<PAGE>

================================================================================

                                  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.

================================================================================


<PAGE>


                                TABLE OF CONTENTS


                                     PART I.


<TABLE>

<S>                                                                                                     <C>

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
</TABLE>


                                      ii

<PAGE>



                                     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

<PAGE>


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

<PAGE>


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

<PAGE>


Argentina, China, Ecuador, Equatorial Guinea, the Mediterranean Sea, the North
Sea, and Vietnam. For more information regarding Samedan's oil and gas
properties, see "Item 2. Properties--Oil and Gas" of this Form 10-K.

EXPLORATION ACTIVITIES

DOMESTIC OFFSHORE. Samedan has been actively engaged in exploration,
exploitation and development of oil and gas properties in the Gulf of Mexico
(offshore Texas, Louisiana, Mississippi and Alabama) and offshore California
since 1968. Generally, offshore properties are characterized by prolific
reservoirs with high production rates, which therefore tend to deplete more
rapidly than the Company's onshore properties. The Company's current offshore
production is derived from 232 wells operated by Samedan and 279 wells operated
by others. During the past 32 years, Samedan has drilled or participated in the
drilling of 992 gross wells offshore. At December 31, 2000, the Company held
offshore federal leases covering 1,037,827 gross developed acres and 793,507
gross undeveloped acres on which the Company currently intends to conduct future
exploration activities. For more information, see "Item 2. Properties--Oil and
Gas" of this Form 10-K.

DOMESTIC ONSHORE. Samedan has been actively engaged in exploration, exploitation
and development of oil and gas properties in three regions since the 1930's. The
Gulf Coast Region covers onshore Louisiana, New Mexico and Texas. Properties in
the Gulf Coast Region are characterized by gas reservoirs with strong production
rates and oil fields with primary and secondary recovery operations that tend to
deplete more gradually than the Company's offshore properties. The Mid-Continent
Region covers Oklahoma and Southern Kansas. Properties in the Mid-Continent
Region tend to be characterized by stable oil and gas production from primary
and secondary recovery operations and the reservoirs tend to produce for longer
periods compared to the Company's offshore properties. The Rocky Mountain Region
covers Colorado, Montana, North Dakota, Wyoming and California. Reservoirs in
the Rocky Mountain Region are primarily characterized by oil and gas production
from primary and secondary recovery operations.

Samedan's current onshore production is derived from 1,494 wells operated by
Samedan and 1,380 wells operated by others. At December 31, 2000, the Company
held 604,902 gross developed acres and 289,527 gross undeveloped acres onshore
on which the Company may conduct future exploration activities. For more
information, see "Item 2. Properties--Oil and Gas" of this Form 10-K.

ARGENTINA. Samedan, through its subsidiary EDC Argentina, Inc., has been
actively engaged in exploration, exploitation and development of oil and gas
properties in Argentina since 1996. The Company's producing properties are
located in southern Argentina in the El Tordillo field, which is characterized
by secondary recovery oil production from a 10,000 acre reservoir. At December
31, 2000, the Company held 28,988 gross developed acres and 1,235,105 gross
undeveloped acres in Argentina on which the Company may conduct future
exploration activities. For more information, see "Item 2. Properties--Oil and
Gas" of this Form 10-K.

CHINA. Samedan, through its subsidiary EDC China, Inc., has been actively
engaged in exploration, exploitation and development of oil and gas properties
in China since 1996. The Company has two concessions in South Bohai Bay,
offshore China. These concessions, Cheng Dao Xi and Cheng Zi Kou, are contiguous
and adjoin non-owned production in the southern portion of Bohai Bay. At
December 31, 2000, the Company held 7,413 gross developed acres and 200,032
gross undeveloped acres in China on which the Company may conduct future
exploration activities. For more information, see "Item 2. Properties--Oil and
Gas" of this Form 10-K.

ECUADOR. Samedan, through its subsidiary EDC Ecuador Ltd., has been actively
engaged in exploration, exploitation and development of oil and gas properties
in Ecuador since 1996. The Company's objective in Ecuador is to develop the gas
market for the Amistad gas field (offshore Ecuador) which was discovered in the
late 1970's. The concession covers 12,355 gross developed acres and 851,771
gross undeveloped acres encompassing the Amistad field. For more information,
see "Item 2. Properties--Oil and Gas" of this Form 10-K.

EQUATORIAL GUINEA. Samedan has been actively engaged in exploration,
exploitation and development of oil and gas properties offshore Equatorial
Guinea (West Africa) since 1990. The primary offshore Equatorial Guinea


                                       4

<PAGE>


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:


<TABLE>
<CAPTION>
                                                   2000                       1999                       1998      
                                            -----------------------------------------------------------------------
(IN PERCENTAGES)                              OIL          GAS          OIL          GAS          OIL           GAS
-------------------------------------------------------------------------------------------------------------------
<S>                                          <C>          <C>          <C>          <C>          <C>           <C>
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
</TABLE>


NET PRODUCTION.  The following table sets forth Samedan's net oil and 
natural gas production including royalty, for the three years ended 
December 31:


<TABLE>
<CAPTION>
                                                                            2000             1999              1998
-------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>              <C>               <C>
Oil Production
   (million BBLS)                                                            9.4             11.0              13.6
Gas Production
   (BCF)                                                                   148.7            166.1             206.8
</TABLE>


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:


<TABLE>
<CAPTION>
                                                                            2000            1999             1998
-----------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>              <C>               <C>
Total Oil Equivalents
   (million BOE)                                                            34.2             38.6              48.1
Total Gas Equivalents
   (BCFe)                                                                  205.4            231.8             288.3
</TABLE>



                                       5


<PAGE>

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

<PAGE>


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

<PAGE>


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

<PAGE>


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.


I
TEM 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

<PAGE>


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

<PAGE>


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

<PAGE>


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.


<TABLE>
<CAPTION>
                              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
------------------------------------------------------------------------------------------------------------------- 
<S>              <C>           <C>          <C>          <C>         <C>           <C>          <C>           <C>   
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
</TABLE>


----------
     (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


<PAGE>



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:


<TABLE>
<CAPTION>

                                                2000(1)(3)                1999(1)(2)(3)              1998(1)(3)    
                                        ---------------------------------------------------------------------------
                                            GROSS          NET        GROSS          NET        GROSS           NET
-------------------------------------------------------------------------------------------------------------------
<S>                                     <C>            <C>          <C>          <C>          <C>           <C>
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
-------------------------------------------------------------------------------------------------------------------
</TABLE>


    (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.


<TABLE>
<CAPTION>
                                                    2000                      1999                      1998       
                                          -------------------------------------------------------------------------
                                            GROSS          NET        GROSS          NET        GROSS           NET
-------------------------------------------------------------------------------------------------------------------
<S>                                       <C>            <C>          <C>          <C>        <C>             <C>

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
</TABLE>


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

<PAGE>



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.


<TABLE>
<CAPTION>
                                                                                    YEAR ENDED DECEMBER 31,        
                                                                         ------------------------------------------
                                                                            2000             1999         1998     
-------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>               <C>              <C>
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
</TABLE>


      (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

<PAGE>


                      [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

<PAGE>


The developed and undeveloped acreage (including both leases and concessions)
that Samedan held as of December 31, 2000, is as follows:


<TABLE>
<CAPTION>

                                                      DEVELOPED ACREAGE (1)(2)         UNDEVELOPED ACREAGE (2)(3)  
                                                   -----------------------------      -----------------------------
LOCATION                                           GROSS ACRES        NET ACRES       GROSS ACRES         NET ACRES
-------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>                 <C>            <C>
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
-------------------------------------------------------------------------------------------------------------------
</TABLE>


    (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

<PAGE>


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.



<TABLE>
<CAPTION>

  Name                         Age                                   Position
----------------------------------------------------------------------------------------------------------------
<S>                            <C>          <C>
  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

</TABLE>


---------------

    (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


<PAGE>

    (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


<PAGE>


                                     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.



<TABLE>
<CAPTION>

                                                                                                                 DIVIDENDS
                                                                                     HIGH             LOW        PER SHARE  
--------------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>             <C>         <C>
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     
                                                                                                                   
                                                                                                                  

</TABLE>


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.



<TABLE>
<CAPTION>

                                                                                                               SHARES
DECEMBER 31, 2000                                                                                         OUTSTANDING
---------------------------------------------------------------------------------------------------------------------
<S>                                                                                                       <C>
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
---------------------------------------------------------------------------------------------------------------------

</TABLE>


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


<PAGE>

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


<PAGE>


ITEM 6.       SELECTED FINANCIAL DATA.



<TABLE>
<CAPTION>

                                                                               YEAR ENDED DECEMBER 31,                     
---------------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)              2000         1999         1998          1997         1996 
---------------------------------------------------------------------------------------------------------------------------
<S>                                                        <C>          <C>          <C>           <C>          <C>
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 
---------------------------------------------------------------------------------------------------------------------------
                                                                                                                               
</TABLE>


For additional information, see "Item 8. Financial Statements and Supplementary
Data" of this Form 10-K.

OPERATING STATISTICS                               



<TABLE>
<CAPTION>

                                                                               YEAR ENDED DECEMBER 31,                             
---------------------------------------------------------------------------------------------------------------------------------
                                                                 2000          1999            1998          1997           1996 
---------------------------------------------------------------------------------------------------------------------------------
<S>                                                           <C>         <C>             <C>            <C>           <C>
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
                                                                                                                                   
                                                                

</TABLE>



                                                          21

<PAGE>


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


<PAGE>

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


<PAGE>

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.



<TABLE>
<CAPTION>

                                                                             2000             1999              1998
--------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>              <C>               <C>
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
--------------------------------------------------------------------------------------------------------------------

</TABLE>


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


<PAGE>
<PAGE>

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.



<TABLE>
<CAPTION>

                                                                             2000             1999              1998
--------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>              <C>               <C>
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
--------------------------------------------------------------------------------------------------------------------

</TABLE>


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


<PAGE>

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.



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                               2000             1999              1998
--------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>              <C>              <C>
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
--------------------------------------------------------------------------------------------------------------------

</TABLE>


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


<PAGE>

The gathering, marketing and processing revenues less expenses for both NGM and
NTI are reflected in the table below.



<TABLE>
<CAPTION>

                                           2000                          1999                          1998           
(IN THOUSANDS)                ----------------------------  ---------------------------  ----------------------------
(AMOUNTS INCLUDE INTER-
COMPANY ELIMINATIONS)                  NTI             NGM           NTI            NGM           NTI             NGM
---------------------------------------------------------------------------------------------------------------------
<S>                           <C>               <C>         <C>              <C>         <C>               <C>
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
---------------------------------------------------------------------------------------------------------------------

</TABLE>


The margins for NGM on a per MMBTU basis were $.027 for 2000, $.026 for 1999 and
$.049 for 1998. The increase in NGM's margin on a per MMBTU basis for 2000
compared to 1999, was due to the improvement in gas prices. The decrease in
NGM's margin on a per MMBTU basis for 1999 compared to 1998, was due primarily
to increased transportation expense. The margins for NTI on a per BBL basis were
$1.28 for 2000, $.87 for 1999 and $.63 for 1998. The increase in NTI's margin on
a per BBL basis for each of the years presented was due primarily to improved
crude oil prices coupled with lower transportation costs.

FUTURE TRENDS

The Company expects increased oil and gas production in 2001 and 2002 compared
to 2000. The increase in 2001 would be primarily due to the Cook and Hanze
acquisitions, as well as the completion of the Alba field expansion and the
startup of the methanol plant, which would utilize gas feedstock from the Alba
field. The Amistad gas field development and Machala power project are expected
to be completed and contributing to cash flow and gas production in 2002. The
China field development is also projected to be completed with first oil
production expected in 2002.

The Company recently set its 2001 exploration and development budget at
approximately $700 million. Such expenditures are planned to be funded through
internally generated cash flows. The Company believes that it has the capital
structure to take advantage of strategic acquisitions, as they become available,
through internally generated cash flows or borrowings.

Management believes that the Company is well positioned with its balanced
reserves of oil and gas and downstream projects. The uncertainty of commodity
prices continues to affect the oil, gas and methanol industries. The Company can
not predict the extent to which its revenues will be affected by inflation,
government regulation or changing prices.


I
TEM 7a.      QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

The Company is exposed to market risk in the normal course of its business
operations. Management believes that the Company is well positioned with its mix
of oil and gas reserves to take advantage of future price increases that may
occur. However, the uncertainty of oil and gas prices continues to impact the
domestic oil and gas industry. Due to the volatility of oil and gas prices, the
Company, from time to time, has used derivative hedging and may do so in the
future as a means of controlling its exposure to price changes. The swap
component of the contracts discussed in the following paragraphs was treated as
a hedge for accounting purposes only.

The Company had entered into three crude oil premium swap contracts related to
its production for calendar year 2000. Two of the contracts provided for
payments based on daily NYMEX settlement prices. These contracts related to
2,500 BBLS per day and 2,000 BBLS per day and had trigger prices of $21.73 per
BBL and $22.45 per BBL, respectively, and both had knockout prices of $17.00 per
BBL. These two contracts entitled the Company to receive settlements from the
counterparties in amounts, if any, by which the settlement price for each NYMEX
trading day was less than the trigger price, provided the NYMEX price was also
greater than the $17.00 per BBL knockout price. If a daily settlement price 
was $17.00 per BBL or less, then neither party had any liability to the other 
for that day. If a


                                      27


<PAGE>

daily settlement price was above the applicable trigger price, then the 
Company would owe the counterparty for the excess of the settlement price 
over the trigger price for that day. Payment was made monthly under each of 
these contracts, in an amount equal to the net amount due to either party 
based on the sum of the daily amounts determined as described in this 
paragraph for that month.

The third contract related to 2,500 BBLS per day and provided for payments based
on monthly average NYMEX settlement prices. The contract entitled the Company to
receive monthly settlements from the counterparty in an amount, if any, by which
the arithmetic average of the daily NYMEX settlement prices for the month was
less than the trigger price, which was $21.73 per BBL, multiplied by the number
of days in the month, provided such average NYMEX price was also greater than
the $17.00 per BBL knockout price. If the average NYMEX settlement price for the
month was $17.00 per BBL or less, then neither party would have any liability to
the other for that month. If the average NYMEX settlement price for the month
was above the trigger price, then the Company would pay the counterparty an
amount equal to the excess of the average settlement price over the trigger
price, multiplied by the number of days in the month.

The net effect of these premium swap contracts was a $2.87 per BBL reduction in
the average crude oil price realized by the Company in 2000.

The Company has treated the swap component of these contracts as a hedge (for
accounting purposes only), at swap prices ranging from $19.40 per BBL to $20.20
per BBL, which existed at the dates it entered into these contracts. In
addition, the Company has separately accounted for the premium component of
these contracts by marking them to market, resulting in a gain of $2,921,000
recorded in other income for the year ended December 31, 2000.

In addition to the premium swap crude oil hedging contracts, the Company had
entered into crude oil costless collar hedges from January 1, 2000 to April 30,
2000 for volumes of 2,000 BBLS per day. These costless collars had a floor price
ranging from $21.53 per BBL to $23.27 per BBL and a cap price ranging from
$25.83 per BBL to $27.31 per BBL. These costless collar contracts entitled the
Company to receive settlements from the counterparties in amounts, if any, by
which the monthly average settlement price for each NYMEX trading day during a
contract month was less than the floor price. If the monthly average settlement
price was above the applicable cap price, then the Company would owe the
counterparties for the excess of the monthly average settlement price over the
applicable cap price. If the monthly average settlement price fell between the
applicable floor and cap price, then neither party would have any liability to
the other party for that month. Payment, if any, was made monthly under each of
the contracts in an amount equal to the net amount due either party based on the
volumes per day multiplied by the difference between the NYMEX average price and
the cap, if the NYMEX average price exceeded the cap price, or if the NYMEX
average price was less than the floor price, then the volumes per day multiplied
by the difference between the floor price and the NYMEX average price.

The net effect of these costless collar hedges was a $.05 per BBL reduction in
the average crude oil price realized by the Company in 2000.

The Company had no oil or gas hedging contracts for future production as of
December 31, 2000.

During 1999 and 1998, the Company had no oil or gas hedging transactions for its
production.

NGM, from time to time, employs hedging arrangements in connection with its
purchases and sales of production. While most of NGM's purchases are made for an
index-based price, NGM's customers often require prices that are either fixed or
related to NYMEX. In order to establish a fixed margin and mitigate the risk of
price volatility, NGM may convert a fixed or NYMEX sale to an index-based sales
price (such as by purchasing an index-based futures contract obligating NGM for
delivery of production). Due to the size of such transactions and certain
restraints imposed by contract and by Company guidelines, as of December 31,
2000, the Company had no material market risk exposure from NGM's hedging
activity.

                                      28


<PAGE>

The Company has a $300 million credit agreement (see Note 3 - Debt, to the
Consolidated Financial Statements) which exposes the Company to the risk of
earnings or cash flow loss due to changes in market interest rates. At December
31, 2000, there was $80 million borrowed against the credit facility which has a
maturity date of December 24, 2002. The interest rate is based upon a Eurodollar
rate plus a range of 17.5 to 50 basis points. All other Company long-term debt
is fixed-rate and, therefore, does not expose the Company to the risk of
earnings or cash flow loss due to changes in market interest rates.

On June 17, 1999, the Company entered into a new $100 million 364 day credit
agreement with certain commercial lending institutions. This agreement, which is
based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon the
percentage of utilization, expired in 2000 without ever having been utilized.

The Company does not invest in foreign currency derivatives. The U.S. dollar is
considered the primary currency for each of the Company's international
operations. Transactions that are completed in a foreign currency are translated
into U.S. dollars and recorded in the financial statements. Translation gains or
losses were not material in any of the periods presented and the Company does
not believe it is currently exposed to any material risk of loss on this basis.
Such gains or losses are included in other expense on the income statement.
However, certain sales transactions are concluded in foreign currencies and the
Company, therefore, is exposed to potential risk of loss based on fluctuation in
exchange rates from time to time.















                                      29



<PAGE>



ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.


<TABLE>

                              INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

   <S>                                                                                                       <C>
   Report of Independent Public Accountants................................................................   31

   Consolidated Balance Sheet as of December 31, 2000 and 1999.............................................   32

   Consolidated Statement of Operations for each of the three years in the period ended
     December 31, 2000.....................................................................................   33

   Consolidated Statement of Cash Flows for each of the three years in the period ended
     December 31, 2000.....................................................................................   34

   Consolidated Statement of Shareholders' Equity for each of the three years in the period ended
     December 31, 2000.....................................................................................   35

   Notes to Consolidated Financial Statements..............................................................   36

   Supplemental Oil and Gas Information (Unaudited)........................................................   50

   Interim Financial Information (Unaudited)...............................................................   56
</TABLE>



All other financial statement schedules have been omitted because the required
information is not present or is not present in amounts sufficient to require
submission of the schedule or because the information required is included in
the financial statements, including the notes thereto.


                                      30

<PAGE>



REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders and Board of Directors of Noble Affiliates, Inc.:

      We have audited the accompanying consolidated balance sheet of Noble
Affiliates, Inc. (a Delaware corporation) and subsidiaries as of December 31,
2000 and 1999, and the related consolidated statements of operations,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 2000. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

      We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.

