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, 2001March 31, 2002

(_) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.

Commission file number 1-10447

CABOT OIL & GAS CORPORATION
(Exact name of registrant as specified in its charter)

DELAWARE 04-3072771
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)

1200 Enclave Parkway, Houston, Texas 77077
(Address of principal executive offices including Zip Code)

(281) 589-4600
(Registrant's telephone number)

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 and (2) has been subject to such filing
requirements for the past 90 days.

Yes X No ______
-----No___
--

As of October 25, 2001,April 24, 2002, there were 31,602,49731,965,705 shares of Class A Common
Stock, Par Value $.10 Per Share, outstanding.

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CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

Part I. Financial Information Page
----

Item 1. Financial Statements

Condensed Consolidated Statement of Operations for the Three and Nine Months
Ended September 30, 2001March 31, 2002 and 2000................................................2001.................................................................. 3

Condensed Consolidated Balance Sheet at September 30, 2001March 31, 2002 and December 31, 2000..2001..................... 4

Condensed Consolidated Statement of Cash Flows for the Three and Nine Months
Ended September 30, 2001March 31, 2002 and 2000................................................2001.................................................................. 5

Notes to the Condensed Consolidated Financial Statements..............................Statements......................................... 6

Report of Independent Accountant's Review of Interim Financial Information.................................................... 13Information....................... 12

Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations....................................................... 14Operations...................................................................... 13

Item 3A. Quantitative and Qualitative Disclosures about Market Risk................. 24Risk................................. 20

Part II. Other Information

Item 2. Changes in Securities and Use of Proceeds.................................. 26

Item 6. Exhibits and Reports on Form 8-K............................................ 26

Signature.............................................................................. 278-K............................................................ 22

Signature................................................................................................. 23

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements
------------------------------ ------------------------------

CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS (Unaudited)
(In Thousands, Except Per Share Amounts)

THREE MONTHS ENDED
NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------- -----------------------------MARCH 31,
-------------------------------
2002 2001
2000 2001 2000
-------- -------- ------------------- -----------

NET OPERATING REVENUES
Natural Gas Production.....................Production........................................................ $ 71,227 $45,099 $245,363 $123,08846,506 $ 100,725
Brokered Natural Gas....................... 18,447 32,771 81,142 106,731Gas.......................................................... 13,698 35,422
Crude Oil and Condensate................... 12,712 7,593 35,232 16,567& Condensate........................................................ 13,718 11,556
Change in Derivative Fair Value (Note 8).. (422) -- 789 --
Other...................................... 2,262 773 4,198 7,417
-------- ------- -------- --------
104,226 86,236 366,724 253,803..................................... (616) 6,198
Other......................................................................... 1,767 990
---------- -----------
75,073 154,891
OPERATING EXPENSES
Brokered Natural Gas Cost.................. 18,472 31,541 78,951 102,949
Direct Operations - Field & Pipeline....... 11,745 8,718 29,615 26,292
Exploration................................ 14,441 4,691 39,754 12,086Cost..................................................... 12,267 34,155
Production and Pipeline Operations............................................ 12,235 8,220
Exploration................................................................... 7,056 10,773
Depreciation, Depletion and Amortization... 22,716 13,216 54,805 38,329Amortization...................................... 23,210 15,891
Impairment of Unproved Properties.......... 2,232 963 5,196 2,886Properties............................................. 2,337 1,482
Impairment of Long-Lived Assets............ 1,721Assets............................................... 1,063 -- 1,721 9,143
General and Administrative................. 6,520 5,318 18,158 15,536Administrative.................................................... 5,739 5,946
Taxes Other Than Income.................... 4,547 6,016 21,164 15,570
-------- ------- -------- --------
82,394 70,463 249,364 222,791than Income....................................................... 6,152 9,902
---------- -----------
70,059 86,369
Gain (Loss) on Sale of Assets................ (231) 26 (258) (21)
-------- ------- -------- --------Assets..................................................... (18) 4
---------- -----------
INCOME FROM OPERATIONS....................... 21,601 15,799 117,102 30,991
MinorityOPERATIONS............................................................ 4,996 68,526
Interest in Subsidiaries............ 14 -- 14 --
Interest Expense............................. 5,126 5,709 14,535 17,044
-------- ------- -------- --------Expense and Other........................................................ 6,226 4,706
---------- -----------
Income (Loss) Before Income Taxes................... 16,461 10,090 102,553 13,947Taxes................................................. (1,230) 63,820
Income Tax Expense........................... 6,430 3,953 39,868 5,546
-------- ------- -------- --------Expense (Benefit)...................................................... (432) 24,758
---------- -----------
NET INCOME................................... 10,031 6,137 62,685 8,401

Dividend Requirement on Preferred Stock...... -- -- -- (3,749)
-------- ------- -------- --------
Net Income Available to
Common Stockholders.......................INCOME (LOSS)................................................................. $ 10,031(798) $ 6,137 $ 62,685 $ 12,150
======== ======= ======== ========39,062
========== ===========

Basic Earnings (Loss) Per Share
Available to Common Stockholders..........Share................................................... $ 0.33(0.03) $ 0.21 $ 2.10 $ 0.451.33

Diluted Earnings (Loss) Per Share
Available to Common Stockholders..........Share................................................. $ 0.32(0.03) $ 0.21 $ 2.07 $ 0.451.32

Average Common Shares Outstanding............ 30,644 28,976 29,829 26,830Outstanding................................................. 31,604 29,318

The accompanying notes are an integral part of these condensed
consolidated financial statements.

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CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (Unaudited)
(In Thousands)

SEPTEMBER 30,MARCH 31, DECEMBER 31,
2002 2001
2000
---------- --------------------- -------------

ASSETS
Current Assets
Cash and Cash Equivalents..............................Equivalents................................................ $ 13,9324,976 $ 7,5745,706
Accounts Receivable.................................... 58,731 85,677
Inventories............................................ 20,266 11,037
Other.................................................. 23,129 5,981
---------- --------Receivable...................................................... 51,635 50,711
Inventories.............................................................. 12,065 17,560
Other.................................................................... 12,740 11,010
------------- -------------
Total Current Assets................................ 116,058 110,269Assets.................................................. 81,416 84,987
Properties and Equipment, Net (Successful Efforts Method).. 974,403 623,174.................... 982,146 981,338
Other Assets............................................... 2,636 2,191
---------- --------
$1,093,097 $735,634
========== ========Assets................................................................. 2,613 2,706
------------- -------------
$ 1,066,175 $ 1,069,031
============= =============

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current Portion of Long-Term Debt......................Accounts Payable......................................................... $ --64,028 $ 16,000
Accounts Payable....................................... 90,811 81,56679,575
Accrued Liabilities.................................... 29,036 20,542
---------- --------Liabilities...................................................... 41,114 30,665
------------- -------------
Total Current Liabilities........................... 119,847 118,108Liabilities............................................. 105,142 110,240
Long-Term Debt............................................. 367,000 253,000Debt............................................................... 412,000 393,000
Deferred Income Taxes...................................... 221,737 108,174Taxes........................................................ 194,543 200,859
Other Liabilities.......................................... 18,338 13,847Liabilities............................................................ 18,798 18,380
Stockholders' Equity
Common Stock:
Authorized -- 40,000,000 Shares of $.10 Par Value
Issued and Outstanding - 31,911,685 Shares and
31,905,097 Shares in 2002 and 29,494,411 Shares in 2001, and 2000, Respectively....Respectively...................... 3,191 2,9493,191
Additional Paid-in Capital............................. 343,907 285,572Capital............................................... 346,885 346,260
Retained Earnings/(AccumulatedEarnings (Accumulated Deficit)................ 17,515 (41,632)
Accumulated.................................. (1,412) 650
Other Comprehensive Income (Loss) (Note 9)........ 5,946 --............................... (8,588) 835
Less Treasury Stock, at Cost:
302,600 Shares in 20012002 and 2000.....................2001....................................... (4,384) (4,384)
---------- --------------------- -------------
Total Stockholders' Equity.......................... 366,175 242,505
---------- --------
$1,093,097 $735,634
========== ========Equity............................................ 335,692 346,552
------------- -------------
$ 1,066,175 $ 1,069,031
============= =============

The accompanying notes are an integral part of these condensed
consolidated financial statements.

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CABOT OIL & GAS CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited)
(In Thousands)

THREE MONTHS ENDED
NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------------- ---------------------MARCH 31,
------------------------------
2002 2001
2000 2001 2000
--------- -------- --------- -------------------- -----------

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income.....................................Income (Loss)............................................................. $ 10,031(798) $ 6,137 $ 62,685 $ 8,40139,062
Adjustment to Reconcile Net Income to Cash
Provided by Operating Activities:
Depletion, Depreciation and Amortization..... 22,716 13,216 54,805 38,329Amortization.................................. 23,210 15,891
Impairment of Undeveloped Leasehold.......... 2,232 963 5,196 2,886Leasehold....................................... 2,337 1,482
Impairment of Long-Lived Assets.............. 1,721Assets........................................... 1,063 -- 1,721 9,143
Deferred Income Taxes........................ 11,550 3,567 30,657 4,175Tax Expense............................................... (471) 13,788
(Gain) Loss on Sale of Assets................ 231 (26) 258 21Assets............................................. 18 (4)
Exploration Expense.......................... 14,441 4,691 39,754 12,086Expense....................................................... 7,056 10,773
Change in Derivative Fair Value.............. 422 -- (789) --
Other........................................ 939 823 2,320 1,077Value........................................... 616 (6,198)
Other..................................................................... 1,364 777
Changes in Assets and Liabilities:
Accounts Receivable.......................... (3,090) (3,997) 26,946 (11,774)
Inventories.................................. (6,072) (6,289) (9,229) (3,673)Receivable....................................................... (924) 14,533
Inventories............................................................... 5,495 3,461
Other Current Assets......................... (5,914) (255) (6,448) (1,060)Assets...................................................... (3,235) 1,759
Other Assets................................. (662) 253 (445) 593Assets.............................................................. 93 144
Accounts Payable and Accrued Liabilities..... (5,814) 3,398 3,577 11,799Liabilities.................................. (6,100) 13,110
Other Liabilities............................ 4,974 146 3,790 1,831
--------- -------- --------- ---------Liabilities......................................................... (175) 1,020
----------- -----------
Net Cash Provided by Operating Activities.. 47,705 22,627 214,798 73,834
--------- -------- --------- ---------Activities.............................. 29,549 109,598
----------- -----------

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures........................... (213,041) (29,614) (276,795) (71,674)Expenditures.......................................................... (41,062) (34,748)
Proceeds from Sale of Assets................... 5,159 882 5,898 2,663Assets.................................................. (2) 438
Exploration Expense............................ (14,441) (4,691) (39,754) (12,086)
--------- -------- --------- ---------Expense........................................................... (7,056) (10,773)
----------- -----------
Net Cash Used by Investing Activities......... (222,323) (33,423) (310,651) (81,097)
--------- -------- --------- ---------Activities.................................. (48,120) (45,083)
----------- -----------

CASH FLOWS FROM FINANCING ACTIVITIES
Increase in Debt.............................................................. 56,000 19,000
Decrease in Debt.............................................................. (37,000) (89,000)
Sale of Common Stock........................... 372 1,549 7,748 81,597
Retirement of Preferred Stock.................. -- -- -- (51,600)
Increase in Debt............................... 289,000 39,000 362,000 95,000
Decrease in Debt............................... (109,000) (28,000) (264,000) (112,000)Stock.......................................................... 105 4,194
Dividends Paid................................. (1,183) (1,160) (3,537) (5,391)
--------- -------- --------- ---------Paid................................................................ (1,264) (1,172)
----------- -----------
Net Cash Provided (Used) by Financing Activities..... 179,189 11,389 102,211 7,606
--------- -------- --------- ---------Activities....................... 17,841 (66,978)
----------- -----------

Net IncreaseDecrease in Cash and Cash Equivalents....... 4,571 593 6,358 343Equivalents......................................... (730) (2,463)
Cash and Cash Equivalents, Beginning of Period.. 9,361 1,429Period.................................... 5,706 7,574
1,679
--------- -------- --------- -------------------- -----------
Cash and Cash Equivalents, End of Period........Period.......................................... $ 13,9324,976 $ 2,022 $ 13,932 $ 2,022
========= ======== ========= =========5,111
=========== ===========

The accompanying notes are an integral part of these condensed
consolidated financial statements.

