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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 JUNE 30, 2000

/ / 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)

110 West Broadway
Ardmore, Oklahoma 73401
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)

(580) 223-4110
(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 August 4, 2000: 55,857,963

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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)
June 30, December 31,
2000 1999
----------- -----------

ASSETS
Current Assets:
Cash and short-term investments ...................... $ 39,901 $ 2,925
Accounts receivable-trade ............................ 145,477 98,794
Materials and supplies inventories ................... 4,745 5,517
Other current assets ................................. 9,188 10,678
----------- -----------

Total Current Assets ................................. 199,311 117,914
----------- -----------

Property, Plant and Equipment, at cost .................. 2,940,464 2,830,793
Less: accumulated depreciation,
depletion and amortization ................. (1,659,437) (1,588,423)
----------- -----------

1,281,027 1,242,370
----------- -----------

Investment in unconsolidated subsidiary ................. 41,897 15,625

Other Assets ............................................ 47,428 44,442
----------- -----------

Total Assets ......................................... $ 1,569,663 $ 1,420,351
=========== ===========

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable-trade ............................... $ 156,464 $ 103,753
Other current liabilities ............................ 28,672 48,215
Income taxes-current ................................. 7,932 2,503
----------- -----------

Total Current Liabilities ............................ 193,068 154,471
----------- -----------

Deferred Income Taxes ................................... 96,040 83,075
----------- -----------

Other Deferred Credits and Noncurrent Liabilities ....... 57,931 53,877
----------- -----------

Long-term Debt .......................................... 505,406 445,319
----------- -----------

Shareholders' Equity:
Common stock ......................................... 195,807 195,231
Capital in excess of par value ....................... 365,069 360,983
Retained earnings .................................... 202,043 142,813
----------- -----------

762,919 699,027
Less common stock in treasury at cost
(December 31, 1999, 1,524,900 shares and
June 30, 2000, 2,911,300 shares) ..................... (45,701) (15,418)
----------- -----------

Total Shareholders' Equity ........................... 717,218 683,609
----------- -----------

Total Liabilities and Shareholders' Equity ........... $ 1,569,663 $ 1,420,351
=========== ===========

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)

Six Months Ended June 30,
------------------------------------
2000 1999
---------- ----------

REVENUES:
Oil and gas sales and royalties...................................... $ 320,112 $ 238,203
Gathering, marketing and processing.................................. 250,537 153,906
Other income......................................................... 7,722 4,393
---------- ----------

578,371 396,502
---------- ----------

COSTS AND EXPENSES:
Oil and gas operations............................................... 54,146 61,111
Oil and gas exploration.............................................. 27,249 17,202
Gathering, marketing and processing.................................. 243,767 144,972
Depreciation, depletion and amortization............................. 108,422 126,682
Selling, general and administrative.................................. 23,986 23,015
Interest............................................................. 18,960 25,723
Interest capitalized................................................. (2,486) (2,693)
---------- ----------

474,044 396,012
---------- ----------

INCOME BEFORE TAXES...................................................... 104,327 490

INCOME TAX PROVISION..................................................... 40,587 (1) 212 (1)
---------- ----------

NET INCOME............................................................... $ 63,740 $ 278
========== ==========

BASIC EARNINGS PER SHARE................................................. $ 1.14 (2) $ .00 (2)
========== ==========

DILUTED EARNINGS PER SHARE............................................... $ 1.12 (2) $ .00 (2)
========== ==========

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 June 30,
-------------------------------------
2000 1999
----------- ----------

REVENUES:
Oil and gas sales and royalties...................................... $ 169,109 $ 125,970
Gathering, marketing and processing.................................. 132,668 90,273
Other income......................................................... 4,833 2,347
----------- ----------

306,610 218,590
----------- ----------

COSTS AND EXPENSES:
Oil and gas operations............................................... 27,981 29,759
Oil and gas exploration.............................................. 11,258 6,962
Gathering, marketing and processing.................................. 129,584 86,469
Depreciation, depletion and amortization............................. 56,864 60,133
Selling, general and administrative.................................. 12,015 11,624
Interest............................................................. 9,338 12,688
Interest capitalized................................................. (1,405) (1,570)
----------- ----------

245,635 206,065
----------- ----------

INCOME BEFORE TAXES...................................................... 60,975 12,525

INCOME TAX PROVISION..................................................... 24,114 (1) 3,346 (1)
----------- ----------

NET INCOME.............................................................. $ 36,861 $ 9,179
=========== ==========

BASIC EARNINGS PER SHARE................................................ $ .66 (2) $ .16 (2)
=========== ==========

DILUTED EARNINGS PER SHARE.............................................. $ .65 (2) $ .16 (2)
=========== ==========

SEE NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS.

