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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------------
FORM 10-Q

/X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2001

/ / 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)

(281) 872-3100
(Registrant's telephone number, including area code)

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
--- ---

Number of shares of common stock outstanding as of May 3, 2001: 56,585,018

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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEET
(Dollars in thousands)

(Unaudited)
March 31, December 31,
2001 2000
------------------ ----------------

ASSETS
Current Assets:
Cash and short-term investments................................... $ 29,266 $ 23,152
Accounts receivable-trade......................................... 210,343 235,843
Materials and supplies inventories................................ 9,293 4,645
Other current assets.............................................. 13,329 7,621
------------ -------------

Total Current Assets.............................................. 262,231 271,261
------------ -------------

Property, Plant and Equipment, at cost............................... 3,397,917 3,256,467
Less: accumulated depreciation,
depletion and amortization.............................. (1,835,825) (1,771,344)
------------ -------------

1,562,092 1,485,123
------------ -------------

Investment in Unconsolidated Subsidiary.............................. 94,496 74,159

Other Assets......................................................... 59,837 48,737
------------ -------------

Total Assets...................................................... $ 1,978,656 $ 1,879,280
============ =============

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable-trade............................................ $ 266,779 $ 279,379
Other current liabilities......................................... 38,757 30,730
Income taxes-current.............................................. 55,610 15,308
------------- -------------

Total Current Liabilities......................................... 361,146 325,417
------------- -------------

Deferred Income Taxes................................................ 127,338 117,048
------------- -------------

Other Deferred Credits and Noncurrent Liabilities.................... 64,208 61,639
------------- -------------

Long-term Debt....................................................... 455,538 525,494
------------- -------------

Shareholders' Equity:
Common stock...................................................... 198,309 196,672
Capital in excess of par value.................................... 387,808 373,259
Retained earnings................................................. 429,111 325,452
Accumulated other comprehensive income............................ 899
------------- -------------

1,016,127 895,383
Less common stock in treasury
(at cost, 2,911,300 shares)....................................... (45,701) (45,701)
------------- -------------

Total Shareholders' Equity........................................ 970,426 849,682
------------- -------------

Total Liabilities and Shareholders' Equity........................ $ 1,978,656 $ 1,879,280
============= =============

SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.

NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS
(Dollars in Thousands, Except Per Share Amounts)
(Unaudited)

Three Months Ended March 31,
-----------------------------------------
2001 2000
------------- ----------

REVENUES:
Oil and gas sales and royalties.................................... $ 316,346 $ 151,003
Gathering, marketing and processing................................ 243,621 117,869
Income from unconsolidated subsidiary.............................. 297 411
Other income....................................................... 751 2,478
------------ -----------

561,015 271,761
------------ -----------

COSTS AND EXPENSES:
Oil and gas operations............................................. 33,893 26,165
Oil and gas exploration............................................ 38,514 15,991
Gathering, marketing and processing................................ 240,030 114,183
Depreciation, depletion and amortization........................... 64,243 51,558
Selling, general and administrative................................ 11,790 11,971
Interest........................................................... 10,449 9,622
Interest capitalized............................................... (2,887) (1,081)
------------ -----------

396,032 228,409
------------ -----------

INCOME BEFORE TAXES.................................................... 164,983 43,352

INCOME TAX PROVISION................................................... 59,073 (1) 16,472 (1)
------------ -----------

NET INCOME............................................................. $ 105,910 $ 26,880
============ ===========

BASIC EARNINGS PER SHARE............................................... $ 1.88 (2) $ .48 (2)
============ ===========

DILUTED EARNINGS PER SHARE............................................. $ 1.84 (2) $ .47 (2)
============ ===========

SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.

NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
AND SHAREHOLDERS' EQUITY
(Dollars in Thousands)
(Unaudited)

Accumulated
Capital in Other Total
Comprehensive Common Excess of Retained Comprehensive Treasury Shareholders'
Income Stock Par Value Earnings Income Stock Equity
- ---------------------------------------------------------------------------------------------------------------------------------

Balance at 12/31/00 196,672 373,259 325,452 (45,701) 849,682
Net income 105,910 105,910 105,910
Derivatives marked
to market 899 899 899
Shares issued 1,637 14,549 16,186
Dividends declared
($.04 per share) (2,250) (2,250)
Other (1) (1)
------- -------------------------------------------------------------------------------

Total 106,809
=======

Balance at 3/31/01 198,309 387,808 429,111 899 (45,701) 970,426
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NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

Three Months Ended March 31,
--------------------------------------
2001 2000
------------ ----------