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CABOT OIL & GAS CORPORATION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. FINANCIAL STATEMENT PRESENTATION

During interim periods, Cabot Oil & Gas Corporation follows the same
accounting policies used in its Annual Report to Stockholders and its Report on
Form 10-K filed with the Securities and Exchange Commission (with the addition
of SFAS 133, which was adopted on January 1, 2001 - see Note 8).Commission. People using
financial information produced for interim periods are encouraged to refer to
the footnotes in the Annual Report to Stockholders when reviewing interim
financial results. In management's opinion, the accompanying interim financial
statements contain all material adjustments, consisting only of normal recurring
adjustments, necessary for a fair presentation. The results of operations for
any interim period are not necessarily indicative of the results of operations
for the entire year.

Our independent accountants have performed a review of these condensed
consolidated interim financial statements in accordance with standards
established by the American Institute of Certified Public Accountants. Pursuant
to Rule 436(c) under the Securities Act of 1933, this report should not be
considered a part of a registration statement prepared or certified by
PricewaterhouseCoopers LLP within the meanings of Section 7 and 11 of the Act.

In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statementsapproved
for issuance Statement of Financial Accounting Standards No. 141 "Business Combinations"
("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142").
SFAS 141 requires all business combinations initiated after June 30, 2001 to be
accounted for under the purchase method. For all business combinations for
which the date of acquisition is after June 30, 2001, SFAS 141 also establishes
specific criteria for the recognition of intangible assets separately from
goodwill and requires unallocated negative goodwill to be written off
immediately as an extraordinary gain, rather than deferred and amortized. SFAS
142 changes the accounting for goodwill and other intangible assets after an
acquisition. The most significant changes made by SFAS 142 are: 1) goodwill
and intangible assets with indefinite lives will no longer be amortized; 2)
goodwill and intangible assets with indefinite lives must be tested for
impairment at least annually; and 3) the amortization period for intangible
assets with finite lives will no longer be limited to forty years. The Company
does not believe that the adoption of these statements will have a material
effect on its financial position, results of operations, or cash flows.

In June 2001, the FASB also approved for issuance SFAS 143, "Asset Retirement
Obligations."Obligations" ("SFAS 143"). SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-lived assets, including (1)
the timing of the liability recognition, (2) initial measurement of the
liability, (3) allocation of asset retirement cost to expense, (4) subsequent
measurement of the liability and (5) financial statement disclosures. SFAS 143
requires that an asset retirement cost should be capitalized as part of the cost
of the related long-lived asset and subsequently allocated to expense using a
systematic and rational method. The Company will adopt the statement effective
no later than January 1, 2003, as required. The transition adjustment resulting
from the adoption of SFAS 143 will be reported as a cumulative effect of a
change in accounting principle. At this time, the Company cannot reasonably
estimate the effect of the adoption of this statement on its financial position,
results of operations, or cash flows.

In August 2001, the FASB also approved SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). SFAS 144 replaces
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of."

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from the rest of the entity and that will be eliminated from the ongoing
operations of the entity in a disposal transaction. The provisions of SFAS 144
are effective for financial statements issued for fiscal years beginning after
December 15, 2001 and, generally, are to be applied prospectively. At this time,
the Company cannot estimate the effect of this statement on its financial
position, results of operations, or cash flows.

2. PROPERTIES AND EQUIPMENT

Properties and equipment are comprised of the following:

SEPTEMBER 30,MARCH 31, DECEMBER 31,
2002 2001
2000
---------- --------------------- ------------
(In thousands)

Unproved Oil and Gas Properties.......................Properties........................................ $ 71,95570,014 $ 31,78070,709
Proved Oil and Gas Properties......................... 1,363,772 993,397Properties.......................................... 1,426,317 1,400,341
Gathering and Pipeline Systems........................ 129,402 128,257Systems......................................... 132,201 131,768
Land, Building and Improvements....................... 4,563 4,538
Other................................................. 25,913 25,601
---------- ----------
1,595,605 1,183,573Improvements........................................ 4,767 4,674
Other.................................................................. 27,844 27,513
----------- ------------
1,661,143 1,635,005
Accumulated Depreciation, Depletion and Amortization.. (621,202) (560,399)
---------- ----------Amortization................... (678,997) (653,667)
----------- ------------
$ 974,403982,146 $ 623,174
========== ==========981,338
=========== ============

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3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

SEPTEMBER 30,MARCH 31, DECEMBER 31,
2002 2001
2000
------- ----------------- ------------
(In thousands)

Accounts Receivable
Trade Accounts......................................... $48,321 $79,773Accounts.......................................................... $ 41,976 $ 39,570
Joint Interest Accounts................................ 12,550 4,074Accounts................................................. 11,274 12,889
Current Income Tax Receivable.......................... 37 37Receivable........................................... 2,662 2,662
Other Accounts......................................... 747 4,347
------- -------
61,655 88,231Accounts.......................................................... 990 986
---------- ----------
56,902 56,107
Allowance for Doubtful Accounts......................... (2,924) (2,554)
------- -------
$58,731 $85,677
======= =======Accounts........................................... (5,267) (5,396)
---------- ----------
$ 51,635 $ 50,711
========== ==========

Other Current Assets
Derivative Instrument Asset - SFAS 133................. $10,701Commodity Hedging Contracts............................................. $ -- $ 2,387
Drilling Advances...................................... 1,700 2,459Advances....................................................... 4,544 2,111
Prepaid Balances....................................... 1,186 1,101Balances........................................................ 1,508 2,114
Restricted Cash and Other Investments...................................... 3,503 --
Other Accounts......................................... 6,039 2,421
------- -------
$23,129Accounts...................................... 6,688 4,398
---------- ----------
$ 5,981
======= =======12,740 $ 11,010
========== ==========

Accounts Payable
Trade Accounts......................................... $25,986 $20,855Accounts.......................................................... $ 20,457 $ 19,914
Natural Gas Purchases.................................. 8,411 12,525Purchases................................................... 3,828 4,559
Royalty and Other Owners............................... 13,472 22,858Owners................................................ 12,581 11,041
Capital Costs.......................................... 26,725 13,486Costs........................................................... 17,304 30,923
Taxes Other Than Income................................ 3,121 2,654Income................................................. 1,835 2,686
Drilling Advances...................................... 2,968 456Advances....................................................... 2,405 2,627
Wellhead Gas Imbalances................................ 2,480 2,185Imbalances................................................. 2,634 2,353
Other Accounts......................................... 7,648 6,547
------- -------
$90,811 $81,566
======= =======

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SEPTEMBER 30, DECEMBER 31,
2001 2000
------- -------
(In thousands)
Accounts.......................................................... 2,984 5,472
---------- ----------
$ 64,028 $ 79,575
========== ==========

Accrued Liabilities
Employee Benefits......................................Benefits....................................................... $ 5,8653,894 $ 5,4417,151
Taxes Other Than Income................................ 15,905 11,363Income................................................. 14,354 13,623
Interest Payable....................................... 5,436 2,478
Short-Term Derivative Instrument LiabilityPayable........................................................ 5,789 6,996
Commodity Hedging Contracts - SFAS 133.. 7Short-Term................................ 14,380 --
Other Accrued.......................................... 1,823 1,260
------- -------
$29,036 $20,542
======= =======Accrued........................................................... 2,697 2,895
---------- ----------
$ 41,114 $ 30,665
========== ==========

Other Liabilities
Postretirement Benefits Other Than Pension.............Pension.............................. $ 1,7461,693 $ 1,4971,689
Accrued Pension Cost................................... 7,031 6,743
Long-Term Derivative Instrument Liability - SFAS 133... 205 --Cost.................................................... 7,715 7,280
Taxes Other Than Income and Other...................... 9,356 5,607
------- -------
$18,338 $13,847
======= =======Other....................................... 9,390 9,411
---------- ----------
$ 18,798 $ 18,380
========== ==========

4. LONG-TERM DEBT

At September 30, 2001,March 31, 2002, the Company had $97$142 million outstanding under its
credit facility, which provides for an available credit line of $250 million.
The available credit line is subject to adjustment from time-to-time on the
basis of the projected present value (as determined by the banks' petroleum
engineer incorporating certain assumptions provided by the lender) of estimated
future net cash flows from proved oil and gas reserves and other assets of the
Company. The revolving term under this credit facility

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presently ends in December 2003 and is subject to renewal. We strive to manage our debt at a
level below the available credit line in order to maintain excess borrowing
capacity. At September 30, 2001, thisMarch 31, 2002,
excess capacity totaled $153$108 million, or 61%43% of the total available credit line.

In July 2001,addition to the credit facility, the Company issued $170has the following debt
outstanding:

... $100 million of 7.3% weighted average
fixed rate notes12-year 7.19% Notes to be repaid in a private placement transaction for the purposefive annual
installments of partially
funding the acquisition$20 million beginning in November 2005
... $75 million of Cody Company. These notes contain certain restrictive
convenants consistent with those10-year 7.26% Notes due in our existing debt agreements. See discussionJuly 2011
... $75 million of 12-year 7.36% Notes due in Note 10.July 2013
... $20 million of 15-year 7.46% Notes due in July 2016

5. EARNINGS PER SHARE

Basic earnings per share for the third quarter were based on the quarterly
weighted average shares outstanding of 30,644,481 in 2001 and 28,975,578 in
2000. Basic earnings per share for the first ninethree months of the year were based
on the year-to-date weighted average shares outstanding of 29,828,85031,603,717 in 20012002
and 26,830,47329,318,262 in 2000.2001. The diluted earnings per share amounts are based on
weighted average shares outstanding plus common stock equivalents. Third
quarter commonCommon stock
equivalents which include both stock awards and stock options, and totaled 354,300471,719 in
20012002 and 246,400396,431 in 2000. For the year to date
period ended September 30, the common stock equivalents were 434,244 in 2001 and
262,783 in 2000.2001.

6. ENVIRONMENTAL LIABILITY

The EPA notified Cabot Oil & Gasthe Company in February 2000 that it might haveof its potential liability
for waste material disposed of at the Casmalia Superfund Site ("Site"), located
on a 252-acre parcel in Santa Barbara County, California. Over 10,000 separate
parties disposed of waste at the Site while it was operational from 1973 to
1992. The EPA stated that federal, state and local governmental agencies along
with the numerous private entities that used the Site for disposal of
approximately 4.5 billion pounds of waste would be expected to pay the clean-up
costs, which are estimated by the EPA to be $271.9 million. The EPA is also
pursuing the owners/operators of the Site to pay for remediation.

Documents received by the Company with the notification from the EPA
indicate that Cabot Oil & Gasthe Company used the Site principally to dispose of salt water
from two wells over a period from 1976 to 1979. There is no allegation that the
Company violated any laws in the disposal of material at the Site. The EPA's
actions stem from the fact that the owners/operators of the Site do not have the
financial means to implement a closure plan for the Site.