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

Six Months Ended June 30,
-----------------------------------
2000 1999
--------- ----------

Cash Flows from Operating Activities:
Net income............................................................ $ 63,740 $ 278
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization............................ 108,422 126,682
Amortization of undeveloped lease costs, net........................ 5,164 3,105
Increase (decrease) in other deferred credits....................... 17,019 201
(Increase) decrease in other assets and other noncash items, net.... (4,640) 1,139
Changes in working capital, not including cash:
(Increase) decrease in accounts receivable.......................... (46,683) 11,309
(Increase) decrease in other current assets and inventories......... 32,032 31,565
Increase (decrease) in accounts payable............................. 52,711 (24,939)
Increase (decrease) in other current liabilities.................... (44,115) (1,689)
--------- ----------

Net Cash Provided by Operating Activities................................ 183,650 147,651
--------- ----------

Cash Flows From Investing Activities:
Capital expenditures.................................................. (160,300) (35,344)
Investment in unconsolidated subsidiary............................... (26,272) (24,324)
Proceeds from sale of property, plant and equipment................... 10,030 1,928
--------- ----------

Net Cash Used in Investing Activities ................................... (176,542) (57,740)
--------- ----------

Cash Flows From Financing Activities:
Noble share repurchase............................................... (30,283)
Exercise of stock options............................................ 4,662 94
Cash dividends....................................................... (4,511) (4,558)
Repayment of bank debt............................................... (12,000) (25,000)
Proceeds from bank borrowings........................................ 72,000
--------- ----------

Net Cash Provided by (Used in) Financing Activities ..................... 29,868 (29,464)
--------- ----------

Increase (Decrease) in Cash and Short-term Investments................... 36,976 60,447
--------- ----------

Cash and Short-term Investments at Beginning of Period................... 2,925 19,100
--------- ----------

Cash and Short-term Investments at End of Period......................... $ 39,901 $ 79,547
========= ==========

Supplemental Disclosures of Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized).................................. $ 16,793 $ 18,664
Income taxes ......................................................... $ 21,100 $ 2,000

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 June 30, 2000
and December 31, 1999 and the results of operations for the three month and six
month periods ended June 30, 2000 and 1999, respectively, and the cash flows for
the six month periods ended June 30, 2000 and 1999. These consolidated condensed
financial statements should be read in conjunction with the consolidated
financial statements and the notes thereto incorporated in the Company's annual
report on Form 10-K for the year ended December 31, 1999.

(1) INCOME TAX PROVISION (BENEFIT)

For the three months ended June 30:

(In thousands)
-----------------
2000 1999
------- -------

Current ................................................................. $16,779 $(1,885)
Deferred ................................................................ 7,335 5,231
------- -------

$24,114 $ 3,346
======= =======

For the six months ended June 30:

(In thousands)
-----------------
2000 1999
------- -------

Current ................................................................. $28,105 $(9,354)
Deferred ................................................................ 12,482 9,566
------- -------

$40,587 $ 212
======= =======

(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 the diluted EPS components required by Statement of Financial
Accounting Standards ("SFAS") No. 128, "Earnings per Share."

For the three months ended June 30:

2000 1999
-------------------------- ---------------------------
INCOME SHARES INCOME SHARES
(IN THOUSANDS, EXCEPT PER SHARE) (NUMERATOR) (DENOMINATOR) (NUMERATOR) (DENOMINATOR)
- -------------------------------------------------------------------------------------------------------------------

Net income/shares $36,861 55,756 $9,179 57,168
- -------------------------------------------------------------------------------------------------------------------
BASIC EPS $.66 $.16

Net income/shares $36,861 55,756 $9,179 57,168
Effect of Dilutive Securities
- -----------------------------
Stock options 924 295
Adjusted net income/shares $36,861 56,680 $9,179 57,463
- -------------------------------------------------------------------------------------------------------------------
DILUTED EPS $.65 $.16
- -------------------------------------------------------------------------------------------------------------------

For the six months ended June 30:

Net income/shares $63,740 56,076 $278 56,982
- -------------------------------------------------------------------------------------------------------------------
BASIC EPS $1.14 $.00