Cash Flows from Operating Activities:
Net income............................................................ $ 105,910 $ 26,880
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization............................ 64,243 51,558
Dry hole............................................................ 30,902 7,919
Amortization of undeveloped lease costs, net........................ 2,965 2,377
Loss on disposal of assets.......................................... 32 654
Noncurrent deferred income taxes.................................... 10,291 5,146
(Income) from unconsolidated subsidiary............................. (297) (411)
Increase (decrease) in deferred credits............................. 2,568 1,466
(Increase) decrease in other........................................ (10,095) (6,970)
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable.......................... 25,500 (13,925)
(Increase) decrease in other current assets and inventories......... (10,419) 3,374
Increase (decrease) in accounts payable............................. (12,600) 30,118
Increase (decrease) in other current liabilities.................... 48,329 (5,184)
------------ ----------

Net Cash Provided by Operating Activities 257,329 103,002
------------ ----------

Cash Flows From Investing Activities:
Capital expenditures.................................................. (175,217) (81,392)
Investment in unconsolidated subsidiary............................... (20,041) (4,655)
Proceeds from sale of property, plant and equipment................... 107 5,218
------------ ----------

Net Cash Used in Investing Activities ................................... (195,151) (80,829)
------------ ----------

Cash Flows From Financing Activities:
Common stock repurchases.............................................. (30,258)
Exercise of stock options............................................. 16,186 322
Cash dividends........................................................ (2,250) (2,282)
Proceeds from credit facility......................................... 40,000 35,000
Repayment of credit facility.......................................... (110,000)
Repayment of notes payable - unconsolidated subsidiary................ (23,245)
------------ ----------

Net Cash Used in Financing Activities.................................... (56,064) (20,463)
------------ ----------

Increase (Decrease) in Cash and Short-term Investments................... 6,114 1,710
------------ ----------

Cash and Short-term Investments at Beginning of Period................... 23,152 2,925
------------ ----------

Cash and Short-term Investments at End of Period......................... $ 29,266 $ 4,635
============ ==========

Supplemental Disclosures of Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized).................................. $ 3,357 $ 3,460
Income taxes.......................................................... $ 1,631 $ 0

SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.

NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
(Unaudited)

In the opinion of Noble Affiliates, Inc. (the "Company"), the
accompanying unaudited consolidated condensed financial statements contain all
adjustments, consisting only of necessary and normal recurring adjustments,
necessary to present fairly the Company's financial position as of March 31,
2001 and the results of operations and the cash flows for the three month
periods ended March 31, 2001 and 2000. These consolidated condensed financial
statements should be read in conjunction with the consolidated financial
statements and the notes thereto included in the Company's annual report on Form
10-K for the year ended December 31, 2000.

(1) INCOME TAX PROVISION

For the three months ended March 31:

(In thousands)
-----------------------
2001 2000
-------- ---------

Current............................................................... $ 48,782 $ 11,326
Deferred.............................................................. 10,291 5,146
-------- ---------

$ 59,073 $ 16,472
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(2) BASIC EARNINGS PER SHARE AND DILUTED EARNINGS PER SHARE

Basic earnings per share of common stock was computed using the weighted
average number of shares of common stock 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 for the quarter ending March 31:

2001 2000
-------------------------- -----------------------------
INCOME SHARES INCOME SHARES
(IN THOUSANDS, EXCEPT PER SHARE) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR)
- -----------------------------------------------------------------------------------------------------------------------

Net income/shares $105,910 56,320 $26,880 56,396
- -----------------------------------------------------------------------------------------------------------------------
BASIC EPS $1.88 $.48
- -----------------------------------------------------------------------------------------------------------------------

Net income/shares $105,910 56,320 $26,880 56,396
EFFECT OF DILUTIVE SECURITIES
Stock options 1,177 260
Adjusted net income/shares $105,910 57,497 $26,880 56,656
- -----------------------------------------------------------------------------------------------------------------------
DILUTED EPS $1.84 $.47
- -----------------------------------------------------------------------------------------------------------------------

(3) 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.

During the first quarter of 2001, the Company had no oil or gas hedging
transactions for its production other than those entered into by NGM, which are
described below.

For calendar year 2000, the Company had entered into three crude oil
premium swap contracts related to its production. 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 were above the applicable trigger price,
then the Company would have owed 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 have paid 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 Company 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 separately accounted for the premium component of these
contracts by marking them to market, resulting in a gain of $1,162,000 recorded
in other income for the three months ended March 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 approximately 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 have
owed 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 had
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 price, 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.

