Back to GetFilings.com
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------------
FORM 10-K
(Mark One)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____to_____
Commission file number: 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._____
Aggregate market value of Common Stock held by nonaffiliates as of February 14,
2001: $2,414,000,000.
Number of shares of Common Stock outstanding as of February 14, 2001:
56,323,961.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Registrant's definitive proxy statement for the 2001 Annual
Meeting of Stockholders to be held on April 24, 2001, which will be filed with
the Securities and Exchange Commission within 120 days after December 31, 2000,
are incorporated by reference into Part III.
================================================================================
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................................................................... 8
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.................................. 27
Item 8. Financial Statements and Supplementary Data................................................. 30
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........ 56
PART III.
Item 10. Directors and Executive Officers of the Registrant.......................................... 57
Item 11. Executive Compensation...................................................................... 57
Item 12. Security Ownership of Certain Beneficial Owners and Management.............................. 57
Item 13. Certain Relationships and Related Transactions.............................................. 57
PART IV.
Item 14. Financial Statement Schedules, Exhibits and Reports on Form 8-K............................. 57
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, and all
of such forward-looking statements are qualified 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 and
1
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 enhance the financial
2
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. Samedan's subsidiaries include EDC. In this report,
quantities of oil or natural gas liquids are expressed in barrels ("BBLS");
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") 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 has an unconsolidated subsidiary, Atlantic Methanol Capital Company
("AMCCO"), a 50 percent owned joint venture that indirectly owns 90 percent of
Atlantic Methanol Production Company ("AMPCO"), which is constructing a methanol
plant in Equatorial Guinea. AMCCO is 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" 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 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
3
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 232 wells operated by Samedan and 279 wells operated
by others. During the past 32 years, Samedan has drilled or participated in the
drilling of 992 gross wells offshore. At December 31, 2000, the Company held
offshore federal leases covering 1,037,827 gross developed acres and 793,507
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.
Samedan's current onshore production is derived from 1,494 wells operated by
Samedan and 1,380 wells operated by others. At December 31, 2000, the Company
held 604,902 gross developed acres and 289,527 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 EDC 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, 2000, the Company held 28,988 gross developed acres and 1,235,105 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 EDC 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, 2000, the Company held 7,413 gross developed acres and 200,032
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 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 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
4
production is from the Alba field, which produces gas and condensate. The gas
production will be utilized as feedstock by a methanol plant currently under
construction. The plant will be 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 gas sufficient for the plant to operate for 30 years. At December 31,
2000, 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 and EDC
(Denmark) Inc., 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 142 wells
operated by others. Reservoirs in the North Sea tend to have the same attributes
as Gulf of Mexico reservoirs. At December 31, 2000, the Company held 131,527
gross developed acres and 682,262 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. In 1998, the Company, through its subsidiary, Samedan,
Mediterranean Sea, entered into a participation agreement with a 40 percent
interest covering 11 licenses, permits or leases. At December 31, 2000, the
Company held 61,776 gross developed acres and 1,020,198 gross undeveloped acres.
The acreage is located about 20 miles offshore Israel in water depths ranging
from 700 feet to 5,000 feet. Through a recent acquisition, the Company has
increased its interest in the 11 licenses to 47 percent. For more information,
see "Item 2. Properties--Oil and Gas" of this Form 10-K.
VIETNAM. During 2000, Samedan acquired a 78 percent interest in two offshore
blocks totaling 1,701,812 gross undeveloped acres in the Nam Con Son basin. The
Company anticipates reducing its interest to 60 percent before the planned
exploration wells are drilled 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:
2000 1999 1998
-----------------------------------------------------------------------
(IN PERCENTAGES) OIL GAS OIL GAS OIL GAS
- -------------------------------------------------------------------------------------------------------------------
Operated well count basis 23.1 66.0 22.8 61.2 20.7 58.9
Operated sales volume basis 48.3 64.5 48.1 59.8 45.3 59.2
NET PRODUCTION. The following table sets forth Samedan's net oil and
natural gas production including royalty, for the three years ended
December 31:
2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------
Oil Production
(million BBLS) 9.4 11.0 13.6
Gas Production
(BCF) 148.7 166.1 206.8
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:
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------
Total Oil Equivalents
(million BOE) 34.2 38.6 48.1
Total Gas Equivalents
(BCFe) 205.4 231.8 288.3
5
ACQUISITIONS OF OIL AND GAS PROPERTIES, LEASES AND CONCESSIONS
During 2000, Samedan spent approximately $99 million on the purchase of proved
oil and gas properties. Samedan spent approximately $.1 million in 1999 and
$48.4 million in 1998 on proved properties. For more information, see "Item 2.
Properties--Oil and Gas" of this Form 10-K.
During 2000, Samedan spent approximately $17.6 million on acquisitions of
unproved properties. Samedan spent approximately $7.9 million in 1999 and $37.6
million in 1998 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 2000, approximately 69 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 and EDC have short-term gas sales contracts with NGM, whereby Samedan
and EDC are paid an index price for all gas sold to NGM. Samedan and EDC sold
approximately 95 percent of their production to NGM in 2000. Sales, including
hedging transactions, are recorded as gathering, marketing and processing
revenues. NGM records the amount paid to Samedan, EDC 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
five 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 45 percent of the Company's oil 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 members
of the Organization of Petroleum Exporting Countries. The Company's average oil
price increased $8.08 from $16.29 per BBL in 1999 to $24.37 per BBL in 2000. Due
to the volatility of oil prices, the Company, from time to time, has used
derivative hedging 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 Disclosure 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 2000. Gas
prices, which were once determined largely by governmental regulations, are now
determined by the marketplace. The Company's average gas price increased from
$2.23 per MCF in 1999 to $3.77 per MCF in 2000. Due to the volatility of gas
prices, the Company, from time to time, has used derivative hedging 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 Disclosure
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
2000 accounted for approximately 19 percent of the Company's oil sales,
representing approximately three percent of total revenues. The five largest
6
purchasers accounted for approximately 57 percent of total oil sales. The
largest single non-affiliated purchaser of the Company's gas production in 2000
accounted for approximately two percent of its gas sales. The five largest
purchasers accounted for approximately eight 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 national, state and local levels. Oil and gas development and
production activities are subject to various state 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. Numerous governmental departments
and agencies are authorized by statute to issue rules and regulations binding on
the oil and gas industry. 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 rate sufficient 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. 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
7
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.
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 accounts
for its interest in AMCCO using the equity method within the Company's
wholly-owned subsidiary, Samedan of North Africa, Inc. For more information, see
"Item 8. Financial Statements and Supplementary Data" of this Form 10-K. Samedan
is participating with a 50 percent expense interest (45 percent ownership net of
a five percent government carried interest) to construct a methanol plant in
Equatorial Guinea. The total projected cost of the plant and supporting
facilities is estimated to be $448 million including various contingencies and
capitalized interest, with the Company responsible for $224 million. 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 Alba field as feedstock.
Reserve estimates indicate the Alba field can deliver sufficient gas for the
plant to operate 30 years. The construction contract stipulates that first
production should be achieved by the second quarter of 2001. Current marketing
plans are to use two tankers, which are under long-term contracts, to transport
the methanol to markets in
8
Europe and the United States. During 1999, AMCCO issued $250 million senior
secured notes due 2004 that are not included in the Company's balance sheet.
For more information, see "Item 7. Management Discussion and Analysis of
Financial Condition and Results of Operations" of this Form 10-K.
EMPLOYEES
During the year, the total number of employees of the Company increased from 556
at December 31, 1999, to 576 at December 31, 2000.
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 is located
in Houston, Texas, and NTI's office is located in Ardmore, Oklahoma. The Company
also maintains offices in Ardmore, Oklahoma for centralized accounting, lease
records, 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
2000, Samedan drilled or participated in the drilling of 268 gross (146 net)
wells, comprised of 50 gross (11.5 net) international wells and 218 gross (134.5
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. During 2000, an exploitation program at Samedan's South
Timbalier field consisting of two development wells, four workovers and
additional compression increased production 66 MMCF of gas per day, net to the
Company's interest.
Upgrades at East Cameron 331/332 have resulted in a net incremental increase in
total production of nearly 20 MMCF of gas and 1,080 BBLS of oil per day.
An exploitation project consisting of seven sidetracks was completed at Main
Pass 306, increasing production 875 net BBLS of oil per day.
The High Island A-517 A-8 and A-14 development wells commenced production of 8.2
net MMCF of gas per day each.
The Vermilion 161 BJ-6 development well commenced production of 7.5 MMCF of gas
and 330 BBLS of oil per day, net to Samedan's interest.
Production began from the 12 block Viosca Knoll 252 Unit. Four wells were
producing approximately 42 MMCF of gas per day, net to Samedan's 40 percent
interest. Additional exploration and development opportunities remain.
Samedan recompleted its West Delta 58 C-4 well to the OX sand. The zone contains
68 feet of hydrocarbon pay and commenced production at the rate of 9.7 MMCF of
gas and 992 BBLS of condensate per day, net to Samedan's interest.
9
A workover in the Vermilion 167 field yielded a net incremental increase of 600
BBLS of oil per day.
Samedan entered into an exploration alliance with McMoRan Exploration Company
and committed to participate with a 25 percent working interest in six
prospects. Additionally, Samedan agreed to work with McMoRan in identifying
future prospects on approximately 660,000 acres previously accumulated by
McMoRan. Samedan's estimated costs for the committed exploration prospects are
approximately $25 million.
The Vermilion 196 #2 well, in which Samedan owns a 25 percent working interest,
logged 70 feet of net hydrocarbon pay in three sands. The property expansion is
continuing with two development wells and initial production is expected in the
third quarter of 2001.
Samedan purchased an additional 13.2 percent working interest (for a total
working interest of 33.2 percent) in Vermilion 408 from McMoRan Exploration
Company for $2.8 million. The block contains two wells with reserves estimated
to be four million BOE.
DOMESTIC ONSHORE. In 2000, Samedan maintained an active drilling program in the
Bowdoin field located in Phillips and Valley Counties, Montana where 95
successful wells were drilled.
The Harry Stagg #1 located in Lafayette Parish, Louisiana commenced production
at a rate of 5.6 MMCF of gas and 274 BBLS of condensate per day, net to the
Company's interest, with 8,400 pounds per square inch of flowing tubing
pressure.
The Runnels #3 in Matagorda County, Texas commenced production at the daily rate
of 2.6 MMCF of natural gas and 68 BBLS of oil, net to Samedan's interest.
EQUATORIAL GUINEA. The expansion of the 34 percent owned Alba field has been
completed with the successful drilling of the Alba #8 well. The expansion
included engineering, fabrication, transportation, and installation of a tripod
well platform, a four-pile 12 slot manned platform with compression, various
infield flow lines, a 19-mile pipeline and the drilling of several wells, some
for production and some for reinjection. The expansion will increase the
production capacity of the field, which lies 18 miles off the coast of
Equatorial Guinea, to 225 MMCF of gas per day from 90 MMCF of gas per day.