      In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Noble Affiliates, Inc. and
subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting principles generally accepted
in the United States.


                                                        ARTHUR ANDERSEN LLP


Oklahoma City, Oklahoma
January 26, 2001




                                      31

<PAGE>


CONSOLIDATED BALANCE SHEET
NOBLE AFFILIATES, INC. AND SUBSIDIARIES


<TABLE>
<CAPTION>
                                                                                              DECEMBER 31,      
-------------------------------------------------------------------------------------------------------------------
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)                                                      2000            1999 
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                  <C>             <C>
ASSETS
CURRENT ASSETS:
   Cash and short-term investments                                                   $     23,152    $      2,925  
   Accounts receivable - trade                                                            235,843          98,794  
   Materials and supplies inventories                                                       4,645           5,517  
   Other current assets                                                                     7,621          10,678  
-------------------------------------------------------------------------------------------------------------------
          Total current assets                                                            271,261         117,914  
-------------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT, AT COST:
   Oil and gas mineral interests, equipment and facilities
     (successful efforts method of accounting)                                          3,213,223       2,786,848  
   Other                                                                                   43,244          43,945  
-------------------------------------------------------------------------------------------------------------------
                                                                                        3,256,467       2,830,793  
Accumulated depreciation, depletion and amortization                                   (1,771,344)     (1,588,423) 
-------------------------------------------------------------------------------------------------------------------
          Total property, plant and equipment, net                                      1,485,123       1,242,370  
-------------------------------------------------------------------------------------------------------------------
INVESTMENT IN UNCONSOLIDATED SUBSIDIARY                                                    74,159          15,625  
-------------------------------------------------------------------------------------------------------------------
OTHER ASSETS                                                                               48,737          44,442  
-------------------------------------------------------------------------------------------------------------------
          TOTAL ASSETS                                                               $  1,879,280    $  1,420,351  
-------------------------------------------------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
   Accounts payable - trade                                                          $    279,379    $    103,753  
   Other current liabilities                                                               30,730          48,215  
   Income taxes - current                                                                  15,308           2,503  
-------------------------------------------------------------------------------------------------------------------
          Total current liabilities                                                       325,417         154,471  
-------------------------------------------------------------------------------------------------------------------
DEFERRED INCOME TAXES                                                                     117,048          83,075  
-------------------------------------------------------------------------------------------------------------------
OTHER DEFERRED CREDITS AND NONCURRENT LIABILITIES                                          61,639          53,877  
-------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT                                                                            525,494         445,319  
-------------------------------------------------------------------------------------------------------------------
SHAREHOLDERS' EQUITY:
   Preferred stock - par value $1.00; 4,000,000 shares authorized, none issued
   Common stock - par value $3.33 1/3; 100,000,000 shares authorized;
      59,002,162 and 58,569,963 shares issued in 2000 and 1999, respectively              196,672         195,231  
   Capital in excess of par value                                                         373,259         360,983  
   Retained earnings                                                                      325,452         142,813  
-------------------------------------------------------------------------------------------------------------------
                                                                                          895,383         699,027  
   Less common stock in treasury at cost
     (December 31, 2000, 2,911,300 shares and
      December 31, 1999, 1,524,900 shares)                                                (45,701)        (15,418) 
-------------------------------------------------------------------------------------------------------------------
          Total shareholders' equity                                                      849,682         683,609 
-------------------------------------------------------------------------------------------------------------------
              TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY                             $  1,879,280    $  1,420,351 
-------------------------------------------------------------------------------------------------------------------
</TABLE>


                  SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

                                           32


<PAGE>


CONSOLIDATED STATEMENT OF OPERATIONS
NOBLE AFFILIATES, INC. AND SUBSIDIARIES


<TABLE>
<CAPTION>
                                                                                   YEAR ENDED DECEMBER 31,          
--------------------------------------------------------------------------------------------------------------------   
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)                                    2000           1999           1998 
-------------------------------------------------------------------------------------------------------------------- 
<S>                                                                    <C>             <C>            <C>
REVENUES:

   Oil and gas sales and royalties                                      $    791,353   $    548,733   $    609,164   
   Gathering, marketing and processing                                       589,933        338,046        284,407
   Other income                                                               10,816         23,100         18,045
   Income (loss) from investment in unconsolidated subsidiary                  1,489            (37)  
--------------------------------------------------------------------------------------------------------------------   
          Total Revenue                                                    1,393,591        909,842        911,616
--------------------------------------------------------------------------------------------------------------------   
COSTS AND EXPENSES:

   Oil and gas exploration                                                    88,243         46,784        110,158
   Oil and gas operations                                                    121,866        116,698        149,030
   Gathering, marketing and processing                                       574,266        323,314        270,826
   Depreciation, depletion and amortization                                  230,800        254,515        313,191
   Impairment of operating assets                                                                          223,251
   Selling, general and administrative                                        47,291         47,859         48,110  
   Interest                                                                   37,968         48,935         50,511 
   Interest capitalized                                                       (6,326)        (5,894)        (6,753)
--------------------------------------------------------------------------------------------------------------------   
                Total Expenses                                             1,094,108        832,211      1,158,324
--------------------------------------------------------------------------------------------------------------------   
INCOME (LOSS) BEFORE TAXES                                                   299,483         77,631       (246,708)
--------------------------------------------------------------------------------------------------------------------   
INCOME TAX PROVISION (BENEFIT):

   Current                                                                    74,616         24,508        (19,679)       
   Deferred                                                                   33,270          3,662        (63,004) 
--------------------------------------------------------------------------------------------------------------------   
          Total Tax Provision (Benefit)                                      107,886         28,170        (82,683)
--------------------------------------------------------------------------------------------------------------------   
NET INCOME (LOSS                                                        $    191,597   $     49,461   $   (164,025)
--------------------------------------------------------------------------------------------------------------------   
BASIC EARNINGS (LOSS) PER SHARE                                         $       3.42   $        .87   $      (2.88)
--------------------------------------------------------------------------------------------------------------------   
DILUTED EARNINGS (LOSS) PER SHARE                                       $       3.38   $        .86   $      (2.88)
--------------------------------------------------------------------------------------------------------------------   
WEIGHTED AVERAGE SHARES OUTSTANDING:

   Basic                                                                      55,999         57,005         56,955 

   Diluted                                                                    56,755         57,349         56,955 
--------------------------------------------------------------------------------------------------------------------   
</TABLE>



SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

                                      33

<PAGE>

CONSOLIDATED STATEMENT OF CASH FLOWS
NOBLE AFFILIATES, INC. AND SUBSIDIARIES


<TABLE>
<CAPTION>
                                                                         YEAR ENDED DECEMBER 31,         
----------------------------------------------------------------------------------------------------------  
(IN THOUSANDS)                                                       2000         1999           1998     
----------------------------------------------------------------------------------------------------------  
<S>                                                              <C>           <C>           <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
   Net income (loss)                                             $   191,597   $    49,461   $  (164,025)
   Adjustments to reconcile net income to net cash
       provided by operating activities:  
     Depreciation, depletion and amortization                        230,800       254,515       313,191
     Dry hole                                                         38,463        19,204        57,736
     Impairment of operating assets                                                              223,251
     Amortization of undeveloped leasehold costs, net                 16,075         9,645         7,953
     (Gain) loss on disposal of assets                                (3,799)      (12,079)       15,434
     Noncurrent deferred income taxes                                 33,973       (23,749)      (37,260)
     (Income) loss from unconsolidated subsidiary                     (1,489)           37 
     Increase (decrease) in other deferred credits                     7,762         1,011        (3,558) 
     (Increase) decrease in other                                     (3,747)       (1,295)       12,708
   Changes in working capital, not including cash:
     (Increase) decrease in accounts receivable                     (137,049)        7,719        56,154
     (Increase) decrease in other current assets                       3,557        16,571       (44,423)
     Increase (decrease) in accounts payable                         198,871        (4,785)      (55,025)                
     Increase (decrease) in other current liabilities                 (4,680)       26,845          (126)
----------------------------------------------------------------------------------------------------------  
NET CASH PROVIDED BY OPERATING ACTIVITIES                            570,334       343,100       382,010
----------------------------------------------------------------------------------------------------------  
CASH FLOWS FROM INVESTING ACTIVITIES:
   Capital expenditures                                             (536,901)     (142,124)     (489,452)
   Investment in unconsolidated subsidiary                           (57,045)      (51,962)      (25,061)
   Proceeds from the transfer of our interest
     to unconsolidated subsidiary                                                   61,987
   Proceeds from sale of property, plant and equipment                12,608        58,137         3,412
----------------------------------------------------------------------------------------------------------  
NET CASH USED IN INVESTING ACTIVITIES                               (581,338)      (73,962)     (511,101)
----------------------------------------------------------------------------------------------------------  
CASH FLOWS FROM FINANCING ACTIVITIES:
   Exercise of stock options                                          13,717         1,188         2,229  
   Cash dividends paid                                                (8,958)       (9,120)       (9,113)
   Proceeds from bank debt                                           137,000
   Repayment of bank debt                                            (57,000)     (300,000)
   Repayment of notes payable - unconsolidated subsidiary            (23,245)      (38,101)
   Proceeds from notes payable - unconsolidated subsidiary                          60,720
   Purchase of treasury stock                                        (30,283)
   Proceeds from issuance of long-term debt                                                      100,000
----------------------------------------------------------------------------------------------------------  
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES                   31,231      (285,313)       93,116
----------------------------------------------------------------------------------------------------------  
INCREASE (DECREASE) IN CASH AND SHORT-TERM CASH INVESTMENTS           20,227       (16,175)      (35,975)
CASH AND SHORT-TERM CASH INVESTMENTS AT BEGINNING OF YEAR              2,925        19,100        55,075
----------------------------------------------------------------------------------------------------------  
CASH AND SHORT-TERM CASH INVESTMENTS AT END OF YEAR              $    23,152   $     2,925   $    19,100
----------------------------------------------------------------------------------------------------------  

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
   Cash paid during the year for:                                
   Interest (net of amount capitalized)                          $    32,976   $    44,845   $    43,368
   Income taxes                                                  $    56,890   $    30,000   $     4,276
</TABLE>



SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

                                      34

<PAGE>


CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
NOBLE AFFILIATES, INC. AND SUBSIDIARIES


<TABLE>
<CAPTION>
                                                                              CAPITAL IN     TREASURY
                                                COMMON STOCK                  EXCESS OF      STOCK AT      RETAINED
(IN THOUSANDS, EXCEPT SHARES ISSUED)            SHARES ISSUED     AMOUNT      PAR VALUE        COST        EARNINGS      
---------------------------------------------------------------------------------------------------------------------
<S>                                             <C>              <C>          <C>            <C>         <C>         
DECEMBER 31, 1997                                58,423,438      $194,743      $358,054      $(15,418)   $  275,610
---------------------------------------------------------------------------------------------------------------------
Net Loss                                                                                                   (164,025)

Exercise of stock options                            82,470           275         1,954

Cash dividends ($.16 per share)                                                                             (9,113)
---------------------------------------------------------------------------------------------------------------------

DECEMBER 31, 1998                                58,505,908      $195,018      $360,008      $(15,418)   $  102,472
---------------------------------------------------------------------------------------------------------------------

Net Income                                                                                                   49,461

Exercise of stock options                            64,055           213           975

Cash dividends ($.16 per share)                                                                              (9,120)
---------------------------------------------------------------------------------------------------------------------

DECEMBER 31, 1999                                58,569,963      $195,231      $360,983      $(15,418)   $  142,813
---------------------------------------------------------------------------------------------------------------------

Net Income                                                                                                  191,597

Purchase of treasury stock                                                                    (30,283)

Exercise of stock options                           432,199         1,441        12,276

Cash dividends ($.16 per share)                                                                              (8,958)
---------------------------------------------------------------------------------------------------------------------

DECEMBER 31, 2000                                59,002,162      $196,672      $373,259      $(45,701)   $  325,452
---------------------------------------------------------------------------------------------------------------------
</TABLE>


SEE ACCOMPANYING NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

                                      35


<PAGE>


                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
       (DOLLAR AMOUNTS IN TABLES, UNLESS OTHERWISE INDICATED, ARE IN 
                      THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

CONSOLIDATION

The consolidated accounts include Noble Affiliates, Inc. (the "Company") and 
the consolidated accounts of its wholly-owned subsidiaries: Noble Gas 
Marketing, Inc. ("NGM"); Noble Trading, Inc. ("NTI"); NPM, Inc.; and Samedan 
Oil Corporation ("Samedan"). Listed below are consolidated entities at 
December 31, 2000.

     NOBLE AFFILIATES, INC.
         Noble Gas Marketing, Inc.
              Noble Gas Pipeline, Inc.
         Noble Trading, Inc.
         NPM, Inc.
         Samedan Oil Corporation
              Samedan of North Africa, Inc.
                  Samedan International
                      Machalapower Cia. Ltda.
                      Samedan, Mediterranean Sea
                      Samedan Transfer Sub
                  Samedan Vietnam Limited
              Samedan, Mediterranean Sea, Inc.
              Samedan of Tunisia, Inc.
              Samedan Oil of Canada, Inc.
              Samedan Oil of Indonesia, Inc.
              Samedan Pipe Line Corporation
              Samedan Royalty Corporation
              Energy Development Corporation ("EDC")
                  EDC Australia, Ltd.
                  EDC Ecuador Ltd.
                        EDC Ecuador Limited
                  EDC Portugal Ltd.
                  EDC (UK) Limited
                        EDC (Denmark) Inc.
                        EDC (Europe) Limited
                             EDC (ISE) Limited
                             EDC (Oilex) Limited
                             Brabant Oil Limited
                                   Burnside Overseas Exploration Ltd.
                  Energy Development Corporation (Argentina), Inc.
                  Energy Development Corporation (China), Inc.
                  Energy Development Corporation (HIPS), Inc.
                  Gasdel Pipeline System Incorporated
                  HGC, Inc.
                  Producers Service, Inc.

NATURE OF OPERATIONS

The Company is an independent energy company engaged through its subsidiaries in
the exploration, development, production and marketing of oil and gas. Samedan
operates throughout the major basins in the United States, including the Gulf of
Mexico, as well as international operations in Argentina, China, Ecuador,
Equatorial Guinea, the 

                                      36


<PAGE>

Mediterranean Sea, the North Sea, and Vietnam. The Company markets its oil and 
gas production through NGM, NTI and Samedan.

USE OF ESTIMATES

The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities. Such estimates and
assumptions also affect the disclosure of contingent assets and liabilities at
the date of the financial statements as well as amounts of revenues and expenses
recognized during the reporting period. Of the estimates and assumptions that
affect reported results, the estimate of the Company's oil and gas reserves is
the most significant.

FOREIGN CURRENCY TRANSLATION

The U.S. dollar is considered the primary currency for each of the Company's
international operations. Transactions that are completed in a foreign currency
are translated into U.S. dollars and recorded in the financial statements.
Translation gains or losses were not material in any of the periods presented
and are included in other expense on the income statement.

INVENTORIES

Materials and supplies inventories, consisting principally of tubular goods and
production equipment, are stated at the lower of cost or market, with cost being
determined by the first-in, first-out method.

PROPERTY, PLANT AND EQUIPMENT

The Company accounts for its oil and gas properties under the successful efforts
method of accounting. Under this method, costs to acquire mineral interests in
oil and gas properties, to drill and equip exploratory wells that find proved
reserves and to drill and equip development wells are capitalized. Capitalized
costs of producing oil and gas properties are amortized to operations by the
unit-of-production method based on proved developed oil and gas reserves on a
property-by-property basis as estimated by Company engineers. Estimated future
restoration and abandonment costs are recorded by charges to depreciation,
depletion and amortization ("DD&A") expense over the productive lives of the
related properties. The Company has provided $79.7 million for such future costs
classified with accumulated DD&A in the December 31, 2000 balance sheet. The
total estimated future dismantlement and restoration costs of $136.1 million are
included in future production and development costs for purposes of estimating
the future net revenues relating to the Company's proved reserves. Upon sale or
retirement of depreciable or depletable property, the cost and related
accumulated DD&A are eliminated from the accounts and the resulting gain or loss
is recognized.

Individually significant undeveloped oil and gas properties are periodically
assessed for impairment of value and a loss is recognized at the time of
impairment by providing an impairment allowance. Other undeveloped properties
are amortized on a composite method based on the Company's experience of
successful drilling and average holding period. Geological and geophysical
costs, delay rentals and costs to drill exploratory wells which do not find
proved reserves are expensed. Repairs and maintenance are charged to expense as
incurred.

Developed oil and gas properties and other long-lived assets are periodically
assessed to determine if circumstances indicate that the carrying amount of an
asset may not be recoverable. The Company performs this review of recoverability
by estimating future cash flows. If the sum of the expected future cash flows is
less than the carrying amount of the asset, an impairment is recognized based on
the discounted amount of such cash flows.

                                      37


<PAGE>

INCOME TAXES

The Company files a consolidated federal income tax return. Deferred income
taxes are provided for temporary differences between the financial reporting and
tax bases of the Company's assets and liabilities.

CAPITALIZATION OF INTEREST

The Company capitalizes interest costs associated with the development and
construction of significant properties or projects.

STATEMENT OF CASH FLOWS

For purposes of reporting cash flows, cash and short-term investments include
cash on hand and investments purchased with original maturities of three months
or less.

BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE

Basic income per share of common stock has been computed on the basis of the
weighted average number of shares outstanding during each period. The diluted
net income per share of common stock includes the effect of outstanding stock
options. The following table summarizes the calculation of basic earnings per
share ("EPS") and diluted EPS components required by SFAS No. 128, as of
December 31:



<TABLE>
<CAPTION>

                                          2000                          1999                         1998(1)         
                              ----------------------------  ---------------------------  ----------------------------
(IN THOUSANDS                       INCOME          SHARES        INCOME         SHARES        INCOME          SHARES
EXCEPT PER SHARE AMOUNTS)      (NUMERATOR)   (DENOMINATOR)   (NUMERATOR)  (DENOMINATOR)   (NUMERATOR)   (DENOMINATOR)
---------------------------------------------------------------------------------------------------------------------
<S>                           <C>            <C>            <C>           <C>            <C>            <C>
Net income/shares                 $191,597          55,999       $49,461         57,005    $(164,025)          56,955
---------------------------------------------------------------------------------------------------------------------
BASIC EPS                                  $3.42                          $.87                       $(2.88)
---------------------------------------------------------------------------------------------------------------------

Net income/shares                 $191,597          55,999       $49,461         57,005    $(164,025)          56,955
Effect of Diluted Securities
   Stock options                                       756                          344                              
---------------------------------------------------------------------------------------------------------------------
Adjusted net income
   and shares                     $191,597          56,755       $49,461         57,349    $(164,025)          56,955
---------------------------------------------------------------------------------------------------------------------
DILUTED EPS                                $3.38                          $.86                       $(2.88)
---------------------------------------------------------------------------------------------------------------------

</TABLE>


    (1) In 1998, the diluted EPS is antidilutive as a result of the net
        operating loss; therefore, the basic EPS and diluted EPS are the same.