A group of potentially responsible parties, including the Company, formed a
group, called -8-
the Casmalia Negotiating Committee ("CNC"). The CNC has had
extensive settlement discussions with the EPA and has reached a settlement in
principal with
the EPA andto pay approximately $27 million toward Site clean up in return for a
release from liability. The CNC is currently negotiating a consent decree to
memorialize the settlement. Management expects our contribution toOn January 30, 2002, the settlement to be
approximately $1.2 to $1.3 million, whichCompany placed $1,283,283
in an escrow account. This amount approximates ourthe Company's volumetric share of
EPA's cost estimate, plus a 5% premium.premium and is the Company's settlement amount.
The escrow account is being funded by the Company and many other CNC members to
maximize the likelihood that there will be sufficient funds to fund the
settlement agreement upon its completion, which is expected later in 2002. This
cash settlement, once released from escrow and paid to the federal government,
will resolve all federal claims against the Company for response costs and will
release the Company from all response costs related to the Site. FutureSite, except for
future claims against the Company for natural resource damage, unknown
conditions, transshipment risks and claims by third parties, against the Companyall of which are
expected to be covered by insurance to be purchased by participating CNC
members. Responsibility for certain State of California oversight and response
costs, while not covered by the settlement or insurance, isare not expected to be
material. Payment by the Company of our settlement amount will be due 30 days from
entry of the consent decree by the United States District Court for the Central
District of California, Western Division, which is not expected until 2002.
There is not a material likelihood thatNo determination has been made as to whether any insurance arrangement in place from
1976 to 1979
will allow the Company to recover ourits contribution to the settlement.

Cabot Oil & GasThe Company has established a reserve that management believes to be
adequate to provide for this environmental liability based on its estimate of
the probable outcome of this matter and estimated legal costs.

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7. WYOMING ROYALTY LITIGATION

Wyoming Royalty Litigation

In June 2000, two overriding royalty owners sued the Company in Wyoming
State court.court for unspecified damages. The plaintiffs have requested class
certification under the Wyoming Rules of Civil Procedure and allege that the
Company has deducted impermissibleimproper costs of production from royalty payments to the
plaintiffs and other similarly situated persons. Additionally, the suit claims
that the Company has failed to properly inform the plaintiffs and other
similarly situated persons of the deductions taken from royalties. The twoIn December
2001, fourteen overriding royalty owners didsued the Company in Wyoming federal
court. The plaintiffs in the federal case have made the same general claims
pertaining to deductions from their overriding royalty as the plaintiffs in the
Wyoming state court case but have not claim a specific amount of damages in their complaint.asked for class certification.

The Company believes that it has substantial defenses to this claimthese claims and
intends to vigorously assert such defenses. The Company has a reserve that it
believes is adequate to provide for these potential liabilities based on its
estimate of the probable outcome of this matter. While the potential liabilityimpact to
the Company may materially affect quarterly or annual financial results
including cash flows, management does not believe it would materially impact the
Company's financial position.

West Virginia Royalty Litigation

In late December 2001, two royalty owners sued the Company in West Virginia
State court for an unspecified amount of damages. The plaintiffs have requested
class certification under the West Virginia Rules of Civil Procedure and allege
that the Company has failed to pay royalty based upon the wholesale market value
of the gas produced, that the Company has taken improper deductions from the
royalty and has failed to properly inform the plaintiffs and other similarly
situated persons of deductions taken from the royalty. The plaintiffs have also
claimed that they are entitled to a 1/8th royalty share of the gas sales
contract settlement the Company reached with Columbia in the 1995 Columbia
bankruptcy proceeding.

The Company has removed the suit to Federal court. At a recent status
conference, the Court set up a schedule for the procedural handling of the
plaintiffs' allegations that the case should proceed as a class action. Under
this procedure, all discovery and pleadings necessary to place class
certification issue before the Court are expected to be completed by November 1,
2002.

The investigation into this claim continues and it is in the discovery
phase. The Company intends to vigorously defend the case. The Company has a
reserve that it believes is adequate to provide for these potential liabilities
based on its estimate of the probable outcome of this matter. While the
potential impact to the Company may materially affect quarterly or annual
financial results including cash flows, management does not believe it would
materially impact the Company's financial position.

8. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY

On January 1, 2001, the Company adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" as amended by SFAS 137 and SFAS 138. Under
SFAS 133, all derivative instruments are recorded on the balance sheet at fair
value. If the derivative does not qualify as a hedge or is not designated as a
hedge, the gain or loss on the derivative is recognized currently in earnings.
To qualify for hedge accounting, the derivative must qualify either as a fair
value hedge, cash flow hedge or foreign currency hedge. Currently, the Company
uses only cash flow hedges and the remaining discussion will relate exclusively
to this type of derivative instrument. If the derivative qualifies for hedge
accounting, the gain or loss on the derivative is deferred in Other
Comprehensive Income/Loss, a component of Stockholders' Equity, to the extent
the hedge is effective.

The relationship between the hedging instrument and the hedged item must be
highly effective in achieving the offset of changes in cash flows attributable
to the hedged risk both at the inception of the contract and on an ongoing
basis. The Company measures effectiveness on a monthly basis. Hedge accounting
is discontinued prospectively when a hedge instrument becomes ineffective.
Gains and losses deferred in accumulated Other Comprehensive Income related to
cash flow hedges that become ineffective remain unchanged until the related
production is delivered. If the Company determines that it is probable that a
hedged forecasted transaction will not occur, deferred gains or losses on the
hedging instrument are recognized in earnings immediately.

Gains and losses on hedging instruments related to accumulated Other
Comprehensive Income and adjustments to carrying amounts on hedged production
are included in natural gas or crude oil production revenues in the period that
the related production is delivered. Gains and losses of hedging

-9-

instruments, which represent hedge ineffectiveness and changes in the time value
component of the fair value, are included in Change in Derivative Fair Value on
the income statement in the period in which they occur.

The Company periodically enters into derivative commodity instruments to
hedge its exposure to price fluctuation on natural gas and crude oil production.
At September 30, 2001,March 31, 2002, the Company had three types of cash flow hedges open: a series of eightnine
natural gas collar arrangements, a series of ten natural gas costless collar
arrangements one natural gas price swap and one natural gascrude oil price floor.collar arrangement. At September 30, 2001,March 31, 2002, a
$9.7$13.9 million pre-tax unrealized gainloss was recorded to Other Comprehensive Income
along with a $0.2$14.4 million derivative liability, a derivative asset of $10.7 million and a non-cash gainloss of
$0.8approximately $0.5 million. The ineffective portion of the cash flow hedges a $0.8
million gain at September 30, 2001, was
recorded as a component of the Change in Derivative Fair Value on the income
statement. The remainder of the Change in
Derivative Fair Value was a $24,000 gain at September 30, 2001, representing the
time value component of the costless collar arrangement. Based onIf commodity prices and other circumstancesequal those as of September 30, 2001,March 31, 2002, the Company
expects towould reclass a deferred gainloss of $5.9approximately $8.6 million ($9.713.9 million pre-tax)pre-
tax) to earnings from Accumulated Other Comprehensive Income during the next
twelve months.

-9-
For 2001,2002, the Company has entered into costlessthe following derivative
arrangements:

... A series of nine natural gas price collar arrangements for 24.4covering 16.1 Bcf of
its natural gas production over the period of January through April 2002 with weighted
average floor and ceiling prices of $5.59/$2.68 per Mcf and $9.68/$3.53 per Mcf.
In addition, the Company had entered into a... A series of ten natural gas price swapcostless collar arrangements covering 0.918.3
Bcf of production for 2001 at aover the period of May through August 2002 with weighted
average floor and ceiling prices of $2.54 per Mcf and $3.17 per Mcf.
... A crude oil price of $3.75/Mcf. This swap also covers 0.7 Bcfcollar arrangement covering 1,224 Mbbls of production in 2002 at
$3.11/Mcf, and 0.4 Bcf in 2003 at $2.81/Mcf. Cody Company had purchased a
natural gas price floor prior toover
the merger with the Company that is in placeperiod of March through December 2001. This derivative sets2002 with a $2.81/Mcf natural gas$20.00 per barrel floor price
floor
onand a total of 1.3 Bcf of production from the Cody properties during August
through December 2001. This natural gas price floor was valued at $205,300 upon
acquisition and does not qualify for hedge treatment under SFAS 133. At
September 30, 2001, this derivative has been recorded at market value on the
balance sheet and the resulting gain of $0.5 million, representing the movement
of gas prices since the Cody acquisition (August 1, 2001), is included in the
period's operating revenue.

On January 1, 2001, in accordance with the transition provisions of SFAS
133, the Company recorded an after-tax loss of $2.6 million in Other
Comprehensive Loss representing the cumulative effect of an accounting change to
recognize at fair value all cash flow derivatives. The Company recorded cash
flow hedge derivative liabilities of $4.3 million and an after-tax, non-cash
loss of less than $0.1 million was recorded in earnings as a component of the
Change in Derivative Fair Value.

During the first nine months of 2001, gains of $23.7 million ($14.5 million
after tax) were transferred from Other Comprehensive Income and the Derivative
Instrument Asset on the balance sheet decreased $9.8 million ($6.0 million after
tax). During the third quarter of 2001, gains of $20.0 million ($12.2 million
after tax) were transferred from Other Comprehensive Income and the Derivative
Instrument Asset on the balance sheet decreased $31.9 million ($19.6 million
after tax).

All hedge transactions are subject to the Company's risk management policy,
approved by the Board of Directors, which does not permit speculative positions.
The Company formally documents all relationships between hedging instruments and
hedged items, as well as its risk management objectives and strategy for
undertaking the hedge. This process includes specific identification of the
hedging instrument and the hedge transaction, the nature of the risk being
hedged and how the hedging instrument's effectiveness will be assessed. Both at
the inception of the hedge and on an ongoing basis, the Company assesses whether
the derivatives that are used in hedging transactions are highly effective in
offsetting changes in cash flows of hedged items.

-10-
$23.00 per barrel ceiling price.

9. COMPREHENSIVE INCOME

Comprehensive income includes net income and certain items recorded
directly to stockholders' equity and classified as Other Comprehensive Income.
The Company recorded Other Comprehensive Income for the first time in January of
2001. Following the adoption of SFAS 133, the Company recorded an after-tax
credit to Other Comprehensive Income of $5.9 million in the first nine months of
2001 related to the change in fair value of certain derivative financial
instruments that has qualified for cash flow hedge accounting. The following table illustrates the calculation of comprehensive income for the
nine-month
periodthree-month periods ended September 30, 2001:March 31:

THREE MONTHS ENDED THREE MONTHS ENDED
MARCH 31, 2002 MARCH 31, 2001
--------------------------- --------------------------
(In thousands)
--------------

Accumulated Other Comprehensive Income -
December 31, 2000..Beginning of Period.................................. $ 835 $ --
Net Income.................................................. $62,685Income (Loss)......................................... $ (798) $ 39,062

Other Comprehensive Income (net of tax)
---------------------------------------
Cumulative effect of change in accounting
principle - January 1, 20012001....................... -- (2,617)
Reclassification adjustment for
settled contracts 14,543contracts................................. (1,592) 487
Changes in fair value of outstanding
hedging positions (5,980)
-------hedge positions................................... (7,831) 424
--------- ----------
Other Comprehensive Income..................................Income................................ $ 5,946 $5,946
------- ------(9,423) $ (9,423) $ (1,706) $ (1,706)
--------- ---------- ---------- ----------

Comprehensive Income........................................ $68,631
=======Income...................................... $ (10,221) $ 37,356
========= ==========
Accumulated Other Comprehensive Income...................... $5,946
======Income -
End of Period........................................ $ (8,588) $ (1,706)
========== ===========

There were no items10. RETIREMENT OF EXECUTIVE OFFICER

In May 2002, Ray Seegmiller will retire as the Company's Chairman and
Chief Executive Officer. The Company expects to record a charge of approximately
$3.2 million in Other Comprehensive Income during 2000.