Approximately 125 MMCF of gas per day will be supplied to a methanol plant on
Bioko Island, scheduled to start production in the second quarter of 2001.
Approximately 10 MMCF of gas per day will be used for onshore operations, and
the remainder will be reinjected.
The Company, through its 50 percent ownership interest in AMCCO, indirectly owns
a 45 percent working interest in AMPCO, which is constructing a methanol plant
to use gas from the Alba field. The plant is designed to produce 2,500 metric
tons of methanol per day, which is the equivalent of approximately 20,000 BBLS
per day. The plant is designed to use approximately 125 MMCF of gas per day and
is approximately 95 percent complete. It is being built under a turnkey
construction contract and projected to be completed and begin production in the
second quarter of 2001. For additional information, see "Item 1.
Business--Unconsolidated Subsidiary" of this Form 10-K.
ECUADOR. The Company owns a 100 percent working interest in the Block 3
concession, located offshore Ecuador in the Gulf of Guayaquil. The concession
includes 12,355 gross developed acres and 851,771 gross undeveloped acres
encompassing the Amistad gas field. The Company constructed and set a drilling
and production platform for the Amistad gas field. A platform drilling rig had
drilled three wells at year end. Additional evaluation wells will be drilled in
2001.
Gas from the field is targeted to supply an electrical power generation facility
to be constructed near the city of Machala. The Company has made progress
payments to General Electric for the construction of two units that will
ultimately be capable of producing 240 megawatts of electricity when in a
combined cycle configuration.
ISRAEL. The Company made a gas discovery approximately 15 miles off the coast of
Israel with the Mari-B #1 well. The Mari-B #2 well was drilled approximately one
mile east of the Mari-B #1 discovery. A delineation well was drilled to appraise
the southern extension of the nearby Noa field which was discovered in 1999.
Based on the data
10
from these wells, it is estimated that the combined Noa/Mari-B areas contain
recoverable reserves in excess of 1.2 TCF of gas.
In late 2000, the Company increased its interest in the exploration agreement
from 40 to 47 percent. The agreement covers 11 licenses, permits or leases
encompassing 1,081,974 gross acres offshore Israel.
The partners in the exploration agreement are currently negotiating a supply
contract with Israel Electric Corporation Ltd.
CHINA. In October 2000, the Chinese government granted final approval of the
development plan for the Cheng Dao Xi field to the Company's wholly-owned
indirect subsidiary Energy Development Corporation (China), Inc. The field is
located in the southern portion of Bohai Bay. The plan includes a drilling and
production platform set in approximately 25 feet of water and 16 wells to
develop the field, including injection wells to maintain field pressure. The
production facilities are designed to process 10,000 BBLS of oil per day.
A five-mile pipeline will also be installed to connect the field to the existing
onshore infrastructure located in the Shengli oil field. The total projected
$101 million cost for the development and construction of the field and pipeline
will be shared 57 percent by the Company and 43 percent by the China
Petro-Chemical Corporation. Initial production is expected in the second quarter
of 2002.
VIETNAM. Oil and gas exploration rights were acquired on two blocks in the Nam
Con Son basin offshore Vietnam. Samedan will be the operator with a 60 percent
interest in the two blocks, which encompass 1.7 million acres. Both oil and gas
have been tested on the blocks in wells drilled by previous operators, but the
discoveries were not developed. Two exploratory wells are planned for 2001.
NORTH SEA. EDC (Europe) Limited, a wholly-owned indirect subsidiary of the
Company, acquired, through an asset exchange, a 12 percent interest in Block
21/20a in the Cook field, 100 miles east of Aberdeen, Scotland. This field
commenced production of 12,000 gross BBLS of oil per day in April 2000.
Recoverable reserves are estimated in excess of 20 million BBLS of oil to be
produced over a span of at least five years.
Interests in two licenses in the Hanze field in the Dutch sector of the North
Sea were acquired. The Company owns a 15 percent interest in one license in
which production is expected to start during the second half of 2001. An
exploration well on the second license, in which the Company owns 40 percent, is
planned in 2001. A new oil platform, currently under construction, is expected
to have a production rate of approximately 31,500 BBLS of oil per day. The Hanze
field would be the first oil field to come into production in the Dutch sector
of the North Sea in 10 years.
ARGENTINA. The Company participated with a 13 percent working interest in 38
exploitation wells in the El Tordillo field during 2000. 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. Seismic work should commence in 2001.
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
- -------------------------------------------------------------------------------------------------------------------
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
1998 15.63 .13 15.16 .33 42.21 3.92 10.71
- ----------
(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, 2001, Samedan was drilling 9 gross (4.3 net) exploratory wells
and 8 gross (3.6 net) development wells. These wells are located in Oklahoma,
Texas, Louisiana, Argentina, and offshore in the Gulf of Mexico, Israel,
Ecuador, Equatorial Guinea, and the North Sea. These wells have objectives
ranging from approximately 5,500 feet to 25,000 feet. The drilling cost to
Samedan of these wells is approximately $47 million if all are dry and
approximately $62 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, were as follows:
2000(1)(3) 1999(1)(2)(3) 1998(1)(3)
---------------------------------------------------------------------------
GROSS NET GROSS NET GROSS NET
- -------------------------------------------------------------------------------------------------------------------
OIL WELLS
United States - Onshore 1,341.5 564.0 1,512.5 683.2 4,571.5 895.8
United States - Offshore 210.5 119.2 254.5 128.2 344.0 145.9
International 604.0 66.2 1,041.0 122.9 1,019.0 119.2
- -------------------------------------------------------------------------------------------------------------------
TOTAL 2,156.0 749.4 2,808.0 934.3 5,934.5 1,160.9
- -------------------------------------------------------------------------------------------------------------------
GAS WELLS
United States - Onshore 1,532.5 947.1 1,435.5 873.9 1,608.5 944.7
United States - Offshore 300.5 133.4 406.5 150.4 410.0 152.2
International 31.0 3.5 27.0 2.5 25.0 2.0
- -------------------------------------------------------------------------------------------------------------------
TOTAL 1,864.0 1,084.0 1,869.0 1,026.8 2,043.5 1,098.9
- -------------------------------------------------------------------------------------------------------------------
(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 contributing
to the decreased well count.
(3) One or more completions in the same bore hole is 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.
2000 1999 1998
-------------------------------------------------------------------------
GROSS NET GROSS NET GROSS NET
- -------------------------------------------------------------------------------------------------------------------
MULTIPLE COMPLETIONS
Oil 13.5 6.9 14.0 9.2 21.5 15.5
Gas 36.5 14.0 49.0 23.2 47.5 24.7
NOT PRODUCING (SHUT-IN)
Oil 386.0 177.5 857.0 233.5 1,609.5 237.2
Gas 62.0 20.6 33.0 4.5 58.5 23.2
At year-end 2000, 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, 2000, 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,
------------------------------------------
2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------
Average sales price per BBL of oil (1):
United States $ 23.75 $16.37 $ 11.98
International $ 26.09 $16.01 $ 10.28
Combined (2) $ 24.37 $16.29 $ 11.66
Average sales price per MCF of natural gas (1):
United States $ 3.90 $ 2.30 $ 2.18
International $ 2.08 $ 1.38 $ 2.13
Combined $ 3.77 $ 2.23 $ 2.18
Average production (lifting) cost per unit of oil and natural
gas production, excluding depreciation (MCFe) (3):
United States $ .59 $ .51 $ .50
International $ .64 $ .49 $ .66
Combined $ .59 $ .50 $ .52
(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) Oil production is converted to gas equivalents (MCFe) based on one BBL
of oil equals six MCF of gas.
14
[MAP OF GULF OF MEXICO OPERATIONS]
SIGNIFICANT OFFSHORE UNDEVELOPED LEASE HOLDINGS (INTERESTS ROUNDED TO NEAREST
WHOLE PERCENT)
NET WORKING
BLOCK INTEREST (%)
- -------------------------
EAST BREAKS
- -----------
279 33
420* 48
421* 48
464* 48
465* 48
475* 100
510* 33
519* 100
563* 100
588* 97
589* 97
632* 97
633* 97
GREEN CANYON
- ------------
23* 50
24* 43
25* 43
27* 43
85* 50
227* 50
228* 50
303* 40
723* 100
724* 100
768* 100
WEST CAMERON
- ------------
136 40
392 100
393 100
400 100
438 100
443 100
446 100
583 100
602 100
614 25
VERMILION
- ---------
195 25
207 25
232 50
278 100
280 50
283 50
285 50
286 100
300 50
312 100
349 75
353 100
360 67
361 67
365 50
377 100
394 75
GARDEN BANKS
- ------------
34 100
35 100
62 25
63 25
64 25
78 100
107 25
116 100
122 100
154 100
326* 100
751* 100
795* 100
841* 39
MAIN PASS
- ---------
192 100
293 100
GALVESTON
- ---------
249-L 50
250-L 50
274-L 50
275-L 50
277-L 50
340-S 50
341-S 50
349-S 50
MUSTANG ISLAND
- --------------
829 80
830 80
SOUTH MARSH ISLAND
- ------------------
38 100
62 67
63 67
64 67
65 67
70 50
104 100
167 100
179 35
180 35
185 35
186 35
195 50
MISSISSIPPI CANYON
- ------------------
524* 50
573 100
583* 50
595* 24
639* 24
661* 25
665* 50
705* 25
849* 48
SOUTH TIMBALIER
- ---------------
98 50
156 67
201 100
315 30
BRAZOS
- ------
308-L 50
336-L 50
337-L 50
543 100
EWING BANK
- ----------
833* 14
834* 14
949 97
993 48
995 43
996 43
EUGENE ISLAND
- -------------
96 25
97 25
109 25
300 67
317 67
HIGH ISLAND
- -----------
A-218 100
A-230 100
A-232 100
A-426 33
A-435 33
A-516 100
VIOSCA KNOLL
- ------------
344 100
697 50
820 50
908* 100
ATWATER VALLEY
- --------------
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, 2000, is as follows:
DEVELOPED ACREAGE (1)(2) UNDEVELOPED ACREAGE (2)(3)
----------------------------- -----------------------------
LOCATION GROSS ACRES NET ACRES GROSS ACRES NET ACRES
- -------------------------------------------------------------------------------------------------------------------
United States Onshore
Alabama 2,396 506
California 5,330 2,258 5,229 3,523
Colorado 61,678 59,088 21,682 16,858
Kansas 92,601 53,073 20,042 11,908
Louisiana 20,864 6,387 12,841 6,373
Michigan 1,876 427
Mississippi 878 34 1,884 51
Montana 172,843 119,234 17,586 5,264
New Mexico 3,117 1,766 2,325 1,738
North Dakota 1,932 1,554 5,767 3,246
Oklahoma 141,513 54,712 46,459 15,928
South Dakota 800 131
Texas 74,268 37,893 84,294 42,298
Utah 5,160 2,433 640 500
Wyoming 24,718 11,797 65,706 42,727
- -------------------------------------------------------------------------------------------------------------------
Total United States Onshore 604,902 350,229 289,527 151,478
- -------------------------------------------------------------------------------------------------------------------
United States Offshore (Federal Waters)
Alabama 80,640 39,168 25,603 17,698
California 27,314 5,151 63,884 16,310
Florida 11,520 2,304
Louisiana 654,090 275,051 411,257 247,697
Mississippi 22,411 10,141 40,320 18,056
Texas 253,372 102,313 240,923 168,414
- -------------------------------------------------------------------------------------------------------------------
Total United States Offshore (Federal Waters) 1,037,827 431,824 793,507 470,479
- -------------------------------------------------------------------------------------------------------------------
International
Argentina 28,988 3,977 1,235,105 1,162,339
Australia 938,999 373,252
China 7,413 4,225 200,032 149,293
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 296,797 169,174
Israel 61,776 29,071 1,020,198 480,095
Netherlands 168,624 49,782
United Kingdom 131,527 4,539 432,736 150,057
Vietnam 1,701,812 1,327,413
- -------------------------------------------------------------------------------------------------------------------
Total International 287,262 69,894 7,193,730 4,838,345
- -------------------------------------------------------------------------------------------------------------------
TOTAL 1,929,991 851,947 8,276,764 5,460,302
- -------------------------------------------------------------------------------------------------------------------
(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.
