------------------
EXERCISABLE AT DECEMBER 31, 2001 2,530,285 $ 15.00-$40.38
---------------------------------------------------------------------------------------------------------------------
Fair value estimates are based on several assumptions and should not be viewed
as indicative of the operations of the Company in future periods. 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 used for
grants in 2001, 2000 and 1999, respectively, as follows:
(AMOUNTS EXPRESSED IN PERCENTAGES) 2001 2000 1999
---------------------------------------------------------------------------------------------------------------------
Interest rate 5.46 6.25 5.50
Dividend yield .40 .40 .40
Expected volatility 38.19 51.67 42.95
Expected life 9.64 9.71 8.80
The weighted average fair value of options granted using the Black-Scholes
option pricing model for 2001, 2000 and 1999, respectively, is as follows:
2001 2000 1999
---------------------------------------------------------------------------------------------------------------------
Black-Scholes model weighted average fair value
option price $23.86 $16.66 $10.01
The Company applies APB Opinion No. 25 in accounting for its fixed price stock
options. The table below sets forth the Company's net income and earnings per
share for each of the years ended December 31, as reported and on a pro forma
basis as if the compensation cost of stock options had been determined utilizing
fair values.
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS) 2001 2000 1999
---------------------------------------------------------------------------------------------------------------------
Net Income:
As Reported $ 133,575 $191,597 $ 49,461
Pro Forma $ 126,037 $183,427 $ 41,176
Basic Earnings Per Share:
As Reported $ 2.36 $ 3.42 $ .87
Pro Forma $ 2.23 $ 3.28 $ .72
Diluted Earnings Per Share:
As Reported $ 2.33 $ 3.38 $ .86
Pro Forma $ 2.20 $ 3.23 $ .72
Compensation expense totaling $781,275 was recognized in 2000, due to the
accelerated vesting of stock options as a result of the retirement of certain
employees.
47
NOTE 6 - EMPLOYEE BENEFIT PLANS
PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a non-contributory defined benefit pension plan covering
substantially all of its domestic employees. The benefits are based on an
employee's years of service and average earnings for the 60 consecutive calendar
months of highest compensation. The Company also has an unfunded restoration
plan to ensure payments of amounts for which employees are entitled under the
provisions of the pension plan, but which are subject to limitations imposed by
federal tax laws. The Company's funding policy has been to make annual
contributions equal to the actuarially computed liability to the extent such
amounts are deductible for income tax purposes. Plan assets consist of equity
securities and fixed income investments.
The Company sponsors other plans for the benefit of its employees and retirees.
These plans include health care and life insurance benefits. The following table
reflects the required disclosures on our pension and other postretirement
benefit plans at December 31:
PENSION BENEFITS OTHER BENEFITS
---------------------- ----------------------
(IN THOUSANDS) 2001 2000 2001 2000
--------------------------------------------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year $ 76,623 $ 64,194 $ 2,718 $ 2,738
Adjustment for contributions paid in 2000 (54)
Service cost 3,790 3,566 220 231
Interest cost 6,218 5,525 193 187
Plan participants' contributions 71 42
Actuarial (gain) loss 6,882 6,423 (333) (328)
BENEFIT PAID (3,872) (3,085) (181) (152)
--------------------------------------------------------------------------------------------------------------------
Benefit obligation at year end $ 89,587 $ 76,623 $ 2,688 $ 2,718
--------------------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year $ 55,487 $ 59,168 $ $
Actual return on plan assets (1,541) (992)
Employer contribution 3,497 396 180 152
Benefit paid (3,873) (3,085) (180) (152)
--------------------------------------------------------------------------------------------------------------------
Fair value of plan at end of year $ 53,570 $ 55,487 $ $
--------------------------------------------------------------------------------------------------------------------
Fund status $ (36,017) $ (21,136) $ (2,688) $ (2,718)
Unrecognized net actuarial loss (gain) 6,826 (6,560) (304) 19
Unrecognized prior service cost 2,451 2,743 (274) (304)
UNRECOGNIZED NET TRANSITION OBLIGATION (ASSETS) 1,191 1,214
--------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit costs $ (25,549) $ (23,739) $ (3,266) $ (3,003)
--------------------------------------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost $ 3,790 $ 3,567 $ 220 $ 231
Interest cost 6,218 5,525 193 188
Expected return on plan assets (4,899) (4,666)
Transition (assets) obligation recognition 24 24
Amortization of prior service cost 292 291 (30) (30)
RECOGNIZED NET ACTUARIAL LOSS (66) (347) (10) (11)
--------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost $ 5,359 $ 4,394 $ 373 $ 378
--------------------------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31,
Discount rate 7.25% 8.00% 7.25% 8.00%
Expected return on plan assets 8.50% 8.50%
Rate of compensation increase 4.75% 5.50% 5.50% 5.50%
48
The following table reflects the aggregate pension obligation components for the
defined benefit pension plan and the restoration benefit plan, which are
aggregated in the previous tables, at December 31:
DEFINED BENEFIT RESTORATION
PENSION PLAN BENEFIT PLAN
---------------------- ----------------------
(IN THOUSANDS) 2001 2000 2001 2000
--------------------------------------------------------------------------------------------------------------------
AGGREGATED PENSION BENEFITS
Aggregate fair value of plan assets $ 53,570 $ 55,487 $ $
Aggregate accumulated benefit obligation 73,868 61,902 15,719 14,721
--------------------------------------------------------------------------------------------------------------------
Fund status of net periodic
Benefit assets (obligation) $ (20,298) $ (6,415) $ (15,719) $ (14,721)
--------------------------------------------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the amounts
reported for health care plans. A one-percentage-point change in assumed health
care cost trend rates would have the following results:
1-PERCENTAGE- 1-PERCENTAGE-
(IN THOUSANDS) POINT INCREASE POINT DECREASE
-------------------------------------------------------------------------------------------------------------------
Total service and interest cost components $ 455 $ 376
Total postretirement benefit obligation $ 2,940 $2,469
EMPLOYEE SAVINGS PLAN ("ESP")
The Company has an ESP which is a defined contribution plan. Participation in
the ESP is voluntary and all regular employees of the Company are eligible to
participate. The Company may match up to 100 percent of the participant's
contribution not to exceed six percent of the employee's base compensation. The
following table indicates the Company's contribution for the years ended
December 31:
(IN THOUSANDS) 2001 2000 1999
-------------------------------------------------------------------------------------------------------------------
Employers' plan contribution $1,805 $1,858 $1,823
NOTE 7 - ADDITIONAL BALANCE SHEET AND STATEMENT OF OPERATIONS INFORMATION
Included in accounts receivable-trade is an allowance for doubtful accounts at
December 31:
(IN THOUSANDS) 2001 2000
-------------------------------------------------------------------------------------------------------------------
Allowance for doubtful accounts $ 638 $ 645
Other current assets include the following at December 31:
(IN THOUSANDS) 2001 2000
-------------------------------------------------------------------------------------------------------------------
Deferred tax asset (liability) $ (1,880) $ 1,079
Prepaid federal income taxes $ 66,131 $ 56,890
Other current liabilities include the following at December 31:
(IN THOUSANDS) 2001 2000
-------------------------------------------------------------------------------------------------------------------
Gas imbalance liabilities $ 1,593 $ 1,348
Accrued interest payable $ 10,692 $ 11,949
Louisiana workers compensation $ 6,433 $ 5,387
Oil and gas operations expense included the following for the years ended
December 31:
(IN THOUSANDS) 2001 2000 1999
--------------------------------------------------------------------------------------------------------------------
Lease operating expense $ 114,116 $ 93,948 $ 107,289
Workover expense 15,094 21,124 5,708
Production taxes 8,829 10,264 6,679
OTHER (4,490) (3,470) (2,978)
--------------------------------------------------------------------------------------------------------------------
Total operations expense $ 133,549 $ 121,866 $ 116,698
--------------------------------------------------------------------------------------------------------------------
49
Oil and gas exploration expense included the following for the years ended
December 31:
(IN THOUSANDS) 2001 2000 1999
-------------------------------------------------------------------------------------------------------------------
Dry hole expense $ 99,684 $ 38,463 $ 19,204
Undeveloped lease amortization 17,213 16,075 9,645
Abandoned assets (415) 3,375 2,483
Seismic 15,607 18,738 7,797
OTHER 19,592 11,592 7,655
-------------------------------------------------------------------------------------------------------------------
Total exploration expense $ 151,681 $ 88,243 $ 46,784
-------------------------------------------------------------------------------------------------------------------
During the past three years, there was no purchaser that accounted for more than
ten percent of total oil and gas sales and royalties.
NOTE 8 - ASPECT ACQUISITION
During the fourth quarter of 2001, the Company acquired all of Aspect Energy's
interests in 110 wells located along the Texas and Louisiana Gulf Coast. Current
production is approximately 1,900 BBLS of oil per day and 57 MMCF of gas per
day. We acquired approximately 59 BCFe of reserves along with working capital
and hedging positions. Also acquired was a 50 percent interest in Aspect's
future drilling prospects in this region. As part of the transaction, the
Company paid $107 million in cash, issued $14 million of common stock previously
held in treasury and assumed a $40 million note payable.
NOTE 9 - UNCONSOLIDATED SUBSIDIARY
The Company has an unconsolidated subsidiary, Atlantic Methanol Capital Company
("AMCCO"), a 50 percent owned joint venture that owns an indirect 90 percent
interest in Atlantic Methanol Production Company ("AMPCO"). The Company
accounted for its interest in AMCCO through 2001 using the equity method within
the Company's wholly-owned subsidiary, Samedan of North Africa, Inc. The Company
participated with a 50 percent expense interest (45 percent ownership net of a
five percent government carried interest) in the construction of a methanol
plant in Equatorial Guinea. The total construction costs of the plant and
supporting facilities as of December 31, 2001 were $403 million including
various contingencies, with the Company responsible for $201.5 million. AMPCO
estimates that an additional $32 million will be incurred to complete various
supporting facilities to finalize the project. The Company will be responsible
for $16 million in 2002. The plant is designed to produce 2,500 metric tons of
methanol per day, which equates to approximately 20,000 BBLS per day. At this
level of production, the plant would use approximately 125 MMCF of gas per day
from the 34 percent owned Alba field as feedstock. Reserve estimates indicate
the Alba field can deliver sufficient gas for the plant to operate 30 years. The
methanol plant was completed and on line in the second quarter of 2001. During
1999, AMCCO issued $250 million senior secured notes due 2004 that are not
included in the Company's balance sheet. On January 2, 2002, the Company's
partner in AMCCO directed AMCCO to sell 50 percent of its interest in AMPCO as a
component of the partner's sale of all of its Equatorial Guinea assets. The
proceeds of the AMPCO sale were used to repay in full AMCCO's $125 million
Series A-1 Notes on January 28, 2002 and to make a distribution to the Company's
partner. Since the Company's partner in AMCCO no longer retains an economic
interest in AMPCO, the Company will consolidate the results of AMCCO, thereby
including the $125 million Series A-2 Notes in the Company's balance sheet. The
terms of the $125 million Series A-2 Notes remain unchanged.
50
The following are summarized financial statements for AMCCO as of December 31:
CONSOLIDATED BALANCE SHEET (Unaudited)
ATLANTIC METHANOL CAPITAL COMPANY
(IN THOUSANDS) 2001 2000
---------------------------------------------------------------------------------------------------------------------
ASSETS
Current assets $ 86,213 $ 45,676
Non-current assets 432,431 392,272
---------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 518,644 $ 437,948
---------------------------------------------------------------------------------------------------------------------
LIABILITIES, MINORITY INTEREST AND MEMBERS' EQUITY
Current liabilities $ 14,892 $ 1,197
Non-current liabilities 272,406 250,000
Minority interest 41,210 36,556
Members' equity 190,136 150,195
---------------------------------------------------------------------------------------------------------------------
Total Liabilities, Minority Interest and Members' Equity $ 518,644 $ 437,948
---------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
ATLANTIC METHANOL CAPITAL COMPANY
(IN THOUSANDS) 2001 2000 1999
---------------------------------------------------------------------------------------------------------------------
REVENUE
Methanol sales $ 43,343 $ $
Other income 5,346 4,389 2,524
---------------------------------------------------------------------------------------------------------------------
Total Revenue $ 48,689 $ 4,389 $ 2,524
Less cost of goods sold (28,548)
---------------------------------------------------------------------------------------------------------------------
Gross Margin $ 20,141 $ 4,389 $ 2,524
---------------------------------------------------------------------------------------------------------------------
EXPENSES
DD&A $ 8,427 $ $
Other expenses 4,363
Interest (net of amount capitalized) 19,069 1,005 1,640
ADMINISTRATIVE 317 86
---------------------------------------------------------------------------------------------------------------------
Total Expenses $ 32,176 $ 1,091 $ 1,640
---------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) BEFORE EXTRAORDINARY ITEMS $ (12,035) $ 3,298 $ 884
---------------------------------------------------------------------------------------------------------------------
EXTRAORDINARY ITEMS (1) $ 24,776 $ $
---------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS) $ (36,811) $ 3,298 $ 884
---------------------------------------------------------------------------------------------------------------------
(1) During the year, a prepayment penalty was recorded in connection with
the early retirement of Series A-1 Secured Notes in 2002. The charge
for the extraordinary item has been allocated to the Company's partner
in AMCCO. Therefore, the Company has not recognized anything related to
this loss in its financial statements.