In addition to the hedging arrangements pertaining to the Company's
production as described above, Noble Gas Marketing, Inc. ("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.

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.

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 stockholder 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 was required to adopt the statement for fiscal years
beginning after June 15, 2000. 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 amended the accounting and reporting standards of SFAS
No. 133 for certain derivative instruments and certain hedging activities and
was required to be adopted concurrently with SFAS No. 133. The normal purchase
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.

(4) METHANOL PLANT

The Company's unconsolidated subsidiary, Atlantic Methanol Capital
Company ("AMCCO"), is a 50 percent owned joint venture that owns an indirect 90
percent interest in Atlantic Methanol Production Company ("AMPCO"), which 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 began during the
second quarter of 2001. The construction cost of the turnkey contract was $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. The Company paid approximately $4 million in construction contract
phase payments in the first quarter of 2001 and has one final payment of
approximately $4 million due in the second quarter of 2001.

(5) COMPANY STOCK REPURCHASE PLAN

The Company's Board of Directors authorized a repurchase of up to $50
million in the Company's common stock. As of March 31, 2001, the Company had
completed 60.5 percent of the repurchase plan. The 2000 repurchase of 1,386,400
shares at an average cost of $21.84 per share was funded from the Company's
current cash flow. No such repurchases have occurred during 2001.

(6) RECLASSIFICATION TO CONFORM TO CURRENT YEAR PRESENTATION

Certain reclassifications have been made to the 2000 consolidated
financial statements to conform to the 2001 presentation.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

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-Q, the
matters discussed in this Form 10-Q 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 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-Q 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 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.

LIQUIDITY AND CAPITAL RESOURCES

Net cash provided by operating activities increased to $257.3 million in
the three months ended March 31, 2001 from $103.0 million in the same period of
2000. Cash and short-term investments increased from $23.2 million at December
31, 2000 to $29.3 million at March 31, 2001.

During the first quarter of 2001, the Company repaid a net $70 million on
its $300 million credit facility with $10 million outstanding at March 31, 2001.
At December 31, 2000, there was $80 million outstanding on the $300 million
credit facility. Long-term debt at March 31, 2001 was $455.5 million compared
with $525.5 million at December 31, 2000.

The Company has expended approximately $164.4 million of its $624.8
million 2001 capital budget through March 31, 2001. The Company expects to fund
its remaining 2001 capital budget from cash flows from operations and additional
borrowings from the credit facility as required. The Company continues to
evaluate possible strategic acquisitions and believes it is positioned to access
external sources of funding should it be necessary or desirable in connection
with an acquisition.

Through the recently formed Atlantic Methanol Production Company
("AMPCO"), the Company is participating, with a 45 percent expense interest and
a five percent carried interest for the Equatorial Guinea Government, in a joint
venture with CMS Energy Corporation to construct a methanol plant on Bioko
Island in Equatorial Guinea. The plant will use the gas from Samedan's 34
percent owned Alba field as feedstock. The plant is being designed to utilize
approximately 125 MMCF of gas per day. The gas is priced at $.25 per MMBTU.

On January 29, 1998, AMPCO awarded a contract to Raytheon Engineers and
Constructors to build the methanol plant. The turnkey plant construction cost is
$322.5 million and is being designed to produce 2,500 metric tons of methanol
per day, which equates to approximately 20,000 BBLS per day. Initial production
of commercial grade methanol commenced May 2, 2001. The plant's output is fully
subscribed for the balance of the year 2001.

The Company's unconsolidated subsidiary, Atlantic Methanol Capital
Company ("AMCCO"), is a 50 percent owned joint venture that owns an indirect 90
percent interest in AMPCO. 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 initial production of commercial grade methanol commenced May 2, 2001. The
construction cost of the turnkey contract was $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. The Company
paid approximately $4 million in construction contract phase payments in the
first quarter of 2001 and has one final payment of approximately $4 million due
in the second quarter of 2001.

The Company follows the entitlement method of accounting for its gas
imbalances. The Company's estimated gas imbalance receivables were $18.8 million
at March 31, 2001 and $18.5 million at December 31, 2000. Estimated gas
imbalance liabilities were $15.6 million at March 31, 2001 and $14.2 million at
December 31, 2000. These imbalances are valued at the amount which is expected
to be received or paid to settle the imbalances. The settlement of the
imbalances can occur either over the life or at the end of the life of a well,
on a volume basis or by cash settlement. The Company does not expect that a
significant portion of the settlements will occur in any one year. Thus, the
Company believes the settlement of gas imbalances will not have a material
impact on its liquidity.

