<Page>

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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 SEPTEMBER 30, 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 November 2, 2001: 56,598,685

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

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

<Table>
<Caption>
(Unaudited)
September 30, December 31,
2001 2000
------------------ ----------------

ASSETS
Current Assets:
Cash and short-term investments................................... $ 18,008 $ 23,152
Accounts receivable-trade......................................... 171,128 235,843
Materials and supplies inventories................................ 21,291 4,645
Other current assets.............................................. 73,538 7,621
------------ -------------

Total Current Assets.............................................. 283,965 271,261
------------ -------------

Property, Plant and Equipment, at cost............................... 3,685,972 3,256,467
Less: accumulated depreciation,
depletion and amortization.............................. (1,957,409) (1,771,344)
------------ -------------

1,728,563 1,485,123
------------ -------------

Investment in Unconsolidated Subsidiary.............................. 118,378 74,159

Other Assets......................................................... 71,371 48,737
------------ -------------

Total Assets...................................................... $ 2,202,277 $ 1,879,280
============ =============

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable-trade............................................ $ 230,604 $ 279,379
Other current liabilities......................................... 81,390 30,730
Income taxes-current.............................................. 15,308
------------ -------------

Total Current Liabilities......................................... 311,994 325,417
------------ -------------

Deferred Income Taxes................................................ 158,028 117,048
------------ -------------

Other Deferred Credits and Noncurrent Liabilities.................... 64,672 61,639
------------ -------------

Long-term Debt....................................................... 635,626 525,494
------------ -------------

Shareholders' Equity:
Common stock...................................................... 198,352 196,672
Capital in excess of par value.................................... 388,112 373,259
Retained earnings................................................. 479,726 325,452
Accumulated other comprehensive income............................ 11,468
------------ -------------

1,077,658 895,383
Less Common Stock in Treasury
(at cost, 2,911,300 shares)....................................... (45,701) (45,701)
------------ -------------

Total Shareholders' Equity........................................ 1,031,957 849,682
------------ -------------

Total Liabilities and Shareholders' Equity........................ $ 2,202,277 $ 1,879,280
============= =============
</Table>

SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.

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

<Table>
<Caption>
Three Months Ended September 30,
-----------------------------------------
2001 2000
------------- ----------

REVENUES:
Oil and gas sales and royalties.................................... $ 168,547 $ 211,478
Gathering, marketing and processing................................ 134,417 145,876
Income (loss) from unconsolidated subsidiary....................... 1,229 336
Other income....................................................... 643 3,242
------------ -------------

304,836 360,932
------------ -------------

COSTS AND EXPENSES:
Oil and gas operations............................................. 32,005 33,976
Oil and gas exploration............................................ 48,862 17,469
Gathering, marketing and processing................................ 130,782 142,831
Depreciation, depletion and amortization........................... 68,536 57,051
Selling, general and administrative................................ 9,726 10,786
Interest........................................................... 10,974 9,295
Interest capitalized............................................... (3,575) (1,456)
------------ -------------

297,310 269,952
------------ -------------

INCOME BEFORE TAXES.................................................... 7,526 90,980

INCOME TAX PROVISION................................................... 3,718 (1) 33,763 (1)
------------ -------------

NET INCOME............................................................. $ 3,808 $ 57,217
============ =============

BASIC EARNINGS PER SHARE............................................... $ 0.07 (2) $ 1.02 (2)
============ =============

DILUTED EARNINGS PER SHARE............................................. $ 0.07 (2) $ 1.01 (2)
============ =============
</Table>

SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.