51
SUPPLEMENTAL OIL AND GAS INFORMATION
(Unaudited)
There are numerous uncertainties inherent in estimating quantities of proved oil
and gas reserves. Oil and gas reserve engineering is a subjective process of
estimating underground accumulations of oil and gas that cannot be precisely
measured, and estimates of engineers other than Samedan's might differ
materially from the estimates set forth herein. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing and
production subsequent to the date of the estimate may justify revision of such
estimate. Accordingly, reserve estimates are often different from the quantities
of oil and gas that are ultimately recovered.
PROVED GAS RESERVES (Unaudited)
The following reserve schedule was developed by the Company's reserve engineers
and sets forth the changes in estimated quantities of proved gas reserves of the
Company during each of the three years presented.
NATURAL GAS AND CASINGHEAD GAS (MMCF)
-----------------------------------------------------------------------------------------------------------------------
UNITED EQUATORIAL NORTH
PROVED RESERVES AS OF: STATES ARGENTINA ECUADOR GUINEA ISRAEL SEA TOTAL
-----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 2001 752,387 4,544 87,500 383,292 218,154 28,752 1,474,629
Revisions of previous estimates (46,886) 36 (2,550) 159,847 (1,583) 108,864
Extensions, discoveries and
other additions 129,172 371 66,410 195,953
Production (134,507) (603) (8,938) (6,508) (150,556)
Sale of minerals in place (246) (246)
Purchase of minerals in place 51,363 51,363
-----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2001 751,283 4,348 87,500 438,214 378,001 20,661 1,680,007
-----------------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF:
-----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 2000 759,781 5,221 87,500 384,102 26,452 1,263,056
Revisions of previous estimates (7,022) 44 131 7,864 1,017
Extensions, discoveries and
other additions 135,844 218,154 3,101 357,099
Production (136,010) (721) (941) (8,665) (146,337)
Sale of minerals in place (4,840) (4,840)
Purchase of minerals in place 4,634 4,634
-----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2000 752,387 4,544 87,500 383,292 218,154 28,752 1,474,629
-----------------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF:
-----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1999 873,222 5,386 321,642 39,056 1,239,306
Revisions of previous estimates (15,700) 482 63,478 (2,392) 45,868
Extensions, discoveries and
other additions 87,293 87,500 192 174,985
Production (150,871) (647) (1,018) (10,404) (162,940)
Sale of minerals in place (34,165) (34,165)
Purchase of minerals in place 2 2
-----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1999 759,781 5,221 87,500 384,102 26,452 1,263,056
-----------------------------------------------------------------------------------------------------------------------
PROVED DEVELOPED GAS RESERVES AS OF:
-----------------------------------------------------------------------------------------------------------------------
January 1, 2002 721,926 3,996 438,213 20,662 1,184,797
January 1, 2001 690,301 4,544 383,292 25,652 1,103,789
January 1, 2000 703,166 5,221 11,687 26,452 746,526
January 1, 1999 818,787 5,386 12,862 39,056 876,091
52
PROVED OIL RESERVES (Unaudited)
The following reserve schedule was developed by the Company's reserve engineers
and sets forth the changes in estimated quantities of proved oil reserves of the
Company during each of the three years presented.
CRUDE OIL AND CONDENSATE (BBLS IN THOUSANDS)
-----------------------------------------------------------------------------------------------------------------------
UNITED EQUATORIAL NORTH
PROVED RESERVES AS OF: STATES ARGENTINA CHINA GUINEA SEA TOTAL
-----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 2001 69,700 9,437 9,768 47,446 12,418 148,769
Revisions of previous estimates 324 (6) (272) 407 453
Extensions, discoveries and
other additions 7,453 1,846 34,303 43,602
Production (7,363) (1,000) (1,687) (1,711) (11,761)
Sale of minerals in place (37) (37)
Purchase of minerals in place 1,595 1,595
------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2001 71,672 10,277 9,768 79,790 11,114 182,621
------------------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF:
-----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 2000 65,523 10,285 9,768 30,684 5,786 122,046
Revisions of previous estimates (1,493) 68 185 (366) (1,606)
Extensions, discoveries and
other additions 12,788 17,491 5,731 36,010
Production (7,309) (916) (914) (654) (9,793)
Sale of minerals in place (935) (229) (1,164)
Purchase of minerals in place 1,126 2,150 3,276
------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2000 69,700 9,437 9,768 47,446 12,418 148,769
------------------------------------------------------------------------------------------------------------------------
PROVED RESERVES AS OF:
-----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1999 77,306 11,128 22,001 6,146 116,581
Revisions of previous estimates (1,394) (24) 9,617 (57) 8,142
Extensions, discoveries and
other additions 3,687 9,768 354 13,809
Production (8,952) (819) (934) (657) (11,362)
Sale of minerals in place (5,125) (5,125)
Purchase of minerals in place 1 1
------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1999 65,523 10,285 9,768 30,684 5,786 122,046
------------------------------------------------------------------------------------------------------------------------
PROVED DEVELOPED OIL RESERVES AS OF:
------------------------------------------------------------------------------------------------------------------------
January 1, 2002 64,534 8,866 9,768 61,897 11,114 156,179
January 1, 2001 58,903 9,437 9,768 47,446 5,728 131,282
January 1, 2000 60,618 10,285 9,768 14,743 3,986 99,400
January 1, 1999 72,949 11,128 11,425 4,346 99,848
----------
PROVED RESERVES. Proved reserves are estimated quantities of crude oil, natural
gas, natural gas liquids and condensate 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.
PROVED DEVELOPED RESERVES. Proved developed reserves are proved reserves which
are expected to be recovered through existing wells with existing equipment and
operating methods.
53
OIL AND GAS OPERATIONS (Unaudited)
Aggregate results of operations for each period ended December 31, in connection
with the Company's oil and gas producing activities, are shown below. Amounts
are presented in accordance with SFAS No. 19, and may not agree with amounts
determined using traditional industry definitions.