10.the second quarter of 2002 for expenses related to his
retirement. The costs include a lump sum cash payment of $0.9 million in
recognition of Mr. Seegmiller's employment agreement, his contributions to the
Company and in lieu of a 2002 long-term incentive award. Another $1.0 million
will be expensed as part of his supplemental executive retirement plan benefits.
Mr. Seegmiller's previously awarded stock grants and options will vest upon
retirement, resulting in estimated compensation expense of approximately $1.3
million. This amount related to the acceleration of the stock award vesting is
an estimate and will be based on the closing stock price on May 2, 2002.

-10-

11. ACQUISITION OF CODY COMPANY

Effective in August 2001, the Company acquired the stock of Cody Company,
the parent of Cody Energy LLC ("Cody acquisition") for $231.2 million comprised
of $181.3 million of cash and 1,999,993 shares of common stock valued at $49.9
million. Substantially all of the exploration and productionproved reserves of Cody Company are located in
the onshore Gulf Coast region. The acquisition was accounted for using the
purchase method of accounting. As such, the Company reflected the assets and
liabilities acquired at fair value in the Company's balance sheet effective
August 1, 2001 and the results of operations of Cody Company beginning August 1,
2001. The purchase price totaling approximately $314.8$315.6 million was allocated to
specific assets and liabilities based on certain estimates of fair values
resulting in approximately $305.6$302.4 million allocated to property and $9.2$13.2
million allocated to working capital items. This $314.8$315.6 million amount was
inclusive of a $79.2$78.0 million non-cash item pertaining to the deferred income
taxes attributable to the differences between the tax basis and financial statement basisthe fair value
of the acquired oil and gas properties, and acquisition related fees and costs
of $4.4$6.4 million. To partially fundThe purchase price allocation is preliminary and subject to
change as additional information becomes available. Management does not expect
the cash portion of this acquisition, the Company issued
$170 million 7.3% weighted average fixed rate notes in a private placement
transaction. Priorfinal purchase price allocation to the determination of the Note's interest rates, the
Company entered into a treasury lock in order to reduce the risk of rising
interest rates. Interest rates rose during the pricing period, resulting in a
$0.7 million gain that will be amortized over the life of the Notes, and thereby
reducing the effective interest rate by 5.5 basis points. The Notes are in
three series with maturity dates and interest rates as follows:

$75 million with a coupon rate of 7.255% (7.2% effective interest rate) due
in July 2011
$75 million with a coupon rate of 7.355% (7.3% effective interest rate) due
in July 2013
$20 million with a coupon rate of 7.455% (7.4% effective interest rate) due
in July 2016

The remaining $11.3 million of cash used in the Cody acquisition were proceedsdiffer materially from the Company's revolving credit facility.

-11-
preliminary
allocation.

The following unaudited pro forma condensed income statement information
has been prepared to give effect to the Cody acquisition as if it had occurred
at the beginning of the periods presented. The historical results of operations
have been adjusted to reflect the differences between Cody Company's historical
depletion, depreciation, and amortization and such expense calculated based on
the value allocated to the assets acquired in the acquisition. An adjustment
has also been made for additional interest expense associated with the $181.3
million of increased debt outstanding utilized to partially fund the
transaction. The cumulative effect of an accounting change of $3.4 million
($2.1 million after tax) relates to the January 1, 2001 adoption of SFAS 133
"Accounting for Derivative Instruments and Hedging Activities" as amended by
SFAS 137 and SFAS 138.2001. The information presented is not necessarily indicative of
the results of future operations of the Company.

QUARTER ENDED SEPT. 30,
2001 2000
-------- --------
(In thousands)

Revenues..................................................... $109,345 $108,224
-------- --------

Net Income................................................... $ 10,708 $ 8,047
-------- --------
per share - Basic.......................................... $ 0.34 $ 0.26
per share - Diluted........................................ $ 0.34 $ 0.26

NINE MONTHS ENDED SEPT. 30,
2001 2000
-------- --------
(In thousands)

Revenues..................................................... $425,210 $304,741
-------- --------

Income before the cumulative effect of an accounting change.. $ 74,805 $ 10,294
-------- --------
per share - Basic........................................... $ 2.38 $ 0.36
per share - Diluted......................................... $ 2.34 $ 0.35

Net Income................................................... $ 72,681 $ 10,294
-------- --------
per share - Basic.......................................... $ 2.31 $ 0.36
per share - Diluted........................................ $ 2.28 $ 0.35
QUARTER ENDED
MARCH 31, 2001
--------------
(Unaudited)
(In thousands)

Revenues................................................... $ 187,307
----------
Net Income................................................. $ 47,145
-----------
per share - Basic....................................... $ 1.51
per share - Diluted..................................... $ 1.49

The results of operations for Cody Company are consolidated with Cabot Oil & Gas
Corporation as of August 1, 2001.

-12--11-

Report of Independent Accountants

To the Board of Directors and StockholdersShareholders of
Cabot Oil & Gas Corporation:

We have reviewed the accompanying condensed consolidated balance sheet of Cabot
Oil & Gas Corporation and its subsidiaries (the "Company") as of September 30,
2001,March 31, 2002,
and the related condensed consolidated statements of operations and cash flows
for each of the three and nine-monththree-month periods ended September 30, 2001March 31, 2002 and September 30, 2000.March 31, 2001.
These financial statements are the responsibility of the Company's management.

We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.

Based on our review, we are not aware of any material modifications that should
be made to the accompanying condensed consolidated interim financial statements
for them to be in conformity with accounting principles generally accepted in
the United States of America.

We previously audited in accordance with auditing standards generally accepted
in the United States of America, the consolidated balance sheet as of December
31, 2000,2001, and the related consolidated statements of operations, stockholders'
equity, and of cash flows for the year then ended (not presented herein), and in
our report dated February 16, 200115, 2002 we expressed an unqualified opinion on those
consolidated financial statements. In our opinion, the information set forth in
the accompanying condensed consolidated balance sheet as of December 31, 20002001,
is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Houston, Texas
October 30, 2001

-13-April 25, 2002

-12-

ITEM 2. Management's Discussion and Analysis of Financial Condition and Results
-------------------------------------------------------------------------------- --------------------------------------------------------------------------------
of Operations
- -------------

The following review of operations for the thirdfirst quarter of 20012002 and 20002001
should be read along with our Condensed Consolidated Financial Statements and
the Notes included in this Form 10-Q and with the Consolidated Financial
Statements, Notes and Management's Discussion and Analysis included in the Cabot
Oil & Gas Form 10-K for the year ended December 31, 2000.2001.

Overview

Effective August 1, 2001, we acquired Cody Company and subsidiaries for
$231.2 million in cash and common stock. The Cody properties are mainly in the
onshore Gulf Coast region and contributed 2.8 Bcfe of production during the two-
month period following the acquisition. The acquired business contributed $9.1
million in operating revenues and $1.5 million in operating income to our 2001
results.

DuringIn the first nine monthsquarter of 2002, we produced 22.5 Bcfe, an increase of 26%
over the 2001 we realized both the highest level of
natural gas price realizationfirst quarter, and the highest naturalfirst quarter in Company history.
Natural gas production volumeswas 18.4 Bcf, up 3.1 Bcf compared to the 2001 first
quarter. Oil production was up 263 Mbbls, or 65% over the comparable quarter of
last year. Production from the properties acquired with Cody Company contributed
most of the increase, but drilling successes in our history. Forthe Gulf Coast and Eastern
regions have also served to improve production rates.

Commodity prices were unusually high during the first nine monthsquarter of 2001, realizedand
our financial results reflected their impact during that period. However, in the
first quarter of 2002, natural gas prices were 83% higher than the same period of last year. Natural gas production was 49.6
Bcf, up 4.2 Bcf compared to the first nine months of 2000. The Cody properties
contributed 2.3 Bcf of production since the August 1, 2001 effective date of the
acquisition. Oil61% lower and crude oil prices
were up 7% and oil production doubled from the first
nine months of last year. The improvement28% lower than in natural gas and oil production was
primarily driven by Company's discoveries in south Louisiana and the acquisition
of the Cody properties.2001. This softer commodity price environment impacted
our financial results. Operating revenues increased $112.9decreased $79.8 million, or 44%52%, and
net income available to common shareholders increased $50.5decreased $39.9 million, mainly as a result of this improvedweakened price
environment and increased production.environment. Operating cash flows also benefited, improvingwere similarly impacted, declining by $145.4$80.0
million over last year.

Net income for theOur first nine months of 2001quarter net loss was $62.7$0.8 million, or $2.10$0.03 per share. These results includedshare, including
a $0.8$0.6 million non-cash gainloss realized from the change in the fair value of our
derivatives under the newly adopted SFAS 133 (see Note 8), and a $1.1 million severance tax refund, and a $1.7 million impairment to long-lived assets.recorded
on two small fields. The impairments occurred since it was determined that the
reserves on these two small fields were not commercially viable. These selected
items increaseddecreased after-tax net income by $0.1$1.0 million, or $0.04 per share, in the
first nine monthsquarter of 2001.2002. Excluding thisthese selected item,items, our year-to-date 2001first quarter 2002
net income was $62.6$0.2 million, or $2.10$0.01 per share.

We drilled 15421 gross wells (17 development and 4 exploratory wells) with a
success rate of 88% in 200195% compared to 8543 gross wells (39 development and an 88%4 exploratory
wells) and a 91% success rate in the first nine monthsquarter of 2000.2001. For the full year,
we plan to drill approximately 222111 gross wells and spend approximately $220.3$104.7 million in capital and
exploration expenditures (excluding
the Cody acquisition) compared to 129208 gross wells and $122.6$453.4 million of
capital and exploration expenditures in 2000.2001, including the $231.2 million
August 2001 Cody acquisition. Total expenditures were $379.6$34.5 million for the
first nine monthsquarter of 2001 including $231.2 million for the Cody
acquisition,2002, compared to $86.7$53.5 million for the comparable period in
2000.

Production from our recent discoveries in the Gulf Coast helped boost
production in that region by 11.8 Bcfe for the first nine months of 2001.
However, anticipated declines in the other regions offset 3.5 Bcfe of this
production.

Our strategic pursuits are sensitive to energy commodity prices, particularly
the price of natural gas. Market conditions have improved significantly this
year and our realized gas price for the first nine months of 2001 of $4.95/Mcf
was the highest we have ever realized. Although third quarter 2001 realized
natural gas prices rose 30% over the prior year, prices were 21% lower then
those realized in the second quarter of this year. Prices of natural gas for
Henry Hub have declined from a high of $9.19 per Mmbtu in January 2001 to $1.86
per Mmbtu in October 2001. Additionally, the natural gas price collars in place
since February of 2001 covering 44% of our year-to-date natural gas production
will expire at the end of October 2001. These derivatives served to increase
the average realized natural gas price by $0.50/Mcf through September 2001.
Based on this market volatility, there is considerable uncertainty about the
level of natural gas prices for the remainder of this year and beyond.

We remain focused on our strategies of growth from the drill bit and
synergistic acquisitions. Management believes that these strategies are
appropriate in the current industry environment, enabling Cabot Oil & Gas to add
shareholder value over the long term.long-term.

The preceding paragraphs, discussing our strategic pursuits and goals,
contain forward-looking information. See Forward-Looking Information on page 23.

-14-
19.