Net income/shares $63,740 56,076 $278 56,982
Effect of Dilutive Securities
- -----------------------------
Stock options 615 339
Adjusted net income/shares $63,740 56,691 $278 57,321
- -------------------------------------------------------------------------------------------------------------------
DILUTED EPS $1.12 $.00
- -------------------------------------------------------------------------------------------------------------------

(3) RESTATEMENT TO CONFORM TO CURRENT YEAR PRESENTATION

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

(4) TRADING AND HEDGING ACTIVITIES

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

The Company has entered into three crude oil premium swap contracts
related to its production for calendar year 2000. Two of the contracts provide
for payments based on daily NYMEX settlement prices. These contracts relate to
2,500 BBLS per day and 2,000 BBLS per day and have trigger prices of $21.73 per
BBL and $22.45 per BBL, respectively, and both have knockout prices of $17.00
per BBL. These two contracts entitle the Company to receive settlements from the
counterparties in amounts, if any, by which the settlement price for each NYMEX
trading day is less than the trigger price, provided the NYMEX price is also
greater than the $17.00 per BBL knockout price. If a daily settlement price is
$17.00 per BBL or less, then neither party will have any liability to the other
for that day. If a daily settlement price is above the applicable trigger price,
then the Company will owe the counterparty for the excess of the settlement
price over the trigger price for that day. Payment is 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 relates to 2,500 BBLS per day and provides for
payments based on monthly average NYMEX settlement prices. The contract entitles
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 is less than the trigger price, which is $21.73 per BBL, multiplied by
the number of days in the month, provided such average NYMEX price is also
greater than the $17.00 per BBL knockout price. If the average NYMEX settlement
price for the month is $17.00 per BBL or less, then neither party will have any
liability to the other for that month. If the average NYMEX settlement price for
the month is above the trigger price, then the Company will pay the counterparty
an amount equal to the excess of the average settlement price over the trigger
price, multiplied by the number of days in the month.

The Company has treated the swap component of these contracts as a hedge
(for accounting purposes only), at swap prices ranging from $19.40 per BBL to
$20.20 per BBL, which existed at the dates it entered into these contracts. In
addition, the Company has separately accounted for the premium component of
these contracts by marking them to market, resulting in a gain of $95,000 and
$1,257,000 recorded in other income for the three months and six months ended
June 30, 2000, respectively.

the average crude oil price. Premium swap hedges for July 2000 through
December 2000, which average 7,000 BBLS per day, were not closed at June 30,
2000.

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

The net effect of these costless collar hedges was a $.13 per BBL
reduction in the average crude oil price for the second quarter. For the six
months ended June 30, 2000, the net effect of the costless collar hedges was a
$.09 per BBL reduction in the average crude oil price.

The Company had no natural gas or crude oil hedging contracts related to
its production in the first half of 1999.

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.

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 June 30, 2000 the Company had no material market risk exposure
from NGM's hedging activity. During the second quarter of 2000, NGM had hedging
transactions with broker-dealers that represented approximately 599,000 MMBTU's
of gas per day. Hedges for July 2000 through May 2006, which range from 645
MMBTU's to 742,000 MMBTU's of gas per day for future physical transactions, were
not closed at June 30, 2000. During the second quarter of 1999, NGM had hedging
transactions with broker-dealers that represented approximately 476,000 MMBTU's
of gas per day. For the six months ended June 30, 2000, NGM had hedging
transactions that represented approximately 570,000 MMBTU's of gas per day,
compared with 601,000 MMBTU's of gas per day for the same period in 1999.

The Financial Accounting Standards Board ("FASB") issued Statement of
Financial Accounting Standard ("SFAS") No. 133, "Accounting for Derivative
Instruments and Hedging Activities" in June 1998. The Statement establishes
accounting and reporting standards requiring every derivative instrument
(including certain derivative instruments embedded in other contracts) to be
recorded in the balance sheet as either an asset or liability measured at its
fair value. The Statement requires that changes in the derivative's fair value
be recognized currently in earnings unless specific hedge accounting criteria
are met wherein gains and losses are reflected in shareholders' equity until the
hedged item is recognized. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company formally document, designate
and assess the effectiveness of transactions that receive hedge accounting.

statement as of the beginning of any fiscal quarter after the statement's
issuance (that is, fiscal quarters beginning June 16, 1998, and thereafter).
SFAS No. 133 must be applied to (a) derivative instruments and (b) certain
derivative instruments embedded in hybrid contracts that were issued,
acquired, or substantively modified after December 31, 1997 (and, at the
Company's election, before January 1, 1998). The Company has not quantified
the impact of adopting SFAS No. 133 but plans on adopting the statement by
January 1, 2001.