(IN THOUSANDS)
----------------------------------------------------------------------------------------------------------------------
UNITED EQUATORIAL NORTH OTHER
DECEMBER 31, 2001 STATES ARGENTINA ECUADOR GUINEA SEA INT'L TOTAL
----------------------------------------------------------------------------------------------------------------------
Revenues $ 742,909 $ 19,999 $ $ 38,841 $ 54,051 $ $ 855,800
Production costs 146,254 7,574 5,381 8,774 104 168,087
Exploration expenses 86,619 168 39 33,224 16,858 136,908
DD&A and valuation provision 266,805 8,547 79 3,830 18,171 435 297,867
----------------------------------------------------------------------------------------------------------------------
Income (loss) 243,231 3,710 (79) 29,591 (6,118) (17,397) 252,938
Income tax expense (benefit) 85,498 2,277 (27) 14,429 (2,721) (2,950) 96,506
----------------------------------------------------------------------------------------------------------------------
Result of operations from pro-
ducing activities (excluding
corporate overhead and interest
COSTS) $ 157,733 $ 1,433 $ (52) $ 15,162 $ (3,397)$ (14,447) $ 156,432
----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2000
----------------------------------------------------------------------------------------------------------------------
Revenues $ 705,270 $ 25,298 $ $ 25,501 $ 35,284 $ $ 791,353
Production costs 129,359 6,952 5,010 5,962 147,283
Exploration expenses 78,955 179 (4) 121 2,739 2,575 84,565
DD&A and valuation provision 222,161 7,796 47 1,355 12,231 449 244,039
----------------------------------------------------------------------------------------------------------------------
Income (loss) 274,795 10,371 (43) 19,015 14,352 (3,024) 315,466
Income tax expense (benefit) 96,675 6,048 (15) 8,978 4,316 (1,000) 115,002
----------------------------------------------------------------------------------------------------------------------
Result of operations from pro-
ducing activities (excluding
corporate overhead and interest
COSTS) $ 178,120 $ 4,323 $ (28) $ 10,037 $ 10,036 $ (2,024) $ 200,464
----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1999
----------------------------------------------------------------------------------------------------------------------
Revenues $ 493,718 $ 14,302 $ $ 16,036 $ 24,677 $ $ 548,733
Production costs 125,803 4,640 3,183 7,106 140,732
Exploration expenses 45,461 542 130 196 4,270 2,779 53,378
DD&A and valuation provision 231,157 6,401 16 3,212 19,687 849 261,322
----------------------------------------------------------------------------------------------------------------------
Income (loss) 91,297 2,719 (146) 9,445 (6,386) (3,628) 93,301
Income tax expense (benefit) 31,646 1,651 4,428 (733) (1,094) 35,898
----------------------------------------------------------------------------------------------------------------------
Result of operations from pro-
ducing activities (excluding
corporate overhead and interest
costs) $ 59,651 $ 1,068 $ (146) $ 5,017 $ (5,653)$ (2,534) $ 57,403
----------------------------------------------------------------------------------------------------------------------
54
COSTS INCURRED IN OIL AND GAS ACTIVITIES (Unaudited)
Costs incurred in connection with the Company's oil and gas acquisition,
exploration and development activities for each of the years are shown below.
Amounts are presented in accordance with SFAS No. 19, and may not agree with
amounts determined using traditional industry definitions.
(IN THOUSANDS)
---------------------------------------------------------------------------------------------------------------------
UNITED EQUATORIAL NORTH OTHER
DECEMBER 31, 2001 STATES ECUADOR GUINEA ISRAEL SEA INT'L TOTAL
---------------------------------------------------------------------------------------------------------------------
Property acquisition costs
Proved $ 91,251 $ $ $ $ 6,318 $ $ 97,569
Unproved 76,808 2,167 2,310 81,285
---------------------------------------------------------------------------------------------------------------------
Total $ 168,059 $ $ $ $ 8,485 $ 2,310 $ 178,854
---------------------------------------------------------------------------------------------------------------------
Exploration costs $ 134,247 $ 1,402 $ 4,003 $ 131 $ 34,766 $ 17,831 $ 192,380
---------------------------------------------------------------------------------------------------------------------
Development costs $ 279,297 $ 48,335 $ 10,364 $ 11,163 $ 17,338 $ 27,575 $ 394,072
---------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2000
-----------------------------------------------------------------------------------------------------------------------
Property acquisition costs
Proved $ 6,822 $ $ $ 50,861 $ 41,284 $ $ 98,967
Unproved 12,559 1,927 2,218 858 17,562
---------------------------------------------------------------------------------------------------------------------
Total $ 19,381 $ $ $ 52,788 $ 43,502 $ 858 $ 116,529
---------------------------------------------------------------------------------------------------------------------
Exploration costs $ 115,728 $ (4) $ 62 $ 11,387 $ 1,396 $ 2,139 $ 130,708
---------------------------------------------------------------------------------------------------------------------
Development costs $ 180,339 $ 35,078 $ 36,820 $ 1,502 $ 2,219 $ 9,570 $ 265,528
---------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1999
-----------------------------------------------------------------------------------------------------------------------
Property acquisition costs
Proved $ 69 $ $ $ $ $ $ 69
Unproved 7,280 620 7,900
---------------------------------------------------------------------------------------------------------------------
Total $ 7,349 $ $ $ $ $ 620 $ 7,969
---------------------------------------------------------------------------------------------------------------------
Exploration costs $ 43,999 $ 130 $ 123 $ $ 3,229 $ 7,722 $ 55,203
---------------------------------------------------------------------------------------------------------------------
Development costs $ 48,042 $ 2,569 $ 1,748 $ $ 4,972 $ 4,863 $ 62,194
---------------------------------------------------------------------------------------------------------------------
AGGREGATE CAPITALIZED COSTS (Unaudited)
Aggregate capitalized costs relating to the Company's oil and gas producing
activities, and related accumulated DD&A, as of December 31 are shown below:
2001 2000
-------------------------------------- ----------------------------------------
(IN THOUSANDS) U. S. INT'L TOTAL U. S. INT'L TOTAL
---------------------------------------------------------------------------------------------------------------------
Unproved oil and gas properties $ 142,232 $ 14,041 $ 156,273 $ 80,750 $ 69,462 $ 150,212
Proved oil and gas properties 3,007,757 757,885 3,765,642 2,598,115 464,896 3,063,011
---------------------------------------------------------------------------------------------------------------------
3,149,989 771,926 3,921,915 2,678,865 534,358 3,213,223
Accumulated DD&A (1,855,352) (138,425) (1,993,777) (1,637,659) (107,534) (1,745,193)
------------------------------------------------------------------------------------------------------ --------------
Net capitalized costs $ 1,294,637 $ 633,501 $ 1,928,138 $ 1,041,206 $ 426,824 $ 1,468,030
---------------------------------------------------------------------------------------------------------------------
55
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES (Unaudited)
The following information is based on the Company's best estimate of the
required data for the Standardized Measure of Discounted Future Net Cash Flows
as of December 31, 2001, 2000 and 1999 in accordance with SFAS No. 69. The
Standard requires the use of a 10 percent discount rate. This information is not
the fair market value nor does it represent the expected present value of future
cash flows of the Company's proved oil and gas reserves.