Financial Condition

Capital Resources and Liquidity

Our capital resources consist primarily of cash flows from our oil and gas
properties and asset-based borrowings supported by our oil and gas reserves. The
level of earnings and cash flows depend on many factors, including the price of
crude oil and natural gas and our ability to control and reduce costs. Demand
for crude oil and natural gas has historically been subject to seasonal
influences characterized by peak demand and higher prices in the winter heating
season. However, demand and prices have both remained strong throughmoved higher strengthening from the summer of
2000 andto the spring of 2001 until they declinedbegan to decline in the late summer and
early fall of 2001.2001 and remained low to start 2002. This is a variation from the
cyclical nature of demand that we had seen previously in the market.

In August 2001, we completed the acquisition of the stock of Cody Company
for $231.2 million in cash and stock. In July 2001, we issued $170 million 7.3%
weighted average fixed rate notes in a private placement transaction to fund a
portion of the cash required for this transaction. We expect that this
acquisition and the related issuance of debt will result in increases to
operating revenues, operating expenses, production and interest expense.
Increases to the capital spending program are also planned.-13-

Our primary sourcessource of cash during the first nine monthsquarter of 2001 were2002 was from funds
generated from operations as well as from the issuance of new debt.
Another source of cash was the exercise of stock options.and increased borrowing on our revolving credit
facility. Cash was primarily used to acquire the Cody Company stock, fund exploration and development
expenditures and to pay dividends.

We had a net cash inflowoutflow of $6.4$0.7 million in the first nine monthsquarter of 2001.2002.
Cash inflows from operating activities totaled $214.8$29.6 million in the period.
Cash from borrowings contributed $98current
quarter. The $48.1 million which reflects the impact the $170
million in new 7.3% weighted average fixed rate notes issued in July and the
reduction to the revolving line of credit. These cash inflows were used to fund
$316.5 million in capital and exploration expenditures including $181.3were funded
with a combination of the operating cash flows and $19.0 million forof increased
borrowing on the Cody acquisition.

NINE MONTHS ENDED SEPT. 30,
2001 2000
---- ----
(In millions)

Cash Flows Provided by Operating Activities.......... $214.8 $73.8
====== =====revolving credit facility.

THREE MONTHS ENDED MARCH 31,
2002 2001
-------- --------
(In millions)

Cash Flows Provided by Operating Activities..................................$ 29.6 $ 109.6
======== ========

Cash flows from operating activities in the 20012002 first nine monthsquarter were $141.0$80.0
million higherlower than the corresponding periodquarter of 20002001 primarily due to higherlower
natural gas and oil prices and less favorable changes in working capital.

NINE MONTHS ENDED SEPT. 30,
2001 2000
---- ----
(In millions)

Cash Flows Used by Investing Activities.............. $310.7 $81.1
====== =====
THREE MONTHS ENDED MARCH 31,
2002 2001
-------- --------
(In millions)

Cash Flows Used by Investing Activities......................................$ (48.1) $ (45.1)
======== ========

Cash flows used by investing activities in the first nine monthsquarter of 2002 were
entirely for capital and exploration expenditures of $48.1 million. A portion of
this cash spending related to the 2001 and 2000capital program as certain 2001 projects
were completed in the first quarter of 2002. Cash flows used by investing
activities in the first quarter of 2001 were substantially attributable to
capital and exploration expenditures of $316.5$45.5 million, including the Cody acquisition, and $83.8 million,
respectively. Proceedspartially offset by
proceeds from the sale of certain oil and gas properties were $5.9
in 2001 and $2.7 million in 2000.

NINE MONTHS ENDED SEPT. 30,
2001 2000
---- ----
(In millions)

Cash Flows Provided by Financing Activities.......... $102.2 $7.6
====== ====of $0.4 million.

THREE MONTHS ENDED MARCH 31,
2002 2001
-------- --------
(In millions)

Cash Flows Provided (Used) by Financing Activities...........................$ 17.8 $ (67.0)
======== ========

Cash flows provided by financing activities in the first nine monthsquarter of 2002
consist primarily of $19.0 million in increased borrowings on the revolving
credit facility. Cash flows used by financing activities in the first quarter of
2001 included a $98$70 million net increase in debt. We issued 7.3% weighted
average fixed rate notes in July 2001 for $170 million. However,

-15-

during 2001, we also reduced our level of borrowingused to reduce borrowings on our revolving credit
facility and repaid the 10.18% Notes. Additionally, $3.5 million was used to pay
dividends.facility. Proceeds from the exercise of stock options in the periodfirst quarter were
$7.7
million. In the first nine months of 2000, we raised $81.6$0.1 million from the sale
of common stock through a public offeringin 2002 and through stock option exercises. Of
the proceeds, $51.6$4.2 million was used to repurchase all of the then-outstanding
shares of our preferred stock. Cash flows used by financing activities in the
first nine months of 2000 also included $17 million used to reduce borrowings on
our revolving credit facility, and $5.4 million for the payment of dividends,
including the final dividend payment on the preferred stock.2001.

The available credit line under our revolving credit facility, currently
$250 million, is subject to adjustment on the basis of the present value of
estimated future net cash flows from proved oil and gas reserves (as determined
by the bank's petroleum engineer) and other assets. The revolving term of the
credit facility runsends in December 2003. We strive to December 2003.manage our debt at a level
below the available credit line in order to maintain excess borrowing capacity.
Management believes that we have the ability to finance, if necessary, our
capital requirements, including acquisitions.

Our 20012002 interest expense is expected to be approximately $21.3$29.2 million,
including interest on the $170 million 7.3%7.33% weighted average fixed rate notes
used to partially fund the acquisition of Cody Company.Company in 2001. In May 2001, a
$16 million principal payment was made on the 10.18% Notes. This amount had been
reflected as "Current Portion of Long-Term Debt" on the balance sheet.
Additionally, the final $16 million payment on these notes that was due in May
2002 was paid in May 2001 using existing capacity on the revolving credit
agreement.

-14-
Capitalization

Our capitalization information is as follows:

SEPTEMBER 30, DECEMBER 31,
2001 2000
------ ------
(In millions)

Long-Term Debt................................ $367.0 $253.0
Current Portion
MARCH 31, DECEMBER 31,
2002 2001
-------- -----------
(In millions)

Debt..................................................................... $ 412.0 $ 393.0
Stockholders' Equity/(1)/................................................ 335.7 346.6
-------- --------
Total Capitalization..................................................... $ 747.7 $ 739.6
======== ========

Debt to Capitalization................................................... 55.1% 53.1%

/(1)/ Includes common stock, net of Long-Term Debt............. -- 16.0
------ ------
Total Debt.................................. 367.0 269.0
------ ------

Stockholders' Equity
Common Stock (nettreasury stock. No shares of Treasury Stock)........ 366.2 242.5
------ ------
Total....................................... 366.2 242.5
------ ------

Total Capitalization.......................... $733.2 $511.5
====== ======
Debt to Capitalization........................ 50.1% 52.6%preferred
stock were outstanding.

During the first nine monthsquarter of 2001,2002, we paid dividends of $3.5$1.3 million on the
common stock.Common Stock. A regular dividend of $0.04 per share of common stock wasCommon Stock has been
declared for theeach quarter ending September 30, 2001, to be paid November 23, 2001
to stockholders of record as of November 9, 2001.

Assince we became a result of the requirements of SFAS 133 adopted January 1, 2001 (see
Note 9), our Stockholders' Equity includes $5.9 million, net of tax, in Other
Comprehensive Income for the nine-months ended September 30, 2001.

-16-
public company.

Capital and Exploration Expenditures

On an annual basis, we generally fund most of our capital and exploration
activities, excluding major oil and gas property acquisitions, with cash
generated from operations, and budget such capital expenditures based uponwhile
considering projected cash flows for the year.

The following table presents major components of capital and exploration
expenditures:

NINE MONTHS ENDED SEPT. 30,
2001 2000
------ -----
(In millions)
Capital Expenditures
Drilling and Facilities............. $ 86.4 $58.8
Leasehold Acquisitions.............. 14.7 8.2
Pipeline and Gathering.............. 2.4 2.2
Other............................... 0.2 1.2
------ -----
103.7 70.4
------ -----
Proved Property Acquisitions/(1)/..... 236.1 4.2
Exploration Expenses.................. 39.8 12.1
------ -----
Total............................... $379.6 $86.7
====== =====

/(1)/ The 2001 amount includes the Cody acquisition, excluding the $79.2
million deferred tax gross-up. See Note 10, Cody Acquisition.
THREE MONTHS ENDED MARCH 31,
----------------------------
2002 2001
-------- --------
(In millions)

Capital Expenditures
Drilling and Facilities......................................... $ 25.9 $ 26.2
Leasehold Acquisitions.......................................... 1.0 12.7
Pipeline and Gathering ......................................... 0.2 0.5
Other........................................................... 0.3 3.3
-------- --------
27.4 42.7
Exploration Expenses................................................ 7.1 10.8
-------- --------
Total........................................................... $ 34.5 $ 53.5
======== ========

Total capital and exploration expenditures in the first nine monthsquarter of 2001
increased $292.92002
decreased $19.0 million compared to the same periodquarter of 2000,2001, primarily as a
result of the $231.2 million Cody acquisition. The remaining increase of $61.7
million was due primarily to increased drilling activity as well as increasesplanned decreases in leasehold acquisitionsacquisition costs consistent with our future drilling plans.and other capital
projects.

We plan to drill 222111 gross wells in 20012002 compared with 129208 gross wells
drilled in 2000.2001. This 20012002 drilling program includes $220.3$104.7 million in total
capital and exploration expenditures, (excluding the Cody acquisition), updown from $122.6$453.4 million in 2000.2001, which
was our largest capital program to date and included the acquisition of Cody
Company. Expected capital and exploration spending in 20012002 includes $141.4$62.6 million for drilling $21.3and dry
hole exposure, $7.8 million for lease acquisition costs
and $14.8$9.9 million forin geological
and geophysical expenses including seismic data
costs. This 2001 drilling program now includes plans for 15 gross wells and
capital and exploration expenditures of $16.9 million on the properties acquired
from Cody Company in August 2001.expenses. In addition to the drilling and exploration program,
other 20012002 capital expenditures are planned primarily for production equipment
and for gathering and pipeline infrastructure maintenance and construction. We
will continue to assess the natural gas price environment and may increase or
decrease the capital and exploration expenditures accordingly.

-17--15-

Results of Operations

For the purpose of reviewing our results of operations, "Net Income" is
defined as net income available to common stockholders.