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

<Table>
<Caption>
Nine Months Ended September 30,
-----------------------------------------
2001 2000
------------- ----------

REVENUES:
Oil and gas sales and royalties.................................... $ 714,537 $ 531,590
Gathering, marketing and processing................................ 562,387 396,413
Income (loss) from unconsolidated subsidiary....................... 482 1,227
Other income....................................................... 1,912 10,073
------------ -------------

1,279,318 939,303
------------ -------------

COSTS AND EXPENSES:
Oil and gas operations............................................. 98,573 88,122
Oil and gas exploration............................................ 114,153 44,718
Gathering, marketing and processing................................ 552,457 386,598
Depreciation, depletion and amortization........................... 209,647 165,473
Selling, general and administrative................................ 32,207 34,772
Interest........................................................... 30,704 28,255
Interest capitalized............................................... (10,372) (3,942)
------------ -------------

1,027,369 743,996
------------ -------------

INCOME BEFORE TAXES.................................................... 251,949 195,307

INCOME TAX PROVISION................................................... 90,898 (1) 74,350 (1)
------------ -------------

NET INCOME............................................................. $ 161,051 $ 120,957
============ =============

BASIC EARNINGS PER SHARE............................................... $ 2.85 (2) $ 2.16 (2)
============ =============

DILUTED EARNINGS PER SHARE............................................. $ 2.81 (2) $ 2.13 (2)
============ =============
</Table>

SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.

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

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

Balance at December 31, 2000 196,672 373,259 325,452 (45,701) 849,682
Net income 161,051 161,051 161,051
Derivatives marked
to market 11,468 11,468 11,468
Shares issued 1,680 14,853 16,533
Dividends declared
($.12 per share) (6,777) (6,777)
----------- ------------------------------------------------------------------------
Total 172,519
===========

Balance at September 30, 2001 198,352 388,112 479,726 11,468 (45,701) 1,031,957
=====================================================================================================================
</Table>

SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.

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NOBLE AFFILIATES, INC. AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)

<Table>
<Caption>
Nine Months Ended September 30,
----------------------------------------
2001 2000
------------ ----------

Cash Flows from Operating Activities:
Net income............................................................ $ 161,051 $ 120,957
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization............................ 209,647 165,473
Dry hole............................................................ 79,661 18,078
Amortization of undeveloped lease costs, net........................ 12,297 8,514
(Gain) loss on disposal of assets................................... (1,919) (2,823)
Noncurrent deferred income taxes.................................... 40,981 13,106
(Income) loss from unconsolidated subsidiary........................ (482) (1,227)
Increase (decrease) in deferred credits............................. 3,033 4,932
(Increase) decrease in other....................................... (9,188) (1,856)
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable.......................... 64,715 (74,431)
(Increase) decrease in other current assets and inventories......... (84,411) 27,341
Increase (decrease) in accounts payable............................. (48,775) 59,831
Increase (decrease) in other current liabilities.................... 35,352 (26,110)
------------- ----------

Net Cash Provided by Operating Activities 461,962 311,785
------------- ----------

Cash Flows From Investing Activities:
Capital expenditures.................................................. (544,421) (276,920)
Investment in unconsolidated subsidiary............................... (43,736) (37,385)
Proceeds from sale of property, plant and equipment................... 1,295 11,906
------------- ----------

Net Cash Used in Investing Activities ................................... (586,862) (302,399)
------------- ----------

Cash Flows From Financing Activities:
Common stock repurchases.............................................. (30,283)
Exercise of stock options............................................. 16,533 7,433
Cash dividends........................................................ (6,777) (6,745)
Proceeds from credit facility......................................... 235,000 72,000
Repayment of credit facility.......................................... (125,000) (27,000)
------------ ----------

Net Cash Provided by Financing Activities................................ 119,756 15,405
------------ ----------

Increase (Decrease) in Cash and Short-term Investments................... (5,144) 24,791
------------ ----------

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

Cash and Short-term Investments at End of Period......................... $ 18,008 $ 27,716
============ ==========

Supplemental Disclosures of Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized).................................. $ 16,389 $ 20,154
Income taxes.......................................................... $ 66,131 $ 41,765
</Table>

SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.

6
<Page>

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 September 30, 2001 and December 31, 2000; the results of operations for
the three month and nine month periods ended September 30, 2001 and 2000,
respectively; the statement of comprehensive income and equity for the nine
month period ended September 30, 2001; and the cash flows for the nine month
periods ended September 30, 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 (BENEFIT)

For the three months ended September 30:

<Table>
<Caption>
(In thousands)
------------------------------------
2001 2000
---------- ---------

Current............................................................... $(12,788) $ 33,622
Deferred.............................................................. 16,506 141
---------- ---------

$ 3,718 $ 33,763
========== =========
</Table>

For the nine months ended September 30:

<Table>
<Caption>
(In thousands)
------------------------------------
2001 2000
---------- ---------

Current............................................................... $ 49,917 $ 61,727
Deferred.............................................................. 40,981 12,623
---------- ---------

$ 90,898 $ 74,350
========== =========
</Table>

(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 tables summarize the calculation of basic earnings per
share ("EPS") and diluted EPS.