UNITED EQUATORIAL NORTH OTHER
DECEMBER 31, 2001 STATES ECUADOR GUINEA ISRAEL SEA INT'L TOTAL
---------------------------------------------------------------------------------------------------------------------
(IN MILLIONS OF DOLLARS)
Future cash inflows $ 3,399 $ 264 $ 1,576 $ 900 $ 281 $ 317 $ 6,737
Future production and
development costs 1,618 103 381 150 84 168 2,504
Future income tax expenses 437 26 598 193 49 24 1,327
---------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,344 135 597 557 148 125 2,906
10% annual discount for
estimated timing of cash flows 562 56 406 364 25 65 1,478
---------------------------------------------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $ 782 $ 79 $ 191 $ 193 $ 123 $ 60 $ 1,428
---------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2000
---------------------------------------------------------------------------------------------------------------------
(IN MILLIONS OF DOLLARS)
Future cash inflows $ 8,825 $ 305 $ 1,125 $ 524 $ 379 $ 462 $ 11,620
Future production and
development costs 1,759 90 178 92 89 186 2,394
Future income tax expenses 1,909 58 256 117 78 74 2,492
---------------------------------------------------------------------------------------------------------------------
Future net cash flows 5,157 157 691 315 212 202 6,734
10% annual discount for
estimated timing of cash flows 2,037 62 273 124 84 80 2,660
---------------------------------------------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $ 3,120 $ 95 $ 418 $ 191 $ 128 $ 122 $ 4,074
---------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1999
---------------------------------------------------------------------------------------------------------------------
(IN MILLIONS OF DOLLARS)
Future cash inflows $ 3,565 $ 320 $ 779 $ $ 181 $ 463 $ 5,308
Future production and
development costs 1,566 73 189 85 207 2,120
Future income tax expenses 376 46 111 18 49 600
---------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,623 201 479 78 207 2,588
10% annual discount for
estimated timing of cash flows 686 85 203 33 88 1,095
---------------------------------------------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $ 937 $ 116 $ 276 $ $ 45 $ 119 $ 1,493
---------------------------------------------------------------------------------------------------------------------
Construction of AMPCO's methanol plant was completed in the second quarter of
2001. The future net cash inflows for 2001, 2000 and 1999 do not include cash
flows relating to the Company's anticipated future methanol sales. For more
information regarding the methanol plant, see "Item 1. Business--Unconsolidated
Subsidiary," "Item 2. Properties--Oil and Gas" and "Item 8. Financial Statements
and Supplementary Data--Note 9 - Unconsolidated Subsidiary" of this Form 10-K.
56
Future cash inflows are estimated by applying year-end prices of oil and gas
relating to the Company's proved reserves to the year-end quantities of those
reserves, with consideration given to the effect of existing hedging contracts,
if any.
The year-end NYMEX West Texas intermediate crude oil price utilized in the
computation of future cash inflows was $19.84 per BBL, which was adjusted by
differentials applied on a property-by-property basis to yield a weighted
average price of $17.39 per BBL. The West Texas intermediate crude oil price, as
of February 22, 2002, was $21.07 per BBL, an increase of $1.23 per BBL compared
to year-end 2001. The Company estimates that a $1.00 per BBL change in the
average oil price from the year-end price would change discounted future net
cash flows before income taxes by approximately $79 million.
The year-end NYMEX natural gas price utilized in the computation of future cash
inflows was $2.57 per MCF, which was adjusted by differentials applied on a
property-by-property basis to yield a weighted average price of $2.45 per MCF.
As of February 22, 2002, NYMEX natural gas prices had decreased approximately
$.12 per MCF to $2.45 per MCF compared with the year-end price. The Company
estimates that a $.10 per MCF change in the average gas price from the year-end
price would change discounted future net cash flows before income taxes by
approximately $70 million.
Future production and development costs, which include dismantlement and
restoration expense, are computed by estimating the expenditures to be incurred
in developing and producing the Company's proved oil and gas reserves at the end
of the year, based on year-end costs, and assuming continuation of existing
economic conditions.
Future income tax expenses are computed by applying the appropriate year-end
statutory tax rates to the estimated future pretax net cash flows relating to
the Company's proved oil and gas reserves, less the tax bases of the properties
involved. The future income tax expenses give effect to tax credits and
allowances, but do not reflect the impact of general and administrative costs
and exploration expenses of ongoing operations relating to the Company's proved
oil and gas reserves.
At December 31, 2001, the Company had estimated gas imbalance receivables of
$20.9 million and estimated gas imbalance liabilities of $15.5 million; at
year-end 2000, $18.5 million in receivables and $14.2 million in liabilities;
and at year-end 1999, $17.9 million in receivables and $12.0 million in
liabilities. Neither the gas imbalance receivables nor gas imbalance liabilities
have been included in the standardized measure of discounted future net cash
flows as of each of the three years ended December 31, 2001, 2000 and 1999.
57
SOURCES OF CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS (Unaudited)
Principal changes in the aggregate standardized measure of discounted future net
cash flows attributable to the Company's proved oil and gas reserves, as
required by Financial Accounting Standards Board's SFAS No. 69, at year end are
shown below.