RESULTS OF OPERATIONS

For the first quarter of 2001, the Company recorded net income of $105.9
million, or $1.88 per share, compared with a net income of $26.9 million, or
$.48 per share, in the first quarter of 2000. The increase resulted primarily
from substantially higher product prices.

Gas sales for the Company, excluding third party sales by Noble Gas
Marketing, Inc. ("NGM"), a wholly owned subsidiary of the Company, increased 170
percent for the three months ended March 31, 2001 compared with the same period
in 2000. The primary reason for the increased sales was an increase in average
gas price of 175 percent in the 2001 first quarter compared with the first
quarter of 2000.

Oil sales for the Company, excluding third party sales by Noble Trading,
Inc. ("NTI"), a wholly owned subsidiary of the Company, increased 13 percent for
the three months ended March 31, 2001, compared with the same period in 2000.
The increase in sales was due to an average oil price increase of six percent
coupled with a seven percent increase in the daily average production in the
first quarter of 2001 compared with the first quarter of 2000.

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.

For the first quarter of 2001, revenues and expenses from NGM and NTI
third party sales totaled $243.6 million and $240.0 million, respectively, for a
combined gross margin of $3.6 million. In comparison, for the first quarter of
2000, NGM and NTI third party sales and expenses of $117.9 million and $114.2
million, respectively, resulted in a combined gross margin of $3.7 million.

Due to the issuance of SFAS No. 137, which deferred the effective date of
SFAS No. 133, the Company was required to adopt the statement for fiscal years
beginning after June 15, 2000. 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). Due to the adoption of
SFAS Nos. 133 and 138, NGM, in the first quarter of 2001, recorded on the
Balance Sheet and Statement of Other Comprehensive Income and Equity an
additional $5.8 million in other current assets; $4.8 million in other current
liabilities; $0.9 million in accumulated other comprehensive income and $39
thousand in other income from various types of hedging transactions.

Certain selected oil and gas operating statistics follow:

For the three months
ended March 31,
-----------------------
2001 2000
--------- -----------

Oil revenue (in thousands)................................................. $ 61,472 $ 54,603
Average daily oil production - BBLS....................................... 28,124 26,167
Average oil price per BBL.................................................. $ 24.93 $ 23.55
Gas revenues (in thousands)................................................ $ 248,151 $ 91,994
Average daily gas production - MCFS........................................ 413,614 422,360
Average gas price per MCF.................................................. $ 6.80 $ 2.47

BBLS - BARRELS
MCF - THOUSAND CUBIC FEET

Oil and gas exploration expense increased $22.5 million to $38.5 million
for the three months ended March 31, 2001, as compared with the same period of
2000. This increase is attributable entirely to a corresponding increase in dry
hole expense, as compared to the same period of 2000.

Oil and gas operations expense increased $7.7 million to $33.9 million
for the three months ended March 31, 2001, as compared with the same period of
2000. This increase is primarily attributable to a $6.6 million increase in
lease operations expense as compared to the same period of 2000.

Depreciation, depletion and amortization (DD&A) expense increased 25
percent for the three months ended March 31, 2001 compared with the same period
in 2000. The unit rate of DD&A per barrel of oil equivalents (BOE), converting
gas to oil on the basis of 6 MCF per barrel, was $7.35 for the first three
months of 2001 compared with $5.87 for the same period of 2000. The increase in
the unit rate per BOE is due primarily to increased development costs incurred
in the Gulf of Mexico to stabilize the Company's oil and gas production volumes,
which are being amortized in the current and subsequent quarters. The Company
has recorded, through charges to DD&A, a reserve for future liabilities related
to dismantlement and reclamation costs for offshore facilities. This reserve is
based on the best estimates of Company engineers of such costs to be incurred in
future years.

Interest expense increased nine percent to $10.4 million for the three
months ended March 31, 2001 as compared with the same period of 2000. The
increase is attributable to an increase in credit facility borrowings for the
comparable quarter of 2000.

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 in the North Sea, as well as the completion of the Alba field
expansion in Equatorial Guinea and the startup of the methanol plant, which
would utilize gas feedstock from the Alba field. Offshore Ecuador, the Amistad
gas field development is expected to be completed and contributing to gas
production and cash flow in 2002, as well as the Machala power project which
will utilize gas from the Amistad gas field to supply electrical power. The
China field development in the southern portion of Bohai Bay is also projected
to be completed with first oil production expected in 2002.