16
ITEM 3. LEGAL PROCEEDINGS.
The Noble Drilling litigation disclosed in the Company's 1999 Form 10-K was
settled during 2000.
The Company has other 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 2000.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information, as of March 12, 2001, with
respect to the executive officers of the Registrant.
Name Age Position
- ----------------------------------------------------------------------------------------------------------------
Robert Kelley (1) 55 Chairman of the Board
Charles D. Davidson (2) 51 President, Chief Executive Officer, Director
Alan R. Bullington (3) 49 Vice President, General Manager-International Division,
Samedan Oil Corporation
Robert K. Burleson (4) 43 President, Noble Gas Marketing, Inc.
Dan O. Dinges (5) 47 Senior Vice President, General Manager-Offshore Division
and Operating Committee Member of Samedan Oil Corporation
Albert D. Hoppe (6) 56 Senior Vice President, General Counsel and Secretary of the
Registrant and Operating Committee Member of Samedan Oil Corporation
James L. McElvany (7) 47 Vice President-Finance and Treasurer of the Registrant and Operating
Committee Member of Samedan Oil Corporation
Richard A. Peneguy, Jr. (8) 50 Vice President, General Manager-Onshore Division,
Samedan Oil Corporation
W. A. Poillion (9) 51 Senior Vice President and Operating Committee Member of
Samedan Oil Corporation
Kenneth P. Wiley (10) 48 Vice President-Information Systems of the Registrant
- ---------------
(1) Robert Kelley served as President and Chief Executive Officer of the
Registrant from August 1, 1986 until October 2000 and as Chairman of the
Board since October 27, 1992. Prior to August 1986, he had served as
Executive Vice President of the Registrant from January 1986. Mr. Kelley
served as President and Chief Executive Officer of Samedan, positions he
held since 1984. For more than five years prior thereto, Mr. Kelley
served as an officer of Samedan. He has served as a director of the
Company since 1986. Mr. Kelley has announced his retirement effective
April 30, 2001.
17
(2) Charles D. Davidson was elected 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.
(3) Alan R. Bullington was promoted 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.
(4) Robert K. Burleson has served as President of Noble Gas Marketing, Inc.
since June 14, 1995. Prior thereto, 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.
(5) Dan O. Dinges was promoted to Senior Vice President and General Manager,
Offshore Division of Samedan on January 1, 1998. Prior thereto, he had
served as Vice President and General Manager, Offshore Division of
Samedan since January 1989. Mr. Dinges has been a member of the
Operating Committee of Samedan since January 31, 1995.
(6) Albert D. Hoppe was elected Senior Vice President, General Counsel and
Secretary of the Registrant on December 5, 2000. Prior thereto, he
served as Vice President, General Counsel and Secretary of Vastar
Resources, Inc. from 1994 through 2000.
(7) James L. McElvany has served as Vice President-Finance and Treasurer of
the Registrant since July 1, 1999. Prior to July 1999, he had served as
Vice President-Controller of the Registrant since December 1997. Prior
thereto, he served as Controller of the Registrant since December 1983.
He has been a member of the Operating Committee of Samedan since July 1,
1999.
(8) Richard A. Peneguy, Jr. was promoted to Vice President and General
Manager, Onshore Division of Samedan on January 1, 2000. Prior thereto,
he had served as General Manager, Onshore Division of Samedan since
January 1, 1991.
(9) W. A. Poillion was promoted to Senior Vice President-Production and
Drilling of Samedan on January 1, 1998. Prior thereto, he had served as
Vice President-Production and Drilling of Samedan since November 1990.
He has been a member of the Operating Committee of Samedan since
November 1, 1990. From March 1, 1985 to October 31, 1990, he served as
Manager of Offshore Production and Drilling for Samedan.
(10) Kenneth P. Wiley has served as Vice President-Information Systems 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. With the exception of Mr. Davidson, no
other officer or executive officer of the Registrant has an employment agreement
with the Registrant or any of its subsidiaries. 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
- --------------------------------------------------------------------------------------------------------------------------
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
1999
- ----
First quarter $31.44 $19.25 $.04
Second quarter $35.00 $24.88 $.04
Third quarter $33.88 $27.00 $.04
Fourth quarter $29.19 $19.13 $.04
TRANSFER AGENT AND REGISTRAR. The transfer agent and registrar for the Common
Stock is First Chicago Trust Company of New York, P.O. Box 2500, Jersey City,
New Jersey 07303.
STOCKHOLDERS' PROFILE. As of December 31, 2000, the number of holders of record
of Common Stock was 1,179. The following chart indicates the common stockholders
by category.
SHARES
DECEMBER 31, 2000 OUTSTANDING
- ---------------------------------------------------------------------------------------------------------------------
Individuals 472,983
Joint accounts 65,082
Fiduciaries 143,075
Institutions 2,513,538
Nominees 52,889,663
Foreign 6,521
- ---------------------------------------------------------------------------------------------------------------------
Total-Excluding Treasury Shares 56,090,862
- ---------------------------------------------------------------------------------------------------------------------
RECENT SALES OF UNREGISTERED SECURITIES. The Company's unconsolidated
subsidiary, Atlantic Methanol Capital Company ("AMCCO"), is a 50 percent owned
joint venture that indirectly owns 90 percent of Atlantic Methanol Production
Company ("AMPCO"), which is constructing a methanol plant in Equatorial Guinea.
On November 10, 1999, AMCCO issued $125 million of 10.875% Series A-1 Senior
Secured 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 remaining construction payments.
The Company has guaranteed the payment of interest on the Series A-2 Notes. In
addition, the Company established a new series of preferred stock, Series B
Mandatorily Convertible Preferred Stock, par value $1.00 per share (the "Series
B Preferred"). The Company issued, in a private placement pursuant to Section
4(2) of the Securities Act, 125,000 shares of 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.
19
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
Donaldson, Lufkin & Jenrette, 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) 2000 1999 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------------------
REVENUES AND INCOME
Revenues $1,393,591 $ 909,842 $ 911,616 $1,116,623 $ 887,203
Net cash provided by operating activities 570,334 343,100 382,010 492,473 413,707
Net income (loss) 191,597 49,461 (164,025) 99,278 83,880
PER SHARE DATA
Basic earnings (loss) per share $ 3.42 $ .87 $ (2.88) $ 1.75 $ 1.63
Cash dividends $ .16 $ .16 $ .16 $ .16 $ .16
Year-end stock price $ 46.00 $ 21.44 $ 24.63 $ 35.25 $ 47.88
Basic weighted average shares outstanding 55,999 57,005 56,955 56,872 51,414
FINANCIAL POSITION (at year end)
Property, plant and equipment, net:
Oil and gas mineral interests,
equipment and facilities $1,485,123 $1,242,370 $1,429,667 $1,546,426 $1,559,691
Total assets 1,879,280 1,420,351 1,686,080 1,852,782 1,956,938
Long-term obligations:
Long-term debt, net of current portion 525,494 445,319 745,143 644,967 798,028
Deferred income taxes 117,048 83,075 106,823 144,083 108,434
Other 61,639 53,877 52,868 56,425 50,603
Shareholders' equity 849,682 683,609 642,080 812,989 720,067
Ratio of debt to book capital .38 .39 .54 .44 .54
CAPITAL EXPENDITURES
Oil and gas mineral interests,
equipment and facilities $ 502,430 $ 121,077 $ 445,910 $ 320,561 $ 982,499
Methanol and power projects 98,737 89,728 25,131
Other 4,430 1,410 2,733 8,499 3,485
- ---------------------------------------------------------------------------------------------------------------------------
Total capital expenditures $ 605,597 $ 212,215 $ 473,774 $ 329,060 $ 985,984
- ---------------------------------------------------------------------------------------------------------------------------
For additional information, see "Item 8. Financial Statements and Supplementary
Data" of this Form 10-K.
OPERATING STATISTICS
YEAR ENDED DECEMBER 31,
- ---------------------------------------------------------------------------------------------------------------------------------
2000 1999 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------------------------------
GAS
Sales (in millions) $ 549.9 $ 359.8 $ 441.8 $ 499.4 $ 365.4
Production (MMCF per day) 406.3 455.1 566.6 565.4 469.4
Average price (per MCF) $ 3.77 $ 2.23 $ 2.18 $ 2.48 $ 2.17
OIL
Sales (in millions) $ 224.2 $ 174.9 $ 154.3 $ 243.6 $ 225.2
Production (BBLS per day) 25,805 30,003 37,217 38,345 34,520
Average price (per BBL) $ 24.37 $ 16.29 $ 11.66 $ 17.86 $ 18.28
Royalty sales (in millions) $ 17.3 $ 14.0 $ 13.1 $ 18.1 $ 13.9
21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
LIQUIDITY AND CAPITAL RESOURCES
LIQUIDITY
The Company's net cash provided from operations in 2000 was significantly higher
than 1999 due to higher commodity prices during the second half of the year for
crude oil and natural gas.
The oil price received by the Company in 2000 increased 50 percent from 1999 and
the gas price received by the Company increased 69 percent in 2000 over the
price received in 1999. In 1999, the Company's oil price increased 40 percent
and the natural gas price increased two percent compared to 1998.