(IN MILLIONS) 2001 2000 1999
--------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows at the beginning
of the year $ 4,074 $ 1,493 $ 982
Extensions, discoveries and improved
recovery, less related costs 448 1,462 410
Revisions of previous quantity estimates 114 (20) 89
Changes in estimated future
development costs (128) (52) (202)
Purchases (sales) of minerals in place 108 69 (58)
Net changes in prices and production costs (3,376) 2,448 673
Accretion of discount 564 185 102
Sales of oil and gas produced, net of
production costs (713) (662) (425)
Development costs incurred during
the period 220 172 21
Net change in income taxes 908 (1,207) (317)
Change in timing of estimated future
production, and other (791) 186 218
--------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows at the end
of the year $ 1,428 $ 4,074 $ 1,493
--------------------------------------------------------------------------------------------------------------------
INTERIM FINANCIAL INFORMATION (Unaudited)
Interim financial information for the years ended December 31, 2001 and 2000 is
as follows:
QUARTER ENDED
--------------------------------------------------------------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS) MAR. 31, JUNE 30, SEPT. 30, DEC. 31,
-------------------------------------------------------------------------------------------------------------------
2001
Revenues $ 559,967 $ 413,992 $ 302,964 $ 299,876
Gross profit (loss) from operations $ 174,185 $ 88,320 $ 13,073 $ (19,447)
Net income (loss) $ 105,910 $ 51,334 $ 3,808 $ (27,476)
Basic earnings (loss) per share $ 1.88 $ .91 $ .07 $ (.48)
Diluted earnings (loss) per share $ 1.84 $ .89 $ .07 $ (.48)
2000
Revenues $ 268,872 $ 301,777 $ 357,353 $ 453,284
Gross profit from operations $ 49,444 $ 68,025 $ 97,489 $ 103,399
Net income $ 26,880 $ 36,861 $ 57,217 $ 70,640
Basic earnings per share $ .48 $ .66 $ 1.02 $ 1.26
Diluted earnings per share $ .47 $ .65 $ 1.01 $ 1.24
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Not applicable.
58
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The section entitled "Election of Directors" in the Registrant's proxy statement
for the 2002 annual meeting of stockholders sets forth certain information with
respect to the directors of the Registrant and is incorporated herein by
reference. Certain information with respect to the executive officers of the
Registrant is set forth under the caption "Executive Officers of the Registrant"
in Part I of this report.
The section entitled "Section 16(a) Beneficial Ownership Reporting Compliance"
in the Registrant's proxy statement for the 2002 annual meeting of stockholders
sets forth certain information with respect to compliance with Section 16(a) of
the Securities Exchange Act of 1934, as amended, and is incorporated herein by
reference.
ITEM 11. EXECUTIVE COMPENSATION.
The section entitled "Executive Compensation" in the Registrant's proxy
statement for the 2002 annual meeting of stockholders sets forth certain
information with respect to the compensation of management of the Registrant,
and except for the report of the Compensation, Benefits and Stock Option
Committee of the Board of Directors and the information therein under "Executive
Compensation--Performance Graph" is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The sections entitled "Security Ownership of Certain Beneficial Owners" and
"Security Ownership of Directors and Executive Officers" in the Registrant's
proxy statement for the 2002 annual meeting of stockholders set forth certain
information with respect to the ownership of the Registrant's common stock and
are incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The section entitled "Certain Transactions" in the Registrant's proxy statement
for the 2002 annual meeting of stockholders sets forth certain information with
respect to certain relationships and related transactions, and is incorporated
herein by reference.
PART IV
ITEM 14. FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND REPORTS ON FORM 8-K.
(a) The following documents are filed as a part of this report:
(1) Financial Statements and Financial Statement Schedules and
Supplementary Data: These documents are listed in the Index
to Consolidated Financial Statements in Item 8 hereof.
(2) Exhibits: The exhibits required to be filed by this Item 14
are set forth in the Index to Exhibits accompanying this
report.
(b) The Registrant made no filings on Form 8-K during 2001.
59
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of 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.
NOBLE AFFILIATES, INC.
Date: March 11, 2002 BY: /s/ James L. McElvany,
--------------------------------------
James L. McElvany,
Vice President, Finance and Treasurer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.
Signature Capacity in which signed Date
--------- ------------------------ ----
/s/ Charles D. Davidson Chairman of the Board, President, March 11, 2002
------------------------------------
Charles D. Davidson Chief Executive Officer and Director
(Principal Executive Officer)
/s/ James L. McElvany Vice President, Finance and Treasurer March 11, 2002
------------------------------------
James L. McElvany (Principal Financial and Accounting
Officer)
/s/ Alan A. Baker Director March 11, 2002
------------------------------------
Alan A. Baker
/s/ Michael A. Cawley Director March 11, 2002
------------------------------------
Michael A. Cawley
/s/ Edward F. Cox Director March 11, 2002
------------------------------------
Edward F. Cox
/s/ James C. Day Director March 11, 2002
------------------------------------
James C. Day
/s/ Dale P. Jones Director March 11, 2002
------------------------------------
Dale P. Jones
/s/ T. Don Stacy Director March 11, 2002
------------------------------------
T. Don Stacy
60
INDEX TO EXHIBITS
Exhibit
Number Exhibit **
------ ----------
3.1 -- Certificate of Incorporation, as amended, of the
Registrant as currently in effect (filed as Exhibit 3.2 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1987 and incorporated herein by reference).
3.2 -- Certificate of Designations of Series A Junior Participating
Preferred Stock of the Registrant dated August 27, 1997 (filed
Exhibit A of Exhibit 4.1 to the Registrant's Registration
Statement on Form 8-A filed on August 28, 1997 and incorporated
herein by reference).
3.3 -- Composite copy of Bylaws of the Registrant as currently in
effect (filed as Exhibit 3.4 to the Registrant's Annual Report
on Form 10-K for the year ended December 31, 1997 and
incorporated herein by reference).
3.4 -- Certificate of Designations of Series B Mandatorily Convertible
Preferred Stock of the Registrant dated November 9, 1999
(filed as Exhibit 3.4 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1999 and incorporated
herein by reference).
4.1 -- Indenture dated as of October 14, 1993 between the Registrant
and U.S. Trust Company of Texas, N.A., as Trustee, relating to
the Registrant's 7 1/4% Notes Due 2023, including form of the
Registrant's 7 1/4% Notes Due 2023 (filed as Exhibit 4.1 to the
Registrant's Quarterly Report on Form 10-Q for the quarter
ended September 30, 1993 and incorporated herein by reference).
4.2 -- Indenture relating to Senior Debt Securities dated as of April
1, 1997 between the Registrant and U.S. Trust Company of Texas,
N.A., as Trustee (filed as Exhibit 4.1 to the Registrant's
Quarterly Report on Form 10-Q for the quarter ended March 31,
1997 and incorporated herein by reference).
4.3 -- First Indenture Supplement relating to $250 million of the
Registrant's 8% Senior Notes Due 2027 dated as of April 1, 1997
between the Registrant and U.S. Trust Company of Texas, N.A.,
as Trustee (filed as Exhibit 4.2 to the Registrant's Quarterly
Report on Form 10-Q for the quarter ended March 31, 1997 and
incorporated herein by reference).