During 2000, the FASB issued SFAS No. 138 which amends the accounting and
reporting standards of SFAS No. 133 for certain derivative instruments and
certain hedging activities and should be adopted concurrently with SFAS No. 133,
according to its provisions and the issuance of SFAS No. 137. The normal
purchases and normal sales exception may be applied to contracts that implicitly
or explicitly permit net settlement and contracts that have a market mechanism
to facilitate net settlement. The Company has not quantified the impact SFAS No.
138 will have upon the adoption of SFAS No. 133.

(5) METHANOL PLANT

The Company's unconsolidated subsidiary, Atlantic Methanol Capital
Company LDC ("AMCCO"), is a 50 percent owned joint venture that indirectly owns
90 percent of Atlantic Methanol Production Company LLC ("AMPCO"), which is
constructing a methanol plant in Equatorial Guinea. During 1999, AMCCO issued
$125 million senior secured notes due 2004 net to the Company's interest (which
are not included in the Company's balance sheet) to fund the remaining
construction payments. The plant construction started during 1998 and commercial
production is expected during the second quarter of 2001. The construction cost
of the turnkey contract is $322.5 million. Other associated expenditures
required to complete the project and produce marketable supplies of methanol are
projected to be $101.3 million. The total cost of the methanol project is
estimated to be $423.8 million including various contingencies and capitalized
interest, with the Company responsible for $211.9 million. Payments are due upon
the completion of specific phases of the construction. The Company has
construction contract phase payments totaling $15.3 million due in the second
half of 2000 and $8.0 million due in the first half of 2001.

(6) 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 June 30, 2000, the Company had
completed 60.5 percent of the repurchase plan. The repurchase of 1,386,400
shares at an average cost of $21.84 per share was funded from the Company's
current cash flow.

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

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This report on Form 10-Q includes "forward-looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended. All statements other
than statements of historical fact included in this Form 10-Q, including,
without limitation, statements contained under "Management's Discussion and
Analysis of Financial Condition and Results of Operations" regarding anticipated
capital expenditures, projected timing of planned projects or activities, the
Company's financial position, business strategy, plans and objectives of
management of the Company for future operations and industry conditions, are
forward-looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, it can give no
assurance that such expectations will prove to have been correct. Important
factors that could cause actual results to differ materially from the Company's
expectations ("Cautionary Statements") include without limitation future
production levels, future prices and demand for oil and gas, results of future
exploration and development activities, future operating and development costs,
the effect of existing and future laws and governmental regulations (including
those pertaining to the environment) and the political and economic climate of
the United States and the foreign countries in which the Company operates from
time to time, as discussed in this quarterly report on Form 10-Q and the other
documents of the Company filed with the Securities and Exchange Commission (the
"Commission"). All subsequent written and oral forward-looking statements
attributable to the Company or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Statements.

LIQUIDITY AND CAPITAL RESOURCES

Net cash provided by operating activities increased to $183.7 million in
the six months ended June 30, 2000 from $147.7 million in the same period of
1999. Cash and short-term investments increased from $2.9 million at December
31, 1999 to $39.9 million at June 30, 2000.

During the first half of 2000, the Company borrowed $72.0 million on its
$300 million credit facility. During the second quarter of 2000, the Company
repaid $12.0 million. At December 31, 1999, there was no debt outstanding on the
$300 million credit facility. Long-term debt at June 30, 2000 was $505.4 million
compared with $445.3 million at December 31, 1999.

The Company has expended approximately $186.6 million of its $426.0
million 2000 capital budget through June 30, 2000. The Company expects to fund
its remaining 2000 capital budget from cash flows from operations and additional
borrowings from the credit facilities 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 LLC
("AMPCO"), Samedan is participating, with a 50 percent expense interest (45
percent ownership net of a five percent government carried interest), 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 34.8
percent owned Alba field as feedstock. The plant is being designed to utilize
approximately 115 MMCF of gas per day. The gas will be priced at approximately
$.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. The construction
contract stipulates that the first commercial production of methanol is expected
by the second quarter of 2001. Current marketing plans are to enter into
long-term contracts with methanol users in the United States and Europe.