REVENUE RECOGNITION AND GAS IMBALANCES

Samedan and EDC have gas sales contracts with NGM, whereby Samedan and EDC are
paid an index price for all gas sold to NGM. NGM records sales, including
hedging transactions, as gathering, marketing and processing revenues. NGM
records the amount paid to Samedan, EDC and third parties as cost of sales in
gathering, marketing and processing. All intercompany sales and costs have been
eliminated.

The Company follows an entitlements method of accounting for its gas imbalances.
Gas imbalances occur when the Company sells more or less gas than its entitled
ownership percentage of total gas production. Any excess amount received above
the Company's share is treated as a liability. If less than the Company's
entitlement is received, the underproduction is recorded as a receivable. The
Company records the noncurrent liability in Other Deferred Credits and
Noncurrent Liabilities, and the current liability in Other Current Liabilities.
The Company's gas imbalance liabilities were $14.2 million and $12.0 million for
2000 and 1999, respectively. The Company records the noncurrent receivable in
Other Assets, and the current receivable in Other Current Assets. The Company's
gas imbalance receivables were $18.5 million and $17.9 million for 2000 and
1999, respectively, and are valued at the amount which is expected to be
received.

                                      38


<PAGE>

TAKE-OR-PAY SETTLEMENTS

The Company records gas contract settlements which are not subject to recoupment
in Other Income when the settlement is received.

TRADING AND HEDGING ACTIVITIES

The Company, through its subsidiaries, from time to time, uses various hedging
arrangements in connection with anticipated crude oil and natural gas sales to
minimize the impact of product price fluctuations. Such arrangements include
fixed price hedges, costless collars, and other contractual arrangements.
Although these hedging arrangements expose the Company to credit risk, the
Company monitors the creditworthiness of its counterparties, which generally are
major financial institutions, and believes that losses from nonperformance are
unlikely to occur. Hedging gains and losses related to the Company's oil and gas
production are recorded in oil and gas sales and royalties. The swap component
of the contracts discussed in the following paragraphs was treated as a hedge
for accounting purposes only.

The Company had entered into three crude oil premium swap contracts related to
its production for calendar year 2000. Two of the contracts provided for
payments based on daily NYMEX settlement prices. These contracts related to
2,500 BBLS per day and 2,000 BBLS per day and had trigger prices of $21.73 per
BBL and $22.45 per BBL, respectively, and both had knockout prices of $17.00 per
BBL. These two contracts entitled the Company to receive settlements from the
counterparties in amounts, if any, by which the settlement price for each NYMEX
trading day was less than the trigger price, provided the NYMEX price was also
greater than the $17.00 per BBL knockout price. If a daily settlement price was
$17.00 per BBL or less, then neither party had any liability to the other for
that day. If a daily settlement price was above the applicable trigger price,
then the Company would owe the counterparty for the excess of the settlement
price over the trigger price for that day. Payment was made monthly under each
of these contracts, in an amount equal to the net amount due to either party
based on the sum of the daily amounts determined as described in this paragraph
for that month.

The third contract related to 2,500 BBLS per day and provided for payments based
on monthly average NYMEX settlement prices. The contract entitled the Company to
receive monthly settlements from the counterparty in an amount, if any, by which
the arithmetic average of the daily NYMEX settlement prices for the month was
less than the trigger price, which was $21.73 per BBL, multiplied by the number
of days in the month, provided such average NYMEX price was also greater than
the $17.00 per BBL knockout price. If the average NYMEX settlement price for the
month was $17.00 per BBL or less, then neither party would have any liability to
the other for that month. If the average NYMEX settlement price for the month
was above the trigger price, then the Company would pay the counterparty an
amount equal to the excess of the average settlement price over the trigger
price, multiplied by the number of days in the month.

The net effect of these premium swap contracts was a $2.87 per BBL reduction in
the average crude oil price realized by the Company in 2000.

The Company has treated the swap component of these contracts as a hedge (for
accounting purposes only), at swap prices ranging from $19.40 per BBL to $20.20
per BBL, which existed at the dates it entered into these contracts. In
addition, the Company has separately accounted for the premium component of
these contracts by marking them to market, resulting in a gain of $2,921,000
recorded in other income for the year ended December 31, 2000.

In addition to the premium swap crude oil hedging contracts, the Company had
entered into crude oil costless collar hedges from January 1, 2000 to April 30,
2000 for volumes of 2,000 BBLS per day. These costless collars had a floor price
ranging from $21.53 per BBL to $23.27 per BBL and a cap price ranging from
$25.83 per BBL to $27.31 per BBL. These costless collar contracts entitled the
Company to receive settlements from the counterparties in amounts, if any, by
which the monthly average settlement price for each NYMEX trading day during a
contract month was less than the floor price. If the monthly average settlement
price was above the applicable cap price, then the Company would owe the
counterparties for the excess of the monthly average settlement price over the
applicable cap price. If 

                                      39


<PAGE>

the monthly average settlement price fell between the applicable floor and cap 
price, then neither party would have any liability to the other party for that 
month. Payment, if any, was made monthly under each of the contracts in an 
amount equal to the net amount due either party based on the volumes per day 
multiplied by the difference between the NYMEX average price and the cap, if 
the NYMEX average price exceeded the cap price, or if the NYMEX average price 
was less than the floor price, then the volumes per day multiplied by the 
difference between the floor price and the NYMEX average price.

The net effect of these costless collar hedges was a $.05 per BBL reduction in
the average crude oil price realized by the Company in 2000.

The Company had no oil or gas hedging contracts for future production as of
December 31, 2000.

During 1999 and 1998, the Company had no oil or gas hedging transactions for its
production.

In addition to the hedging arrangements pertaining to the Company's production
as described above, NGM employs various hedging arrangements in connection with
its purchases and sales of third party production to lock in profits or limit
exposure to gas price risk. Most of the purchases made by NGM are on an index
basis; however, purchasers in the markets in which NGM sells often require fixed
or NYMEX related pricing. NGM may use a hedge to convert the fixed or NYMEX sale
to an index basis thereby determining the margin and minimizing the risk of
price volatility. During 2000, NGM had hedging transactions with broker-dealers
that ranged from 423,000 MMBTU to 1,023,000 MMBTU of gas per day. At December
31, 2000, NGM had in place hedges ranging from approximately 20,000 MMBTU to
1,133,000 MMBTU of gas per day for January 2001 to May 2006 for future physical
transactions.

In 1999, NGM had hedging transactions with broker-dealers that ranged from
146,000 MMBTU to 815,000 MMBTU of gas per day. During 1998, NGM had hedging
transactions with broker-dealers that ranged from 508,811 MMBTU to 1,061,536
MMBTU of gas per day. NGM records hedging gains or losses relating to fixed term
sales as gathering, marketing and processing revenues in the periods in which
the related contract is completed.

SELF-INSURANCE

The Company self-insures the medical and dental coverage provided to certain of
its employees, certain workers' compensation and the first $200,000 of its
general liability coverage.

A provision for self-insured claims is recorded when sufficient information is
available to reasonably estimate the amount of the loss.

UNCONSOLIDATED SUBSIDIARY

The Company has an unconsolidated subsidiary, Atlantic Methanol Capital Company
("AMCCO"), a 50 percent owned joint venture that owns an indirect 90 percent
interest in Atlantic Methanol Production Company ("AMPCO"). The Company accounts
for its interest in AMCCO using the equity method within the Company's
wholly-owned subsidiary, Samedan of North Africa, Inc. Samedan is participating
with a 50 percent expense interest (45 percent ownership net of a five percent
government carried interest) to construct a methanol plant in Equatorial Guinea.

RECLASSIFICATION

Certain reclassifications have been made to the 1999 and 1998 consolidated
financial statements to conform to the 2000 presentation.

RECENTLY ISSUED PRONOUNCEMENTS

The Financial Accounting Standards Board ("FASB") issued Statement of Financial
Accounting Standard ("SFAS") No. 133, "Accounting for Derivative Instruments and
Hedging Activities" in June 1998. The Statement establishes 

                                      40


<PAGE>

accounting and reporting standards requiring every derivative instrument 
(including certain derivative instruments embedded in other contracts) to be 
recorded in the balance sheet as either an asset or liability measured at its 
fair value. The Statement requires that changes in the derivative's fair value 
be recognized currently in earnings unless specific hedge accounting criteria 
are met wherein gains and losses are reflected in shareholders' equity until 
the hedged item is recognized. Special accounting for qualifying hedges allows 
a derivative's gains and losses to offset related results on the hedged item 
in the income statement, and requires that a company formally document, 
designate and assess the effectiveness of transactions that receive hedge 
accounting.

Due to the issuance of SFAS No. 137, which deferred the effective date of SFAS
No. 133, the Company is required to adopt the statement for fiscal years
beginning after June 15, 2000. A company may also implement the statement as of
the beginning of any fiscal quarter after the statement's issuance (that is,
fiscal quarters beginning June 16, 1998, and thereafter). SFAS No. 133 must be
applied to (a) derivative instruments and (b) certain derivative instruments
embedded in hybrid contracts that were issued, acquired, or substantively
modified after December 31, 1997 (and, at the Company's election, before January
1, 1998).

During 2000, the FASB issued SFAS No. 138 which amends the accounting and
reporting standards of SFAS No. 133 for certain derivative instruments and
certain hedging activities and should be adopted concurrently with SFAS No. 133,
according to its provisions and the issuance of SFAS No. 137. The normal
purchases and normal sales exception may be applied to contracts that implicitly
or explicitly permit net settlement and contracts that have a market mechanism
to facilitate net settlement. The Company adopted SFAS Nos. 133 and 138
effective January 1, 2001. The adoption of these FASB's did not have a material
impact on the Company's results of operations or financial position.

NOTE 2 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS 

The following methods and assumptions were used to estimate the fair value of
each class of financial instruments pursuant to the requirements of SFAS No.
107, "Disclosures about Fair Value of Financial Instruments."

CASH AND SHORT-TERM INVESTMENTS

The carrying amount approximates fair value due to the short maturity of the
instruments.

OIL AND GAS PRICE HEDGE AGREEMENTS

The fair value of oil and gas price hedges is the estimated amount the Company
would receive or pay to terminate the hedge agreements at the reporting date
taking into account creditworthiness of the hedging parties.

LONG-TERM DEBT

The fair value of the Company's long-term debt is estimated based on the quoted
market prices for the same or similar issues or on the current rates offered to
the Company for debt of the same remaining maturities.





                                      41



<PAGE>

The carrying amounts and estimated fair values of the Company's financial
instruments as of December 31, for each of the years are as follows:



<TABLE>
<CAPTION>

                                                                   2000                              1999           
                                                      ----------------------------       ---------------------------
                                                        CARRYING              FAIR         CARRYING            FAIR
(IN THOUSANDS)                                            AMOUNT             VALUE           AMOUNT           VALUE 
--------------------------------------------------------------------------------------------------------------------
<S>                                                   <C>               <C>              <C>             <C>
Cash and short-term investments                       $   23,152        $   23,152       $    2,925      $    2,925
Long-term debt (including current portion)            $  525,494        $  539,375       $  445,319      $  407,500
Oil hedge agreements                                  $                 $                $               $   (7,879)

</TABLE>


NOTE 3 - DEBT

A summary of debt at December 31 follows:



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                                                 2000             1999
--------------------------------------------------------------------------------------------------------------------
<S>                                                                                      <C>              <C>
$300 million Credit Agreement                                                            $   80,000       $
7 1/4% Notes Due 2023                                                                       100,000          100,000
8% Senior Notes Due 2027                                                                    250,000          250,000
7 1/4% SENIOR DEBENTURES DUE 2097                                                           100,000          100,000
--------------------------------------------------------------------------------------------------------------------
Outstanding debt                                                                            530,000          450,000
--------------------------------------------------------------------------------------------------------------------
Less: unamortized discount                                                                    4,506            4,681
--------------------------------------------------------------------------------------------------------------------
Long-term debt                                                                           $  525,494       $  445,319
--------------------------------------------------------------------------------------------------------------------

</TABLE>


The Company's total long-term debt, net of unamortized discount, at December 31,
2000, was $525 million compared to $445 million at December 31, 1999. The ratio
of debt to book capital (defined as the Company's debt plus its equity) was 38
percent at December 31, 2000, compared with 39 percent at December 31, 1999.

The Company's long-term debt is comprised of: $100 million of 7 1/4% Notes Due
2023, $250 million of 8% Senior Notes Due 2027, $100 million of 7 1/4% Senior
Debentures Due 2097 and the outstanding balance of $80 million on a $300 million
credit facility. Other than the $80 million due on the credit facility, there is
no principal payment due on long term debt during the next five years.

The Company has a $300 million credit facility which exposes the Company to the
risk of earnings or cash flow loss due to changes in market interest rates. At
December 31, 2000, there was $80 million borrowed against the credit facility
which has a maturity date of December 24, 2002. The interest rate is based upon
a Eurodollar rate plus a range of 17.5 to 50 basis points. At year-end 1999, the
Company had no borrowing outstanding on this facility.

On June 17, 1999, the Company entered into a new $100 million 364 day credit 
agreement with certain commercial lending institutions. This agreement, which 
is based upon a Eurodollar rate plus 37.5 to 87.5 basis points depending upon 
the percentage of utilization, expired in 2000 without ever having been 
utilized.




                                      42


<PAGE>

NOTE 4 - INCOME TAXES

The following table details the difference between the federal statutory tax
rate and the effective tax rate for the years ended December 31:



<TABLE>
<CAPTION>

(AMOUNTS EXPRESSED IN PERCENTAGES)                                           2000             1999              1998 
---------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>              <C>              <C>
Statutory rate (benefit)                                                     35.0             35.0             (35.0)
Effect of:
   State taxes, net of federal benefit                                         .3                                (.2)
   Difference between U.S. and foreign rates                                   .2              3.1               1.3
   Other, net                                                                  .5             (1.8)               .4 
---------------------------------------------------------------------------------------------------------------------
Effective rate                                                               36.0             36.3             (33.5)
---------------------------------------------------------------------------------------------------------------------

</TABLE>


The net current deferred tax asset (liability) in the following table is
classified as Other Current Assets in the Consolidated Balance Sheet. The tax
effects of temporary differences which gave rise to deferred tax assets and
liabilities as of December 31 were:



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                                               2000               1999 
---------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>                 <C>
U.S. and State Current Deferred Tax Assets:
   Accrued expenses                                                                    $    1,061          $     525
   Deferred income                                                                           (186)                36
   Allowance for doubtful accounts                                                            225                284
   Other                                                                                      (21)                14 
---------------------------------------------------------------------------------------------------------------------
   Net current deferred tax asset                                                           1,079                859 
---------------------------------------------------------------------------------------------------------------------
U.S. and State Non-current Deferred Tax Liabilities:
   Property, plant and equipment, principally due to
    differences in depreciation, amortization, lease
    impairment and abandonments                                                          (121,799)           (84,969)
   Accrued expenses                                                                         9,309              8,041
   Deferred income                                                                          3,303              2,748
   Allowance for doubtful accounts                                                          5,779              4,865
   Income tax accruals                                                                      9,579              9,244
   Other                                                                                    2,962              2,552 
---------------------------------------------------------------------------------------------------------------------
   Net non-current deferred liability                                                     (90,867)           (57,519)
---------------------------------------------------------------------------------------------------------------------
   U.S. and state net deferred tax liability                                              (89,788)           (56,660)
---------------------------------------------------------------------------------------------------------------------
Foreign Deferred Tax Liabilities:
   Property, plant and equipment of
    foreign operations                                                                    (26,181)           (25,556)
---------------------------------------------------------------------------------------------------------------------
   Deferred tax liability                                                                 (26,181)           (25,556)
---------------------------------------------------------------------------------------------------------------------
Total net deferred tax liability                                                       $ (115,969)         $ (82,216)
---------------------------------------------------------------------------------------------------------------------

</TABLE>


The components of income from operations before income taxes for each year are
as follows:



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                               2000            1999               1998 
---------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>              <C>              <C>
Domestic                                                                 $268,489         $83,439          $(225,692)
Foreign                                                                    30,994          (5,808)           (21,016)
---------------------------------------------------------------------------------------------------------------------
Total                                                                    $299,483         $77,631          $(246,708)
---------------------------------------------------------------------------------------------------------------------

</TABLE>





                                      43


<PAGE>

The income tax provision (benefit) relating to operations for each year consists
of the following:



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                               2000             1999              1998 
---------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>                <C>              <C>
U.S. current                                                            $  65,358          $18,963          $(20,842)
U.S. deferred                                                              32,311            7,150           (62,366)
State current                                                                 917              313               236
State deferred                                                                334             (313)           (1,080)
Foreign current                                                             8,341            5,232               927
Foreign deferred                                                              625           (3,175)              442 
---------------------------------------------------------------------------------------------------------------------
Total                                                                    $107,886          $28,170          $(82,683)
---------------------------------------------------------------------------------------------------------------------

</TABLE>


NOTE 5 - COMMON STOCK, STOCK OPTIONS AND STOCKHOLDER RIGHTS

The Company has two stock option plans, the 1992 Stock Option and Restricted
Stock Plan ("1992 Plan") and the 1988 Non-Employee Director Stock Option Plan
("1988 Plan"). The Company accounts for these plans under APB Opinion 25.
Compensation expense totaling $781,275 was recognized in 2000, due to the
accelerated vesting of stock options as a result of the retirement of certain
employees and is recorded in selling, general and administrative expense in the
accompanying Consolidated Statement of Operations.

Under the Company's 1992 Plan, the Board of Directors may grant stock options
and award restricted stock. No restricted stock has been issued under the 1992
Plan. Since the adoption of the 1992 Plan, stock options have been issued at the
market price on the date of grant. The earliest the granted options may be
exercised is over a three year period at the rate of 33 1/3% each year
commencing on the first anniversary of the grant date. The options expire ten
years from the grant date. The 1992 Plan was amended in 2000, by a vote of the
shareholders, to increase the maximum number of shares of common stock that may
be issued under the 1992 Plan to 6,500,000 shares. At December 31, 2000, the
Company had reserved 5,799,221 shares of common stock for issuance, including
2,353,006 shares available for grant, under its 1992 Plan.

The Company's 1988 Plan allows stock options to be issued to certain
non-employee directors at the market price on the date of grant. The options may
be exercised one year after issue and expire ten years from the grant date. The
1988 Plan provides for the grant of options to purchase a maximum of 550,000
shares of the Company's authorized but unissued common stock. At December 31,
2000, the Company had reserved 399,000 shares of common stock for issuance,
including 165,500 shares available for grant, under its 1988 Plan.

The Company adopted a stockholder rights plan on August 27, 1997, designed to
assure that the Company's stockholders receive fair and equal treatment in the
event of any proposed takeover of the Company and to guard against partial
tender offers and other abusive takeover tactics to gain control of the Company
without paying all stockholders a fair price. The rights plan was not adopted in
response to any specific takeover proposal. Under the rights plan, the Company
declared a dividend of one right ("Right") on each share of Noble Affiliates,
Inc. common stock. Each Right will entitle the holder to purchase one
one-hundredth of a share of a new Series A Junior Participating Preferred Stock,
par value $1.00 per share, at an exercise price of $150.00. The Rights are not
currently exercisable and will become exercisable only in the event a person or
group acquires beneficial ownership of 15 percent or more of Noble Affiliates,
Inc. common stock. The dividend distribution was made on September 8, 1997, to
stockholders of record at the close of business on that date. The Rights will
expire on September 8, 2007.