CASH PROVIDED FROM OPERATIONS
[CHART - dollars per BOE] [CHART - dollars per share]
The Company's unconsolidated subsidiary, AMCCO, is a 50 percent owned joint
venture that indirectly owns 90 percent of AMPCO, which is constructing a
methanol plant in Equatorial Guinea. During 1999, AMCCO issued $250 million
senior secured notes due 2004 which are not included in the Company's balance
sheet, to fund the remaining construction payments. The plant construction
started during 1998 and commercial production is expected during the second
quarter of 2001. The construction cost of the turnkey contract is $322.5
million. Other associated expenditures required to complete the project and
produce marketable supplies of methanol are projected to be $125.5 million. The
total cost of the methanol project is estimated to be $448 million including
various contingencies and capitalized interest, with the Company responsible for
$224 million. Payments are due upon the completion of specific phases of the
construction. During 2000, the Company recorded costs of $72 million toward the
project, including capitalized interest, and $45.6 million in construction
contract payments. The Company has construction contract phase payments totaling
$8.1 million due in 2001.
During 2000, $512 million was spent on exploration and development projects, $72
million on the methanol project and $27 million on the Machala power project in
Ecuador for total expenditures of $611 million. The 2001 exploration and
development budget is approximately $700 million, including $45 million for the
methanol project and $42 million on the Machala power project.
The Company's current ratio (current assets divided by current liabilities) was
.83:1 at December 31, 2000, compared with .76:1 at December 31, 1999. The
increase in the current ratio was due primarily to an increase in cash and
short-term investments along with a $17.5 million decrease in other current
liabilities. The Company's cash and short-term investments increased from $2.9
million at December 31, 1999, to $23.2 million at December 31, 2000.
22
FINANCING
The Company's total long-term debt, net of unamortized discount, at December 31,
2000, was $525 million compared to $445 million at December 31, 1999. The ratio
of debt to book capital (defined as the Company's debt plus its equity) was 38
percent at December 31, 2000, compared with 39 percent at December 31, 1999.
The Company's long-term debt 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 and the outstanding balance of $80 million on a $300 million
credit facility. Other than the $80 million due on the credit facility, there is
no principal payment due on long term debt during the next five years.
The Company has a $300 million credit facility which exposes the Company to the
risk of earnings or cash flow loss due to changes in market interest rates. At
December 31, 2000, there was $80 million borrowed against the credit facility
which has a maturity date of December 24, 2002. The interest rate is based upon
a Eurodollar rate plus a range of 17.5 to 50 basis points. At year-end 1999, the
Company had no borrowing against this facility.
On June 17, 1999, the Company entered into a new $100 million 364 day credit
agreement with certain commercial lending institutions. This agreement, which is
based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon the
percentage of utilization, expired in 2000 without ever having been utilized.
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 authorized a repurchase of up to $50 million of
the Company's common stock. As of March 1, 2001, the Company had completed 60.5
percent of the repurchase plan. The repurchase of 1,386,400 shares during 2000
at an average cost of $21.84 per share was funded from the Company's current
cash flow.
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, 1999 and 1998 dispositions were 1.2 million BBLS of oil and 4.8 BCF of
gas, 5.1 million BBLS of oil and 34.2 BCF of gas, and .2 million BBLS of oil and
2.2 BCF of gas, respectively. 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 establishes 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 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.
Due to the issuance of SFAS No. 137, which deferred the effective date of SFAS
No. 133, the Company is required to adopt the statement for fiscal years
beginning after June 15, 2000. A company may also implement the statement as of
the beginning of any fiscal quarter after the statement's issuance (that is,
fiscal quarters beginning June 16, 1998, and thereafter). SFAS No. 133 must be
applied to (a) derivative instruments and (b) certain derivative instruments
embedded in hybrid contracts that were issued, acquired, or substantively
modified after December 31, 1997 (and, at the Company's election, before January
1, 1998).
23
During 2000, the FASB issued SFAS No. 138 which amends the accounting and
reporting standards of SFAS No. 133 for certain derivative instruments and
certain hedging activities and should be adopted concurrently with SFAS No. 133,
according to its provisions and the issuance of SFAS No. 137. The normal
purchases and normal sales exception may be applied to contracts that implicitly
or explicitly permit net settlement and contracts that have a market mechanism
to facilitate net settlement. The Company adopted SFAS Nos. 133 and 138
effective January 1, 2001. The adoption of these FASB's did not have a material
impact on the Company's results of operations or financial position.
RESULTS OF OPERATIONS
NET INCOME AND REVENUES
The Company's net income for 2000 of $191.6 million was primarily the result of
a 50 percent and 69 percent increase in the average oil and gas price to $24.37
per BBL and $3.77 per MCF, respectively, compared to 1999. The impact of the
increased oil price was approximately $76 million in additional oil revenues
compared to 1999. The impact of the increase in the 2000 average natural gas
price was approximately $229 million in additional gas revenues compared to
1999. The increase in net income for 1999 compared to 1998, is primarily due to
significantly higher oil prices received during 1999 coupled with the $143
million charge for property impairments in 1998.
NATURAL GAS INFORMATION
Natural gas revenues increased dramatically in 2000, due to a 69 percent
increase in the average price. The 69 percent increase in the average price
received for the Company's 2000 gas production offset a decline of 11 percent in
the average daily gas production. Gas production in both the third and fourth
quarters of 2000 rose above the low experienced in the second quarter of 2000.
Natural gas accounted for 71 percent of the Company's total gas and oil revenues
in 2000. Gas sales and average daily production for 1999 declined despite a
slight increase in the Company's average price. Revenues were down because
natural gas production declined 20 percent in 1999 compared to 1998. The table
below depicts daily natural gas production in MMCF by area for the last three
years.
2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------
Offshore 291.3 304.9 404.5
Onshore 86.9 116.9 139.4
International 28.1 33.3 22.7
- --------------------------------------------------------------------------------------------------------------------
Total 406.3 455.1 566.6
- --------------------------------------------------------------------------------------------------------------------
Natural gas production during 2000 ranged from a low of 354.2 MMCF per day in
June, to a high of 438.3 MMCF per day in December.
2000 DAILY PRODUCTION BY QUARTER
[CHART - MMCF] [CHART - MBBLS]
24
CRUDE OIL INFORMATION
Crude oil revenues increased during 2000 due to significantly stronger oil
prices. The 50 percent increase in the average price received for the Company's
2000 oil production offset a decline of 14 percent in the average daily
production. Oil production in both the third and fourth quarters of 2000 rose
above the low experienced in the second quarter of 2000. Crude oil accounted
for 29 percent of the Company's total oil and gas revenues in 2000. Oil sales
increased 40 percent and average daily production declined 19 percent in 1999,
compared to 1998. The table below depicts daily oil production in BBLS by area
for the last three years.
2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------
Offshore 12,077 13,501 17,566
Onshore 6,942 9,901 12,505
International 6,786 6,601 7,146
- --------------------------------------------------------------------------------------------------------------------
Total 25,805 30,003 37,217
- --------------------------------------------------------------------------------------------------------------------
Crude oil production during 2000 ranged from a low of 24,019 BBLS per day in
May, to a high of 27,434 BBLS per day in August. The Company's December 2000
oil production volume was 25,974 BBLS per day.
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 four
percent in 2000 from 1999 and decreased 22 percent in 1999 compared to 1998.
Included in operations expense were workover costs of $21.1 million, $5.7
million and $6.5 million for 2000, 1999 and 1998, respectively. The workovers,
which enhanced production during 2000, increased operations expense by $.10 per
MCFe. Workover costs for 1999 and 1998 were held to a minimum due to low product
prices.
[CHART - OPERATING EXPENSES] [CHART - DD&A EXPENSES]
25
In 2000, depreciation, depletion and amortization ("DD&A") expense decreased
nine percent, compared to 1999, due to lower oil and gas production volumes.
This decrease reflects a 14 percent decrease in oil volumes and an 11 percent
decrease in natural gas production volumes. In 1999, DD&A expense decreased 19
percent compared to 1998, resulting from lower oil and gas production volumes
and a lower DD&A rate due to the impairment of operating assets in 1998.
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 Company's
accumulated provision for future dismantlement and restoration cost was $79.7
million at December 31, 2000, $83.0 million at December 31, 1999 and $68.8
million at December 31, 1998. Total estimated future dismantlement and
restoration costs of $136.1 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) 2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------
Dry hole expense $ 38,463 $ 19,204 $ 57,736
Undeveloped lease amortization 16,075 9,645 7,953
Abandoned assets 3,375 2,483 15,325
Seismic 18,738 7,797 15,754
Other 11,592 7,655 13,390
- --------------------------------------------------------------------------------------------------------------------
Total Exploration Expense $ 88,243 $ 46,784 $ 110,158
- --------------------------------------------------------------------------------------------------------------------
IMPAIRMENT OF OPERATING ASSETS
The Company recorded no asset impairments under SFAS No. 121 during 2000 or
1999. In the fourth quarter of 1998, the Company recorded a $223.3 million
pre-tax charge for the write-down of properties due to downward reserve
revisions. The assets impaired under SFAS No. 121 were oil and gas properties
maintained under the successful efforts method of accounting. The excess of the
net book value over the projected discounted future net revenue of the impaired
properties was charged to "Impairment of Operating Assets" expense.
SELLING, GENERAL AND ADMINISTRATIVE EXPENSES ("SG&A")
SG&A expenses have decreased $.6 million in 2000 compared to 1999 and $.3
million in 1999 compared to 1998. 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.
26
The gathering, marketing and processing revenues less expenses for both NGM and
NTI are reflected in the table below.
2000 1999 1998
(IN THOUSANDS) ---------------------------- --------------------------- ----------------------------
(AMOUNTS INCLUDE INTER-
COMPANY ELIMINATIONS) NTI NGM NTI NGM NTI NGM
- ---------------------------------------------------------------------------------------------------------------------
Revenues $ 91,204 $ 498,729 $ 62,671 $ 275,375 $ 67,075 $ 216,728
Expenses
Cost of goods sold 63,005 464,600 35,974 237,475 40,293 179,931
Transportation 19,455 24,014 19,128 27,816 20,024 27,200
General and administrative 190 3,002 180 2,742 161 2,614
- ---------------------------------------------------------------------------------------------------------------------
Total Expenses $ 82,650 $ 491,616 $ 55,282 $ 268,033 $ 60,478 $ 209,745
- ---------------------------------------------------------------------------------------------------------------------
Gross Margin $ 8,554 $ 7,113 $ 7,389 $ 7,342 $ 6,597 $ 6,983
- ---------------------------------------------------------------------------------------------------------------------
The margins for NGM on a per MMBTU basis were $.027 for 2000, $.026 for 1999 and
$.049 for 1998. The increase in NGM's margin on a per MMBTU basis for 2000
compared to 1999, was due to the improvement in gas prices. The decrease in
NGM's margin on a per MMBTU basis for 1999 compared to 1998, was due primarily
to increased transportation expense. The margins for NTI on a per BBL basis were
$1.28 for 2000, $.87 for 1999 and $.63 for 1998. The increase in NTI's margin on
a per BBL basis for each of the years presented was due primarily to improved
crude oil prices coupled with lower transportation costs.