4.4 -- Second Indenture Supplement, between the Company and U.S. Trust
Company of Texas, N.A. as trustee, relating to $100 million of
the Registrant's 7 1/4% Senior Debentures Due 2097 dated as of
August 1, 1997 (filed as Exhibit 4.1 to the Registrant's
Quarterly Report on Form 10-Q for the quarter ended June 30,
1997 and incorporated herein by reference).
4.5 -- Rights Agreement, dated as of August 27, 1997, between the
Registrant and Liberty Bank and Trust Company of Oklahoma City,
N.A., as Right's Agent (filed as Exhibit 4.1 to the
Registrant's Registration Statement on Form 8-A filed on August
28, 1997 and incorporated herein by reference).
4.6 -- Amendment No. 1 to Rights Agreement dated as of December 8,
1998, between the Registrant and Bank One Trust Company, as
successor Rights Agent to Liberty Bank and Trust Company of
Oklahoma City, N.A. (filed as Exhibit 4.2 to the Registrant's
Registration Statement on Form 8-A/A (Amendment No. 1) filed on
December 14, 1998 and incorporated herein by reference).
10.1* -- Samedan Oil Corporation Bonus Plan, as amended and restated on
September 24, 1996 (filed as Exhibit 10.1 to the Registrant's
Annual Report on Form 10-K for the fiscal year ended December
31, 1996 and incorporated herein by reference).
10.2* -- Restoration of Retirement Income Plan for certain participants
in the Noble Affiliates Retirement Plan dated September 21,
1994, effective as of May 19, 1994 (filed as Exhibit 10.5 to
the Registrant's Annual Report on Form 10-K for the year ended
December 31, 1994 and incorporated herein by reference).
Exhibit
Number Exhibit **
------ ----------
10.3 * -- Noble Affiliates Thrift Restoration Plan dated May 9, 1994
(filed as Exhibit 10.6 to the Registrant's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994 and
incorporated herein by reference).
10.4* -- Noble Affiliates Restoration Trust dated September 21, 1994,
effective as of October 1, 1994 (filed as Exhibit 10.7 to the
Registrant's Annual Report on Form 10-K for the fiscal year
ended December 31, 1994 and incorporated herein by reference).
10.5* -- Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock
Plan, as amended and restated, dated November 2, 1992 (filed as
Exhibit 4.1 to the Registrant's Registration Statement on Form
S-8 (Registration No. 33-54084) and incorporated herein by
reference).
10.6* -- 1982 Stock Option Plan of the Registrant (filed as Exhibit 4.1
to the Registrant's Registration Statement on Form S-8
(Registration No. 2-81590) and incorporated herein by
reference).
10.7* -- Amendment No. 1 to the 1982 Stock Option Plan of the Registrant
(filed as Exhibit 4.2 to the Registrant's Registration
Statement on Form S-8 (Registration No. 2-81590) and
incorporated herein by reference).
10.8* -- Amendment No. 2 to the 1982 Stock Option Plan of the Registrant
(filed as Exhibit 10.11 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1995 and incorporated
herein by reference).
10.9* -- 1988 Nonqualified Stock Option Plan for Non-Employee Directors
of the Registrant, as amended and restated, effective as of
April 24, 2001.
10.10* -- Form of Indemnity Agreement entered into between the Registrant
and each of the Registrant's directors and bylaw officers
(filed as Exhibit 10.18 to the Registrant's Annual Report of
Form 10-K for the year ended December 31, 1995 and incorporated
herein by reference).
10.11 -- Guaranty of the Registrant dated October 28, 1982, guaranteeing
certain obligations of Samedan (filed as Exhibit 10.12 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1993 and incorporated herein by reference).
10.12 -- Stock Purchase Agreement dated as of July 1, 1996, between
Samedan Oil Corporation and Enterprise Diversified Holdings
Incorporated (filed as Exhibit 2.1 to the Registrant's Current
Report on Form 8-K (Date of Event: July 31, 1996) dated August
13, 1996 and incorporated herein by reference).
10.13* -- Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock
Plan, as amended and restated on December 10, 1996, subject to
the approval of stockholders (filed as Exhibit 10.21 to the
Registrant's Annual Report on Form 10-K for the year ended
December 31, 1996 and incorporated herein by reference).
10.14 -- Amended and Restated Credit Agreement dated as of December 24,
1997 among the Registrant, as borrower, and Union Bank of
Switzerland, Houston agency, as the agent for the lender, and
NationsBank of Texas, N.A. and Texas Commerce Bank National
Association, as managing agents, and Bank of Montreal, CIBC
Inc., The First National Bank of Chicago, Royal Bank of Canada,
and Societe Generale, Southwest agency, as co-agents, and
certain commercial lending institutions, as lenders (filed as
Exhibit 10.20 to the Registrant's Annual Report on Form 10-K
for the fiscal year ended December 31, 1997 and incorporated
herein by reference).
Exhibit
Number Exhibit **
------ -------
10.15 -- Noble Preferred Stock Remarketing and Registration Rights
Agreement dated as of November 10, 1999 by and among the
Registrant, Noble Share Trust, The Chase Manhattan Bank, and
Donaldson, Lufkin & Jenrette Securities Corporation (filed as
Exhibit 10.15 to the Registrant's Annual Report on Form 10-K
for the year ended December 31, 1999 and incorporated herein by
reference).
10.16* -- Employment Agreement effective as of October 2, 2000 between
Noble Affiliates, Inc. and Charles D. Davidson (filed as
Exhibit 10.16 to the Registrant's Annual Report on Form 10-K
for the year ended December 31, 2000 and incorporated herein
by reference).
10.17* -- Letter agreement dated February 1, 2002 between the Registrant
and Charles D. Davidson, terminating Mr. Davidson's employment
agreement and entering into the attached Change of Control
Agreement.
10.18* -- Form of Change of Control Agreement entered into between the
Registrant and each of the Registrant's officers, with schedule
setting forth differences in Change of Control Agreements.
10.19 -- Five-year Credit Agreement dated as of November 30, 2001 among
the Registrant, as borrower, and JPMorgan Chase Bank, as the
administrative agent for the lenders, and Societe Generale, as
the syndication agent for the lenders, Mizuho Financial Group,
Credit Lyonnais, New York Branch, The Royal Bank of Scotland
PLC, and Deutsche Bank Ag New York Branch, as co-documentation
agents, and certain commercial lending institutions, as
lenders.
10.20 -- 364-day Credit Agreement dated as of November 30, 2001 among
the Registrant, as borrower, and JPMorgan Chase Bank, as the
administrative agent for the lenders, and Societe Generale, as
the syndication agent for the lenders, Mizuho Financial Group,
Credit Lyonnais, New York Branch, The Royal Bank of Scotland
PLC, and Deutsche Bank Ag New York Branch, as co-documentation
agents, and certain commercial lending institutions, as
lenders.