                                      44




<PAGE>

Stock options outstanding under the plans mentioned above and one previously
terminated plan are presented for the periods indicated.



<TABLE>
<CAPTION>

                                                                                     NUMBER                OPTION
                                                                                    OF SHARES            PRICE RANGE 
---------------------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>                <C>
OUTSTANDING DECEMBER 31, 1997                                                       2,205,335          $ 11.63-$40.38
---------------------------------------------------------------------------------------------------------------------
  Granted                                                                             722,604          $ 35.94-$37.75
  Exercised                                                                           (82,470)         $ 11.63-$40.38
  Canceled                                                                            (28,227)         $ 24.25-$40.38
---------------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1998                                                       2,817,242          $ 13.38-$40.38
---------------------------------------------------------------------------------------------------------------------
  Granted                                                                             810,895          $ 20.06-$27.50
  Exercised                                                                           (64,055)         $ 13.38-$24.25
  Canceled                                                                            (85,812)         $ 20.06-$40.38
---------------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 1999                                                       3,478,270          $ 13.50-$40.38
---------------------------------------------------------------------------------------------------------------------
  Granted                                                                             774,343          $ 20.06-$38.88
  Exercised                                                                          (432,199)         $ 13.50-$40.38
  Canceled                                                                           (109,404)         $ 20.06-$40.38
---------------------------------------------------------------------------------------------------------------------
OUTSTANDING DECEMBER 31, 2000                                                       3,711,010          $ 13.50-$40.38
---------------------------------------------------------------------------------------------------------------------

EXERCISABLE AT DECEMBER 31, 2000                                                    2,404,760          $ 13.50-$40.38
---------------------------------------------------------------------------------------------------------------------

</TABLE>


The SFAS No. 123 method of accounting is based on several assumptions and should
not be viewed as indicative of the operations of the Company in future periods.
The fair value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted-average
assumptions used for grants in 2000, 1999 and 1998, respectively, as follows:



<TABLE>
<CAPTION>

(AMOUNTS EXPRESSED IN PERCENTAGES)                                            2000             1999              1998
---------------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>              <C>              <C>
Interest rate                                                                 6.25             5.50              5.75
Dividend yield                                                                 .40              .40               .40
Expected volatility                                                          51.67            42.95             32.66
Expected life                                                                 9.71             8.80              9.74

</TABLE>


The weighted average fair value of options granted using the Black-Scholes
option pricing model for 2000, 1999 and 1998, respectively, is as follows:



<TABLE>
<CAPTION>

                                                                              2000             1999              1998
---------------------------------------------------------------------------------------------------------------------
<S>                                                                         <C>              <C>               <C>
Black-Scholes model weighted average fair value
   option price                                                             $16.66           $10.01            $19.02

</TABLE>


The Company applies APB Opinion No. 25 in accounting for its fixed price stock
options. Compensation expense totaling $781,275 was recognized in 2000, due to
the accelerated vesting of stock options as a result of the retirement of
certain employees. The table below sets forth the Company's net income and
earnings per share for each of the years ended December 31, as reported and on a
pro forma basis as if the compensation cost of stock options had been determined
consistent with SFAS No. 123, "Accounting for Stock-Based Compensation."



<TABLE>
<CAPTION>

(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)                                       2000             1999             1998 
---------------------------------------------------------------------------------------------------------------------
<S>                                                                      <C>                <C>           <C>
Net Income:
   As Reported                                                           $ 191,597          $49,461       $ (164,025)
   Pro Forma                                                             $ 183,427          $41,176       $ (171,741)
Basic Earnings Per Share:
   As Reported                                                           $    3.42          $   .87       $    (2.88)
   Pro Forma                                                             $    3.28          $   .72       $    (3.02)
Diluted Earnings Per Share:
   As Reported                                                           $    3.38          $   .86       $    (2.88)
   Pro Forma                                                             $    3.23          $   .72       $    (3.02)

</TABLE>





                                      45


<PAGE>

NOTE 6 - EMPLOYEE BENEFIT PLANS

PENSION PLAN AND OTHER POSTRETIREMENT BENEFIT PLANS

The Company has a non-contributory defined benefit pension plan covering
substantially all of its domestic employees. The benefits are based on an
employee's years of service and average earnings for the 60 consecutive calendar
months of highest compensation. The Company also has an unfunded restoration
plan to ensure payments of amounts for which employees are entitled under the
provisions of the pension plan, but which are subject to limitations imposed by
federal tax laws. The Company's funding policy has been to make annual
contributions equal to the actuarially computed liability to the extent such
amounts are deductible for income tax purposes. Plan assets consist of equity
securities and fixed income investments.

The Company sponsors other plans for the benefit of its employees and retirees.
These plans include health care and life insurance benefits. The following table
reflects the required SFAS No. 132, "Employers' Disclosures About Pension and
Other Postretirement Benefits," disclosures at December 31:



<TABLE>
<CAPTION>

                                                            PENSION BENEFITS                     OTHER BENEFITS      
                                                     -----------------------------      ----------------------------
(IN THOUSANDS)                                            2000              1999             2000              1999 
--------------------------------------------------------------------------------------------------------------------
<S>                                                  <C>               <C>              <C>               <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year              $  64,194         $  82,823        $   2,738         $   3,187
Service cost                                             3,566             3,802              231               294
Interest cost                                            5,525             4,720              187               187
Plan participants' contributions                                                               42                38
Amendments                                                                                                     (363)
Actuarial (gain) loss                                    6,423           (24,294)            (328)             (533)
Benefit paid                                            (3,085)           (2,857)            (152)              (72)
--------------------------------------------------------------------------------------------------------------------
Benefit obligation at year end                       $  76,623         $  64,194        $   2,718         $   2,738 
--------------------------------------------------------------------------------------------------------------------
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year       $  59,168         $  60,559        $                 $
Actual return on plan assets                              (992)            1,083
Employer contribution                                      396               383              152                72
Benefit paid                                            (3,085)           (2,857)            (152)              (72)
--------------------------------------------------------------------------------------------------------------------
Fair value of plan at end of year                    $  55,487         $  59,168        $                 $         
--------------------------------------------------------------------------------------------------------------------
Fund status                                          $ (21,136)        $  (5,026)       $  (2,718)        $  (2,738)
Unrecognized net actuarial loss (gain)                  (6,560)          (18,989)              19               222
Unrecognized prior service cost                          2,743             3,035             (304)             (334)
Unrecognized net transition obligation (assets)          1,214             1,239                                    
--------------------------------------------------------------------------------------------------------------------
Prepaid (accrued) benefit costs                      $ (23,739)        $ (19,741)       $  (3,003)        $  (2,850)
--------------------------------------------------------------------------------------------------------------------
COMPONENTS OF NET PERIODIC BENEFIT COST
Service cost                                         $   3,567         $   3,802        $     231         $     294
Interest cost                                            5,525             4,720              188               188
Expected return on plan assets                          (4,666)           (4,264)
Transition (assets) obligation recognition                  24                24
Amortization of prior service cost                         291               291              (30)              (30)
Recognized net actuarial loss                             (347)               35              (11)               34 
--------------------------------------------------------------------------------------------------------------------
Net periodic benefit cost                            $   4,394         $   4,608        $     378         $     486 
--------------------------------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31,
Discount rate                                             8.00%             8.00%            8.00%             8.00%
Expected return on plan assets                            8.50%             8.50%
Rate of compensation increase                             5.50%             5.50%            5.50%             5.50%

</TABLE>




                                      46


<PAGE>

The following table reflects the aggregate pension obligation components
required by SFAS No. 132 for the defined benefit pension plan and the
restoration benefit plan, which are aggregated in the previous tables, at
December 31:



<TABLE>
<CAPTION>

                                                             DEFINED BENEFIT                      RESTORATION
                                                               PENSION PLAN                       BENEFIT PLAN      
                                                      ----------------------------      ----------------------------
(IN THOUSANDS)                                            2000              1999             2000              1999 
--------------------------------------------------------------------------------------------------------------------
<S>                                                   <C>               <C>             <C>                <C>
AGGREGATED PENSION BENEFITS
Aggregate fair value of plan assets                   $ 55,487          $ 59,168        $                  $
Aggregate accumulated benefit obligation                61,902            56,092           14,721             8,102 
--------------------------------------------------------------------------------------------------------------------
Fund status of net periodic
   benefit assets (obligation)                        $ (6,415)         $  3,076        $ (14,721)         $ (8,102)
--------------------------------------------------------------------------------------------------------------------

</TABLE>


Assumed health care cost trend rates have a significant effect on the amounts
reported for health care plans. A one-percentage-point change in assumed health
care cost trend rates would have the following results:



<TABLE>
<CAPTION>

                                                                           1-PERCENTAGE-              1-PERCENTAGE-
(IN THOUSANDS)                                                            POINT INCREASE             POINT DECREASE
-------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>                        <C>
Total service and interest cost components                                   $   472                     $  373
Total postretirement benefit obligation                                      $ 2,628                     $2,136

</TABLE>


EMPLOYEE SAVINGS PLAN ("ESP")

The Company has an ESP which is a defined contribution plan. Participation in
the ESP is voluntary and all regular employees of the Company are eligible to
participate. The Company may match up to 100 percent of the participant's
contribution not to exceed six percent of the employee's base compensation. The
following table indicates the Company's contribution for the years ended
December 31:



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                              2000             1999              1998
-------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>              <C>               <C>
Employers' plan contribution                                              $1,858           $1,823            $1,938

</TABLE>


NOTE 7 - ADDITIONAL BALANCE SHEET AND STATEMENT OF OPERATIONS INFORMATION

Included in accounts receivable-trade is an allowance for doubtful accounts at
December 31:



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                                               2000              1999
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>               <C>
Allowance for doubtful accounts                                                        $      645        $    1,237

</TABLE>



Other current assets include the following at December 31:



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                                               2000              1999
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>               <C>
Deferred tax asset                                                                      $   1,079         $     859
Prepaid federal income taxes                                                            $  56,890         $  30,000

</TABLE>



Other current liabilities include the following at December 31:



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                                               2000              1999
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>               <C>
Gas imbalance liabilities                                                               $   1,348         $   2,604
Note payable unconsolidated subsidiary                                                  $                 $  23,245
Accrued interest payable                                                                $  11,949         $  10,897
Louisiana workers compensation                                                          $   5,387         $   4,751

</TABLE>


Oil and gas operations expense included the following for the years ended
December 31:



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                              2000             1999              1998 
--------------------------------------------------------------------------------------------------------------------
<S>                                                                   <C>              <C>               <C>
Lease operating expense                                               $   93,948       $  107,289        $  136,155
Workover expense                                                          21,124            5,708             6,518
Production taxes                                                          10,264            6,679             8,436
Other                                                                     (3,470)          (2,978)           (2,079)
--------------------------------------------------------------------------------------------------------------------
   Total operations expense                                           $  121,866       $  116,698        $  149,030 
--------------------------------------------------------------------------------------------------------------------

</TABLE>


                                      47


<PAGE>

Oil and gas exploration expense included the following for the years ended
December 31:



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                              2000             1999              1998
-------------------------------------------------------------------------------------------------------------------
<S>                                                                    <C>              <C>              <C>
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
-------------------------------------------------------------------------------------------------------------------

</TABLE>


During the past three years, there was no purchaser that accounted for more than
ten percent of total oil and gas sales and royalties.

NOTE 8 - IMPAIRMENT OF LONG-LIVED ASSETS

The Company follows SFAS No. 121 and any assets impaired are oil and gas
properties maintained under the successful efforts method of accounting. The
excess of the net book value over the projected discounted future net revenue of
the impaired properties is charged to "Impairment of Operating Assets." The
Company recorded no asset impairments under SFAS No. 121 during 2000 or 1999. In
December 1998, the Company recorded a $223.3 million pre-tax charge for the
write-down under SFAS No. 121 of properties due to downward reserve revisions.


















                                      48



<PAGE>

NOTE 9 - UNCONSOLIDATED SUBSIDIARY

The Company has an unconsolidated subsidiary, AMCCO, a 50 percent owned joint
venture that owns an indirect 90 percent interest in AMPCO. The Company accounts
for its interest in AMCCO using the equity method within the Company's
wholly-owned subsidiary, Samedan of North Africa, Inc. Samedan is participating
with a 50 percent expense interest (45 percent ownership net of a five percent
government carried interest) to construct a methanol plant in Equatorial Guinea.
The total projected cost of the plant and supporting facilities is estimated to
be $448 million including various contingencies and capitalized interest, with
the Company responsible for $224 million. The plant is designed to produce 2,500
metric tons of methanol per day, which equates to approximately 20,000 BBLS per
day. At this level of production, the plant would use approximately 125 MMCF of
gas per day from the Alba field as feedstock. Reserve estimates indicate the
Alba field can deliver sufficient gas for the plant to operate 30 years. The
construction contract stipulates that first production should be achieved by the
second quarter of 2001. Current marketing plans are to use two tankers, which
are under long-term contracts, to transport the methanol to markets in Europe
and the United States. On November 10, 1999, AMCCO issued $125 million of
10.875% Series A-1 Senior Secured Notes and $125 million of 8.95% Series A-2
Senior Secured Notes ("Series A-2 Notes") due 2004, which are not included in
the Company's balance sheet. The Company has guaranteed the payment of interest
on the Series A-2 Notes. In addition, the Company established a new series of
preferred stock, Series B Mandatory Convertible Preferred Stock, par value $1.00
per share (the "Series B Preferred"). The Company issued, in a private placement
pursuant to Section 4(2) of the Securities Act, 125,000 shares of the Series B
Preferred to Noble Share Trust, which is a Delaware statutory business trust, in
exchange for all of the beneficial ownership interests in Noble Share Trust.
Noble Share Trust holds the 125,000 shares of Series B Preferred for the benefit
of the holders of the Series A-2 Notes. The following are summarized financial
statements for AMCCO as of December 31:

CONSOLIDATED BALANCE SHEET
ATLANTIC METHANOL CAPITAL COMPANY



<TABLE>
<CAPTION>

(IN THOUSANDS)                                                                               2000                1999
---------------------------------------------------------------------------------------------------------------------
<S>                                                                                    <C>                 <C>
ASSETS
    Current assets                                                                     $   45,676          $   68,638
    Non-current assets                                                                    392,272             239,946
---------------------------------------------------------------------------------------------------------------------
Total assets                                                                           $  437,948          $  308,584
---------------------------------------------------------------------------------------------------------------------

LIABILITIES, MINORITY INTEREST AND MEMBERS' EQUITY
    Current liabilities                                                                $    1,197          $    3,504
    Non-current liabilities                                                               250,000             250,000
    Minority interest                                                                      36,556              22,939
    Members' equity                                                                       150,195              32,141
---------------------------------------------------------------------------------------------------------------------
Total liabilities, minority interest and members' equity                               $  437,948          $  308,584
---------------------------------------------------------------------------------------------------------------------



CONSOLIDATED STATEMENT OF OPERATIONS
ATLANTIC METHANOL CAPITAL COMPANY

(IN THOUSANDS)                                                                               2000                1999
---------------------------------------------------------------------------------------------------------------------
Interest income                                                                          $  4,389            $  2,524
Expenses:
    Interest (net of amount capitalized)                                                    1,005               1,640
    Administrative                                                                             86                    
---------------------------------------------------------------------------------------------------------------------
Net income                                                                               $  3,298            $    884
---------------------------------------------------------------------------------------------------------------------

</TABLE>



                                      49


<PAGE>

                      SUPPLEMENTAL OIL AND GAS INFORMATION
                                   (Unaudited)

There are numerous uncertainties inherent in estimating quantities of proved oil
and gas reserves. Oil and gas reserve engineering is a subjective process of
estimating underground accumulations of oil and gas that can not be precisely
measured, and estimates of engineers other than Samedan's might differ
materially from the estimates set forth herein. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of drilling, testing and
production subsequent to the date of the estimate may justify revision of such
estimate. Accordingly, reserve estimates are often different from the quantities
of oil and gas that are ultimately recovered.

PROVED GAS RESERVES (Unaudited)

The following reserve schedule was developed by the Company's reserve engineers
and sets forth the changes in estimated quantities of proved gas reserves of the
Company during each of the three years presented.



<TABLE>
<CAPTION>

                                                               NATURAL GAS AND CASINGHEAD GAS (MMCF)                   
-----------------------------------------------------------------------------------------------------------------------
                                        UNITED                           EQUATORIAL                NORTH
PROVED RESERVES AS OF:                  STATES    ARGENTINA     ECUADOR      GUINEA    ISRAEL        SEA         TOTAL 
-----------------------------------------------------------------------------------------------------------------------
<S>                                   <C>         <C>           <C>      <C>          <C>         <C>        <C> 
JANUARY 1, 2000                        759,781        5,221      87,500     384,102               26,452     1,263,056
Revisions of previous estimates         (7,022)          44                     131                7,864         1,017
Extensions, discoveries and
   other additions                     135,844                                        218,154      3,101       357,099
Production                            (136,010)        (721)                   (941)              (8,665)     (146,337)
Sale of minerals in place               (4,840)                                                                 (4,840)
Purchase of minerals in place            4,634                                                                   4,634 
-----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2000                      752,387        4,544      87,500     383,292   218,154     28,752     1,474,629 
-----------------------------------------------------------------------------------------------------------------------

PROVED RESERVES AS OF:                                                                                                 
-----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1999                        873,222        5,386                 321,642               39,056     1,239,306
Revisions of previous estimates        (15,700)         482                  63,478               (2,392)       45,868
Extensions, discoveries and
   other additions                      87,293                   87,500                              192       174,985
Production                            (150,871)        (647)                 (1,018)             (10,404)     (162,940)
Sale of minerals in place              (34,165)                                                                (34,165)
Purchase of minerals in place                2                                                                       2 
-----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1999                      759,781        5,221      87,500     384,102               26,452     1,263,056 
-----------------------------------------------------------------------------------------------------------------------

PROVED RESERVES AS OF:                                                                                                 
-----------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1998                      1,107,158        5,565                 322,205               47,287     1,482,215
Revisions of previous estimates       (155,314)          27                     396               (1,030)     (155,921)
Extensions, discoveries and
   other additions                      71,061                                                                  71,061
Production                            (196,220)        (206)                   (959)              (7,201)     (204,586)
Sale of minerals in place               (2,232)                                                                 (2,232)
Purchase of minerals in place           48,769                                                                  48,769 
-----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998                      873,222        5,386                 321,642               39,056     1,239,306 
-----------------------------------------------------------------------------------------------------------------------

PROVED DEVELOPED GAS RESERVES AS OF:                                                                                   
-----------------------------------------------------------------------------------------------------------------------
   January 1, 2001                     690,301        4,544                 383,292               25,652     1,103,789
   January 1, 2000                     703,166        5,221                  11,687               26,452       746,526
   January 1, 1999                     818,787        5,386                  12,862               39,056       876,091
   January 1, 1998                   1,022,192        5,565                  13,425               47,287     1,088,469
                  

</TABLE>


-----------------

                                      50


<PAGE>

PROVED OIL RESERVES (Unaudited)

The following reserve schedule was developed by the Company's reserve engineers
and sets forth the changes in estimated quantities of proved oil reserves of the
Company during each of the three years presented.