For the three months ended September 30:

<Table>
<Caption>
2001 2000
------------------------- -------------------------
INCOME SHARES INCOME SHARES
(IN THOUSANDS, EXCEPT PER SHARE) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR)
- ---------------------------------------------------------------------------------------------------------------------

Net income/shares $3,808 56,595 $57,217 55,875
- ---------------------------------------------------------------------------------------------------------------------
BASIC EPS $0.07 $1.02
- ---------------------------------------------------------------------------------------------------------------------

Net income/shares $3,808 56,595 $57,217 55,875
EFFECT OF DILUTIVE SECURITIES

Stock options 575 830
Adjusted net income/shares $3,808 57,170 $57,217 56,705
- ---------------------------------------------------------------------------------------------------------------------
DILUTED EPS $0.07 $1.01
- ---------------------------------------------------------------------------------------------------------------------
</Table>

7
<Page>

For the nine months ended September 30:

Net income/shares $161,051 56,502 $120,957 56,008
- ---------------------------------------------------------------------------------------------------------------------
BASIC EPS $2.85 $2.16
- ---------------------------------------------------------------------------------------------------------------------

Net income/shares $161,051 56,502 $120,957 56,008
EFFECT OF DILUTIVE SECURITIES

Stock options 829 690
Adjusted net income/shares $161,051 57,331 $120,957 56,698
- ---------------------------------------------------------------------------------------------------------------------
DILUTED EPS $2.81 $2.13
- ---------------------------------------------------------------------------------------------------------------------
</Table>

(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 upon settlement.

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

On August 16, 2001, the Company (floating price payor) entered into a
total of three natural gas costless collar contracts related to its
production. The first contract, for the fourth quarter of 2001, for 50,000
MMBTU of gas per day, has a floor price of $3.25 per MMBTU and a ceiling
price of $4.60 per MMBTU. The other two contracts, for calendar year 2002,
each for 25,000 MMBTU of gas per day, have a floor price of $3.25 per MMBTU
and ceiling prices ranging from $5.05 to $5.10 per MMBTU. These contracts
entitle the Company to receive settlement from the counterparty (fixed price
payor) on a calendar quarterly basis, in amounts, if any, by which the
average settlement price for the last scheduled NYMEX trading day applicable
for each month, per calendar quarter, is less than the floor price. The
Company would pay the counterparty if the average settlement price for the
last scheduled NYMEX trading day applicable for each month per calendar
quarter is more than the ceiling price. The amount payable by the floating
price payor, if the floating price is above the ceiling price, is the product
of the notional quantity per calculation period and the excess, if any, of
the floating price over the ceiling price in respect of each calendar
quarter. The amount payable by the fixed price payor, if the floating price
is below the floor price, is the product of the notional quantity per
calculation period and the excess, if any, of the floor price over the
floating price in respect of each calendar quarter.

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 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

8
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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 $1,663,000
and $2,920,000 recorded in other income for the three months and nine months
ended September 30, 2000, respectively.

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 was required to 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. Due to the
adoption of SFAS Nos. 133 and 138, NGM recorded on the Balance Sheet and
Statement of Other Comprehensive Income and Equity, $52.7 million in other
current assets; $41.4 million in other current liabilities; $642.5 thousand
in long term assets; and $509.0 thousand in other income from hedging
transactions for the first nine months of 2001.

(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
completed construction of a methanol plant in Equatorial Guinea in the second
quarter of 2001. During 1999, AMCCO issued $250 million senior secured notes
due 2004, which are not included in the Company's balance sheet, 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, some of which have been delayed, are
projected to be $125.5 million. The Company paid approximately $1.7 million
in construction contract phase payments in the third quarter of 2001. The
plant produced approximately 201,800 metric tons of methanol in the third
quarter of 2001. The plant's output is fully subscribed for the balance of
the year 2001.