FUTURE TRENDS
The Company expects increased oil and gas production in 2001 and 2002 compared
to 2000. The increase in 2001 would be primarily due to the Cook and Hanze
acquisitions, as well as the completion of the Alba field expansion and the
startup of the methanol plant, which would utilize gas feedstock from the Alba
field. The Amistad gas field development and Machala power project are expected
to be completed and contributing to cash flow and gas production in 2002. The
China field development is also projected to be completed with first oil
production expected in 2002.
The Company recently set its 2001 exploration and development budget at
approximately $700 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.
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 can
not 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
domestic oil and gas industry. Due to the volatility of oil and gas prices, the
Company, from time to time, has used derivative hedging and may do so in the
future as a means of controlling its exposure to price changes. The swap
component of the contracts discussed in the following paragraphs was treated as
a hedge for accounting purposes only.
The Company had 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
27
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 had
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.
The Company had no oil or gas hedging contracts for future production as of
December 31, 2000.
During 1999 and 1998, 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,
2000, the Company had no material market risk exposure from NGM's hedging
activity.
28
The Company has a $300 million credit agreement (see Note 3 - Debt, to the
Consolidated Financial Statements) which exposes the Company to the risk of
earnings or cash flow loss due to changes in market interest rates. At December
31, 2000, there was $80 million borrowed against the credit facility which has a
maturity date of December 24, 2002. The interest rate is based upon a Eurodollar
rate plus a range of 17.5 to 50 basis points. 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.
On June 17, 1999, the Company entered into a new $100 million 364 day credit
agreement with certain commercial lending institutions. This agreement, which is
based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon the
percentage of utilization, expired in 2000 without ever having been utilized.
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.
29
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants................................................................ 31
Consolidated Balance Sheet as of December 31, 2000 and 1999............................................. 32
Consolidated Statement of Operations for each of the three years in the period ended
December 31, 2000..................................................................................... 33
Consolidated Statement of Cash Flows for each of the three years in the period ended
December 31, 2000..................................................................................... 34
Consolidated Statement of Shareholders' Equity for each of the three years in the period ended
December 31, 2000..................................................................................... 35
Notes to Consolidated Financial Statements.............................................................. 36
Supplemental Oil and Gas Information (Unaudited)........................................................ 50
Interim Financial Information (Unaudited)............................................................... 56
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.
30
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,
2000 and 1999, and the related consolidated statements of operations,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 2000. 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, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Oklahoma City, Oklahoma
January 26, 2001
31
CONSOLIDATED BALANCE SHEET
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
DECEMBER 31,
- -------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT SHARE AMOUNTS) 2000 1999
- -------------------------------------------------------------------------------------------------------------------
ASSETS
CURRENT ASSETS:
Cash and short-term investments $ 23,152 $ 2,925
Accounts receivable - trade 235,843 98,794
Materials and supplies inventories 4,645 5,517
Other current assets 7,621 10,678
- -------------------------------------------------------------------------------------------------------------------
Total current assets 271,261 117,914
- -------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, AT COST:
Oil and gas mineral interests, equipment and facilities
(successful efforts method of accounting) 3,213,223 2,786,848
Other 43,244 43,945
- -------------------------------------------------------------------------------------------------------------------
3,256,467 2,830,793
Accumulated depreciation, depletion and amortization (1,771,344) (1,588,423)
- -------------------------------------------------------------------------------------------------------------------
Total property, plant and equipment, net 1,485,123 1,242,370
- -------------------------------------------------------------------------------------------------------------------
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY 74,159 15,625
- -------------------------------------------------------------------------------------------------------------------
OTHER ASSETS 48,737 44,442
- -------------------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 1,879,280 $ 1,420,351
- -------------------------------------------------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - trade $ 279,379 $ 103,753
Other current liabilities 30,730 48,215
Income taxes - current 15,308 2,503
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 325,417 154,471
- -------------------------------------------------------------------------------------------------------------------
DEFERRED INCOME TAXES 117,048 83,075
- -------------------------------------------------------------------------------------------------------------------
OTHER DEFERRED CREDITS AND NONCURRENT LIABILITIES 61,639 53,877
- -------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT 525,494 445,319
- -------------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY:
Preferred stock - par value $1.00; 4,000,000 shares authorized, none issued
Common stock - par value $3.33 1/3; 100,000,000 shares authorized;
59,002,162 and 58,569,963 shares issued in 2000 and 1999, respectively 196,672 195,231
Capital in excess of par value 373,259 360,983
Retained earnings 325,452 142,813
- -------------------------------------------------------------------------------------------------------------------
895,383 699,027
Less common stock in treasury at cost
(December 31, 2000, 2,911,300 shares and
December 31, 1999, 1,524,900 shares) (45,701) (15,418)
- -------------------------------------------------------------------------------------------------------------------
Total shareholders' equity 849,682 683,609
- -------------------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 1,879,280 $ 1,420,351
- -------------------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
32
CONSOLIDATED STATEMENT OF OPERATIONS
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
- --------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------
REVENUES:
Oil and gas sales and royalties $ 791,353 $ 548,733 $ 609,164
Gathering, marketing and processing 589,933 338,046 284,407
Other income 10,816 23,100 18,045
Income (loss) from investment in unconsolidated subsidiary 1,489 (37)
- --------------------------------------------------------------------------------------------------------------------
Total Revenue 1,393,591 909,842 911,616
- --------------------------------------------------------------------------------------------------------------------
COSTS AND EXPENSES:
Oil and gas exploration 88,243 46,784 110,158
Oil and gas operations 121,866 116,698 149,030
Gathering, marketing and processing 574,266 323,314 270,826
Depreciation, depletion and amortization 230,800 254,515 313,191
Impairment of operating assets 223,251
Selling, general and administrative 47,291 47,859 48,110
Interest 37,968 48,935 50,511
Interest capitalized (6,326) (5,894) (6,753)
- --------------------------------------------------------------------------------------------------------------------
Total Expenses 1,094,108 832,211 1,158,324
- --------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE TAXES 299,483 77,631 (246,708)
- --------------------------------------------------------------------------------------------------------------------
INCOME TAX PROVISION (BENEFIT):
Current 74,616 24,508 (19,679)
Deferred 33,270 3,662 (63,004)
- --------------------------------------------------------------------------------------------------------------------
Total Tax Provision (Benefit) 107,886 28,170 (82,683)
- --------------------------------------------------------------------------------------------------------------------
NET INCOME (LOSS $ 191,597 $ 49,461 $ (164,025)
- --------------------------------------------------------------------------------------------------------------------
BASIC EARNINGS (LOSS) PER SHARE $ 3.42 $ .87 $ (2.88)
- --------------------------------------------------------------------------------------------------------------------
DILUTED EARNINGS (LOSS) PER SHARE $ 3.38 $ .86 $ (2.88)
- --------------------------------------------------------------------------------------------------------------------
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic 55,999 57,005 56,955
Diluted 56,755 57,349 56,955
- --------------------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
33
CONSOLIDATED STATEMENT OF CASH FLOWS
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
- ----------------------------------------------------------------------------------------------------------
(IN THOUSANDS) 2000 1999 1998
- ----------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ 191,597 $ 49,461 $ (164,025)
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 230,800 254,515 313,191
Dry hole 38,463 19,204 57,736
Impairment of operating assets 223,251
Amortization of undeveloped leasehold costs, net 16,075 9,645 7,953
(Gain) loss on disposal of assets (3,799) (12,079) 15,434
Noncurrent deferred income taxes 33,973 (23,749) (37,260)
(Income) loss from unconsolidated subsidiary (1,489) 37
Increase (decrease) in other deferred credits 7,762 1,011 (3,558)
(Increase) decrease in other (3,747) (1,295) 12,708
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable (137,049) 7,719 56,154
(Increase) decrease in other current assets 3,557 16,571 (44,423)
Increase (decrease) in accounts payable 198,871 (4,785) (55,025)
Increase (decrease) in other current liabilities (4,680) 26,845 (126)
- ----------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 570,334 343,100 382,010
- ----------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (536,901) (142,124) (489,452)
Investment in unconsolidated subsidiary (57,045) (51,962) (25,061)
Proceeds from the transfer of our interest
to unconsolidated subsidiary 61,987
Proceeds from sale of property, plant and equipment 12,608 58,137 3,412
- ----------------------------------------------------------------------------------------------------------
NET CASH USED IN INVESTING ACTIVITIES (581,338) (73,962) (511,101)
- ----------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Exercise of stock options 13,717 1,188 2,229
Cash dividends paid (8,958) (9,120) (9,113)
Proceeds from bank debt 137,000
Repayment of bank debt (57,000) (300,000)
Repayment of notes payable - unconsolidated subsidiary (23,245) (38,101)
Proceeds from notes payable - unconsolidated subsidiary 60,720
Purchase of treasury stock (30,283)
Proceeds from issuance of long-term debt 100,000
- ----------------------------------------------------------------------------------------------------------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 31,231 (285,313) 93,116
- ----------------------------------------------------------------------------------------------------------
INCREASE (DECREASE) IN CASH AND SHORT-TERM CASH INVESTMENTS 20,227 (16,175) (35,975)
CASH AND SHORT-TERM CASH INVESTMENTS AT BEGINNING OF YEAR 2,925 19,100 55,075
- ----------------------------------------------------------------------------------------------------------
CASH AND SHORT-TERM CASH INVESTMENTS AT END OF YEAR $ 23,152 $ 2,925 $ 19,100
- ----------------------------------------------------------------------------------------------------------
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for:
Interest (net of amount capitalized) $ 32,976 $ 44,845 $ 43,368
Income taxes $ 56,890 $ 30,000 $ 4,276
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
34
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CAPITAL IN TREASURY
COMMON STOCK EXCESS OF STOCK AT RETAINED
(IN THOUSANDS, EXCEPT SHARES ISSUED) SHARES ISSUED AMOUNT PAR VALUE COST EARNINGS
- ---------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1997 58,423,438 $194,743 $358,054 $(15,418) $ 275,610
- ---------------------------------------------------------------------------------------------------------------------
Net Loss (164,025)
Exercise of stock options 82,470 275 1,954
Cash dividends ($.16 per share) (9,113)
- ---------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998 58,505,908 $195,018 $360,008 $(15,418) $ 102,472
- ---------------------------------------------------------------------------------------------------------------------
Net Income 49,461
Exercise of stock options 64,055 213 975
Cash dividends ($.16 per share) (9,120)
- ---------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1999 58,569,963 $195,231 $360,983 $(15,418) $ 142,813
- ---------------------------------------------------------------------------------------------------------------------
Net Income 191,597
Purchase of treasury stock (30,283)
Exercise of stock options 432,199 1,441 12,276
Cash dividends ($.16 per share) (8,958)
- ---------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2000 59,002,162 $196,672 $373,259 $(45,701) $ 325,452
- ---------------------------------------------------------------------------------------------------------------------
SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
35
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"). Listed below are consolidated entities at
December 31, 2000.