<TABLE>
<CAPTION>

                                                           CRUDE OIL AND CONDENSATE (BBLS IN THOUSANDS)               
-----------------------------------------------------------------------------------------------------------------------
                                          UNITED                                EQUATORIAL         NORTH
PROVED RESERVES AS OF:                    STATES      ARGENTINA       CHINA         GUINEA           SEA          TOTAL
-----------------------------------------------------------------------------------------------------------------------
<S>                                       <C>         <C>             <C>       <C>               <C>           <C>
JANUARY 1, 2000                           65,523         10,285       9,768         30,684         5,786        122,046
Revisions of previous estimates           (1,493)            68                        185          (366)        (1,606)
Extensions, discoveries and
   other additions                        12,788                                    17,491         5,731         36,010
Production                                (7,309)          (916)                      (914)         (654)        (9,793)
Sale of minerals in place                   (935)                                                   (229)        (1,164)
Purchase of minerals in place              1,126                                                   2,150          3,276 
------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2000                         69,700          9,437       9,768         47,446        12,418        148,769 
------------------------------------------------------------------------------------------------------------------------

PROVED RESERVES AS OF:                                                                                                  
------------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1999                           77,306         11,128                     22,001         6,146        116,581
Revisions of previous estimates           (1,394)           (24)                     9,617           (57)         8,142
Extensions, discoveries and
   other additions                         3,687                      9,768                          354         13,809
Production                                (8,952)          (819)                      (934)         (657)       (11,362)
Sale of minerals in place                 (5,125)                                                                (5,125)
Purchase of minerals in place                  1                                                                      1 
------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1999                         65,523         10,285       9,768         30,684         5,786        122,046 
------------------------------------------------------------------------------------------------------------------------

PROVED RESERVES AS OF:                                                                                                  
------------------------------------------------------------------------------------------------------------------------
JANUARY 1, 1998                           89,065         11,997                     22,766         7,035        130,863
Revisions of previous estimates           (5,935)            16                        166          (129)        (5,882)
Extensions, discoveries and
   other additions                         4,802                                                      35          4,837
Production                               (11,540)          (885)                      (931)         (795)       (14,151)
Sale of minerals in place                   (155)                                                                  (155)
Purchase of minerals in place              1,069                                                                  1,069 
------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1998                         77,306         11,128                     22,001         6,146        116,581 
------------------------------------------------------------------------------------------------------------------------

PROVED DEVELOPED OIL RESERVES AS OF:                                                                                    
------------------------------------------------------------------------------------------------------------------------
   January 1, 2001                        58,903          9,437       9,768         47,446         5,728        131,282
   January 1, 2000                        60,618         10,285       9,768         14,743         3,986         99,400
   January 1, 1999                        72,949         11,128                     11,425         4,346         99,848
   January 1, 1998                        82,713         11,997                     12,191         5,234        112,135
                  
</TABLE>


PROVED RESERVES. Proved reserves are estimated quantities of crude oil, natural
gas, natural gas liquids and condensate liquids which geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions.

PROVED DEVELOPED RESERVES. Proved developed reserves are proved reserves which
are expected to be recovered through existing wells with existing equipment and
operating methods.



                                      51



<PAGE>

OIL AND GAS OPERATIONS (Unaudited)

Aggregate results of operations for each period ended December 31, in connection
with the Company's oil and gas producing activities are shown below. Amounts are
presented in accordance with SFAS No. 19, and may not agree with amounts
determined using traditional industry definitions.


<TABLE>
<CAPTION>

(IN THOUSANDS)                                                                                                        
-----------------------------------------------------------------------------------------------------------------------------
                                      UNITED                                 EQUATORIAL     NORTH      OTHER
DECEMBER 31, 2000                     STATES       ARGENTINA      ECUADOR      GUINEA        SEA       INT'L         TOTAL  
-----------------------------------------------------------------------------------------------------------------------------
<S>                                  <C>           <C>            <C>        <C>          <C>         <C>         <C>
Revenues                             $ 705,270     $  25,298      $          $  25,501    $  35,284   $           $ 791,353 
Production costs                       129,359         6,952                     5,010        5,962                 147,283
Exploration expenses                    78,955           179          (4)          121        2,739      2,575       84,565
DD&A and valuation provision           222,161         7,796          47         1,355       12,231        449      244,039 
-----------------------------------------------------------------------------------------------------------------------------
Income (loss)                          274,795        10,371         (43)       19,015       14,352     (3,024)     315,466
Income tax expense (benefit)            96,675         6,048         (15)        8,978        4,316     (1,000)     115,002 
-----------------------------------------------------------------------------------------------------------------------------
Result of operations from pro-
   ducing activities (excluding
   corporate overhead and interest
   costs)                            $ 178,120     $   4,323      $  (28)    $  10,037    $  10,036   $ (2,024)   $ 200,464 
-----------------------------------------------------------------------------------------------------------------------------

DECEMBER 31, 1999                                                                                                     
-----------------------------------------------------------------------------------------------------------------------------
Revenues                             $ 493,718     $  14,302      $          $  16,036    $  24,677   $           $ 548,733
Production costs                       125,803         4,640                     3,183        7,106                 140,732
Exploration expenses                    45,461           542         130           196        4,270      2,779       53,378
DD&A and valuation provision           231,157         6,401          16         3,212       19,687        849      261,322 
-----------------------------------------------------------------------------------------------------------------------------
Income (loss)                           91,297         2,719        (146)        9,445       (6,386)    (3,628)      93,301
Income tax expense (benefit)            31,646         1,651                     4,428         (733)    (1,094)      35,898 
-----------------------------------------------------------------------------------------------------------------------------
Result of operations from pro-
   ducing activities (excluding
   corporate overhead and interest
   costs)                            $  59,651     $   1,068      $ (146)    $   5,017    $  (5,653)  $ (2,534)   $  57,403 
-----------------------------------------------------------------------------------------------------------------------------

DECEMBER 31, 1998
-----------------------------------------------------------------------------------------------------------------------------
Revenues                             $ 564,771     $   9,105      $          $  10,282    $  25,006   $           $ 609,164
Production costs                       154,594         6,274                     2,962        9,044                 172,874
Exploration expenses                    90,614            87                       658        5,828      9,987      107,174
DD&A and valuation provision           513,725         6,083                     2,998       13,869         46      536,721*
-----------------------------------------------------------------------------------------------------------------------------
Income (loss)                         (194,162)       (3,339)                    3,664       (3,735)   (10,033)    (207,605)
Income tax expense (benefit)           (68,764)       (1,822)                    1,786         (794)    (2,489)     (72,083)
-----------------------------------------------------------------------------------------------------------------------------
Result of operations from pro-
   ducing activities (excluding
   corporate overhead and interest
   costs)                            $(125,398)    $  (1,517)     $          $   1,878    $  (2,941)  $ (7,544)   $(135,522)
-----------------------------------------------------------------------------------------------------------------------------
</TABLE>


     *Includes a pre-tax charge of $223.3 million pursuant to SFAS No. 121.


                                      52

<PAGE>

COSTS INCURRED IN OIL AND GAS ACTIVITIES (Unaudited)

Costs incurred in connection with the Company's oil and gas acquisition,
exploration and development activities for each of the years are shown below.
Amounts are presented in accordance with SFAS No. 19, and may not agree with
amounts determined using traditional industry definitions.


<TABLE>
<CAPTION>

(IN THOUSANDS)                                                                                                       
---------------------------------------------------------------------------------------------------------------------
                                 UNITED                  EQUATORIAL                NORTH      OTHER
DECEMBER 31, 2000                STATES      ECUADOR       GUINEA      ISRAEL       SEA       INT'L          TOTAL
---------------------------------------------------------------------------------------------------------------------
<S>                            <C>           <C>         <C>          <C>        <C>         <C>          <C>
Property acquisition costs
   Proved                      $   6,822     $            $           $ 50,861   $ 41,284    $            $  98,967
   Unproved                       12,559                                 1,927      2,218         858        17,562
---------------------------------------------------------------------------------------------------------------------
Total                          $  19,381     $            $           $ 52,788   $ 43,502    $    858     $ 116,529
---------------------------------------------------------------------------------------------------------------------
Exploration costs              $ 115,728     $     (4)    $     62    $ 11,387   $  1,396    $  2,139     $ 130,708
---------------------------------------------------------------------------------------------------------------------
Development costs              $ 180,339     $ 35,078     $ 36,820    $  1,502   $  2,219    $  9,570     $ 265,528
---------------------------------------------------------------------------------------------------------------------

DECEMBER 31, 1999                                                                                                    
---------------------------------------------------------------------------------------------------------------------
Property acquisition costs
   Proved                      $      69     $            $           $          $           $            $      69
   Unproved                        7,280                                                          620         7,900
---------------------------------------------------------------------------------------------------------------------
Total                          $   7,349     $            $           $          $           $    620     $   7,969
---------------------------------------------------------------------------------------------------------------------
Exploration costs              $  43,999     $    130     $    123    $          $  3,229    $  7,722     $  55,203
---------------------------------------------------------------------------------------------------------------------
Development costs              $  48,042     $  2,569     $  1,748    $          $  4,972    $  4,863     $  62,194
---------------------------------------------------------------------------------------------------------------------

DECEMBER 31, 1998                                                                                                    
---------------------------------------------------------------------------------------------------------------------
Property acquisition costs
   Proved                      $  48,444     $            $           $          $           $            $  48,444
   Unproved                       36,760                                              311         500        37,571
---------------------------------------------------------------------------------------------------------------------
Total                          $  85,204     $            $           $          $    311    $    500     $  86,015
---------------------------------------------------------------------------------------------------------------------
Exploration costs              $ 132,958     $            $    465    $          $  5,328    $ 10,136     $ 148,887
---------------------------------------------------------------------------------------------------------------------
Development costs              $ 242,838     $            $ 10,977    $          $  9,761    $ 18,169     $ 281,745
---------------------------------------------------------------------------------------------------------------------
</TABLE>


AGGREGATE CAPITALIZED COSTS (Unaudited)

Aggregate capitalized costs relating to the Company's oil and gas producing
activities, and related accumulated DD&A, as of December 31 are shown below:


<TABLE>
<CAPTION>
                                                        2000                                    1999                 
                                     --------------------------------------  ----------------------------------------
(IN THOUSANDS)                           U. S.       INT'L         TOTAL         U. S.       INT'L          TOTAL 
---------------------------------------------------------------------------------------------------------------------
<S>                                 <C>           <C>         <C>            <C>            <C>        <C>
Unproved oil and gas properties     $     80,750  $   69,462  $    150,212   $     79,823   $  13,288  $      93,111
Proved oil and gas properties          2,598,115     464,896     3,063,011      2,389,937     303,800      2,693,737 
---------------------------------------------------------------------------------------------------------------------
                                       2,678,865     534,358     3,213,223      2,469,760     317,088      2,786,848
Accumulated DD&A                      (1,637,659)   (107,534)   (1,745,193)    (1,471,889)    (88,154)    (1,560,043)
---------------------------------------------------------------------------------------------------------------------
Net capitalized costs               $  1,041,206  $  426,824  $  1,468,030   $    997,871   $ 228,934   $  1,226,805 
---------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      53

<PAGE>


STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED 
OIL AND GAS RESERVES (Unaudited)

The following information is based on the Company's best estimate of the
required data for the Standardized Measure of Discounted Future Net Cash Flows
as of December 31, 2000, 1999 and 1998 in accordance with SFAS No. 69. The
Standard requires the use of a 10 percent discount rate. This information is not
the fair market value nor does it represent the expected present value of future
cash flows of the Company's proved oil and gas reserves.


<TABLE>
<CAPTION>
                                         UNITED                 EQUATORIAL               NORTH     OTHER
DECEMBER 31, 2000                        STATES      ECUADOR      GUINEA    ISRAEL        SEA      INT'L      TOTAL
---------------------------------------------------------------------------------------------------------------------
(IN MILLIONS OF DOLLARS)
<S>                                    <C>           <C>        <C>         <C>         <C>        <C>      <C>
Future cash inflows                    $  8,825      $  305     $  1,125    $  524      $  379     $  462   $  11,620
Future production and
    development costs                     1,759          90          178        92          89        186       2,394
Future income tax expenses                1,909          58          256       117          78         74       2,492
---------------------------------------------------------------------------------------------------------------------
Future net cash flows                     5,157         157          691       315         212        202       6,734
10% annual discount for
    estimated timing of cash flows        2,037          62          273       124          84         80       2,660
---------------------------------------------------------------------------------------------------------------------
Standardized measure of
    discounted future net
    cash flows                         $  3,120      $   95     $    418    $  191      $  128     $  122   $   4,074
---------------------------------------------------------------------------------------------------------------------

DECEMBER 31, 1999                                                                                                    
---------------------------------------------------------------------------------------------------------------------
(IN MILLIONS OF DOLLARS)
Future cash inflows                    $  3,565      $  320     $    779    $           $  181     $  463   $   5,308
Future production and
    development costs                     1,566          73          189                    85        207       2,120
Future income tax expenses                  376          46          111                    18         49         600
---------------------------------------------------------------------------------------------------------------------
Future net cash flows                     1,623         201          479                    78        207       2,588
10% annual discount for
    estimated timing of cash flows          686          85          203                    33         88       1,095
---------------------------------------------------------------------------------------------------------------------
Standardized measure of
    discounted future net
    cash flows                         $    937      $  116     $    276    $           $   45     $  119   $   1,493
---------------------------------------------------------------------------------------------------------------------

DECEMBER 31, 1998                                                                                                    
---------------------------------------------------------------------------------------------------------------------
(IN MILLIONS OF DOLLARS)
Future cash inflows                    $  2,647      $          $    301    $           $  113     $   96   $   3,157
Future production and
    development costs                     1,146                      140                    62         30       1,378
Future income tax expenses                  182                       19                     6          8         215
---------------------------------------------------------------------------------------------------------------------
Future net cash flows                     1,319                      142                    45         58       1,564
10% annual discount for
    estimated timing of cash flows          490                       53                    17         22         582
---------------------------------------------------------------------------------------------------------------------
Standardized measure of
    discounted future net
    cash flows                         $    829      $          $     89    $           $   28     $   36   $     982
---------------------------------------------------------------------------------------------------------------------
</TABLE>


Construction of AMPCO's Equatorial Guinea methanol plant is scheduled to be
completed in the second quarter of 2001. The future net cash inflows for 1998,
1999 and 2000 do not include cash flows relating to the Company's anticipated
future methanol sales. For more information regarding Samedan's methanol plant,
see Item 1. "Business--Unconsolidated Subsidiary" and Item 2. "Properties--Oil
and Gas" of this Form 10-K.

                                      54


<PAGE>

Future cash inflows are estimated by applying year-end prices of oil and gas
relating to the Company's proved reserves to the year-end quantities of those
reserves, with consideration given to the effect of existing hedging contracts,
if any.

The year-end NYMEX West Texas intermediate crude oil price utilized in the
computation of future cash inflows was $26.83 per BBL, which was adjusted by
differentials applied on a property-by-property basis to yield a weighted
average price of $24.27 per BBL. The West Texas intermediate crude oil price, as
of February 28, 2001, was $27.38 per BBL, an increase of $.55 per BBL compared
to year-end 2000. The Company estimates that a $1.00 per BBL change in the
average oil price from the year-end price would change discounted future net
cash flows before income taxes by approximately $76 million.

The year-end Henry Hub natural gas price utilized in the computation of future
cash inflows was $10.53 per MCF, which was adjusted by differentials applied on
a property-by-property basis to yield a weighted average price of $9.14 per MCF.
As of February 28, 2001, natural gas index prices at Henry Hub had decreased
approximately $5.36 per MCF to $5.17 per MCF compared with the year-end price.
The Company estimates that a $.10 per MCF change in the average gas price from
the year-end price would change discounted future net cash flows before income
taxes by approximately $45 million.

Future production and development costs, which include dismantlement and
restoration expense, are computed by estimating the expenditures to be incurred
in developing and producing the Company's proved oil and gas reserves at the end
of the year, based on year-end costs, and assuming continuation of existing
economic conditions.

Future income tax expenses are computed by applying the appropriate year-end
statutory tax rates to the estimated future pretax net cash flows relating to
the Company's proved oil and gas reserves, less the tax bases of the properties
involved. The future income tax expenses give effect to tax credits and
allowances, but do not reflect the impact of general and administrative costs
and exploration expenses of ongoing operations relating to the Company's proved
oil and gas reserves.

At December 31, 2000, the Company had estimated gas imbalance receivables of
$18.5 million and estimated gas imbalance liabilities of $14.2 million; at
year-end 1999, $17.9 million in receivables and $12.0 million in liabilities;
and at year-end 1998, $19.1 million in receivables and $14.8 million in
liabilities. Neither the gas imbalance receivables nor gas imbalance liabilities
have been included in the standardized measure of discounted future net cash
flows as of each of the three years ended December 31, 2000, 1999 and 1998.

                                      55


<PAGE>

SOURCES OF CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS (Unaudited)

Principal changes in the aggregate standardized measure of discounted future net
cash flows attributable to the Company's proved oil and gas reserves, as
required by Financial Accounting Standards Board's SFAS No. 69, at year end are
shown below.



<TABLE>
<CAPTION>

(IN MILLIONS)                                                               2000             1999              1998 
--------------------------------------------------------------------------------------------------------------------
<S>                                                                     <C>                <C>              <C>
Standardized measure of discounted
   future net cash flows at the beginning
   of the year                                                          $  1,493           $  982           $ 1,352
Extensions, discoveries and improved
   recovery, less related costs                                            1,462              410                39
Revisions of previous quantity estimates                                     (20)              89              (132)
Changes in estimated future
   development costs                                                         (52)            (202)              (17)
Purchases (sales) of minerals in place                                        69              (58)               46
Net changes in prices and production costs                                 2,448              673              (443)
Accretion of discount                                                        185              102               189
Sales of oil and gas produced, net of
   production costs                                                         (662)            (425)             (454)
Development costs incurred during
   the period                                                                172               21               127
Net change in income taxes                                                (1,207)            (317)              503
Change in timing of estimated future
   production, and other                                                     186              218              (228)
--------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted
   future net cash flows at the end
   of the year                                                          $  4,074           $1,493           $   982 
--------------------------------------------------------------------------------------------------------------------

</TABLE>


INTERIM FINANCIAL INFORMATION (Unaudited)

Interim financial information for the years ended December 31, 2000 and 1999 is
as follows:



<TABLE>
<CAPTION>

                                                                            QUARTER ENDED                       
                                                    ---------------------------------------------------------------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)               MAR. 31,          JUNE 30,        SEPT. 30,          DEC. 31,
-------------------------------------------------------------------------------------------------------------------
<S>                                                 <C>               <C>              <C>               <C>
2000
Revenues                                            $  268,872        $  301,777       $  357,353        $  453,284
Gross profit from operations                        $   49,444        $   68,025       $   97,489        $  103,399
Net income                                          $   26,880        $   36,861       $   57,217        $   70,640
Basic earnings per share                            $      .48        $      .66       $     1.02        $     1.26
Diluted earnings per share                          $      .47        $      .65       $     1.01        $     1.24
1999
Revenues                                            $  175,865        $  216,245       $  241,971        $  252,698
Gross profit from operations                        $      128        $   22,959       $   41,453        $   38,087
Net income (loss)                                   $   (8,901)       $    9,179       $   27,654        $   21,529
Basic earnings per share                            $     (.16)       $      .16       $      .49        $      .38
Diluted earnings per share                          $     (.16)       $      .16       $      .48        $      .38

</TABLE>



I
TEM 9.       CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND 
              FINANCIAL DISCLOSURE.