9
<Page>

required work. The shutdown will result in a reduction of approximately
930,000 MCF of gas sales, net to the Company's interest, to the plant from
the Alba field.

(5) COMPANY STOCK REPURCHASE PLAN

The Company's Board of Directors, in February 2000, authorized a
repurchase of up to $50 million in the Company's common stock. The 2000
repurchase of 1,386,400 shares at an average cost of $21.84 per share was
funded from the Company's current cash flow. On September 17, 2001 the
Company's Board of Directors approved an expansion of the original repurchase
program from $50 million to $100 million. Out of the expanded $100 million
repurchase program, approximately $70 million remains authorized to purchase
additional shares. Under the original $50 million authorization, the Company
repurchased approximately $30 million of common stock in the first quarter of
2000. The Company has not yet repurchased any additional shares under the
expanded authorization.

(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. All of the Company's
forward-looking statements, in this document or elsewhere, are qualified by
this cautionary disclosure.

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

10
<Page>

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.

11
<Page>

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 $462 million in
the nine months ended September 30, 2001 from $311.8 million in the same
period of 2000. Cash and short-term investments decreased from $23.2 million
at December 31, 2000 to $18 million at September 30, 2001.

During the first nine months of 2001, the Company borrowed a net $110
million on its $300 million credit facility, which combined with the $80
million borrowed at December 31, 2000, resulted in a balance of $190 million
drawn on the $300 million credit facility at September 30, 2001. Long-term
debt at September 30, 2001 was $635.6 million compared with $525.5 million at
December 31, 2000.

The Company has expended approximately $588.1 million of its $727
million 2001 capital expenditure budget through September 30, 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 and tactical
acquisitions and believes it is positioned to access external sources of
funding should it be necessary or desirable in connection with an acquisition.

Through Atlantic Methanol Production Company ("AMPCO"), the Company
participated, with a 50 percent expense interest (45 percent ownership net of
a five percent carried interest for the Equatorial Guinea Government), in a
joint venture with CMS Energy Corporation in the construction of a methanol
plant on Bioko Island in Equatorial Guinea. The plant is using the gas from
the Company's 34 percent owned Alba field as feedstock. The plant was
designed to utilize up to 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 plant was 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, some of which have been
delayed, are projected to be $125.5 million. Payments were due upon the
completion of specific phases of the

12
<Page>

construction. The Company paid approximately $1.7 million in construction
contract phase payments in the third quarter of 2001. The plant produced
approximately 201,800 metric tons of methanol in the third quarter of 2001.

The methanol plant in Equatorial Guinea is expected to be shut down
for approximately 30 days in the fourth quarter of 2001 to permit the
contractor to complete final construction requirements under the contract.
The partners have elected to do the work now, during a period of low methanol
pricing, to minimize the economic impact of this required work. The shutdown
will result in a reduction of approximately 930,000 MCF of gas sales, net to
the Company's interest, to the plant from the Alba field.

The Company follows the entitlement method of accounting for its gas
imbalances. The Company's estimated gas imbalance receivables were $19.6
million at September 30, 2001 and $18.5 million at December 31, 2000.
Estimated gas imbalance liabilities were $15.8 million at September 30, 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 third quarter of 2001, the Company recorded net income of $3.8
million, or $.07 per share, compared with a net income of $57.2 million, or
$1.02 per share, in the third quarter of 2000. The decreased earnings in the
third quarter of 2001 were a result of lower commodity prices, particularly
for natural gas, and higher exploration expense, although these effects were
partially offset by continued growth in production volumes. Natural gas and
oil prices decreased 36 percent and 13 percent, respectively, compared with
the third quarter of 2000, offset by higher natural gas and oil production
volumes, which increased 7.5 percent and 22 percent, respectively, compared
with the third quarter of 2000. Exploration expense increased 180 percent
compared to the third quarter of 2000. During the first nine months of 2001,
the Company recorded net income of $161.1 million, or $2.85 per share,
compared with $121.0 million, or $2.16 per share, in the first nine months of
2000. The year to date increase resulted from higher natural gas prices,
which increased 36 percent, coupled with a six percent and 16 percent
increase, respectively, in average daily natural gas and oil production
volumes, offset by a 155 percent increase in exploration expense, compared to
the same period in 2000.