The Company recently set its 2001 exploration and development budget at
$727 million. Such expenditures are planned to be funded through internally
generated cash flows and borrowings from the $300 million credit facility. The
Company believes that it is well positioned 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 to take advantage of future price increases that may
occur. However, the uncertainty of oil and gas prices continues to affect the
oil and gas industry. The Company can not predict the extent to which its
revenues will be affected by inflation, government regulation or changing
prices.

The Company's Board of Directors authorized a repurchase of up to $50
million of the Company's common stock. As of March 31, 2001, the Company had
completed 60.5 percent of the repurchase plan. The 2000 repurchase of 1,386,400
shares at an average cost of $21.84 per share was funded from the Company's
current cash flow. No such repurchases have occurred during 2001.

ITEM 3. 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
Company had no crude oil or natural gas hedges for its production in the first
quarter of 2001 except those entered into by NGM.

For calendar year 2000, the Company had entered into three crude oil
premium swap contracts related to its production. 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 have owed 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
had 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 have
paid 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 effect of these premium swap hedges was a $2.43 per BBL reduction in
the average crude oil price for the first quarter of 2000. Premium swap hedges
for April 2000 through December 2000, which averaged 7,000 BBLS per day, were
not closed at March 31, 2000.

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.

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 purchasing a NYMEX futures contract at the
Henry Hub with an adjoining basis swap at a physical location). Due to the size
of such transactions and certain restraints imposed by contract and by Company
guidelines, as of March 31, 2001 the Company had no material market risk
exposure from NGM's hedging activity. During the first quarter of 2001, NGM had
hedging transactions with broker-dealers that represented approximately
1,299,000 MMBTU's of gas per day. Hedges for April 2001 through December 2002,
which range from 25,000 MMBTU's to 925,000 MMBTU's of gas per day, and from
January 2003 through May 2006, for 20,000 MMBTU's of gas per day, for future
physical transactions, were not closed at March 31, 2001. During the first
quarter of 2000, NGM had hedging transactions with broker-dealers that
represented approximately 541,000 MMBTU's of gas per day.

The Company has a $300 million credit agreement which exposes the Company
to the risk of earnings or cash flow loss due to changes in market interest
rates. At March 31, 2001, the Company had $10 million outstanding on its $300
million 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.

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.

PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

(a) The annual meeting of stockholders of the Company was held at 9:30
a.m., local time, on Tuesday, April 24, 2001 in Houston, Texas.

(b) Proxies were solicited by the Board of Directors of the Company pursuant
to Regulation 14A under the Securities Exchange Act of 1934. There was no
solicitation in opposition to the Board of Directors' nominees as listed
in the proxy statement and all such nominees were duly elected.

(c) Out of a total of 56,523,490 shares of common stock of the Company
outstanding and entitled to vote, 49,707,620 shares were present in
person or by proxy, representing approximately 88 percent.

Number of Shares
WITHHOLDING
Number of Shares AUTHORITY
Voting FOR Election To Vote for Election
As Director As Director
----------------------------------- ---------------------------------

Alan A. Baker......................... 49,569,379 138,241
Michael A. Cawley..................... 49,572,939 134,681
Edward F. Cox......................... 49,564,929 142,691
Charles D. Davidson................... 42,109,192 7,598,428
Dale P. Jones......................... 49,566,287 141,333
T. Don Stacy.......................... 35,320,765 14,386,855

(d) The only other matter voted on by the shareholders, as fully described
in the proxy statement for the annual meeting, and the result of the
voting is as follows:

1. Stockholders adopted a resolution to amend the Noble Affiliates,
Inc. 1988 Non-Qualified Stock Option Plan for Non-Employee
Directors, as described in the Company's proxy statement dated
March 23, 2001. (For 44,889,972; Against 4,626,020; Abstaining
191,628).

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) The information required by this Item 6(a) is set forth in the Index to
Exhibits accompanying this quarterly report on Form 10-Q.

(b) The Company did not file any reports on Form 8-K during the three months
ended March 31, 2001.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934 as
amended, the registrant has duly caused this report to be signed on its behalf
by the undersigned thereunto duly authorized.

NOBLE AFFILIATES, INC.
(Registrant)

Date May 15, 2001 /s/ JAMES L. McELVANY
------------------------ ---------------------------------------------
JAMES L. McELVANY
Vice President-Finance and Treasurer
(Principal Financial Officer
and Authorized Signatory)

INDEX TO EXHIBITS

Exhibit
Number Exhibit
- ------------------------- ------------------------------------

None