The Company's unconsolidated subsidiary, Atlantic Methanol Capital
Company LDC ("AMCCO"), is a 50 percent owned joint venture that indirectly owns
90 percent of AMPCO. During 1999, AMCCO issued $125 million senior secured notes
due 2004 net to the Company's interest (which are not included in the Company's
balance sheet) to fund the remaining construction payments. The plant
construction started during 1998 and commercial production is expected during
the second quarter of 2001. The construction cost of the turnkey contract is
$322.5 million. Other associated expenditures required to complete the project
and produce marketable supplies of methanol are projected to be $101.3 million.
The total cost of the methanol project is estimated to be $423.8 million
including various contingencies and capitalized interest, with the Company
responsible for $211.9 million. Payments are due upon the completion of specific
phases of the construction. The Company has construction contract phase payments
totaling $15.3 million due in the second half of 2000 and $8.0 million due in
the first half of 2001.

The Company follows the entitlements method of accounting for its gas
imbalances. The Company's estimated gas imbalance receivables were $18.2 million
at June 30, 2000 and $17.9 million at December 31, 1999. Estimated gas imbalance
liabilities were $13.5 million at June 30, 2000 and $12.0 million at December
31, 1999. 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 second quarter of 2000, the Company recorded net income of $36.9
million, or $.66 per share, compared with net income of $9.2 million, or $.16
per share, in the second quarter of 1999. During the first six months of 2000,
the Company recorded net income of $63.7 million, or $1.14 per share, compared
with $278 thousand, or less than one cent per share, in the first six months of
1999. 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 36
percent and 27 percent, respectively, for the three months and six months ended
June 30, 2000, as compared with the same periods in 1999. The increase in sales
is due to an increase in the

average gas price of 56 percent and 49 percent, respectively, for the three
months and six months ended June 30, 2000, compared with the same periods in
1999.

Oil sales for the Company, excluding third party sales by Noble Trading,
Inc. ("NTI"), a wholly owned subsidiary of the Company, increased 30 percent and
55 percent, respectively, for the three months and six months ended June 30,
2000, compared with the same periods in 1999. The increase in sales was due to
an increase in the average oil price of 58 percent and 92 percent, respectively,
for the three months and six months ended June 30, 2000, compared with the same
periods of 1999.

NGM markets 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 as gathering, marketing and processing
revenues and expenses. All intercompany sales and expenses have been eliminated.

For the second quarter of 2000, revenues and expenses from NGM and NTI
third party sales totaled $132.7 million and $129.6 million, respectively, for a
combined gross margin of $3.1 million. In comparison, for the second quarter of
1999, NGM and NTI third party sales and expenses of $90.3 million and $86.5
million, respectively, resulted in a combined gross margin of $3.8 million. For
the six months ended June 30, 2000, combined NGM and NTI revenues and expenses
from third party sales totaled $250.5 million and $243.8 million, respectively,
for a gross margin of $6.7 million. In comparison, combined NGM and NTI third
party sales and expenses of $153.9 million and $145.0 million, respectively,
resulted in a gross margin of $8.9 million for the same period in 1999.

The effect of these swap hedges was a $2.53 per BBL reduction in the
average crude oil price for the second quarter. For the six months ended June
30, 2000, the net effect of the swap hedges was a $2.48 per BBL reduction in the
average crude oil price. Premium swap hedges for July 2000 through December
2000, which average 7,000 BBLS per day, were not closed at June 30, 2000.

The Company had no natural gas or crude oil hedging contracts related to
its production in the first half of 1999.

Due to the issuance of SFAS No. 137, which deferred the effective date of
SFAS No. 133, the Company is required to adopt the statement for fiscal years
beginning after June 15, 2000. A company may also implement the statement as of
the beginning of any fiscal quarter after the statement's issuance (that is,
fiscal quarters beginning June 16, 1998, and thereafter). SFAS No. 133 must be
applied to (a) derivative instruments and (b) certain derivative instruments
embedded in hybrid contracts that were issued, acquired, or substantively
modified after December 31, 1997 (and, at the Company's election, before January
1, 1998). The Company has not quantified the impact of adopting SFAS No. 133 but
plans on adopting the statement by January 1, 2001.

were not closed at June 30, 2000. During the second quarter of 1999, NGM had
hedging transactions with broker-dealers that represented approximately
476,000 MMBTU's of gas per day. For the six months ended June 30, 2000, NGM
had hedging transactions that represented approximately 570,000 MMBTU's of
gas per day, compared with 601,000 MMBTU's of gas per day for the same period
in 1999.