NOBLE AFFILIATES, INC.
Noble Gas Marketing, Inc.
Noble Gas Pipeline, Inc.
Noble Trading, Inc.
NPM, Inc.
Samedan Oil Corporation
Samedan of North Africa, Inc.
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
Energy Development Corporation ("EDC")
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
Burnside Overseas Exploration Ltd.
Energy Development Corporation (Argentina), Inc.
Energy Development Corporation (China), Inc.
Energy Development Corporation (HIPS), Inc.
Gasdel Pipeline System Incorporated
HGC, Inc.
Producers Service, Inc.
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
36
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 $79.7 million for such future costs
classified with accumulated DD&A in the December 31, 2000 balance sheet. The
total estimated future dismantlement and restoration costs of $136.1 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.
37
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 required by SFAS No. 128, as of
December 31:
2000 1999 1998(1)
---------------------------- --------------------------- ----------------------------
(IN THOUSANDS INCOME SHARES INCOME SHARES INCOME SHARES
EXCEPT PER SHARE AMOUNTS) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR)
- ---------------------------------------------------------------------------------------------------------------------
Net income/shares $191,597 55,999 $49,461 57,005 $(164,025) 56,955
- ---------------------------------------------------------------------------------------------------------------------
BASIC EPS $3.42 $.87 $(2.88)
- ---------------------------------------------------------------------------------------------------------------------
Net income/shares $191,597 55,999 $49,461 57,005 $(164,025) 56,955
Effect of Diluted Securities
Stock options 756 344
- ---------------------------------------------------------------------------------------------------------------------
Adjusted net income
and shares $191,597 56,755 $49,461 57,349 $(164,025) 56,955
- ---------------------------------------------------------------------------------------------------------------------
DILUTED EPS $3.38 $.86 $(2.88)
- ---------------------------------------------------------------------------------------------------------------------
(1) In 1998, the diluted EPS is antidilutive as a result of the net
operating loss; therefore, the basic EPS and diluted EPS are the same.
REVENUE RECOGNITION AND GAS IMBALANCES
Samedan and EDC have gas sales contracts with NGM, whereby Samedan and EDC are
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, EDC 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 $14.2 million and $12.0 million for
2000 and 1999, 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 $18.5 million and $17.9 million for 2000 and
1999, respectively, and are valued at the amount which is expected to be
received.
38
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. The swap component
of the contracts discussed in the following paragraphs was treated as a hedge
for accounting purposes only.
The Company had 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 had
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
39
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.
The Company had no oil or gas hedging contracts for future production as of
December 31, 2000.
During 1999 and 1998, 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 2000, NGM had hedging transactions with broker-dealers
that ranged from 423,000 MMBTU to 1,023,000 MMBTU of gas per day. At December
31, 2000, NGM had in place hedges ranging from approximately 20,000 MMBTU to
1,133,000 MMBTU of gas per day for January 2001 to May 2006 for future physical
transactions.
In 1999, NGM had hedging transactions with broker-dealers that ranged from
146,000 MMBTU to 815,000 MMBTU of gas per day. During 1998, NGM had hedging
transactions with broker-dealers that ranged from 508,811 MMBTU to 1,061,536
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 $200,000 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 accounts
for its interest in AMCCO using the equity method within the Company's
wholly-owned subsidiary, Samedan of North Africa, Inc. Samedan is participating
with a 50 percent expense interest (45 percent ownership net of a five percent
government carried interest) to construct a methanol plant in Equatorial Guinea.
RECLASSIFICATION
Certain reclassifications have been made to the 1999 and 1998 consolidated
financial statements to conform to the 2000 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 establishes
40
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 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.
Due to the issuance of SFAS No. 137, which deferred the effective date of SFAS
No. 133, the Company is required to adopt the statement for fiscal years
beginning after June 15, 2000. A company may also implement the statement as of
the beginning of any fiscal quarter after the statement's issuance (that is,
fiscal quarters beginning June 16, 1998, and thereafter). SFAS No. 133 must be
applied to (a) derivative instruments and (b) certain derivative instruments
embedded in hybrid contracts that were issued, acquired, or substantively
modified after December 31, 1997 (and, at the Company's election, before January
1, 1998).
During 2000, the FASB issued SFAS No. 138 which amends the accounting and
reporting standards of SFAS No. 133 for certain derivative instruments and
certain hedging activities and should be adopted concurrently with SFAS No. 133,
according to its provisions and the issuance of SFAS No. 137. The normal
purchases and normal sales exception may be applied to contracts that implicitly
or explicitly permit net settlement and contracts that have a market mechanism
to facilitate net settlement. The Company adopted SFAS Nos. 133 and 138
effective January 1, 2001. The adoption of these FASB's did not have a 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 pursuant to the requirements of SFAS No.
107, "Disclosures about Fair Value 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.
41
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:
2000 1999
---------------------------- ---------------------------
CARRYING FAIR CARRYING FAIR
(IN THOUSANDS) AMOUNT VALUE AMOUNT VALUE
- --------------------------------------------------------------------------------------------------------------------
Cash and short-term investments $ 23,152 $ 23,152 $ 2,925 $ 2,925
Long-term debt (including current portion) $ 525,494 $ 539,375 $ 445,319 $ 407,500
Oil hedge agreements $ $ $ $ (7,879)
NOTE 3 - DEBT
A summary of debt at December 31 follows:
(IN THOUSANDS) 2000 1999
- --------------------------------------------------------------------------------------------------------------------
$300 million Credit Agreement $ 80,000 $
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 530,000 450,000
- --------------------------------------------------------------------------------------------------------------------
Less: unamortized discount 4,506 4,681
- --------------------------------------------------------------------------------------------------------------------
Long-term debt $ 525,494 $ 445,319
- --------------------------------------------------------------------------------------------------------------------
The Company's total long-term debt, net of unamortized discount, at December 31,
2000, was $525 million compared to $445 million at December 31, 1999. The ratio
of debt to book capital (defined as the Company's debt plus its equity) was 38
percent at December 31, 2000, compared with 39 percent at December 31, 1999.
The Company's long-term debt 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 and the outstanding balance of $80 million on a $300 million
credit facility. Other than the $80 million due on the credit facility, there is
no principal payment due on long term debt during the next five years.
The Company has a $300 million credit facility which exposes the Company to the
risk of earnings or cash flow loss due to changes in market interest rates. At
December 31, 2000, there was $80 million borrowed against the credit facility
which has a maturity date of December 24, 2002. The interest rate is based upon
a Eurodollar rate plus a range of 17.5 to 50 basis points. At year-end 1999, the
Company had no borrowing outstanding on this facility.
On June 17, 1999, the Company entered into a new $100 million 364 day credit
agreement with certain commercial lending institutions. This agreement, which
is based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon
the percentage of utilization, expired in 2000 without ever having been
utilized.
42
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) 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
Statutory rate (benefit) 35.0 35.0 (35.0)
Effect of:
State taxes, net of federal benefit .3 (.2)
Difference between U.S. and foreign rates .2 3.1 1.3
Other, net .5 (1.8) .4
- ---------------------------------------------------------------------------------------------------------------------
Effective rate 36.0 36.3 (33.5)
- ---------------------------------------------------------------------------------------------------------------------
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) 2000 1999
- ---------------------------------------------------------------------------------------------------------------------
U.S. and State Current Deferred Tax Assets:
Accrued expenses $ 1,061 $ 525
Deferred income (186) 36
Allowance for doubtful accounts 225 284
Other (21) 14
- ---------------------------------------------------------------------------------------------------------------------
Net current deferred tax asset 1,079 859
- ---------------------------------------------------------------------------------------------------------------------
U.S. and State Non-current Deferred Tax Liabilities:
Property, plant and equipment, principally due to
differences in depreciation, amortization, lease
impairment and abandonments (121,799) (84,969)
Accrued expenses 9,309 8,041
Deferred income 3,303 2,748
Allowance for doubtful accounts 5,779 4,865
Income tax accruals 9,579 9,244
Other 2,962 2,552
- ---------------------------------------------------------------------------------------------------------------------
Net non-current deferred liability (90,867) (57,519)
- ---------------------------------------------------------------------------------------------------------------------
U.S. and state net deferred tax liability (89,788) (56,660)
- ---------------------------------------------------------------------------------------------------------------------
Foreign Deferred Tax Liabilities:
Property, plant and equipment of
foreign operations (26,181) (25,556)
- ---------------------------------------------------------------------------------------------------------------------
Deferred tax liability (26,181) (25,556)
- ---------------------------------------------------------------------------------------------------------------------
Total net deferred tax liability $ (115,969) $ (82,216)
- ---------------------------------------------------------------------------------------------------------------------
The components of income from operations before income taxes for each year are
as follows:
(IN THOUSANDS) 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
Domestic $268,489 $83,439 $(225,692)
Foreign 30,994 (5,808) (21,016)
- ---------------------------------------------------------------------------------------------------------------------
Total $299,483 $77,631 $(246,708)
- ---------------------------------------------------------------------------------------------------------------------
43
The income tax provision (benefit) relating to operations for each year consists
of the following:
(IN THOUSANDS) 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
U.S. current $ 65,358 $18,963 $(20,842)
U.S. deferred 32,311 7,150 (62,366)
State current 917 313 236
State deferred 334 (313) (1,080)
Foreign current 8,341 5,232 927
Foreign deferred 625 (3,175) 442
- ---------------------------------------------------------------------------------------------------------------------
Total $107,886 $28,170 $(82,683)
- ---------------------------------------------------------------------------------------------------------------------
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 25.
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 and is recorded in selling, general and administrative expense in the
accompanying Consolidated Statement of Operations.
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, 2000, the
Company had reserved 5,799,221 shares of common stock for issuance, including
2,353,006 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. At December 31,
2000, the Company had reserved 399,000 shares of common stock for issuance,
including 165,500 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.
44
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, 1997 2,205,335 $ 11.63-$40.38
- ---------------------------------------------------------------------------------------------------------------------
Granted 722,604 $ 35.94-$37.75
Exercised (82,470) $ 11.63-$40.38
Canceled (28,227) $ 24.25-$40.38
- ---------------------------------------------------------------------------------------------------------------------
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
- ---------------------------------------------------------------------------------------------------------------------
EXERCISABLE AT DECEMBER 31, 2000 2,404,760 $ 13.50-$40.38
- ---------------------------------------------------------------------------------------------------------------------
The SFAS No. 123 method of accounting is 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 2000, 1999 and 1998, respectively, as follows:
(AMOUNTS EXPRESSED IN PERCENTAGES) 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
Interest rate 6.25 5.50 5.75
Dividend yield .40 .40 .40
Expected volatility 51.67 42.95 32.66
Expected life 9.71 8.80 9.74
The weighted average fair value of options granted using the Black-Scholes
option pricing model for 2000, 1999 and 1998, respectively, is as follows:
2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
Black-Scholes model weighted average fair value
option price $16.66 $10.01 $19.02
The Company applies APB Opinion No. 25 in accounting for its fixed price stock
options. 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. 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
consistent with SFAS No. 123, "Accounting for Stock-Based Compensation."