Gas sales for the Company, excluding third party sales by Noble Gas
Marketing, Inc. ("NGM"), a wholly owned subsidiary of the Company, decreased
32 percent and increased 43 percent for the three months and nine months
ended September 30, 2001 compared with the same periods in 2000. The primary
reason for the decreased sales in the third quarter of 2001 was the result of
a 36 percent decrease in the average price of natural gas compared to the
same period in 2000. The nine month increase in gas sales is the result of a
36 percent increase in the price of natural gas coupled with a six percent
increase in the average daily production of natural gas, compared to the same
period in 2000.

Oil sales for the Company, excluding third party sales by Noble
Trading, Inc. ("NTI"), a wholly owned subsidiary of the Company, increased
eight percent and 15 percent for the three months and nine months ended
September 30, 2001 compared with the same periods in 2000. The increase in
sales was due to an increase in average daily production of 22 percent and 16
percent, respectively, for the three months and nine months ended September
30, 2001 compared with the same periods in 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 third quarter of 2001, revenues and expenses from NGM and NTI
third party sales totaled $134.4 million and $130.8 million, respectively,
for a combined gross margin of $3.6 million. In comparison, for the third
quarter of 2000, NGM and NTI third party sales and expenses of $145.9 million
and $142.8 million, respectively, resulted in a combined gross margin of $3.1
million. For the nine months ended September 30, 2001, combined NGM and NTI
revenues and expenses from third party sales totaled $562.4 million and
$552.5 million, respectively, for a gross margin of $9.9 million. In
comparison, combined NGM and NTI third party sales and expenses of $396.4
million and $386.6 million, respectively, resulted in a gross margin of $9.8
million for the same period in 2000.

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<Page>

SFAS No. 133 was required to 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 recorded on the Balance Sheet and Statement of Other
Comprehensive Income and Equity, $52.7 million in other current assets; $41.4
million in other current liabilities; $642.5 thousand in long term assets;
and $509.0 thousand in other income from hedging transactions for the first
nine months of 2001.

Certain selected oil and gas operating statistics follow:

<Table>
<Caption>
For the three months For the nine months
ended September 30, ended September 30,
------------------------- -----------------------
2001 2000 2001 2000
--------- -------- ------- --------

Oil revenue (in thousands)........................... $ 64,346 $ 59,782 $ 190,510 $ 165,786
Average daily oil production - BBLS.................. 31,665 25,863 29,773 25,624
Average oil price per BBL............................ $ 22.50 $ 25.76 $ 23.95 $ 24.23
Gas revenues (in thousands).......................... $ 99,958 $ 147,161 $ 506,555 $ 353,381
Average daily gas production - MCF................... 431,132 401,084 427,151 401,857
Average gas price per MCF............................ $ 2.60 $ 4.07 $ 4.46 $ 3.28
</Table>

BBLS - BARRELS
MCF - THOUSAND CUBIC FEET

Oil and gas exploration expense increased $31.4 million and $69.4
million for the three months and nine months ended September 30, 2001, as
compared with the same periods of 2000. These increases are attributable to a
$26.4 million increase in dry hole expense, a $1.6 million increase in
undeveloped lease amortization and a $3.6 million increase in seismic for the
three months ended September 30, 2001. For the nine months ended September
30, 2001, as compared with the same periods of 2000, there was a $61.6
million increase in dry hole expense and a $3.8 million increase in
undeveloped lease amortization.

Oil and gas operations expense decreased $2.0 million and increased
$10.5 million for the three months and nine months ended September 30, 2001,
as compared with the same periods of 2000. These variances are primarily
attributable to decreases in lease operations expense for the three months
and increases in lease operations expense for the nine months ended September
30, 2001, as compared with the same periods of 2000.