Certain selected oil and gas operating statistics follow:

For the three months For the six months
ended June 30, ended June 30,
------------------------ ------------------------
2000 1999 2000 1999
----------- ----------- ---------- -----------

Oil revenue (in thousands)............... $ 51,401 $ 39,539 $ 106,004 $ 68,609
Average daily oil production - BBLS...... 24,839 29,998 25,503 31,694
Average oil price per BBL................ $ 23.34 $ 14.77 $ 23.45 $ 12.24
Gas revenue (in thousands)............... $ 114,226 $ 83,693 $ 206,220 $ 162,967
Average daily gas production - MCF....... 382,136 439,372 402,248 479,715
Average gas price per MCF................ $ 3.34 $ 2.14 $ 2.89 $ 1.94

BBLS - BARRELS
MCF - THOUSAND CUBIC FEET

Oil and gas exploration expense increased $4.3 million and $10.0 million
respectively, for the three months and six months ended June 30, 2000, as
compared with the same periods in 1999. These increases are attributable to a
$2.4 million increase in dry hole expense and a $1.9 million increase in
abandoned assets, for the three months ended June 30, 2000 and a $6.8 million
increase in dry hole expense and a $2.2 million increase in seismic expense for
the six months ended June 30, 2000, as compared with the same period of 1999.

Oil and gas operations expense decreased $1.8 million and $7.0 million
respectively for the three months and six months ended June 30, 2000, as
compared with the same periods in 1999. These decreases are due primarily to
decreased lease operations expense of $2.9 million and $8.3 million,
respectively, for the three months and six months ended June 30, 2000, compared
with the same periods in 1999.

Depreciation, depletion and amortization ("DD&A") expense decreased five
percent and 14 percent, respectively, for the three months and six months ended
June 30, 2000 compared with the same periods in 1999. The unit rate of DD&A per
barrel of oil equivalent ("BOE"), converting gas to oil on the basis of 6 MCF
per barrel, was $6.44 for the first six months of 2000 compared with $6.27 for
the same period of 1999. The unit rate of DD&A per BOE was $7.06 for the three
months ended June 30, 2000 compared with $6.40 for the same period in 1999. 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 decreased 26 percent for both the three months and six
months ended June 30, 2000 as compared with the same periods in 1999. The
decrease is attributable to a $214.8 million decrease in long-term debt at June
30, 2000 compared with June 30, 1999.

FUTURE TRENDS

The Company expects flat oil and gas volumes during the remainder of 2000
compared with 1999, with increasing volumes in 2001 and 2002. The 2001 volume
increase would be primarily due to the Alba field condensate production and gas
feedstock for the methanol plant in Equatorial Guinea and the Amistad gas field
production in Ecuador along with domestic exploitation. The 2002 volume increase
would be primarily due to oil production in China.

The Company has set its 2000 exploration and development budget at $497.5
million (composed of the capital budget and the exploration budget). Such
expenditures are planned to be funded through internally generated cash flows
and borrowings from the $300 million credit facility to complete the methanol
project. 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 June 30, 2000, the Company had
completed 60.5 percent of the repurchase plan. The repurchase of 1,386,400
shares at an average cost of $21.84 per share was funded from the Company's
current cash flow.

YEAR 2000 ISSUE

The Year 2000 issue is a result of computer programs being written using
two digits rather than four to define the applicable year. Computer equipment,
software and devices with embedded technology that are time-sensitive may
recognize a date using "00" as the year 1900 rather than the year 2000. This can
result in a system failure or miscalculations causing disruptions of operations,
including, among other things, a temporary inability to process transactions,
send invoices, or engage in similar normal business activities. The Company took
various initiatives intended to ensure that its computer equipment and software
would function properly with respect to dates in the year 2000 and thereafter.

As of June 30, 2000, the Company has encountered no significant Year 2000
problems.

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 1999. The
swap component of the contracts discussed in the following paragraphs was
treated as a hedge for accounting purposes only.

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 June 30, 2000, the Company had $60.0 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.

On June 17, 1999, the Company entered into a new $100 million 364 day
credit agreement with certain commercial lending institutions. There is no
balance outstanding on this agreement which is based upon a Eurodollar rate plus
37.5 to 87.5 basis points depending upon the percentage of utilization.

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.

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 June 30, 2000.

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 August 11, 2000 /s/ James L. McElvany
------------------------ ----------------------------------------
JAMES L. McELVANY
Vice President-Finance and Treasurer
(Principal Financial Officer
and Authorized Signatory)

INDEX TO EXHIBITS

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

27.1 Financial Data Schedule