Selected Financial and Operating Data

THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------- -----------------MARCH 31,
----------------------------
2002 2001
2000 2001 2000
------ ------ ------ ----------------- -----------
(In millions, except where noted)

Operating Revenues.......................................................... $ 75.1 $ 154.9
Operating Expenses.......................................................... 70.1 86.4
Operating Income............................................................ 5.0 68.5
Interest Expense............................................................ 6.2 4.7
Net Operating Revenues....................... $104.2 $ 86.2 $366.7 $253.8
Operating Expenses........................... 82.4 70.5 249.4 222.8
Operating Income............................. 21.6 15.8 117.1 31.0
Interest Expense............................. 5.1 5.7 14.5 17.0
Net Income................................... 10.0 6.1 62.7 12.2Income (Loss)........................................................... (0.8) 39.1
Earnings (Loss) Per Share - Basic...................Basic........................................... $ 0.33(0.03) $ 0.21 $ 2.10 $ 0.451.33
Earnings (Loss) Per Share - Diluted.................Diluted......................................... $ 0.32(0.03) $ 0.21 $ 2.07 $ 0.451.32

Natural Gas Production (Bcf)
Gulf Coast.................................. 7.9 3.5 17.3 9.9
West........................................Coast............................................................. 7.5 4.8
West................................................................... 6.4 7.4 19.4 22.0
Appalachia.................................. 4.6 4.6 12.9 13.5
------ ------ ------ ------6.4
East................................................................... 4.5 4.1
--------- ---------
Total Company............................... 18.9 15.5 49.6 45.4Company.......................................................... 18.4 15.3
========= =========

Natural Gas Production Sales Prices ($/Mcf)
Gulf Coast..................................Coast............................................................. $ 3.912.67 $ 3.727.34
West................................................................... $ 5.192.14 $ 3.12
West........................................6.10
East................................................................... $ 3.102.85 $ 2.626.44
Total Company.......................................................... $ 4.432.53 $ 2.46
Appalachia..................................6.57

Crude Oil Production (Mbbl)
Gulf Coast............................................................. 610 328
West................................................................... 50 68
East................................................................... 8 9
--------- ---------
Total Company.......................................................... 668 405
========= =========

Crude Oil Production Sales Prices ($/Bbl)
Gulf Coast............................................................. $ 4.5620.57 $ 2.7328.83
West................................................................... $ 5.4520.97 $ 2.8127.36
East................................................................... $ 16.41 $ 27.21
Total Company...............................Company.......................................................... $ 3.7720.55 $ 2.90 $ 4.95 $ 2.71

Crude/Condensate
Volume (MBbl)............................... 509 255 1,307 656
Price ($/Bbl)............................... $24.99 $29.72 $26.96 $25.2628.55

Brokered Natural Gas Margin
Volume (Bcf)................................ 5.2 8.2 15.6 33.5........................................................... 3.2 4.8
Margin ($/Mcf).............................. $(0.01)......................................................... $ 0.150.45 $ 0.14 $ 0.110.26

The table below presents the after-tax effect of certain selected items on
our results of operations for the three-three months ended March 31, 2002 and nine-month periods ended September
30, 2001.

THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30,(In millions) 2002 2001
SEPTEMBER 30, 2001
--------------------- --------------------
Amount per share Amount per share
--------- ---------- -------- ----------
(In millions, except per share amounts)--------------------------------------------------------------------

Net Income Before Selected Items............. $10.7Items $ 0.35 $62.60.2 $ 2.1035.3
Change in derivative fair value.............. (0.3) (0.01) 0.5 0.02value/(1)/ (0.4) 3.8
Impairment of long-lived assets.............. (1.1) (0.03) (1.1) (0.04)
Severance tax refund......................... 0.7 0.02 0.7 0.02
----- ------ ----- ------Long-Lived Assets (0.6)
----------------------
Net Income Available to Common Stockholders.. $10.0(Loss) $ 0.33 $62.7(0.8) $ 2.10
===== ====== ===== ======39.1
======================

These selected/(1)/ See discussion in Note 8 of the Notes to the Condensed
Consolidated Financial Statements.

-16-

For the first quarter of 2002, we reported a net loss of $0.8 million or
$0.03 per share. In the comparable quarter of 2001, we reported $39.1 million of
$1.33 per share. Selected items related to the change in derivative valuation
and impairment of long-lived assets impacted our 2000first quarter financial
results. Because theythese items are not a part of our normal business operations or
because they are unrealized gains or losses on future transactions, we have
isolated theirthe effect in the table above. The discussion below excludes the impact
of these selected items in 2001 include the following:

. The change in derivative fair value during the nine months ended September
30, 2001 related to the adoption SFAS 133 on January 1, 2001. See Note 9 for
further discussion.

-18-

. A total impairment of $1.1 million ($1.7 million pre-tax) recorded in the
third quarter. Two fields in the Gulf Coast region were impaired since the
cost capitalized exceeded the future undiscounted cash flows. Also, one
natural gas processing plant in the Rocky Mountains area was written down to
fair market value.

. A severance tax refund of $0.7 million ($1.1 million pre-tax) was received in
the third quarter for taxes previously paid in Louisiana that recently
qualified for the Severance Tax Relief Program as deep wells.

The table below presents the after-tax effect of certain selected items on
our results of operations for the three- and nine-month periods ended September
30, 2000.

THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2000 SEPTEMBER 30, 2000
------------------- --------------------
Amount per share Amount per share
-------- --------- -------- ----------
(In millions, except per share amounts)

Net Income Before Selected Items.............. $ 6.1 $ 0.21 $11.5 $ 0.43
Benefit from miscellaneous net revenue (1).. -- -- 1.7 0.07
Impairment of long-lived assets............. -- -- (5.6) (0.22)
Closure of Pittsburgh office................ -- -- (0.6) (0.03)
Negative preferred stock dividend........... -- -- 5.1 0.20
-------- --------- ----- ------
Net Income Available to Common Stockholders... $ 6.1 $ 0.21 $12.1 $ 0.45
======== ========= ===== ======

(1) Represents net benefit, primarily from a contract settlement.

These selected items are as follows:
. Miscellaneous net revenue, primarily from the settlement of a natural gas
sales contract, was recorded in the first quarter of 2000 ($1.7 million after
tax).

. A $9.1 million impairment ($5.6 million after tax) was recorded on the
Beaurline field in south Texas as a result of a casing collapse in two of the
field's wells.

. We announced the closure of the regional office in Pittsburgh in May 2000 and
recorded costs of $1.0 million ($0.6 million after tax). These costs were
recorded in the income statement categories associated with the specific
activity that will receive the future savings benefit ($0.6 million in
operations, $0.1 million in exploration and $0.3 million in administration).

. As a result of repurchasing all of the preferred stock at less than the book
value, we recorded a $5.1 million negative stock dividend in May 2000.

Thirditems.

First Quarters of 20012002 and 20002001 Compared

Net Income and Revenues. We reported net income before the selected items
-----------------------
in the thirdfirst quarter of 20012002 of $10.7$0.2 million, or $0.35$0.01 per share. During the
corresponding quarter of 2000,2001, we recordedreported net income before the selected item
of $6.1$35.3 million, or $0.21$1.20 per share. Operating revenues increaseddecreased by $18.4$73.0
million and operating income increaseddecreased by $6.8$55.7 million. Natural gas sales
related to our production made up 61%, or $46.5 million, of operating revenue.
The recently acquired Cody Company contributed $9.1
million49% decrease in operating revenues and $1.5 millionwas primarily due to a 61% decline in operating income. Natural gas
made up 68%, or $71.2 million, of net operating revenue in 2001. The increase in
net operating revenues was driven primarily by production improvements of 22%
forour
realized average natural gas and 100% for oil. The 30%price compared to the first quarter of 2001. This
decline was partially offset by a 20% increase in natural gas prices also
contributed to the revenue increase.production. Net
income and operating income were similarly impacted by the increasedecline in commodity volumes and prices.the
average natural gas price.

The average Gulf Coast natural gas production sales price rose $0.19decreased $4.67
per Mcf, or 5%64%, to $3.91, increasing net$2.67, decreasing operating revenues by approximately $1.5$32.7
million. In the Western region, the average natural gas production sales price
increased $0.48decreased $3.96 per Mcf, or 18%65%, to $3.10, increasing net$2.14, decreasing operating revenues by
approximately $3.1$25.6 million. The average AppalachianEastern region natural gas production
sales price increased $1.83decreased $3.59 per Mcf, or 67%56%, to $4.56, increasing net$2.85, decreasing operating
revenues by approximately $8.4$16.1 million. The overall weighted average natural
gas production sales price increased $0.87decreased $4.04 per Mcf, or 30%61%, to $3.77. Hedging gains
buoyed prices in all three regions. On the last day of 2000, we entered into a
series of natural gas price collar arrangements that limited our exposure to the
decline in commodity prices for the months of February through October 2001.
Index prices were below the floor of these collar arrangements in the third
quarter of 2001 resulting in a hedge gain of $20 million, which contributed a

-19-

$1.06 per Mcf increase to our realized natural gas price for the quarter. These
collar arrangements covered approximately 43% of our natural gas production
during the third quarter of 2001 and remain in place through the end of October
2001.$2.53, decreasing
revenues by $74.4 million.

Natural gas production volume in the Gulf Coast region was up 4.42.7 Bcf, or
126%56%, to 7.97.5 Bcf primarily due to the addition of production from properties acquired with the
newly acquired Cody properties and due to new production brought on lineCompany acquisition in south Louisiana.August 2001. Natural gas production volume in the
Western region was down 1.0 Bcf, or 14%, tothe same as the comparable quarter of 2001 at 6.4 Bcf
primarily due to a decrease in drilling activity in the Mid-Continent area
during 1999 and 2000.Bcf.
Natural gas production volume in the AppalachianEastern region was flat at 4.6 Bcf.up 0.4 Bcf to 4.5 Bcf,
as a result of an increase in drilling activity in the region in 2001. The 3.4 Bcf, or 22%,
improvement in total natural gas production of 3.1 Bcf, or 20%, increased
revenue by $9.8$20.2 million in the thirdfirst quarter of 2001.2002.

The volume of crude oil sold in the quarter increased by 263 Mbbls, or 65%,
to 668 Mbbls, increasing operating revenues by $7.5 million. This increase in
crude oil production was due both to production from properties acquired with
Cody Company in August 2001, and production increases in south Louisiana due to
2001 drilling activity. However, crude oil prices fell $8.00 per Bbl, or 28%, to
$20.55, resulting in a decrease to operating revenues of approximately $5.3
million. In total, revenue from crude oil sales was $2.2 million, or 19%, above
the 2001 first quarter.

Brokered natural gas revenue decreased $14.3$21.7 million, or 44%61%, over the
thirdfirst quarter of last year. A 37%The sales price of brokered natural gas fell 41%,
resulting in a decrease in revenue of $9.4 million, combined with a 35% decrease
in volume of natural gas brokered this quarter, reducedreducing revenues by $12.3 million. The sales price of brokered
natural gas declined 10%, resulting in a decrease in revenue of $2.0
million. After including the related brokered natural gas costs, we realized a
net negative margin of less than $0.1$1.4 million in the thirdfirst quarter of 20012002 and a net
positive margin of $1.2$1.3 million in the
comparable quarter of 2000.

Crude oil prices declined $4.73 per Bbl, or 16%, to $24.99, resulting in a
decrease to net operating revenues of approximately $2.4 million. In addition,
the volume of crude oil sold in the quarter increased by 254 Mbbls, or 100%, to
509 Mbbls, boosting net operating revenues by $7.5 million. Of this improvement,
72 Mbbls represented production from the newly acquired Cody properties and the
remainder was primarily from new wells in the Gulf Coast region.2001.

Other net operating revenues increased $1.5$0.8 million to $2.3$1.8 million. This
change was primarily a result of:

... A $0.4 million primarilyincrease in transportation revenue as operations commenced on a
new gathering system in the Western region.
... A $0.9 million increase due to a decrease in payout and gas balancing costs.
In the first quarter of 2001, we had recorded the impact of resolving several
payout and gas balancing issues.
... A $0.8 million decrease in natural gas liquids revenue as a result of ana
downward revision to accrued revenue from the prior quarter.
... A $0.2 million increase in liquids revenue in the Gulf Coast due to
higher volumes processed. A portion of the volume increase was from the Cody
properties.natural gas processing plant revenue.

-17-

Costs and Expenses. Excluding the severance tax refund of $1.1 million
------------------
received in the third quarter of 2001 and the impairment of long-lived assets of
$1.7 million recorded in September, totalTotal costs and expenses from operations increased $11.1decreased
------------------
$17.4 million or 16%, in the thirdfirst quarter of 20012002 compared to the same periodquarter of 2000.2001.
The primary reasons for this fluctuation are as follows:

. Brokered natural gas cost decreased $13.1$21.9 million, or 41%64%, from the thirdfirst
quarter of last year. The cost of brokered natural gas fell 6%45%, resulting
in a decrease to expense of $1.3$10.0 million. Additionally, a 37%35% decrease in
volume of natural gas brokered this quarter reduced costs by $11.8$11.9 million.