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS) 2000 1999 1998
- ---------------------------------------------------------------------------------------------------------------------
Net Income:
As Reported $ 191,597 $49,461 $ (164,025)
Pro Forma $ 183,427 $41,176 $ (171,741)
Basic Earnings Per Share:
As Reported $ 3.42 $ .87 $ (2.88)
Pro Forma $ 3.28 $ .72 $ (3.02)
Diluted Earnings Per Share:
As Reported $ 3.38 $ .86 $ (2.88)
Pro Forma $ 3.23 $ .72 $ (3.02)
45
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 SFAS No. 132, "Employers' Disclosures About Pension and
Other Postretirement Benefits," disclosures at December 31:
PENSION BENEFITS OTHER BENEFITS
----------------------------- ----------------------------
(IN THOUSANDS) 2000 1999 2000 1999
- --------------------------------------------------------------------------------------------------------------------
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year $ 64,194 $ 82,823 $ 2,738 $ 3,187
Service cost 3,566 3,802 231 294
Interest cost 5,525 4,720 187 187
Plan participants' contributions 42 38
Amendments (363)
Actuarial (gain) loss 6,423 (24,294) (328) (533)
Benefit paid (3,085) (2,857) (152) (72)
- --------------------------------------------------------------------------------------------------------------------
Benefit obligation at year end $ 76,623 $ 64,194 $ 2,718 $ 2,738
- --------------------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year $ 59,168 $ 60,559 $ $
Actual return on plan assets (992) 1,083
Employer contribution 396 383 152 72
Benefit paid (3,085) (2,857) (152) (72)
- --------------------------------------------------------------------------------------------------------------------
Fair value of plan at end of year $ 55,487 $ 59,168 $ $
- --------------------------------------------------------------------------------------------------------------------
Fund status $ (21,136) $ (5,026) $ (2,718) $ (2,738)
Unrecognized net actuarial loss (gain) (6,560) (18,989) 19 222
Unrecognized prior service cost 2,743 3,035 (304) (334)
Unrecognized net transition obligation (assets) 1,214 1,239
- --------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit costs $ (23,739) $ (19,741) $ (3,003) $ (2,850)
- --------------------------------------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost $ 3,567 $ 3,802 $ 231 $ 294
Interest cost 5,525 4,720 188 188
Expected return on plan assets (4,666) (4,264)
Transition (assets) obligation recognition 24 24
Amortization of prior service cost 291 291 (30) (30)
Recognized net actuarial loss (347) 35 (11) 34
- --------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost $ 4,394 $ 4,608 $ 378 $ 486
- --------------------------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31,
Discount rate 8.00% 8.00% 8.00% 8.00%
Expected return on plan assets 8.50% 8.50%
Rate of compensation increase 5.50% 5.50% 5.50% 5.50%
46
The following table reflects the aggregate pension obligation components
required by SFAS No. 132 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) 2000 1999 2000 1999
- --------------------------------------------------------------------------------------------------------------------
AGGREGATED PENSION BENEFITS
Aggregate fair value of plan assets $ 55,487 $ 59,168 $ $
Aggregate accumulated benefit obligation 61,902 56,092 14,721 8,102
- --------------------------------------------------------------------------------------------------------------------
Fund status of net periodic
benefit assets (obligation) $ (6,415) $ 3,076 $ (14,721) $ (8,102)
- --------------------------------------------------------------------------------------------------------------------
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 $ 472 $ 373
Total postretirement benefit obligation $ 2,628 $2,136
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) 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------
Employers' plan contribution $1,858 $1,823 $1,938
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) 2000 1999
- -------------------------------------------------------------------------------------------------------------------
Allowance for doubtful accounts $ 645 $ 1,237
Other current assets include the following at December 31:
(IN THOUSANDS) 2000 1999
- -------------------------------------------------------------------------------------------------------------------
Deferred tax asset $ 1,079 $ 859
Prepaid federal income taxes $ 56,890 $ 30,000
Other current liabilities include the following at December 31:
(IN THOUSANDS) 2000 1999
- -------------------------------------------------------------------------------------------------------------------
Gas imbalance liabilities $ 1,348 $ 2,604
Note payable unconsolidated subsidiary $ $ 23,245
Accrued interest payable $ 11,949 $ 10,897
Louisiana workers compensation $ 5,387 $ 4,751
Oil and gas operations expense included the following for the years ended
December 31:
(IN THOUSANDS) 2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------
Lease operating expense $ 93,948 $ 107,289 $ 136,155
Workover expense 21,124 5,708 6,518
Production taxes 10,264 6,679 8,436
Other (3,470) (2,978) (2,079)
- --------------------------------------------------------------------------------------------------------------------
Total operations expense $ 121,866 $ 116,698 $ 149,030
- --------------------------------------------------------------------------------------------------------------------
47
Oil and gas exploration expense included the following for the years ended
December 31:
(IN THOUSANDS) 2000 1999 1998
- -------------------------------------------------------------------------------------------------------------------
Dry hole expense $ 38,463 $ 19,204 $ 57,736
Undeveloped lease amortization 16,075 9,645 7,953
Abandoned assets 3,375 2,483 15,325
Seismic 18,738 7,797 15,754
Other 11,592 7,655 13,390
- -------------------------------------------------------------------------------------------------------------------
Total exploration expense $ 88,243 $ 46,784 $ 110,158
- -------------------------------------------------------------------------------------------------------------------
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 - IMPAIRMENT OF LONG-LIVED ASSETS
The Company follows SFAS No. 121 and any assets impaired are oil and gas
properties maintained under the successful efforts method of accounting. The
excess of the net book value over the projected discounted future net revenue of
the impaired properties is charged to "Impairment of Operating Assets." The
Company recorded no asset impairments under SFAS No. 121 during 2000 or 1999. In
December 1998, the Company recorded a $223.3 million pre-tax charge for the
write-down under SFAS No. 121 of properties due to downward reserve revisions.
48
NOTE 9 - UNCONSOLIDATED SUBSIDIARY
The Company has an unconsolidated subsidiary, AMCCO, a 50 percent owned joint
venture that owns an indirect 90 percent interest in AMPCO. The Company accounts
for its interest in AMCCO using the equity method within the Company's
wholly-owned subsidiary, Samedan of North Africa, Inc. Samedan is participating
with a 50 percent expense interest (45 percent ownership net of a five percent
government carried interest) to construct a methanol plant in Equatorial Guinea.
The total projected cost of the plant and supporting facilities is estimated to
be $448 million including various contingencies and capitalized interest, with
the Company responsible for $224 million. 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 Alba field as feedstock. Reserve estimates indicate the
Alba field can deliver sufficient gas for the plant to operate 30 years. The
construction contract stipulates that first production should be achieved by the
second quarter of 2001. Current marketing plans are to use two tankers, which
are under long-term contracts, to transport the methanol to markets in Europe
and the United States. On November 10, 1999, AMCCO issued $125 million of
10.875% Series A-1 Senior Secured 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. The Company has guaranteed the payment of interest
on the Series A-2 Notes. In addition, the Company established a new series of
preferred stock, Series B Mandatory Convertible Preferred Stock, par value $1.00
per share (the "Series B Preferred"). The Company issued, in a private placement
pursuant to Section 4(2) of the Securities Act, 125,000 shares of 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 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 following are summarized financial
statements for AMCCO as of December 31:
CONSOLIDATED BALANCE SHEET
ATLANTIC METHANOL CAPITAL COMPANY
(IN THOUSANDS) 2000 1999
- ---------------------------------------------------------------------------------------------------------------------
ASSETS
Current assets $ 45,676 $ 68,638
Non-current assets 392,272 239,946
- ---------------------------------------------------------------------------------------------------------------------
Total assets $ 437,948 $ 308,584
- ---------------------------------------------------------------------------------------------------------------------
LIABILITIES, MINORITY INTEREST AND MEMBERS' EQUITY
Current liabilities $ 1,197 $ 3,504
Non-current liabilities 250,000 250,000
Minority interest 36,556 22,939
Members' equity 150,195 32,141
- ---------------------------------------------------------------------------------------------------------------------
Total liabilities, minority interest and members' equity $ 437,948 $ 308,584
- ---------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENT OF OPERATIONS
ATLANTIC METHANOL CAPITAL COMPANY
(IN THOUSANDS) 2000 1999
- ---------------------------------------------------------------------------------------------------------------------
Interest income $ 4,389 $ 2,524
Expenses:
Interest (net of amount capitalized) 1,005 1,640
Administrative 86
- ---------------------------------------------------------------------------------------------------------------------
Net income $ 3,298 $ 884
- ---------------------------------------------------------------------------------------------------------------------
49
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 can not 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, 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 RESERVES AS OF:
- -----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1998 1,107,158 5,565 322,205 47,287 1,482,215
Revisions of previous estimates (155,314) 27 396 (1,030) (155,921)
Extensions, discoveries and
other additions 71,061 71,061
Production (196,220) (206) (959) (7,201) (204,586)
Sale of minerals in place (2,232) (2,232)
Purchase of minerals in place 48,769 48,769
- -----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998 873,222 5,386 321,642 39,056 1,239,306
- -----------------------------------------------------------------------------------------------------------------------
PROVED DEVELOPED GAS RESERVES AS OF:
- -----------------------------------------------------------------------------------------------------------------------
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
January 1, 1998 1,022,192 5,565 13,425 47,287 1,088,469
- -----------------
50
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, 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 RESERVES AS OF:
- ------------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1998 89,065 11,997 22,766 7,035 130,863
Revisions of previous estimates (5,935) 16 166 (129) (5,882)
Extensions, discoveries and
other additions 4,802 35 4,837
Production (11,540) (885) (931) (795) (14,151)
Sale of minerals in place (155) (155)
Purchase of minerals in place 1,069 1,069
- ------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998 77,306 11,128 22,001 6,146 116,581
- ------------------------------------------------------------------------------------------------------------------------
PROVED DEVELOPED OIL RESERVES AS OF:
- ------------------------------------------------------------------------------------------------------------------------
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
January 1, 1998 82,713 11,997 12,191 5,234 112,135
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.
