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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.
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TABLE OF CONTENTS
PART I.
Item 1. Business.................................................................................... 1
General..................................................................................... 3
Oil and Gas................................................................................. 3
Exploration Activities.................................................................. 4
Production Activities .................................................................. 5
Acquisitions of Oil and Gas Properties, Leases and Concessions.......................... 6
Marketing............................................................................... 6
Regulations and Risks................................................................... 7
Competition............................................................................. 8
Unconsolidated Subsidiary................................................................... 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
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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
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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 th