21 -- Subsidiaries.
23 -- Consent of Arthur Andersen LLP.
99 -- Company's letter to SEC re: Arthur Andersen LLP assurances.
* Management contract or compensatory plan or arrangement required to
be filed as an exhibit hereto.
** Copies of exhibits will be furnished upon prepayment of 25 cents
per page. Requests should be addressed to the Vice
President-Finance and Treasurer, Noble Affiliates, Inc., 350
Glenborough Drive, Suite 100, Houston, Texas 77067.
DIRECTORS
CHARLES D. DAVIDSON
CHAIRMAN OF THE BOARD, PRESIDENT AND
CHIEF EXECUTIVE OFFICER,
NOBLE AFFILIATES, INC.
ALAN A. BAKER
CONSULTANT AND FORMER CHAIRMAN AND
CHIEF EXECUTIVE OFFICER,
HALLIBURTON ENERGY SERVICES
MICHAEL A. CAWLEY
TRUSTEE, PRESIDENT AND CHIEF EXECUTIVE OFFICER,
THE SAMUEL ROBERTS NOBLE FOUNDATION, INC.
EDWARD F. COX
PARTNER, LAW FIRM OF
PATTERSON, BELKNAP, WEBB AND TYLER LLP
JAMES C. DAY
CHAIRMAN OF THE BOARD AND
CHIEF EXECUTIVE OFFICER,
NOBLE DRILLING CORPORATION
DALE P. JONES
CONSULTANT AND FORMER VICE CHAIRMAN AND
PRESIDENT, HALLIBURTON COMPANY
BRUCE A. SMITH
CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER,
TESORO PETROLEUM CORPORATION
T. DON STACY
FORMER CHAIRMAN AND
PRESIDENT, AMOCO EURASIA PETROLEUM CO.
DIRECTOR EMERITUS
GEORGE J. MCLEOD
EXECUTIVE OFFICERS
CHARLES D. DAVIDSON
CHAIRMAN OF THE BOARD, PRESIDENT,
CHIEF EXECUTIVE OFFICER AND DIRECTOR
NOBLE AFFILIATES, INC.
ALAN R. BULLINGTON
VICE PRESIDENT, INTERNATIONAL,
NOBLE AFFILIATES, INC.
ROBERT K. BURLESON
VICE PRESIDENT, BUSINESS ADMINISTRATION,
NOBLE AFFILIATES, INC. AND PRESIDENT,
NOBLE GAS MARKETING, INC.
SUSAN M. CUNNINGHAM
SENIOR VICE PRESIDENT, EXPLORATION,
NOBLE AFFILIATES, INC.
ALBERT D. HOPPE
SENIOR VICE PRESIDENT, GENERAL COUNSEL
AND SECRETARY,
NOBLE AFFILIATES, INC.
JAMES L. MCELVANY
VICE PRESIDENT, CHIEF FINANCIAL OFFICER,
TREASURER AND ASSISTANT SECRETARY,
NOBLE AFFILIATES, INC.
RICHARD A. PENEGUY, JR.
VICE PRESIDENT, OFFSHORE,
NOBLE AFFILIATES, INC.
WILLIAM A. POILLION, Jr.
SENIOR VICE PRESIDENT, PRODUCTION AND DRILLING,
NOBLE AFFILIATES, INC.
TED A. PRICE
VICE PRESIDENT, ONSHORE,
NOBLE AFFILIATES, INC.
KENNETH P. WILEY
VICE PRESIDENT, INFORMATION SYSTEMS,
NOBLE AFFILIATES, INC.
CORPORATE AND SUBSIDIARY OFFICES
NOBLE AFFILIATES, INC.
CORPORATE HEADQUARTERS
350 GLENBOROUGH DRIVE
SUITE 100
HOUSTON, TEXAS 77067
(281) 872-3100
INVESTOR RELATIONS
WILLIAM R. MCKOWN III
ASSISTANT TREASURER
(281) 872-3100
INVESTOR_RELATIONS@NOBLEAFF.COM
WWW.NOBLEAFF.COM
SUBSIDIARY HEADQUARTERS
SAMEDAN OIL CORPORATION
350 GLENBOROUGH DRIVE
SUITE 100
HOUSTON, TEXAS 77067
NOBLE GAS MARKETING, INC.
350 GLENBOROUGH DRIVE
SUITE 180
HOUSTON, TEXAS 77067
NOBLE TRADING, INC.
350 GLENBOROUGH DRIVE
SUITE 180
HOUSTON, TEXAS 77067
OPERATIONAL OFFICES
DOMESTIC OFFSHORE
SAMEDAN OIL CORPORATION
350 GLENBOROUGH DRIVE
SUITE 240
HOUSTON, TEXAS 77067
DOMESTIC ONSHORE
SAMEDAN OIL CORPORATION
12600 NORTHBOROUGH DRIVE
SUITE 250
HOUSTON, TEXAS 77067
INTERNATIONAL
SAMEDAN OIL CORPORATION
350 GLENBOROUGH DRIVE
SUITE 300
HOUSTON, TEXAS 77067
INDEPENDENT PUBLIC ACCOUNTANTS
ARTHUR ANDERSEN LLP
OKLAHOMA CITY, OKLAHOMA
TRANSFER AGENT AND REGISTRAR
FIRST UNION NATIONAL BANK
NC1153
1525 WEST W. T. HARRIS BLVD., 3C3
CHARLOTTE, NORTH CAROLINA 28262-1153
(704) 427-6349
RHONDA.WHITLEY@FIRSTUNION.COM
COMMON STOCK LISTED
NEW YORK STOCK EXCHANGE
SYMBOL - NBL
-------------------------------------------------------------------------------
ANNUAL MEETING
The Annual Meeting of Stockholders of Noble Affiliates, Inc. will be held
on Tuesday, April 23, 2002, at 9:30 a.m. at the Wyndham Greenspoint Hotel
located at 12400 Greenspoint Drive in Houston, Texas. All stockholders are
cordially invited to attend.
FORM 10-K
The Company's Annual Report on Form 10-K for the year ended December 31, 2001,
as filed with the Securities and Exchange Commission, is included in this
report. Additional copies are available without charge upon request by writing
to the Chief Financial Officer, Noble Affiliates, Inc., 350 Glenborough Drive,
Suite 100, Houston, Texas 77067, via the Company's Internet website:
http://www.nobleaff.com, or via the Securities and Exchange Commission's
Internet website: http://www.sec.gov.
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