51
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, 2000 STATES ARGENTINA ECUADOR GUINEA SEA INT'L TOTAL
- -----------------------------------------------------------------------------------------------------------------------------
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
- -----------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998
- -----------------------------------------------------------------------------------------------------------------------------
Revenues $ 564,771 $ 9,105 $ $ 10,282 $ 25,006 $ $ 609,164
Production costs 154,594 6,274 2,962 9,044 172,874
Exploration expenses 90,614 87 658 5,828 9,987 107,174
DD&A and valuation provision 513,725 6,083 2,998 13,869 46 536,721*
- -----------------------------------------------------------------------------------------------------------------------------
Income (loss) (194,162) (3,339) 3,664 (3,735) (10,033) (207,605)
Income tax expense (benefit) (68,764) (1,822) 1,786 (794) (2,489) (72,083)
- -----------------------------------------------------------------------------------------------------------------------------
Result of operations from pro-
ducing activities (excluding
corporate overhead and interest
costs) $(125,398) $ (1,517) $ $ 1,878 $ (2,941) $ (7,544) $(135,522)
- -----------------------------------------------------------------------------------------------------------------------------
*Includes a pre-tax charge of $223.3 million pursuant to SFAS No. 121.
52
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, 2000 STATES ECUADOR GUINEA ISRAEL SEA INT'L TOTAL
- ---------------------------------------------------------------------------------------------------------------------
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
- ---------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998
- ---------------------------------------------------------------------------------------------------------------------
Property acquisition costs
Proved $ 48,444 $ $ $ $ $ $ 48,444
Unproved 36,760 311 500 37,571
- ---------------------------------------------------------------------------------------------------------------------
Total $ 85,204 $ $ $ $ 311 $ 500 $ 86,015
- ---------------------------------------------------------------------------------------------------------------------
Exploration costs $ 132,958 $ $ 465 $ $ 5,328 $ 10,136 $ 148,887
- ---------------------------------------------------------------------------------------------------------------------
Development costs $ 242,838 $ $ 10,977 $ $ 9,761 $ 18,169 $ 281,745
- ---------------------------------------------------------------------------------------------------------------------
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:
2000 1999
-------------------------------------- ----------------------------------------
(IN THOUSANDS) U. S. INT'L TOTAL U. S. INT'L TOTAL
- ---------------------------------------------------------------------------------------------------------------------
Unproved oil and gas properties $ 80,750 $ 69,462 $ 150,212 $ 79,823 $ 13,288 $ 93,111
Proved oil and gas properties 2,598,115 464,896 3,063,011 2,389,937 303,800 2,693,737
- ---------------------------------------------------------------------------------------------------------------------
2,678,865 534,358 3,213,223 2,469,760 317,088 2,786,848
Accumulated DD&A (1,637,659) (107,534) (1,745,193) (1,471,889) (88,154) (1,560,043)
- ---------------------------------------------------------------------------------------------------------------------
Net capitalized costs $ 1,041,206 $ 426,824 $ 1,468,030 $ 997,871 $ 228,934 $ 1,226,805
- ---------------------------------------------------------------------------------------------------------------------
53
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, 2000, 1999 and 1998 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, 2000 STATES ECUADOR GUINEA ISRAEL SEA INT'L TOTAL
- ---------------------------------------------------------------------------------------------------------------------
(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
- ---------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998
- ---------------------------------------------------------------------------------------------------------------------
(IN MILLIONS OF DOLLARS)
Future cash inflows $ 2,647 $ $ 301 $ $ 113 $ 96 $ 3,157
Future production and
development costs 1,146 140 62 30 1,378
Future income tax expenses 182 19 6 8 215
- ---------------------------------------------------------------------------------------------------------------------
Future net cash flows 1,319 142 45 58 1,564
10% annual discount for
estimated timing of cash flows 490 53 17 22 582
- ---------------------------------------------------------------------------------------------------------------------
Standardized measure of
discounted future net
cash flows $ 829 $ $ 89 $ $ 28 $ 36 $ 982
- ---------------------------------------------------------------------------------------------------------------------
Construction of AMPCO's Equatorial Guinea methanol plant is scheduled to be
completed in the second quarter of 2001. The future net cash inflows for 1998,
1999 and 2000 do not include cash flows relating to the Company's anticipated
future methanol sales. For more information regarding Samedan's methanol plant,
see Item 1. "Business--Unconsolidated Subsidiary" and Item 2. "Properties--Oil
and Gas" of this Form 10-K.
54
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 $26.83 per BBL, which was adjusted by
differentials applied on a property-by-property basis to yield a weighted
average price of $24.27 per BBL. The West Texas intermediate crude oil price, as
of February 28, 2001, was $27.38 per BBL, an increase of $.55 per BBL compared
to year-end 2000. 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 $76 million.
The year-end Henry Hub natural gas price utilized in the computation of future
cash inflows was $10.53 per MCF, which was adjusted by differentials applied on
a property-by-property basis to yield a weighted average price of $9.14 per MCF.
As of February 28, 2001, natural gas index prices at Henry Hub had decreased
approximately $5.36 per MCF to $5.17 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 $45 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, 2000, the Company had estimated gas imbalance receivables of
$18.5 million and estimated gas imbalance liabilities of $14.2 million; at
year-end 1999, $17.9 million in receivables and $12.0 million in liabilities;
and at year-end 1998, $19.1 million in receivables and $14.8 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, 2000, 1999 and 1998.
55
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) 2000 1999 1998
- --------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows at the beginning
of the year $ 1,493 $ 982 $ 1,352
Extensions, discoveries and improved
recovery, less related costs 1,462 410 39
Revisions of previous quantity estimates (20) 89 (132)
Changes in estimated future
development costs (52) (202) (17)
Purchases (sales) of minerals in place 69 (58) 46
Net changes in prices and production costs 2,448 673 (443)
Accretion of discount 185 102 189
Sales of oil and gas produced, net of
production costs (662) (425) (454)
Development costs incurred during
the period 172 21 127
Net change in income taxes (1,207) (317) 503
Change in timing of estimated future
production, and other 186 218 (228)
- --------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
future net cash flows at the end
of the year $ 4,074 $1,493 $ 982
- --------------------------------------------------------------------------------------------------------------------
INTERIM FINANCIAL INFORMATION (Unaudited)
Interim financial information for the years ended December 31, 2000 and 1999 is
as follows:
QUARTER ENDED
---------------------------------------------------------------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS) MAR. 31, JUNE 30, SEPT. 30, DEC. 31,
- -------------------------------------------------------------------------------------------------------------------
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
1999
Revenues $ 175,865 $ 216,245 $ 241,971 $ 252,698
Gross profit from operations $ 128 $ 22,959 $ 41,453 $ 38,087
Net income (loss) $ (8,901) $ 9,179 $ 27,654 $ 21,529
Basic earnings per share $ (.16) $ .16 $ .49 $ .38
Diluted earnings per share $ (.16) $ .16 $ .48 $ .38
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
Not applicable.
56
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 2001 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 2001 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 2001 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 2001 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 2001 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 2000.
57
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 12, 2001 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/ Robert Kelley Chairman of the Board March 12, 2001
- ------------------------------------
Robert Kelley
/s/ Charles D. Davidson President, Chief Executive Officer March 12, 2001
- ------------------------------------ and Director (Principal Executive
Charles D. Davidson Officer)
/s/ James L. McElvany Vice President-Finance and Treasurer March 12, 2001
- ------------------------------------ (Principal Financial and Accounting
James L. McElvany Officer)
/s/ Alan A. Baker Director March 12, 2001
- ------------------------------------
Alan A. Baker
/s/ Michael A. Cawley Director March 12, 2001
- ------------------------------------
Michael A. Cawley
/s/ Edward F. Cox Director March 12, 2001
- ------------------------------------
Edward F. Cox
/s/ Thomas E. Hassen Director March 12, 2001
- ------------------------------------
Thomas E. Hassen
/s/ Dale P. Jones Director March 12, 2001
- ------------------------------------
Dale P. Jones
/s/ Harold F. Kleinman Director March 12, 2001
- ------------------------------------
Harold F. Kleinman
/s/ T. Don Stacy Director March 12, 2001
- ------------------------------------
T. Don Stacy
58
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.
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).
59
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 January 30, 1996
(filed as Exhibit 10.13 to the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1996 and incorporated herein by reference).
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).
60
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.
21 -- Subsidiaries.
23 -- Consent of Arthur Andersen LLP for inclusion of their report in this
Form 10-K.
* 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.
61
DIRECTORS
ROBERT KELLEY
CHAIRMAN OF THE BOARD,
NOBLE AFFILIATES, INC.
CHARLES D. DAVIDSON
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
THOMAS E. HASSEN
MANAGING DIRECTOR, CO-HEAD
GLOBAL ENERGY RESOURCES GROUP,
CREDIT SUISSE FIRST BOSTON CORPORATION
DALE P. JONES
CONSULTANT AND FORMER VICE CHAIRMAN AND
PRESIDENT, HALLIBURTON COMPANY
HAROLD F. KLEINMAN
OF COUNSEL, LAW FIRM OF
THOMPSON & KNIGHT L.L.P.
T. DON STACY
FORMER CHAIRMAN AND
PRESIDENT, AMOCO EURASIA PETROLEUM CO.
DIRECTORS EMERITI
GEORGE J. MCLEOD
JOHN F. SNODGRASS
JACK D. WILKES
EXECUTIVE OFFICERS
ROBERT KELLEY
CHAIRMAN OF THE BOARD,
NOBLE AFFILIATES, INC.
CHARLES D. DAVIDSON
PRESIDENT AND CHIEF EXECUTIVE OFFICER,
NOBLE AFFILIATES, INC.
ALAN R. BULLINGTON
VICE PRESIDENT AND GENERAL MANAGER,
INTERNATIONAL DIVISION OF SAMEDAN OIL CORPORATION
ROBERT K. BURLESON
PRESIDENT,
NOBLE GAS MARKETING, INC.
DAN O. DINGES
SENIOR VICE PRESIDENT AND GENERAL MANAGER,
OFFSHORE DIVISION OF SAMEDAN OIL CORPORATION
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 AND GENERAL MANAGER,
ONSHORE DIVISION OF SAMEDAN OIL CORPORATION
W. A. POILLION
SENIOR VICE PRESIDENT-PRODUCTION AND DRILLING,
SAMEDAN OIL CORPORATION
KENNETH P. WILEY
VICE PRESIDENT-INFORMATION SYSTEMS,
NOBLE AFFILIATES, INC.
62
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@SAMEDAN.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.
110 WEST BROADWAY
POST OFFICE BOX 909
ARDMORE, OKLAHOMA 73402
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 CHICAGO TRUST COMPANY OF NEW YORK
A DIVISION OF EQUISERVE
POST OFFICE BOX 2500
JERSEY CITY, NEW JERSEY 07303
(800) 317-4445
WWW.EQUISERVE.COM
HEARING IMPAIRED (201) 222-4955
COMMON STOCK LISTED
NEW YORK STOCK EXCHANGE
SYMBOL - NBL
- -------------------------------------------------------------------------------
ANNUAL MEETING
The Annual Meeting of Stockholders of Noble Affiliates, will be held on
Tuesday, April 24, 2001, 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, 2000,
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 Excange Commission's
Internet website: http://www.sec.gov.
- -------------------------------------------------------------------------------