. Direct operating expense increased $3.0$4.0 million, or 35%, over the same
quarter last year. This increase was a result of three main factors. First,
the incremental cost of operating the newly acquired Cody properties during
August and September was $1.5 million. Second, we are incurring higher
costs associated with the expansion of the Gulf Coast regional office,
including investments both in staffing and technology, and the cost of
operations for new wells brought on line primarily in south Louisiana.
Third, several maintenance projects were completed during the quarter
including clean up from flooding in the eastern United States.

. Exploration expense increased $9.8 million, or 208%49%, primarily as a
result of $9.0 millioncosts associated with operating the Gulf Coast properties
acquired with Cody Company in dry hole expenses recorded in the third quarter of 2001
primarilyAugust 2001. Additionally, operating costs
have increased in the Gulf Coast, and to a lesser extent in the Rocky
Mountains, areas, an increasewhere we are have more active properties than in prior quarters.
On a per unit basis, operating expense has risen from $0.46 per Mcf in the
first quarter of $7.62001 to $0.54 per Mcf in 2002.

. Exploration expense decreased $3.7 million, from last year. Additionally,or 34%, primarily as a result
of lower spending on geological and geophysical expense,
primarily related toexpenses and delay rentals
in 2002. During the acquisitionfirst quarter of 2001, we spent more than $3.7 million
in these areas in preparation for drilling which would occur later in 2001
and processingin 2002. These categories of seismic data, has
increased $2.0costs were $1.2 million during the first
quarter of 2002. Certain other employee compensation costs recorded only in
2001 accounted for the quarter. These increases are consistent withremainder of the budget for the expanded 2001 drilling program.decrease.

. Depreciation, depletion, amortization and impairment expense increased $10.8$8.2
million, or 76%47%, over the comparable quarter of last year. The
majority of the higher expense this quarter was due to the increase in natural gas and oil production as well asthis
quarter and the strongerhigher influence of the higher cost Gulf Coast region where equivalent production has increased
134% from last year's third quarter. Approximately 44% of this increase wasrate (including amounts
attributable to the Cody Company properties) on the weighted average due to
the DD&A recorded onhigher production contribution of this region. On a per unit basis, DDA
for the Cody properties this quarter.

-20-
first quarter was $0.97 per Mcf in 2001 and $1.14 per Mcf in 2002.

. General and administrative costs rose $1.2declined $0.2 million, or 23%3%, primarily as a result
of costs associated with certain non-cash compensation programs and
transitional Cody employees.additional bad debt expense recorded in the first quarter of 2001
related to the fourth quarter 2000 bankruptcy of two customers.

. Taxes other than income declined $0.3$3.8 million, or 6%38%, as a result of the
decline in oillower
commodity prices and the decline in natural gas production and prices
in the Rocky Mountainsrealized this year.quarter.

Interest expense increased $0.6$1.5 million as a result of a higher average
level of outstanding debt during the thirdfirst quarter of 20012002 when compared to the
thirdfirst quarter of 2000.2001. The new debt was primarily related to the Cody Company
acquisition.

Income tax expense increased $2.9was down $22.2 million due to the comparable
increasedecrease in earnings before income tax excluding the selected items.

Nine Months of 2001 and 2000 Compared

Net Income and Revenues. Excluding the selected items, we reported net
-----------------------
income in the first nine months of 2001 of $62.6 million, or $2.10 per share.
During the corresponding period of 2000, we had net income excluding selected
items of $11.5 million, or $0.43 per share. Operating revenues and operating
income increased $115.0 million and $78.7 million, respectively. The recently
acquired Cody Company contributed $9.1 million in operating revenues and $1.5
million in operating income. Natural gas made up 67%, or $245.4 million, of net
operating revenue in 2001. The increase in net operating revenues was driven
primarily by an 83% increase in the average natural gas price and by a 99%
increase in oil production. Net income and operating income were similarly
impacted by the increase in commodity prices and production.

The average Gulf Coast natural gas production sales price rose $2.07 per
Mcf, or 66%, to $5.19, increasing net operating revenues by approximately $35.9
million. In the Western region, the average natural gas production sales price
increased $1.97 per Mcf, or 80%, to $4.43, increasing net operating revenues by
approximately $38.1 million. The average Appalachian natural gas production
sales price increased $2.64 per Mcf, or 94%, to $5.45, increasing net operating
revenues by approximately $33.9 million. The overall weighted average natural
gas production sales price increased $2.24 per Mcf, or 83%, to $4.95. Hedging
gains buoyed prices in all three regions. On the last day of 2000, we entered
into a series of natural gas price collars that limited our exposure to the
decline in commodity prices for the months of February through October 2001.
Index prices were below the floor of these collars during several months of 2001
resulting in a hedge gain of $24.7 million, which contributed a $0.50 per Mcf
increase to our realized natural gas price for the first nine months of the
year. These collar arrangements covered approximately 44% of our natural gas
production during the first nine months of 2001and remain in place through
October 2001.

Natural gas production volume in the Gulf Coast region was up 7.4 Bcf, or
75%, to 17.3 Bcf primarily due to the acquisition of the Cody properties and new
production brought on line in south Louisiana. Natural gas production volume in
the Western region was down 2.6 Bcf, or 12%, to 19.4 Bcf primarily due to a
decrease in drilling activity in the Mid-Continent area since 1999. Natural gas
production volume in the Appalachian region was down 0.6 Bcf, or 4%, to 12.9
Bcf, as a result of a decrease in drilling activity in 1999. The 4.2 Bcf, or 9%,
rise in total natural gas production increased revenue by $11.2 million in the
first nine months of 2001.

Crude oil prices increased $1.70 per Bbl, or 7%, to $26.96, resulting in an
increase to net operating revenues of approximately $2.2 million. The volume of
crude oil sold in the first nine months of the year increased by 651 Mbbl, or
99%, to 1,307 Mbbl, increasing net operating revenues by $16.5 million.

Brokered natural gas revenue decreased $25.6 million, or 24%, from the
first nine months of last year. The sales price of brokered natural gas rose
2.02%, resulting in an increase in revenue of $31.5 million, offset by a 53%
decrease in volume of natural gas brokered this period, reducing revenues by
$57.1 million. After including the related brokered natural gas costs, we
realized a net margin of $2.2 million in the first nine months of 2001 and $3.8
million in the comparable period of 2000.

Excluding the selected items, other operating revenues decreased $0.4
million to $4.2 million, due to accruals made for payout liabilities as certain
wells were overproduced.

-21-

Costs and Expenses. Excluding the selected items, total costs and expenses
-------------------
from operations increased $35.8 million, or 17%, due primarily to the following:

. Brokered natural gas cost decreased $24.0 million, or 23%, over the first
nine months of last year. The cost per Mcf of brokered natural gas rose
65%, resulting in an increase to expense of $31.1 million, offset by a 53%
decrease in volume of natural gas brokered this quarter, reducing costs by
$55.1 million.

. Direct operating expense increased $3.8 million, or 15%, primarily as a
result of the cost of operating the Cody properties as well as wells
brought on line during the past year primarily in the Gulf Coast and Rocky
Mountains.

. Exploration expense increased $27.8 million, or 232%, as a result of
primarily as a result of $21.3 million in dry hole expense recorded in
2001, primarily in the Gulf Coast and Rocky Mountain regions, an increase
of $18.9 million from last year. Additionally, geological and geophysical
expense, primarily related to the acquisition and processing of seismic
data, has increased $6.9 million for the period. These increases are
consistent with the budget for the expanded 2001 drilling program.

. Depreciation, depletion and amortization expense increased $18.8 million,
or 46%, due to the increase in natural gas and oil production, the Cody
acquisition and the stronger influence of the higher cost Gulf Coast region
where equivalent production has increased 94% from the first nine months of
last year.

. General and administrative expenses increased $2.9 million, or 19%,
primarily as a result of higher compensation costs most of which is
associated with certain non-cash compensation programs. Increased
competition for experienced professionals in the energy industry has
resulted in increased salary and fringe benefit levels in order to retain
key employees. Additionally, our incentive compensation programs are based
on the Company's annual performance and result in higher expenses in years
of better financial performance.

. Taxes other than income rose $6.7 million, or 43%, as a result of higher
commodity prices realized this year.

Interest expense decreased $2.5 million as a result of a lower average
level of outstanding debt during the first nine months of 2001 when compared to
the first nine months of 2000.

Income tax expense increased $31.4 million due to the comparable increase
in earnings before income tax excluding the selected items.tax.

Recently Issued Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statements of Financial Accounting Standards No. 141 "Business Combinations"
("SFAS 141") and No. 142 "Goodwill and Other Intangible Assets" ("SFAS 142").
SFAS 141 requires all business combinations initiated after June 30, 2001 to be
accounted for under the purchase method. For all business combinations for which
the date of acquisition is after June 30, 2001, SFAS 141 also establishes
specific criteria for the recognition of intangible assets separately from
goodwill and requires unallocated negative goodwill to be written off
immediately as an extraordinary gain, rather than deferred and amortized. SFAS
142 changes the accounting for goodwill and other intangible assets after an
acquisition. The most significant changes made by SFAS 142 are: 1) goodwill and
intangible assets with indefinite lives will no longer be amortized; 2) goodwill
and intangible assets with indefinite lives must be tested for impairment at
least annually; and 3) the amortization period for intangible assets with finite
lives will no longer be limited to forty years. The Company does not believe
that the adoption of these statements will have a material effect on its
financial position, results of operations, or cash flows.

In June 2001, the FASB also approved for issuance SFAS 143 "Asset
Retirement Obligations." SFAS 143 establishes accounting requirements for
retirement obligations associated with tangible long-

-22-

livedlong-lived assets, including (1)
the timing of the liability recognition, (2) initial measurement of the
liability, (3) allocation of asset retirement cost to expense, (4) subsequent
measurement of the liability and (5) financial statement disclosures. SFAS 143
requires that an asset retirement cost should be capitalized as part of the cost
of the related long-lived asset and subsequently allocated to expense using a
systematic and rational method. The Company will adopt the statement effective
no later than January 1, 2003, as required. The transition adjustment resulting
from the adoption of SFAS 143 will be reported as a cumulative effect of a
change in accounting principle. At this time, the Company cannot reasonably
estimate the effect of the adoption of this statement on its financial position,
results of operations, or cash flows.

The new accounting model for long-lived assets to be disposed of by sale
applies to all long-lived assets, including discontinued operations, and
replaces the provisions of APB Opinion No. 30, "Reporting Results of Operations-
Reporting the Effects of Disposal of a Segment of a Business", for the disposal
of segments of a business. SFAS 144 requires that those long-lived assets be
measured at the lower of carrying amount or fair value less cost to sell,
whether reported in continuing operations or in discontinued operations.
Therefore, discontinued operations will no longer be measured at net realizable
value or include amounts for operating losses that have not yet occurred. SFAS
144 also broadens the reporting of discontinued operations to include all
components of an entity with operations that can be distinguished from the rest
of the entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction. The provisions of SFAS 144 are effective for
financial statements issued for fiscal years beginning after December 15, 2001
and, generally, are to be applied prospectively. At this time, the Company
cannot estimate the effect of this statement on its financial position, results
of operations, or cash flows.-18-

Forward-Looking Information

The statements regarding future financial performance and results, market
prices, and the other statements, which are not historical facts contained in
this report are forward-looking statements. The words "expect," "project,"
"estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast,"
"predict" and similar expressions are also intended to identify forward-looking
statements. Such statements involve risks and uncertainties, including, but not
limited to, market factors, market prices (including regional basis
differentials) of natural gas and oil, results for future drilling and marketing
activity, future production and costs and other factors detailed herein and in
our other Securities and Exchange Commission filings. Should one or more of
these risks or uncertainties materialize, or should underlying assumptions prove
incorrect, actual outcomes may vary materially from those indicated.