Not applicable.



                                      56


<PAGE>


                                    PART III


ITEM 10.      DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

The section entitled "Election of Directors" in the Registrant's proxy statement
for the 2001 annual meeting of stockholders sets forth certain information with
respect to the directors of the Registrant and is incorporated herein by
reference. Certain information with respect to the executive officers of the
Registrant is set forth under the caption "Executive Officers of the Registrant"
in Part I of this report.

The section entitled "Section 16(a) Beneficial Ownership Reporting Compliance"
in the Registrant's proxy statement for the 2001 annual meeting of stockholders
sets forth certain information with respect to compliance with Section 16(a) of
the Securities Exchange Act of 1934, as amended, and is incorporated herein by
reference.


ITEM 11.      EXECUTIVE COMPENSATION.

The section entitled "Executive Compensation" in the Registrant's proxy
statement for the 2001 annual meeting of stockholders sets forth certain
information with respect to the compensation of management of the Registrant,
and except for the report of the Compensation, Benefits and Stock Option
Committee of the Board of Directors and the information therein under "Executive
Compensation--Performance Graph" is incorporated herein by reference.


ITEM 12.      SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

The sections entitled "Security Ownership of Certain Beneficial Owners" and
"Security Ownership of Directors and Executive Officers" in the Registrant's
proxy statement for the 2001 annual meeting of stockholders set forth certain
information with respect to the ownership of the Registrant's common stock and
are incorporated herein by reference.


ITEM 13.      CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

The section entitled "Certain Transactions" in the Registrant's proxy statement
for the 2001 annual meeting of stockholders sets forth certain information with
respect to certain relationships and related transactions, and is incorporated
herein by reference.


                                     PART IV


ITEM 14.      FINANCIAL STATEMENT SCHEDULES, EXHIBITS AND REPORTS ON FORM 8-K.

      (a)     The following documents are filed as a part of this report:

              (1) Financial Statements and Financial Statement Schedules and 
                  Supplementary Data: These documents are listed in the Index to
                  Consolidated Financial Statements in Item 8 hereof.

              (2) Exhibits: The exhibits required to be filed by this Item 14 
                  are set forth in the Index to Exhibits accompanying this 
                  report.

      (b)     The Registrant made no filings on Form 8-K during 2000.



                                      57


<PAGE>


                                   SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.


                                       NOBLE AFFILIATES, INC.

Date: March 12, 2001                   By: /s/ James L. McElvany                
                                       -----------------------------------------
                                       James L. McElvany,
                                       Vice President-Finance and Treasurer


Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the dates indicated.



<TABLE>
<CAPTION>

Signature                                          Capacity in which signed                       Date
---------                                          ------------------------                       ----
<S>                                                <C>                                       <C>
/s/ Robert Kelley                                  Chairman of the Board                     March 12, 2001
------------------------------------
Robert Kelley

/s/ Charles D. Davidson                            President, Chief Executive Officer        March 12, 2001
------------------------------------               and Director (Principal Executive
Charles D. Davidson                                Officer)
                                                   

/s/ James L. McElvany                              Vice President-Finance and Treasurer      March 12, 2001
------------------------------------               (Principal Financial and Accounting
James L. McElvany                                  Officer)
                                                   

/s/ Alan A. Baker                                  Director                                  March 12, 2001
------------------------------------
Alan A. Baker

/s/ Michael A. Cawley                              Director                                  March 12, 2001
------------------------------------
Michael A. Cawley

/s/ Edward F. Cox                                  Director                                  March 12, 2001
------------------------------------
Edward F. Cox

/s/ Thomas E. Hassen                               Director                                  March 12, 2001
------------------------------------
Thomas E. Hassen

/s/ Dale P. Jones                                  Director                                  March 12, 2001
------------------------------------
Dale P. Jones

/s/ Harold F. Kleinman                             Director                                  March 12, 2001
------------------------------------
Harold F. Kleinman

/s/ T. Don Stacy                                   Director                                  March 12, 2001
------------------------------------
T. Don Stacy

</TABLE>




                                                          58

<PAGE>


<TABLE>
<CAPTION>

                                INDEX TO EXHIBITS

Exhibit
Number                               Exhibit **
-------                              -------
<S>   <C> <C>
 3.1  --  Certificate of Incorporation, as amended, of the Registrant as currently
          in effect (filed as Exhibit 3.2 to the Registrant's Annual Report on Form
          10-K for the year ended December 31, 1987 and incorporated herein by
          reference).

 3.2  --  Certificate of Designations of Series A Junior Participating Preferred
          Stock of the Registrant dated August 27, 1997 (filed Exhibit A of Exhibit
          4.1 to the Registrant's Registration Statement on Form 8-A filed on
          August 28, 1997 and incorporated herein by reference).

 3.3  --  Composite copy of Bylaws of the Registrant as currently in effect (filed
          as Exhibit 3.4 to the Registrant's Annual Report on Form 10-K for the
          year ended December 31, 1997 and incorporated herein by reference).

 3.4  --  Certificate of Designations of Series B Mandatorily Convertible
          Preferred Stock of the Registrant dated November 9, 1999.

 4.1  --  Indenture dated as of October 14, 1993 between the Registrant and U.S.
          Trust Company of Texas, N.A., as Trustee, relating to the Registrant's 
          7 1/4% Notes Due 2023, including form of the Registrant's 7 1/4% Notes Due
          2023 (filed as Exhibit 4.1 to the Registrant's Quarterly Report on Form
          10-Q for the quarter ended September 30, 1993 and incorporated herein by
          reference).

 4.2  --  Indenture relating to Senior Debt Securities dated as of April 1, 1997
          between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee
          (filed as Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q
          for the quarter ended March 31, 1997 and incorporated herein by 
          reference).

 4.3  --  First Indenture Supplement relating to $250 million of the Registrant's
          8% Senior Notes Due 2027 dated as of April 1, 1997 between the Registrant
          and U.S. Trust Company of Texas, N.A., as Trustee (filed as Exhibit 4.2
          to the Registrant's Quarterly Report on Form 10-Q for the quarter ended
          March 31, 1997 and incorporated herein by reference).

 4.4  --  Second Indenture Supplement, between the Company and U.S. Trust Company
          of Texas, N.A. as trustee, relating to $100 million of the Registrant's 
          7 1/4% Senior Debentures Due 2097 dated as of August 1, 1997 (filed as
          Exhibit 4.1 to the Registrant's Quarterly Report on Form 10-Q for the
          quarter ended June 30, 1997 and incorporated herein by reference).

 4.5  --  Rights Agreement, dated as of August 27, 1997, between the Registrant
          and Liberty Bank and Trust Company of Oklahoma City, N.A., as Right's 
          Agent (filed as Exhibit 4.1 to the Registrant's Registration Statement 
          on Form 8-A filed on August 28, 1997 and incorporated herein by 
          reference).

 4.6  --  Amendment No. 1 to Rights Agreement dated as of December 8, 1998,
          between the Registrant and Bank One Trust Company, as successor Rights
          Agent to Liberty Bank and Trust Company of Oklahoma City, N.A. (filed as
          Exhibit 4.2 to the Registrant's Registration Statement on Form 8-A/A
          (Amendment No. 1) filed on December 14, 1998 and incorporated herein by
          reference).

10.1* --  Samedan Oil Corporation Bonus Plan, as amended and restated on
          September 24, 1996 (filed as Exhibit 10.1 to the Registrant's Annual Report
          on Form 10-K for the fiscal year ended December 31, 1996 and incorporated
          herein by reference).

10.2* --  Restoration of Retirement Income Plan for certain participants in the
          Noble Affiliates Retirement Plan dated September 21, 1994, effective as of
          May 19, 1994 (filed as Exhibit 10.5 to the Registrant's Annual Report on
          Form 10-K for the year ended December 31, 1994 and incorporated herein by
          reference).


                                       59

<PAGE>


Exhibit
Number                               Exhibit **
------                               -------

10.3* --  Noble Affiliates Thrift Restoration Plan dated May 9, 1994 (filed as
          Exhibit 10.6 to the Registrant's Annual Report on Form 10-K for the fiscal
          year ended December 31, 1994 and incorporated herein by reference).

10.4* --  Noble Affiliates Restoration Trust dated September 21, 1994, effective
          as of October 1, 1994 (filed as Exhibit 10.7 to the Registrant's Annual
          Report on Form 10-K for the fiscal year ended December 31, 1994 and
          incorporated herein by reference).

10.5* --  Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock Plan, as
          amended and restated, dated November 2, 1992 (filed as Exhibit 4.1 to the
          Registrant's Registration Statement on Form S-8 (Registration No. 33-54084)
          and incorporated herein by reference).

10.6* --  1982 Stock Option Plan of the Registrant (filed as Exhibit 4.1 to the
          Registrant's Registration Statement on Form S-8 (Registration No. 2-81590)
          and incorporated herein by reference).

10.7* --  Amendment No. 1 to the 1982 Stock Option Plan of the Registrant (filed
          as Exhibit 4.2 to the Registrant's Registration Statement on Form S-8
          (Registration No. 2-81590) and incorporated herein by reference).

10.8* --  Amendment No. 2 to the 1982 Stock Option Plan of the Registrant (filed
          as Exhibit 10.11 to the Registrant's Annual Report on Form 10-K for the
          year ended December 31, 1995 and incorporated herein by reference).

10.9* --  1988 Nonqualified Stock Option Plan for Non-Employee Directors of the
          Registrant, as amended and restated, effective as of January 30, 1996
          (filed as Exhibit 10.13 to the Registrant's Annual Report on Form 10-K for
          the year ended December 31, 1996 and incorporated herein by reference).

10.10* -- Form of Indemnity Agreement entered into between the Registrant and
          each of the Registrant's directors and bylaw officers (filed as Exhibit
          10.18 to the Registrant's Annual Report of Form 10-K for the year ended
          December 31, 1995 and incorporated herein by reference).

10.11 --  Guaranty of the Registrant dated October 28, 1982, guaranteeing certain
          obligations of Samedan (filed as Exhibit 10.12 to the Registrant's Annual
          Report on Form 10-K for the year ended December 31, 1993 and incorporated
          herein by reference).

10.12 --  Stock Purchase Agreement dated as of July 1, 1996, between Samedan Oil
          Corporation and Enterprise Diversified Holdings Incorporated (filed as
          Exhibit 2.1 to the Registrant's Current Report on Form 8-K (Date of Event:
          July 31, 1996) dated August 13, 1996 and incorporated herein by reference).

10.13* -- Noble Affiliates, Inc. 1992 Stock Option and Restricted Stock Plan, as
          amended and restated on December 10, 1996, subject to the approval of
          stockholders (filed as Exhibit 10.21 to the Registrant's Annual Report on
          Form 10-K for the year ended December 31, 1996 and incorporated herein by
          reference).

10.14 --  Amended and Restated Credit Agreement dated as of December 24, 1997
          among the Registrant, as borrower, and Union Bank of Switzerland, Houston
          agency, as the agent for the lender, and NationsBank of Texas, N.A. and
          Texas Commerce Bank National Association, as managing agents, and Bank of
          Montreal, CIBC Inc., The First National Bank of Chicago, Royal Bank of
          Canada, and Societe Generale, Southwest agency, as co-agents, and certain
          commercial lending institutions, as lenders (filed as Exhibit 10.20 to the
          Registrant's Annual Report on Form 10-K for the fiscal year ended December
          31, 1997 and incorporated herein by reference).


                                      60

<PAGE>


Exhibit
Number                                               Exhibit **
------                                               -------

10.15  -- Noble Preferred Stock Remarketing and Registration Rights Agreement
          dated as of November 10, 1999 by and among the Registrant, Noble Share
          Trust, The Chase Manhattan Bank, and Donaldson, Lufkin & Jenrette
          Securities Corporation (filed as Exhibit 10.15 to the Registrant's Annual
          Report on Form 10-K for the year ended December 31, 1999 and incorporated
          herein by reference).

10.16* -- Employment Agreement effective as of October 2, 2000 between Noble
          Affiliates, Inc. and Charles D. Davidson.

21     -- Subsidiaries.

23     -- Consent of Arthur Andersen LLP for inclusion of their report in this
          Form 10-K.



        * Management contract or compensatory plan or arrangement required
          to be filed as an exhibit hereto.

       ** Copies of exhibits will be furnished upon prepayment of 25 cents
          per page. Requests should be addressed to the Vice
          President-Finance and Treasurer, Noble Affiliates, Inc., 350
          Glenborough Drive, Suite 100, Houston, Texas 77067.

</TABLE>



















                                      61

<PAGE>


DIRECTORS

ROBERT KELLEY
CHAIRMAN OF THE BOARD,
NOBLE AFFILIATES, INC.

CHARLES D. DAVIDSON
PRESIDENT AND CHIEF EXECUTIVE OFFICER,
NOBLE AFFILIATES, INC.

ALAN A. BAKER
CONSULTANT AND FORMER CHAIRMAN AND
CHIEF EXECUTIVE OFFICER,
HALLIBURTON ENERGY SERVICES

MICHAEL A. CAWLEY
TRUSTEE, PRESIDENT AND CHIEF EXECUTIVE OFFICER,
THE SAMUEL ROBERTS NOBLE FOUNDATION, INC.

EDWARD F. COX
PARTNER, LAW FIRM OF
PATTERSON, BELKNAP, WEBB AND TYLER

THOMAS E. HASSEN
MANAGING DIRECTOR, CO-HEAD
GLOBAL ENERGY RESOURCES GROUP,
CREDIT SUISSE FIRST BOSTON CORPORATION

DALE P. JONES
CONSULTANT AND FORMER VICE CHAIRMAN AND
PRESIDENT, HALLIBURTON COMPANY

HAROLD F. KLEINMAN
OF COUNSEL, LAW FIRM OF
THOMPSON & KNIGHT L.L.P.

T. DON STACY
FORMER CHAIRMAN AND
PRESIDENT, AMOCO EURASIA PETROLEUM CO.


DIRECTORS EMERITI

GEORGE J. MCLEOD
JOHN F. SNODGRASS
JACK D. WILKES

EXECUTIVE OFFICERS

ROBERT KELLEY
CHAIRMAN OF THE BOARD,
NOBLE AFFILIATES, INC.

CHARLES D. DAVIDSON
PRESIDENT AND CHIEF EXECUTIVE OFFICER,
NOBLE AFFILIATES, INC.

ALAN R. BULLINGTON
VICE PRESIDENT AND GENERAL MANAGER,
INTERNATIONAL DIVISION OF SAMEDAN OIL CORPORATION

ROBERT K. BURLESON
PRESIDENT,
NOBLE GAS MARKETING, INC.

DAN O. DINGES
SENIOR VICE PRESIDENT AND GENERAL MANAGER,
OFFSHORE DIVISION OF SAMEDAN OIL CORPORATION

ALBERT D. HOPPE
SENIOR VICE PRESIDENT, GENERAL COUNSEL,
AND SECRETARY,
NOBLE AFFILIATES, INC.

JAMES L. MCELVANY
VICE PRESIDENT, CHIEF FINANCIAL OFFICER,
TREASURER, AND ASSISTANT SECRETARY,
NOBLE AFFILIATES, INC.

RICHARD A. PENEGUY, JR.
VICE PRESIDENT AND GENERAL MANAGER,
ONSHORE DIVISION OF SAMEDAN OIL CORPORATION

W. A. POILLION
SENIOR VICE PRESIDENT-PRODUCTION AND DRILLING,
SAMEDAN OIL CORPORATION

KENNETH P. WILEY
VICE PRESIDENT-INFORMATION SYSTEMS,
NOBLE AFFILIATES, INC.



                                      62

<PAGE>


CORPORATE AND SUBSIDIARY OFFICES
NOBLE AFFILIATES, INC.

CORPORATE HEADQUARTERS
350 GLENBOROUGH DRIVE
SUITE 100
HOUSTON, TEXAS 77067
(281) 872-3100

INVESTOR RELATIONS
WILLIAM R. MCKOWN III
ASSISTANT TREASURER
(281) 872-3100
INVESTOR_RELATIONS@SAMEDAN.COM
WWW.NOBLEAFF.COM


SUBSIDIARY HEADQUARTERS

SAMEDAN OIL CORPORATION
350 GLENBOROUGH DRIVE
SUITE 100
HOUSTON, TEXAS 77067

NOBLE GAS MARKETING, INC.
350 GLENBOROUGH DRIVE
SUITE 180
HOUSTON, TEXAS 77067

NOBLE TRADING, INC.
110 WEST BROADWAY
POST OFFICE BOX 909
ARDMORE, OKLAHOMA 73402


OPERATIONAL OFFICES

DOMESTIC OFFSHORE
SAMEDAN OIL CORPORATION
350 GLENBOROUGH DRIVE
SUITE 240
HOUSTON, TEXAS 77067

DOMESTIC ONSHORE
SAMEDAN OIL CORPORATION
12600 NORTHBOROUGH DRIVE
SUITE 250
HOUSTON, TEXAS 77067

INTERNATIONAL
SAMEDAN OIL CORPORATION
350 GLENBOROUGH DRIVE
SUITE 300
HOUSTON, TEXAS 77067

INDEPENDENT PUBLIC ACCOUNTANTS
ARTHUR ANDERSEN LLP
OKLAHOMA CITY, OKLAHOMA

TRANSFER AGENT AND REGISTRAR
FIRST CHICAGO TRUST COMPANY OF NEW YORK
A DIVISION OF EQUISERVE
POST OFFICE BOX 2500
JERSEY CITY, NEW JERSEY 07303
(800) 317-4445
WWW.EQUISERVE.COM
HEARING IMPAIRED (201) 222-4955

COMMON STOCK LISTED
NEW YORK STOCK EXCHANGE
SYMBOL - NBL



-------------------------------------------------------------------------------
ANNUAL MEETING
The Annual Meeting of Stockholders of Noble Affiliates, will be held on 
Tuesday, April 24, 2001, 9:30 a.m. at the Wyndham Greenspoint Hotel located at 
12400 Greenspoint Drive in Houston, Texas. All stockholders are cordially 
invited to attend.

FORM 10-K
The Company's Annual Report on Form 10-K for the year ended December 31, 2000, 
as filed with the Securities and Exchange Commission, is included in this 
report. Additional copies are available without charge upon request by writing 
to the Chief Financial Officer, Noble Affiliates, Inc., 350 Glenborough Drive, 
Suite 100, Houston, Texas 77067, via the Company's Internet website: 
http://www.nobleaff.com, or via the Securities and Excange Commission's 
Internet website: http://www.sec.gov.
-------------------------------------------------------------------------------










<PAGE>

                             NOBLE AFFILIATES, INC.

                              EMPLOYMENT AGREEMENT
                              --------------------

         This Employment Agreement (this "Agreement") is effective as of October
2, 2000 between NOBLE AFFILIATES, INC., a Delaware corporation (the "Company"),
and CHARLES D. DAVIDSON (the "Employee").