Depreciation, depletion and amortization (DD&A) expense increased 20
percent and 27 percent, respectively, for the three months and nine months
ended September 30, 2001 compared with the same periods 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 $7.61 for the first nine months of 2001
compared with $6.52 for the same period of 2000. The unit rate of DD&A per
BOE was $7.20 for the three months ended September 30, 2001 compared with
$6.69 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

14
<Page>

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 18 percent and nine percent for the three
months and nine months ended September 30, 2001 as compared with the same
periods of 2000. The increase in interest expense is attributable to an
increase in credit facility borrowings during the first nine months of 2001.

FUTURE TRENDS

The Company expects increased oil and gas production in the fourth
quarter of 2001 and in 2002 as compared to the fourth quarter of 2000. The
increase in 2001 would be primarily due to the Cook and Hanze acquisitions in
the North Sea. The Cook property was acquired in the fourth quarter of 2000
and its current gross production is approximately 21,000 barrels of oil per
day. The Company owns a 12.24 percent interest in the Cook field. The Hanze
field, located offshore Netherlands, is expected by yearend 2001 to have a
production rate of approximately 31,500 barrels of oil per day. The Company
owns a 15 percent interest in the Hanze field and first production began in
the third quarter of 2001. The completion of the Alba field expansion in
Equatorial Guinea and the startup of the methanol plant will 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, from the Cheng Dao Xi
Block, is projected to be completed with first oil production in the second
quarter of 2002.

The Company set its 2001 capital expenditure budget at $727 million of
which approximately $588.1 million has been expended through September 30,
2001. Remaining 2001 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 from the $300 million credit facility.

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 cannot predict the extent to
which its revenues will be affected by inflation, government regulation or
changing prices.

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
current production in the third quarter of 2001 except those entered into by
NGM.

15
<Page>

(fixed price payor) on a calendar quarterly basis, in amounts, if any, by
which the average settlement price for the last scheduled NYMEX trading day
applicable for each month, per calendar quarter, is less than the floor
price. The Company would pay the counterparty if the average settlement price
for the last scheduled NYMEX trading day applicable for each month per
calendar quarter is more than the ceiling price. The amount payable by the
floating price payor, if the floating price is above the ceiling price, is
the product of the notional quantity per calculation period and the excess,
if any, of the floating price over the ceiling price in respect of each
calendar quarter. The amount payable by the fixed price payor, if the
floating price is below the floor price, is the product of the notional
quantity per calculation period and the excess, if any, of the floor price
over the floating price in respect of each calendar quarter.

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 $3.23 per BBL reduction
in the average crude oil price for the third quarter of 2000. For the nine
months ended September 30, 2000, the net effect of the premium swap hedges
was a $2.73 per BBL reduction in the average crude oil price. Premium swap
hedges for October 2000 through December 2000, which averaged 7,000 BBLS per
day, were not closed at September 30, 2000.

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 September 30, 2001 the Company had no material
market risk exposure from NGM's hedging activity. During the third quarter of
2001, NGM had hedging transactions with broker-dealers that represented
approximately 1,473,000 MMBTU's of gas per day. Hedges for October 2001
through May 2006, which range from 20,000 MMBTU's to 1,056,000 MMBTU's of gas
per day, for future physical transactions, were not closed at September 30,
2001. During the third quarter of 2000, NGM had hedging transactions with
broker-dealers that represented approximately 948,000 MMBTU's of gas per day.
For the nine months ended September 30, 2001, NGM had hedging transactions
that represented approximately 1,290,000 MMBTU's of gas per day, compared
with 697,000 MMBTU's of gas per day for the same period in 2000.

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 September 30, 2001, the Company had $190 million
outstanding on its $300 million credit facility, which has a maturity date of
December 24, 2002. The interest rate is based upon a

16
<Page>

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.

17
<Page>

PART II. OTHER INFORMATION
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 September 30, 2001.

18
<Page>

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 November 13, 2001 /s/ JAMES L. McELVANY
--------------------- --------------------------------------------
JAMES L. McELVANY
Vice President-Finance and Treasurer
(Principal Financial Officer
and Authorized Signatory)

19
<Page>

INDEX TO EXHIBITS

<Table>
<Caption>
Exhibit
Number Exhibit
- ------------------------- ---------------------------------------------------

None
</Table>