Conclusion

Our financial results depend upon many factors, particularly the price of
natural gas and oil and our ability to market gas on economically attractive
terms. The average produced natural gas sales price received in the first ninethree
months of 20012002 was over 80% highermore than 60% lower than in 2000.2001. The volatility of natural
gas prices in recent years remains prevalent in 20012002 with wide price swings in
day-
to-dayday-to-day trading on the NYMEX futures market. Additionally, thewe have natural
gas price collars that covered 44% of our 2001 productionin place through September will expire at
the end of October 2001, eliminatingAugust 2002 and oil price collars in place
through December 2002, which both offer some of our protection against the impactfalling prices
and remove some benefit of fallingrising prices. Given this continued price volatility,
we cannot predict with certainty what pricing levels will be in the future.
Because future cash flows are subject to these variables, we cannot assure you
that our operations will provide cash sufficient to fully fund our planned
capital expenditures.

We believe our capital resources, supplemented with external financing, if
necessary, are adequate to meet our capital requirements.

The preceding paragraph containsparagraphs contain forward-looking information. See Forward-
Looking Information above.

-23--19-

ITEM 3A. Quantitative and Qualitative Disclosures about Market Risk
- ---------------------------------------------------------------------

Commodity Price Swaps and Options

Hedges on our Production - Swaps

From time to time, we enter into natural gas and crude oil swap agreements
with counterparties to hedge price risk associated with a portion of our
production. These derivatives are not held for trading purposes. Under these
price swaps, we receive a fixed price on a notional quantity of natural gas and
crude oil in exchange for paying a variable price based on a market-based index,
such as the NYMEX gas and crude oil futures. During the first nine monthsquarter of 2001, natural gas price swaps covered 918 Mmcf, fixing the sales price of this
gas at $3.75 per Mcf. During the first nine months of 2000,2002,
we did not have any natural gas price swaps covering our production. During the
first quarter of 2001, natural gas price swaps covered 261 Mmcf, fixing the
sales price of this gas at $4.31 per Mcf. We entered into no oil price swaps
covering the first nine monthsquarter of 2002 or 2001.

InThe natural gas price swap arrangement that we entered into during the
first nine monthsthird quarter of 2000 covered a portion of production over the notional volumeperiod of October
2000 through September 2003. However, the counterparty declared bankruptcy in
December 2001. Based on the terms of the crude oilnatural gas swap transactionscontract, this action
resulted in the cancellation of the contract. At the time of cancellation, the
contract's value was 364 Mbbls at a price
of $22.67 per Bbl, which represented most of our oil production for the period.less than $0.2 million.

Hedges on Production - Options

In December 2000, we believed that the pricing environment provided a
strategic opportunity to significantly reduce the price risk on a portion of our
production through the use of costless collars. Under the costless collar
arrangements, if the index rises above the ceiling price, we pay the
counterparty. If the applicable index falls below the floor, the counterparty
pays us. The 2001 natural gas price hedges includeincluded several costless collar
arrangements based on eight price indexes at which we sold a portion of our
production. These hedges were in place for the months of February through
October 2001 and covered 5,274 Mmcf, or 34%, of our natural gas production for
the first quarter of 2001. All indexes were within the collars during February,
however some fell below the floor during the period of March resulting in $0.1
million cash revenue for the quarter.

Again in December of 2001, we believed that the pricing environment
provided a strategic opportunity to significantly reduce the price risk on a
portion of our 2002 production through the use of natural gas price collar
arrangements. The natural gas price hedges included several collar arrangements
based on nine price indexes at which we sell a portion of our production. These
hedges are in place for the months of FebruaryJanuary through October 2001April 2002 and cover approximately half68%
of our anticipated natural gas production during this period. ForThese collars have
a ceiling of $3.53 per Mcf and a floor of $2.68 per Mcf. A premium totaling $0.9
million was paid to purchase these collar arrangements.

In March 2002, we entered into another series of natural gas collars that
cover approximately 77% of our anticipated production during the first nine months of 2001, theseMay
through August 2002. These collars covered 21.6 Mmcfhave a ceiling of production. All indexes were within
the collars during February$3.17 per Mcf and April, some fell below thea floor
during the
period of March, and all indexes were below the floor from June through the end
the third quarter, resulting in a $24.7 million cash gain for the first nine
months.

A series of costless collars were$2.54 per Mcf. These natural gas price hedges are similar to those in place
during the first four months of April
through October 2000. During2002, but no premium was paid to enter into
these collars.

Also in the first nine months of 2000, these collars
covered 8,474 Mmcf, or 19%, of our production. During the months of April and
May, the indexes remained within the collars, but rose above the ceiling in June
2000 through the remainder of the swap period, resulting in a $6.7 million cash
loss for the first nine months.

As part of the Cody acquisition, we assumed a derivative contract that Cody
had entered into previously. This derivative was a natural gas price floor
entered into to reduce the risk of declining prices in the Gulf Coast region. It
is in effect through December 2001. During the third quarter of 2001, this
natural gas price floor covered 533 Mmcf of Gulf Coast production, fixing the
floor at $2.81 per Mcf. In September 2001, prices fell below the floor and we
realized a cash gain of $84,000. The natural gas price floor obtained in the
merger with Cody Company valued at $205,300 upon acquisition does not qualify
for hedge treatment under SFAS 133. At September 30, 2001, this derivative has
been recorded at market value on the balance sheet and the resulting gain of
$0.5 million, representing the movement of gas prices since the Cody acquisition
(August 1, 2001), is included in the period's operating revenue.

Hedges on Brokered Transactions

Occasionally, we use price swaps to hedge the natural gas price risk on
brokered transactions. Typically, we enter into contracts to broker natural gas
at a variable price based on the market index price. However, in some
circumstances, some of our customers or suppliers request that a fixed price be
stated in the contract. After entering into fixed price contracts to meet the
needs of our customers or suppliers, we may use price swaps to effectively
convert these fixed price contracts to market-sensitive price contracts. These
price swaps are held by us to their maturity and are not held for trading
purposes.

In the first nine months of 2001, we had no price swaps on brokered
transactions. For the first nine months of 2000,2002, we entered into a crude oil price swaps
with total notional quantities of 1,295 Mmcf related to our brokered activities,
representing 4%collar
arrangement that covers approximately 46% of our total volumeproduction during the period
from March through December 2002. This collar is based on NYMEX settlements, and
has a ceiling of brokered natural gas sold.$23.00 per barrel and a floor of $20.00 per barrel.

In accordance with the latest guidance from the FASB's Derivative
Implementation Group, we test the effectiveness of the combined intrinsic and
time values and the effective portion of each will be recorded as a component of
Other Comprehensive Income. Any ineffective portion will be recorded as a gain
or loss in the current period. As of March 31, 2002, we have recorded $15.3
million of Other Comprehensive Loss, a $0.6 million Unrealized Hedge Loss, the
reversal of a $1.5 million Hedge Assets and a $14.4 million Hedge Liability.

-20-

We are exposed to market risk on these open contracts, to the extent of
changes in market prices of natural gas and oil. Adoption of SFAS 133

-24-

On January 1, 2001,However, the Company adopted SFAS 133 "Accounting for Derivative
Instruments and Hedging Activities" as amendedmarket risk
exposure on these hedged contracts is generally offset by SFAS 137 and SFAS 138. Under
SFAS 133, all derivative instruments are recorded on the balance sheet at fair
value. This new pronouncement impactsgain or loss
recognized upon the accounting for the Company's natural
gas costless collar arrangements and natural gas price swap.

The Company uses derivative instruments to reduce the impact of changing
commodity prices on its financial results. At September 30, 2001, the Company
had two types of cash flow hedges open: a series of eight costless collar
arrangements and one natural gas price swap. The Company has recorded these
items at their fair market value on the balance sheet. The related unrealized
gains and losses were recorded as Other Comprehensive Income, a component of
Stockholders' Equity on the balance sheet, rather than to the income statement
to the extent that the derivative instrument was proven to be effective. For the
first nine months of 2001, a $5.9 million ($9.7 million pre-tax) unrealized gain
was recorded to Other Comprehensive Income. Ineffectiveness arises when the
change in fair valueultimate sale of the cash flow hedge does not perfectly offset the change
in the underlying anticipated natural gas sale. The ineffective portion of the
cash flow hedges (including the gain associated with the natural gas price floor
discussed below), a $0.8 million gain in the first nine months of 2001, was
recorded directly to the income statement as a Change in Derivative Fair Value.
Additionally, the time value component of the market value, a $24 thousand gain
in the first nine months of 2001, was recognized entirely as part of the Change
in Derivative Fair Value.

The natural gas price floor obtained in the merger with Cody Company valued
at $205,300 upon acquisition does not qualify for hedge treatment under SFAS
133. At September 30, 2001, this derivative has been recorded at market value on
the balance sheet and the resulting gain of $0.5 million, representing the
movement of gas prices since the Cody acquisition (August 1, 2001),commodity that is included
in the period's operating revenue.hedged.

The preceding paragraphs contain forward-looking information concerning
future production and projected gains and losses, which may be impacted both by
production and by changes in the future market prices of energy commodities. See
Forward-Looking Information on page 23.

-25-19.

-21-

PART II. OTHER INFORMATION

ITEM 2. Changes in Securities and Use of Proceeds
---------------------------------------------------

On August 16, 2001, Cabot, COG Colorado Corporation, a wholly owned
subsidiary of Cabot ("Merger Sub"), Cody Company, and the shareholders of Cody
Company completed the merger contemplated by the Agreement and Plan of Merger
dated June 20, 2001 (the "Merger Agreement") pursuant to which (i) Cody Company
distributed to its shareholders certain assets, and (ii) Merger Sub merged with
and into Cody Company (the "Merger"), with Cody Company surviving as a wholly
owned subsidiary of Cabot. In the Merger, Cabot paid total consideration of
approximately $231 million to acquire the stock of Cody Company, consisting of
(i) approximately $181 million in cash and (ii) 1,999,993 shares of Cabot Class
A common stock, par value $.01 per share. This issuance of Class A common stock
was exempt from registration under the Securities Act of 1933 by virtue of
Section 4(2) thereof and Rule 506 of Regulation D thereunder in that such
transaction did not involve any public offering or general solicitation and was
made to a limited number of persons, each of whom represented that it was an
accredited investor (as defined under Regulation D).

ITEM 6. Exhibits and Reports on Form 8-K
- -----------------------------------------

(a) Exhibits

15.1 - Awareness letter of independent accountants.

(b) Reports on Form 8-K
Item 2: Acquisition or Disposition of Assets filing made on August
30, 2001 to disclose the merger agreement between Cabot Oil & Gas
Corporation and Cody Company.

Item 2: Acquisition or Disposition of Assets filing made on October
30, 2001 as an amendment to the August 30, 2001 Form 8-K. This
amendment includes Item 7. Financial Statements and Exhibits.

-26-None

-22-

SIGNATURE

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

CABOT OIL & GAS CORPORATION
(Registrant)

October 31, 2001April 30, 2002 By: /s/ Scott C. Schroeder
---------------------------------------------
Scott C. Schroeder, Vice President, Chief
Financial Officer and Treasurer
(Principal Executive Officer Duly Authorized
to Sign on Behalf of the Registrant)

By: /s/ Henry C. Smyth
---------------------------------------------
Henry C. Smyth, Vice President and Controller
(Principal Accounting Officer)

-27--23-