                              W I T N E S S E T H:

         WHEREAS, the Company desires to employ the Employee, and the Employee
desires to be employed by the Company, as President and Chief Executive Officer
in accordance with the terms and conditions set forth in this Agreement;

         NOW THEREFORE, for and in consideration of the premises and the mutual
covenants contained herein, and for other good and valuable consideration, the
receipt and sufficiency of which are hereby acknowledged, and subject to the
terms and conditions hereinafter set forth, the parties hereto agree as follows:

1.       DEFINITIONS.
         -----------

         In addition to the words and terms elsewhere defined in this Agreement,
the following words and terms as used herein shall have the following meanings,
unless the context or use indicates a different meaning:

         "Annualized Compensation Amount" means an amount equal to (i) the
annualized salary payable to the Employee pursuant to Subsection 4(a), plus (ii)
the target bonus established for the Employee pursuant to Subsection 4(b) of

this Agreement, both during the then-effective fiscal year of the Company.

         "Cause" means by reason of any of the following: (A) Employee's
conviction of, or plea of nolo contendere to, any felony or to any crime or
offense causing substantial harm to any of the Related Parties (defined below)
or involving acts of theft, fraud, embezzlement, moral turpitude or similar
conduct; (B) malfeasance in the conduct of Employee's duties, including, but not
limited to, (1) willful and intentional misuse or diversion of funds of any of
the Related Parties, (2) embezzlement, or (3) fraudulent or willful and material
misrepresentations or concealments on any written reports submitted to the
Related Parties; or (C) Employee's material breach of the provisions of this
Agreement or material failure to follow or comply with the reasonable and lawful
written directives of the Board of Directors of the Company, provided, however,
that as regards the foregoing clause (C), Employee shall have been informed, in
writing, of such material breach or failure and given a period of thirty (30)
days to remedy same.

         "Common Stock" means the Company's common stock, $3.33 - 1/3 par value
per share.

         An "Event of Default" means the occurrence of any of the following
events prior to a Triggering Event, unless remedied or otherwise cured within
thirty (30) days after the Company's receipt of written notice from the Employee
of such event: (a) without his prior concurrence, the 


<PAGE>


Employee is assigned any duties or responsibilities that are inconsistent 
with his position, duties, responsibilities or status at the commencement of 
the term of this Agreement, or his reporting responsibilities in effect at 
such time are changed, (b) the Employee's base salary is reduced, or (c) any 
change in any employee benefit plans or arrangements in effect on the date 
hereof in which the Employee participates (including without limitation any 
annual incentive bonus plan, pension and retirement plan, savings and profit 
sharing plan, stock ownership or purchase plan, stock option plan, or life, 
medical or disability insurance plan), which would adversely affect the 
Employee's rights or benefits thereunder, unless such change occurs pursuant 
to a program or a plan amendment or termination that is applicable to all 
senior executive officers of the Company and does not result in a 
proportionately greater reduction in the rights of or benefits to the 
Employee as compared to any other senior executive officer of the Company.

         "Good Reason" means the occurrence of a Triggering Event (as defined
below) AND: (a) without his prior concurrence, the Employee is assigned any
duties or responsibilities that are inconsistent with his position, duties,
responsibilities or status at the commencement of the term of this Agreement, or
his reporting responsibilities in effect at such time are changed, (b) the
Employee's base salary is reduced, or (c) any change in any employee benefit
plans or arrangements in effect on the date hereof in which the Employee
participates (including without limitation any annual incentive bonus plan,
pension and retirement plan, savings and profit sharing plan, stock ownership or
purchase plan, stock option plan, or life, medical or disability insurance
plan), which would adversely affect the Employee's rights or benefits
thereunder, unless such change occurs pursuant to a program or a plan amendment
or termination that is applicable to all senior executive officers of the
Company and does not result in a proportionately greater reduction in the rights
of or benefits to the Employee as compared to any other senior executive officer
of the Company.

         "Related Parties" means the Company and its subsidiaries and other
affiliates.

         A "Triggering Event" shall be deemed to have occurred if:

                  (i)   individuals who, as of the date hereof, constitute the
         Company's Board of Directors (the "Incumbent Board") cease for any
         reason to constitute at least fifty-one percent (51%) of the Company's
         Board, provided that any person becoming a director subsequent to the
         date hereof whose election, or nomination for election by the Company's
         stockholders, was approved by a vote of at least a majority of the
         directors then comprising the Incumbent Board shall be, for purposes of
         this Agreement, considered as though such person were a member of the
         Incumbent Board;

                  (ii)  the stockholders of the Company shall approve a
         reorganization, merger or consolidation, in any case, with respect to
         which persons who were the stockholders of the Company immediately
         prior to such reorganization, merger or consolidation do not,
         immediately thereafter, own outstanding voting securities representing
         at least fifty-one percent (51%) of the combined voting power entitled
         to vote generally in the election of the directors ("Voting
         Securities") of the resulting reorganized, merged or consolidated
         company;



                                       2

<PAGE>


                  (iii) the stockholders of the Company shall approve a
         liquidation or dissolution of the Company or a sale of all or
         substantially all of the Company's assets to a non-Related Party; or

                  (iv)  any "person," as that term is defined in Section 3(a)(9)
         of the Securities Exchange Act of 1934, as amended (the "Exchange Act")
         (other than the Company, any other Related Party, any employee benefit
         plan of the Company or any of its Related Parties, or any entity
         organized, appointed or established by the Company for or pursuant to
         the terms of such a plan), together with all "affiliates" and
         "associates" (as such terms are defined in Rule 12b-2 under the
         Exchange Act) of such person (as well as any "person" or "group" as
         those terms are used in Sections 13(d) and 14(d) of the Exchange Act
         and the rules promulgated thereunder), shall become the "beneficial
         owner" or "beneficial owners" (as defined in Rules 13d-3 and 13d-5
         under the Exchange Act), directly or indirectly, of securities of the
         Company representing in the aggregate twenty-five percent (25%) or more
         of either (A) the then outstanding shares of Common Stock or (B) the
         Voting Securities of the Company, in either such case other than solely
         as a result of acquisitions of such securities directly from the
         Company. Without limiting the foregoing, a person who, directly or
         indirectly, through any contract, arrangement, understanding,
         relationship or otherwise has or shares the power to vote, or to direct
         the voting of, or to dispose, or to direct the disposition of, Common
         Stock or other Voting Securities of the Company shall be deemed the
         beneficial owner of such Common Stock or Voting Securities.

         Notwithstanding the foregoing, a "Triggering Event" shall not be deemed
to have occurred for purposes of subparagraph (iv) of this definition solely as
the result of an acquisition of securities by the Company which, by reducing the
number of shares of Common Stock or other Voting Securities of the Company
outstanding, increases (i) the proportionate number of shares of Common Stock
beneficially owned by any person to twenty-five percent (25%) or more of the
shares of Common Stock then outstanding or (ii) the proportionate voting power
represented by the Voting Securities of the Company beneficially owned by any
person to twenty-five percent (25%) or more of the combined voting power of all
then outstanding Voting Securities; provided, however, that if any person
referred to in clause (i) or (ii) of this sentence shall thereafter become the
beneficial owner of any additional shares of Common Stock or other Voting
Securities of the Company (other than a result of a stock split, stock dividend
or similar transaction), then a Triggering Event shall be deemed to have
occurred.

2.       EMPLOYMENT.
         ----------

         The Company hereby employs the Employee and the Employee hereby accepts
employment on the terms and conditions set forth herein.

3.       TERM.
         ----

         The initial term of this Agreement shall be from the date hereof until
the third anniversary hereof, unless sooner terminated in accordance with the
provisions herein regarding termination. 


                                       3

<PAGE>


Subject to earlier termination as provided herein, the initial three year 
term of this Agreement shall be automatically extended for successive one 
year extensions, beginning on the date of the first anniversary of this 
Agreement and on each anniversary thereafter, unless either the Employee or 
the Company gives written notice to the other at least six months prior to 
such anniversary.

4.       COMPENSATION.
         ------------

         (a)  BASE SALARY. For all services rendered by the Employee under this
Agreement, the Company shall pay the Employee a base salary of Four Hundred
Seventy-Five Thousand Dollars ($475,000) per year. Such salary: (i) shall be
payable in equal installments in accordance with the customary payroll policies
of the Company in effect at the time such payment is made, or as otherwise
mutually agreed upon, and (ii) may, in the sole discretion of the Company's
Board of Directors, be increased in future years.

         (b)  ANNUAL TARGET BONUS. Effective for the Company's fiscal year 
ending December 31, 2001 and continuing with respect to each subsequent 
fiscal year thereafter during the term of this Agreement, Employee will be 
eligible for a "target bonus," under the Company's annual incentive bonus 
plan in effect at the applicable time, of up to seventy percent (70%) of 
Employee's base salary in effect at the applicable time. For the Company's 
fiscal year ending December 31, 2000, Employee's bonus shall not be less than 
the mathematical product of Three Hundred Thousand Dollars ($300,000) 
multiplied by a fraction of which (i) the numerator is the number of days 
during such fiscal year that the Employee is employed by the Company and (ii) 
the denominator is 365. The Employee's bonus pursuant to this Subsection 4(b) 
shall be earned as of the end of the Company's relevant fiscal year and 
payable in accordance with the customary policies of the Company in effect at 
the time for the Company's other senior executive officers.

         (c)  BENEFITS. The Employee shall be entitled to participate in or
receive benefits under any employee benefit plan or arrangements made available
by the Company in the future to its senior executive officers, subject to and on
a basis consistent with the terms, conditions and overall administration of such
plan or arrangement. Nothing paid to the Employee under any plan or arrangement
presently in effect or made available in the future shall be deemed to be in
lieu of the salary and bonuses payable to the Employee pursuant to Subsections
4(a) and 4(b).

         (d)  STOCK OPTION. In consideration of the Employee's execution of this
Agreement, the Company will grant a non-qualified stock option to purchase
Eighty Thousand (80,000) shares of the Common Stock to the Employee (the
"Initial Options") pursuant to the Noble Affiliates, Inc. 1992 Stock Option and
Restricted Stock Plan (the "Option Plan"). Such option shall vest and become
exercisable in three equal annual installments. The exercise price for such
option will be the Fair Market Value (as determined under the Option Plan) of
the Common Stock on the date of grant, such grant to be made within one week
following the commencement of the Employee's employment with the Company. The
option to purchase 80,000 shares of the Common Stock is intended to encompass
Employee's option grants during the calendar year 2000, and, while the Board of
Directors could award additional options to the Employee during such period,
there is no present intention to do so even though options may be awarded to
other executives of the Company 


                                       4

<PAGE>


during such time period. Beginning with calendar year 2001, Employee will be 
eligible to participate in the Option Plan under the same terms and 
conditions in effect for the Company's other senior executive officers.

         (e)  EXPENSES. Upon receipt of itemized vouchers, expense account
reports, and supporting documents submitted to the Company in accordance with
the Company's procedures from time to time in effect, the Company shall
reimburse Employee for all reasonable and necessary travel, entertainment, and
other reasonable and necessary business expenses incurred ordinarily and
necessarily by Employee in connection with the performance of his duties
hereunder.

         (f)  VACATION. Employee shall be entitled to a minimum of five 
(5) weeks paid vacation during each twelve month period commencing on the 
effective date of this Agreement.

5.       POSITION, DUTIES, EXTENT OF SERVICES AND SITUS.
         ----------------------------------------------

         (a)  POSITION AND DUTIES. Employee shall serve as the President and
Chief Executive Officer of the Company.

         (b)  EXTENT OF SERVICES. The Employee shall devote all of his business
time, attention, and energy to the business and affairs of the Company and shall
not during the term of his employment under this Agreement engage in any other
business activity which could constitute a conflict of interest, whether or not
such business activity is pursued for gain, profit, or other pecuniary
advantage. This shall not be construed as preventing the Employee from serving
on the Boards of Directors of other companies or from managing his current
investments or investing his assets in such form or manner as will not require
any services on the part of the Employee in the operation and the affairs of the
companies in which such investments are made, subject to the provisions of
Section 6 hereof.

6.       NON-SOLICITATION; CONFIDENTIALITY AND PENDING PROSPECTS.
         -------------------------------------------------------

         (a)  The Employee acknowledges that (i) as a result of his position 
with the Company he will receive specialized and unique knowledge concerning 
the Company, its business, its customers and the industry in which it 
competes, (ii) the Company's business, in large part, depends upon its 
exclusive possession and use of its proprietary information, (iii) the 
Company is entitled to protection against the unauthorized disclosure or use 
by Employee of its proprietary information, and (iv) he has received in this 
Agreement good and valuable consideration for the covenants he is making in 
this Section 6.

         (b)  For a period of twenty-four (24) months after the termination of
Employee's employment with the Company, the Employee shall not, without the
written consent of the Company: solicit, entice, persuade or induce, directly or
indirectly, any individual (or person who within the preceding ninety (90) days
was an employee) of any of the Related Parties or any other person who is under
contract with or rendering services to any of the Related Parties, to (i)
terminate his or her employment by, or contractual relationship with, a Related
Party, (ii) refrain from 


                                       5

<PAGE>


extending or renewing the same (upon the same or new terms), (iii) refrain 
from rendering services to or for a Related Party, (iv) become employed by or 
to enter into contractual relations with any party other than a Related 
Party, or (v) enter into a relationship with a competitor of any of the 
Related Parties.

         (c)  Employee recognizes and acknowledges that the Company would suffer
irreparable harm and substantial loss if Employee violated any of the terms and
provisions of this Section 6 and that the actual damages which might be
sustained by the Company as the result of any breach of this Section 6 would be
difficult to ascertain. Employee agrees, at the election of the Company and in
addition to, and not in lieu of, the Company's right to terminate Employee's
employment and to seek all other remedies and damages which the Company may have
at law and/or equity for such breach, that the Company shall be entitled to an
injunction restraining Employee from breaching any of the terms or provisions of
this Section 6.

         (d)  During the time of Employee's employment with the Company and for
a period of one (1) year thereafter, Employee will not compete with the Company
for any acquisition, prospect or project that the Company was pursuing prior to
Employee's termination, and Employee shall hold in strict confidence and shall
not, directly or indirectly, disclose or reveal to any person, or use for his
own personal benefit or for the benefit of anyone else, any trade secrets,
confidential dealings, or other confidential or proprietary information of any
kind, nature, or description (whether or not acquired, learned, obtained, or
developed by Employee alone or in conjunction with others) belonging to or
concerning the Company or any other Related Party, except (i) with the prior
written consent of the Company duly authorized by its Board of Directors, (ii)
in the course of the proper performance of Employee's duties hereunder, (iii)
for information (x) that becomes generally available to the public other than as
a result of unauthorized disclosure by Employee or his affiliates or (y) that
becomes available to Employee on a non-confidential basis from a source, other
than the Company, who is not bound by a duty of confidentiality, or by any other
contractual, legal, or fiduciary obligation, to the Company, or (iv) as required
by applicable law or legal process.

7.       DISABILITY.
         ----------

         Employee shall be entitled to participate in, and receive coverage
under, as applicable, any disability plan made available to the Company's senior
executive officers from time to time. The Company shall have the right
immediately to terminate the Employee's employment under this Agreement upon the
"Complete Disability" of the Employee as hereinafter defined. The term "Complete
Disability" as used in this Section 7 shall mean (i) the total inability of the
Employee, despite any reasonable accommodation required by law, due to bodily
injury or disease or any other physical or mental incapacity, to perform the
services provided for hereunder for a period of one hundred twenty (120) days in
the aggregate, within any given period of one hundred eighty (180) consecutive
days during the term of this Agreement, in addition to any statutorily required
leave of absence, and (ii) where such inability will, in the opinion of a
qualified physician selected by the Company's Board of Directors, be permanent
and continuous during the remainder of Employee's life.


                                       6

<PAGE>


8.       DEATH.
         -----

         If the Employee dies during the term of his employment, the Company
shall pay to such person as the Employee shall designate in a notice filed with
the Company, or, if no such person shall be designated, to Employee's estate as
a death benefit, any payments the Employee's spouse, beneficiaries, or estate
may be entitled to receive pursuant to any pension or employee benefit plan or
life insurance policy maintained by the Company at such time for its senior
executive officers, and, except for any obligations of the Company under
Sections 22 and 25, all other obligations of the Company hereunder shall cease
at the time of the Employee's death.

9.       TERMINATION.
         -----------

         9.1  TERMINATION PRIOR TO A TRIGGERING EVENT. (a) Upon at least thirty
(30) days' prior written notice to the Employee and prior to a Triggering Event,
the Company may terminate the Employee's employment with the Company under this
Agreement for Cause or in accordance with Section 7 and, subject to the
provisions of Sections 22 and 25, with no liability on its part for further
payments to the Employee (other than accrued and unpaid salary through the
termination date). The Company may effect a termination for Cause pursuant to
this Subsection 9.1(a) only by the affirmative vote of a majority of the members
of the Board of Directors of the Company. In voting upon such termination for
Cause, if the Employee is also a member of the Board of Directors of the
Company, then he may not vote on, and will not be considered present for any
purpose with respect to, a matter presented to the Board of Directors of the
Company pursuant to this Subsection 9.1(a).

         (b)  Prior to a Triggering Event, the Employee may terminate his
employment with the Company under this Agreement by giving at least six (6)
months' prior written notice of his desire to terminate employment to the Board
of Directors of the Company. If the Employee's employment with the Company under
this Agreement is terminated pursuant to this Subsection 9.1(b), the Employee
will continue to accrue and receive his base salary in effect at the time
pursuant to Subsection 4(a) through the date of termination specified in such
notice with no liability on the part of the Company for further payments to the
Employee, subject to the provisions of Sections 22 and 25.

         (c)  Prior to a Triggering Event, if the Employee's employment with the
Company is terminated by the Company without Cause or if the Employee terminates
his employment with the Company following the occurrence of an Event of Default
which has not been waived in writing by the Employee, the Employee will continue
to accrue and receive his base salary in effect at the time pursuant to
Subsection 4(a) through the date of termination and , unless the Employee's
employment is terminated in accordance with Section 7, will be entitled to
receive the benefits provided for under Subsection 10.1 with no liability on the
part of the Company for further payments to the Employee, subject to the
provisions of Sections 22 and 25.

         9.2  TERMINATION ON OR AFTER A TRIGGERING EVENT. (a) Upon at least
thirty (30) days' prior written notice to the Employee and on or after a
Triggering Event, the Company may terminate the Employee's employment with the
Company under this Agreement for Cause or in accordance with 


                                       7

<PAGE>


Section 7 and, subject to the provisions of Sections 22 and 25, with no 
liability on its part for further payments to the Employee (other than 
accrued and unpaid salary through the termination date). The Company may 
effect a termination for Cause pursuant to this Subsection 9.2(a) only by the 
affirmative vote of a majority of the members of the Board of Directors of 
the Company. In voting upon such termination for Cause, if the Employee is 
also a member of the Board of Directors of the Company, then he may not vote 
on, and will not be considered present for any purpose with respect to, a 
matter presented to the Board of Directors of the Company pursuant to this 
Subsection 9.2(a).

         (b)   On or after a Triggering Event, if the Employee's employment 
with the Company is terminated by the Company without Cause or if the Employee
terminates his employment with the Company for Good Reason, the Employee will
continue to accrue and receive his base salary in effect at the time pursuant to
Subsection 4(a) through the date of termination and, unless the Employee's
employment is terminated in accordance with Section 7, will be entitled to
receive the payments and benefits provided for under Subsections 10.2 and 10.3
with no liability on the part of the Company for further payments to the
Employee, subject to the provisions of Sections 22 and 25.

         (c)   On or after a Triggering Event, the Employee may, in his sole and
absolute discretion and without any prior approval by the Board of Directors of
the Company, and upon six (6) months' prior written notice to the Board of
Directors of the Company, terminate his employment with the Company under this
Agreement for any reason whatsoever. If the Employee's employment with the
Company under this Agreement is terminated pursuant to this Subsection 9.2(c),
the Employee will continue to accrue and receive his base salary in effect at
the time pursuant to Subsection 4(a) through the date of termination specified
in such notice with no liability on the part of the Company for further payments
to the Employee, subject to the provisions of Sections 22 and 25.

10.      COMPENSATION AFTER CERTAIN TERMINATIONS.
         ---------------------------------------

         10.1  REMAINING COMPENSATION. If the Employee's employment with the
Company is terminated pursuant to Subsection 9.1(c), then, within five days
after the date of such termination, the Remaining Compensation (as herein
defined) shall become due and payable and shall be paid to the Employee in a
single lump sum in cash. For purposes of this Subsection 10.1, the "Remaining
Compensation" shall mean the annual base salary for one year only payable to the
Employee pursuant to Subsection 4(a) at the time of termination plus an amount
representing any accrued and unpaid bonuses earned under Subsection 4(b).

         10.2  POST TRIGGERING EVENT SEVERANCE. If, at any time on or within
twenty-four (24) months after a Triggering Event, the Employee's employment with
the Company is terminated by the Company without Cause or if the Employee
terminates his employment with the Company for Good Reason, then:

         (i)   within five days after the date of such termination, the
               Company shall pay the Employee a lump sum amount in cash equal
               to two and one-half (2.5) times the Annualized Compensation
               Amount, and


                                       8

<PAGE>


         (ii)  the vesting of all outstanding Initial Options then owned by
               Employee shall be accelerated so that all such options are
               immediately exercisable in accordance with their terms.

         10.3  GROSS-UP PAYMENT. In the event that (i) the Employee becomes
entitled to the payment provided under Section 10.2 of this Agreement (the
"Change in Control Payment") and any of the Change in Control Payment will be
subject to the tax (the "Excise Tax") imposed by Section 4999 of the Internal
Revenue Code of 1986, as amended (the "Code"), or any successor provision, or
(ii) any payments or benefits received or to be received by the Employee
pursuant to the terms of any other plan, arrangement or agreement (the "Benefit
Payments") will be subject to the Excise Tax, the Company shall pay to the
Employee an additional amount (the "Gross-Up Payment") such that the net amount
retained by the Employee, after deduction of any Excise Tax on the Change in
Control Payment and the Benefit Payments, and any federal, state and local
income tax and Excise Tax upon the payment provided for by this Section 10.3,
shall be equal to the Change in Control Payment and the Benefit Payments,
provided, however, that in determining the amount of the Gross- Up Payment, any
Excise Tax on the Change in Control Payment and the Benefit Payments shall be
determined using a rate no higher than twenty percent (20%). For purposes of
determining whether any of the Change in Control Payment or the Benefit Payments
will be subject to the Excise Tax and the amount of such Excise Tax, (i) any
payments or benefits received or to be received by the Employee in connection
with a change in control of the Company or the Employee's termination of
employment (whether pursuant to the terms of this Agreement or any other plan,
arrangement or agreement with the Company, any person whose actions result in
change in control or any person affiliated with the Company or such persons)
shall be treated as "parachute payments" within the meaning of Section
280G(b)(2) of the Code, and all "excess parachute payments" within the meaning
of Section 280G(b)(1) shall be treated as subject to the Excise Tax, except to
the extent that, in the opinion of tax counsel selected by the Board of
Directors of the Company, such payments or benefits (in whole or in part) do not
constitute parachute payments, or such excess payments (in whole or in part)
represent reasonable compensation for services actually rendered within the
meaning of Section 280G(b)(4) of the Code, (ii) the amount of the Change in
Control Payment and the Benefit Payments that shall be treated as subject to the
Excise Tax shall be equal to the lesser of (A) the total amount of the Change in
Control Payment and the Benefits Payments or (B) the amount of excess parachute
payments within the meaning of Sections 280G(b)(1) and (4) (after applying
clause (i), above) and (iii) the value of any non-cash benefits or any deferred
payment or benefit shall be determined by tax counsel, selected by the Board of
Directors of the Company, in accordance with the principles of Sections
280G(d)(3) and (4) of the Code. For purposes of determining the amount of the
Gross-Up Payment, the Employee shall be deemed to pay federal income taxes at
the highest marginal rate of federal income taxation in the calendar year in
which the Gross-Up Payment is to be made and state and local income taxes at the
highest marginal rates of taxation in the state and locality of the Employee's
residence on the date of termination, net of the maximum reduction in federal
income taxes which could be obtained from deduction of such state and local
taxes. In the event that the Excise Tax is subsequently determined to be less
than the amount taken into account hereunder at the time of termination of the
Employee's employment, the Employee shall repay to the Company at that time that
amount of such reduction in Excise Tax as is finally determined to be the
portion of the Gross-Up Payment attributable to such reduction plus interest on
the amount of such 


                                       9

<PAGE>


repayment at the rate provided in Section 1274(b)(2)(B) of the Code. In the 
event that the Excise Tax is determined to exceed the amount taken into 
account hereunder at the time of the termination of the Employee's employment 
(including by reason of any payment the existence or amount of which cannot 
be determined at the time of the Gross-Up Payment), the Company shall make an 
additional gross-up payment to the Employee in respect of such excess (plus 
any interest payable with respect to such excess) at the time that the amount 
of such excess is finally determined.

11.      MITIGATION.
         ----------

         The Employee shall not be required to mitigate the amount of any
payment provided for in this Agreement by seeking other employment or otherwise,
nor shall the amount of any payment provided for in this Agreement be reduced by
any compensation earned by the Employee as the result of employment by another
employer after the date of termination of Employee's employment with the
Company, or otherwise.

12.      ENTIRE AGREEMENT.
         ----------------

         This Agreement embodies the entire agreement and understanding between
the parties hereto with respect to the subject matter hereof and supersedes all
prior negotiations, agreements, and understandings relating to such subject
matter, and may be modified or amended only by an instrument in writing signed
by the parties hereto.

13.      LAW TO GOVERN.
         -------------

         This Agreement is executed and delivered in the State of Texas and
shall be governed, construed and, except as stated in Section 26, enforced in
accordance with the internal laws of the State of Texas without regard to
principles of conflicts of law that would require the application of the law of
another jurisdiction.

14.      ASSIGNMENT.
         ----------

         This Agreement is personal to the parties, and neither this Agreement
nor any interest herein may be assigned (other than by will or by the laws of
descent and distribution) without the prior written consent of the parties
hereto nor be subject to alienation, anticipation, sale, pledge, encumbrance,
execution, levy, or other legal process of any kind against the Employee or any
of his beneficiaries or any other person. Notwithstanding the foregoing, the
Company shall be permitted to assign this Agreement to any corporation or other
business entity succeeding to substantially all of the business and assets of
the Company by merger, consolidation, sale of assets, or otherwise, if the
Company obtains the assumption of this Agreement by such successor.


                                      10

<PAGE>


15.      BINDING AGREEMENT.
         -----------------

         Subject to the provisions of Section 14 of this Agreement, this
Agreement shall be binding upon and shall inure to the benefit of the Company
and the Employee and their respective representatives, successors, and assigns.

16.      REFERENCES AND GENDER.
         ---------------------

         All references to "Sections" and "Subsections" contained herein are,
unless specifically indicated otherwise, references to sections and subsections
of this Agreement. Whenever herein the singular number is used, the same shall
include the plural where appropriate, and words of either gender shall include
the other gender where appropriate.

17.      WAIVER.
         ------

         No waiver of any right under this Agreement shall be deemed effective
unless the same is set forth in writing and signed by the party giving such
waiver, and no waiver of any right shall be deemed to be a waiver of any such
right in the future. Only the Board of Directors of the Company has authority to
waive any provision of this Agreement.

18.      NOTICES.
         -------

         Except as may be otherwise specifically provided in this Agreement, all
notices required or permitted hereunder shall be in writing and will be deemed
to be delivered on the third day following being deposited in the United States
mail, postage prepaid, registered or certified mail, return receipt requested,
and (i) if to the Company, to its principal business office to the attention of
the Chairman of the Board and (ii) if to the Executive, if addressed to his last
known home address, or at such other addresses as may have theretofore been
specified by written notice delivered in accordance herewith.

19.      OTHER INSTRUMENTS.
         -----------------

         The parties hereto covenant and agree that they will execute such other
and further instruments and documents as are or may become necessary or
convenient to effectuate and carry out the terms of this Agreement.

20.      HEADINGS.
         --------

         The headings used in this Agreement are used for reference purposes
only and do not constitute substantive matter to be considered the terms of this
Agreement.

21.      INVALID PROVISION.
         -----------------

         Any clause, sentence, provision, section, subsection, or paragraph of
this Agreement held by a court of competent jurisdiction to be invalid, illegal,
or ineffective shall not impair, invalidate, or nullify the remainder of this
Agreement, but the effect thereof shall be confined to the clause, sentence,
provision, section, subsection, or paragraph so held to be invalid, illegal or
ineffective.


                                      11

<PAGE>


22.      RIGHTS UNDER PLANS AND PROGRAMS.
         -------------------------------

         Unless expressly provided in this Agreement, no provision of this 
Agreement is intended, nor shall it be construed, to reduce or in any way 
restrict any benefit to which the Employee otherwise may be independently 
entitled under any other agreement, plan, arrangement, or program providing 
benefits for the Employee, and to the extent such other agreement, plan, 
arrangement, or program is made available to the Company's chief executive 
officer and the available provisions conflict with a provision of this 
Agreement, then such applicable provisions of such other agreement, plan, 
arrangement, or program shall control.

23.      MULTIPLE COPIES.
         ---------------

         This Agreement may be executed simultaneously in one or more
counterparts, each of which shall be deemed an original and all of which shall
together constitute one and the same instrument. The terms of this Agreement
shall become binding upon each party from and after the time that he or it
executed a copy hereof. In like manner, from and after the time that any party
executes a consent or other document, such consent or other document shall be
binding upon such parties.

24.      WITHHOLDING OF TAXES.
         --------------------

         The Company may withhold from any amounts payable under this Agreement
all federal, state, city, or other taxes as shall be required pursuant to any
law or government regulation or ruling.

25.      LEGAL FEES AND EXPENSES.
         -----------------------

         Subject to Section 26 and any final, non-appealable determination by a
court of competent jurisdiction, each party shall pay and be responsible for its
legal fees and expenses incurred in connection with a dispute under this
Agreement, including as a result of a party contesting the validity or
enforceability of this Agreement.

26.      ARBITRATION.
         -----------

         ANY DISPUTE ARISING IN CONNECTION WITH THIS AGREEMENT OR IN ANY WAY
ARISING OUT OF OR RELATED TO THE EMPLOYMENT RELATIONSHIP BETWEEN THE EMPLOYEE
AND THE COMPANY, OR THE TERMINATION OF THAT RELATIONSHIP, INCLUDING ANY CLAIM OF
UNLAWFUL DISCRIMINATION, SHALL BE FINALLY RESOLVED BY ARBITRATION IN HOUSTON,
TEXAS, GOVERNED BY THE FEDERAL ARBITRATION ACT AND CONDUCTED PURSUANT TO AND IN
ACCORDANCE WITH THE NATIONAL RULES FOR THE RESOLUTION OF EMPLOYMENT DISPUTES OF
THE AMERICAN ARBITRATION ASSOCIATION. EITHER THE COMPANY OR THE EMPLOYEE MAY
REQUEST ARBITRATION BY SENDING WRITTEN NOTICE TO THE OTHER PARTY. IN ANY SUCH
ARBITRATION, THE ONLY ISSUES TO BE CONSIDERED AND DETERMINED BY THE
ARBITRATOR(S) SHALL BE ISSUES PERTAINING TO LEGAL AND EQUITABLE RIGHTS AND
OBLIGATIONS OF THE PARTIES UNDER THIS AGREEMENT AND ANY APPLICABLE LAW. A
DECISION AND AWARD OF THE ARBITRATOR(S) SHALL BE FINAL, AND MAY BE ENTERED IN
ANY COURT HAVING JURISDICTION THEREOF, AND APPLICATION MAY BE MADE TO SUCH COURT
FOR JUDICIAL ACCEPTANCE AND/OR AN ORDER ENFORCING SUCH DECISION AND/OR AWARD.
JUDICIAL REVIEW 


                                      12

<PAGE>


OF ANY DECISION OR AWARD SHALL BE IN ACCORDANCE WITH THE FEDERAL ARBITRATION 
ACT, EXCEPT THAT REVIEW OF ANY AWARD OF PUNITIVE OR EXEMPLARY DAMAGES SHALL 
BE CONDUCTED AS IF THE AWARD OF SUCH DAMAGES WERE MADE BY A JURY SITTING IN A 
FEDERAL DISTRICT COURT IN HOUSTON, TEXAS. IN THE EVENT THE ARBITRATOR(S) 
DETERMINE THERE IS A PREVAILING PARTY IN THE ARBITRATION, THE PREVAILING 
PARTY SHALL RECOVER FROM THE LOSING PARTY ALL COSTS OF ARBITRATION, INCLUDING 
BUT NOT LIMITED TO THE FEES OF THE ARBITRATOR(S) AND REASONABLE ATTORNEYS' 
FEES INCURRED BY THE PREVAILING PARTY. THE PROVISIONS OF THIS SECTION 26 
SHALL NOT BE CONSTRUED TO LIMIT OR TO PRECLUDE EITHER PARTY FROM BRINGING AN 
ACTION IN ANY COURT OF COMPETENT JURISDICTION FOR INJUNCTIVE RELIEF.

         IN WITNESS WHEREOF, the parties have executed this Agreement on the day
and year first above written.


                                  NOBLE AFFILIATES, INC.


                                  By:    /s/ Robert Kelley
                                      ------------------------------------------
                                      Name:  Robert Kelley
                                           -------------------------------------
                                      Title: Chairman of the Board
                                            ------------------------------------



                                      /s/ CHARLES D. DAVIDSON
                                      ------------------------------------------
                                      CHARLES D. DAVIDSON







                                      13




<PAGE>

                                                                     EXHIBIT 21
                                                                   TO FORM 10-K

                                   SUBSIDIARIES


<TABLE>
<CAPTION>
                                                 STATE OF JURISDICTION OF
NAME                                                    ORGANIZATION             REF
--------------------------------------------     ------------------------        ---
<S>                                              <C>                             <C>
Noble Trading, Inc.                                        Delaware              (1)
NPM, Inc.                                                  Delaware              (1)
Noble Gas Marketing, Inc.                                  Delaware              (1)
Noble Gas Pipeline, Inc.                                   Delaware              (2)
Samedan Oil Corporation                                    Delaware              (1)
Samedan Oil of Canada, Inc.                                Delaware              (3)
Samedan of North Africa, Inc.                              Delaware              (3)
Samedan North Sea, Inc.                                    Delaware              (3)
Samedan Oil of Indonesia, Inc.                             Delaware              (3)
Samedan Pipe Line Corporation                              Delaware              (3)
Samedan Royalty Corporation                                Delaware              (3)
Samedan of Tunisia, Inc.                                   Delaware              (3)
Samedan, Mediterranean Sea, Inc.                           Delaware              (3)
EDC Ireland                                             Cayman Islands           (4)
Samedan International                                   Cayman Islands           (4)
Samedan Vietnam Limited                                 Cayman Islands           (4)
Machalapower Cia. Ltda.                                 Cayman Islands           (5)
Samedan, Mediterranean Sea                              Cayman Islands           (5)
Samedan Transfer Sub                                    Cayman Islands           (5)
Atlantic Methanol Capital Company                       Cayman Islands           (7)
Samedan Methanol                                        Cayman Islands           (8)
Atlantic Methanol Associates LLC                        Cayman Islands           (9)
Atlantic Methanol Production Company LLC                Cayman Islands           (10)
AMPCO Marketing, L.L.C.                                    Michigan              (7)
AMPCO Services, L.L.C.                                     Michigan              (7)
Alba Associates LLC                                     Cayman Islands           (11)
Alba Plant LLC                                          Cayman Islands           (12)
Energy Development Corporation                             Delaware              (3)
Energy Development Corporation
 (Argentina), Inc.           Delaware              (6)
Energy Development Corporation (China), Inc.               Delaware              (6)
Energy Development Corporation (HIPS), Inc.                Delaware              (6)
EDC Ecuador Ltd.                                           Delaware              (6)
EDC Ecuador Limited                                     Cayman Islands           (16)
EDC (Denmark) Inc.                                         Delaware              (13)
EDC Australia Ltd.                                         Delaware              (6)
EDC Portugal Ltd.                                          Delaware              (6)
Gasdel Pipeline System Incorporated                       New Jersey             (6)
Producers Service, Inc.                                   New Jersey             (6)
HGC, Inc.                                                  Delaware              (6)
EDC (UK) Limited                                           Delaware              (6)
EDC (Europe) Limited                                    United Kingdom           (13)
EDC (ISE) Limited                                       United Kingdom           (14)
Brabant Oil Limited                                     United Kingdom           (14)
EDC (Oilex) Limited                                     United Kingdom           (14)
Burnside Overseas Exploration Ltd.                      United Kingdom           (15)
</TABLE>



<PAGE>


REFERENCES:
-----------

(1)      100% directly owned by Noble Affiliates, Inc. (Registrant)
(2)      100% directly owned by Noble Gas Marketing, Inc.
(3)      100% directly owned by Samedan Oil Corporation
(4)      100% directly owned by Samedan of North Africa, Inc.
(5)      100% directly owned by Samedan International
(6)      100% directly owned by Energy Development Corporation
(7)      50% directly owned by Samedan of North Africa, Inc.
(8)      100% directly owned by Atlantic Methanol Capital Company
(9)      50% directly owned by Samedan Methanol
(10)     90% directly owned by Atlantic Methanol Associates LLC
(11)     34.7% directly owned by Samedan International
(12)     80% directly owned by Alba Associates LLC
(13)     100% directly owned by EDC (UK) Limited
(14)     100% directly owned by EDC (Europe) Limited
(15)     100% directly owned by Brabant Oil Limited
(16)     100% directly owned by EDC Ecuador Ltd.





<PAGE>

                                                                 ARTHUR ANDERSEN
                                       

CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS

As independent public accountants, we hereby consent to the incorporation of 
our report dated January 26, 2001, included on page 31 of the Company's 2000 
Form 10-K, into the previously filed Registration Statements on Form S-3 
(File Nos. 333-18929 aned 333-82953) and on Form S-8 (File Nos. 333-39299, 
2-64600, 2-81590, 33-32692, 2-66654 and 33-54084).

                                       /s/ Arthur Andersen LLP
                                       Arthur Andersen LLP

Oklahoma City, Oklahoma
  March 12, 2001