SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended MARCH 31, 2001

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

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
----- ------

As of April 24, 2001, there were 29,424,232 shares of Class A Common
Stock, Par Value $.10 Per Share, outstanding.

This report contains 20 pages and one exhibit.

CABOT OIL & GAS CORPORATION

INDEX TO FINANCIAL STATEMENTS

Page
----

Part I. Financial Information

Item 1. Financial Statements

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

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

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

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

Report of Independent Accountants.............................................. 10

Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................................... 11

Item 3A. Quantitative and Qualitative Disclosures about Market Risk.............. 17

Part II. Other Information

Item 6. Exhibits and Reports on Form 8-K......................................... 19

Signature........................................................................... 20

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
MARCH 31,
-------------------
2001 2000
-------- -------

OPERATING REVENUES
Natural Gas Production.......................... $100,725 $39,086
Brokered Natural Gas............................ 35,422 36,937
Crude Oil & Condensate.......................... 11,556 4,325
Change in Derivative Fair Value (Note 8)....... 6,198 --
Other........................................... 990 4,772
-------- -------
154,891 85,120
OPERATING EXPENSES
Brokered Natural Gas Cost....................... 34,155 35,486
Production and Pipeline Operations.............. 8,220 8,511
Exploration..................................... 10,773 3,233
Depreciation, Depletion and Amortization........ 15,891 12,648
Impairment of Unproved Properties............... 1,482 960
General and Administrative...................... 5,946 4,887
Taxes Other than Income......................... 9,902 4,601
-------- -------
86,369 70,326
Gain (Loss) on Sale of Assets.................... 4 (21)
-------- -------
INCOME FROM OPERATIONS........................... 68,526 14,773
Interest Expense................................. 4,706 5,971
-------- -------
Income Before Income Taxes....................... 63,820 8,802
Income Tax Expense............................... 24,758 3,457
-------- -------
NET INCOME....................................... 39,062 5,345

Dividend Requirement on Preferred Stock.......... -- 851
-------- -------
Net Income Available to Common Stockholders...... $ 39,062 $ 4,494
======== =======

Basic Earnings Per Share Available to Common..... $1.33 $0.18

Diluted Earnings Per Share Available to Common... $1.32 $0.18

Average Common Shares Outstanding................ 29,318 24,798

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

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

MARCH 31, DECEMBER 31,

2001 2000
-------- --------

ASSETS
Current Assets
Cash and Cash Equivalents............................... $ 5,111 $ 7,574
Accounts Receivable..................................... 71,144 85,677
Inventories............................................. 7,576 11,037
Other................................................... 11,090 5,981
-------- --------
Total Current Assets................................. 94,921 110,269
Properties and Equipment, Net (Successful Efforts Method)... 648,123 623,174
Other Assets................................................ 2,047 2,191
-------- --------
$745,091 $735,634
======== ========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Current Portion of Long-Term Debt....................... $ 16,000 $ 16,000
Accounts Payable........................................ 90,201 81,566
Accrued Liabilities..................................... 35,950 20,542
-------- --------
Total Current Liabilities............................ 142,151 118,108
Long-Term Debt.............................................. 183,000 253,000
Deferred Income Taxes....................................... 121,962 108,174
Other Liabilities........................................... 14,867 13,847
Stockholders' Equity
Common Stock:
Authorized -- 40,000,000 Shares of $.10 Par Value
Issued and Outstanding -- 29,725,421 Shares and
29,494,411 Shares in 2001 and 2000, Respectively..... 2,973 2,949
Additional Paid-in Capital.............................. 289,970 285,572
Accumulated Deficit..................................... (3,742) (41,632)
Other Comprehensive Loss (Note 9)....................... (1,706) --
Less Treasury Stock, at Cost:
302,600 Shares in 2001 and 2000...................... (4,384) (4,384)
-------- --------
Total Stockholders' Equity........................... 283,111 242,505
-------- --------
$745,091 $735,634
======== ========

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

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

THREE MONTHS ENDED
MARCH 31,
---------------------
2001 2000
-------- --------

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income...................................... $ 39,062 $ 5,345
Adjustment to Reconcile Net Income to Cash
Provided by Operating Activities:
Depletion, Depreciation and Amortization..... 15,891 12,648
Impairment of Undeveloped Leasehold.......... 1,482 960
Deferred Income Taxes........................ 13,788 2,601
(Gain) Loss on Sale of Assets................ (4) 21
Exploration Expense.......................... 10,773 3,233
Change in Derivative Fair Value.............. (6,198) --
Other........................................ 777 517
Changes in Assets and Liabilities:
Accounts Receivable.......................... 14,533 1,035
Inventories.................................. 3,461 6,002
Other Current Assets......................... 1,759 1,352
Other Assets................................. 144 100
Accounts Payable and Accrued Liabilities..... 13,110 443
Other Liabilities............................ 1,020 1,178
-------- --------
Net Cash Provided by Operating Activities... 109,598 35,435
-------- --------

CASH FLOWS FROM INVESTING ACTIVITIES
Capital Expenditures............................ (34,748) (18,945)
Proceeds from Sale of Assets.................... 438 1,523
Exploration Expense............................. (10,773) (3,233)
-------- --------
Net Cash Used by Investing Activities....... (45,083) (20,655)
-------- --------

CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock............................ 4,194 1,231
Increase in Debt................................ 19,000 27,000
Decrease in Debt................................ (89,000) (42,000)
Dividends Paid.................................. (1,172) (1,854)
-------- --------
Net Cash Used by Financing Activities....... (66,978) (15,623)
-------- --------

Net Decrease in Cash and Cash Equivalents........ (2,463) (843)
Cash and Cash Equivalents, Beginning of Period... 7,574 1,679
-------- --------
Cash and Cash Equivalents, End of Period......... $ 5,111 $ 836
======== ========

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

CABOT OIL & GAS CORPORATION
NOTES TO 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). 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 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
the registration statement prepared or certified by us within the meanings of
Section 7 and 11 of the Act.

2. PROPERTIES AND EQUIPMENT

Properties and equipment are comprised of the following:

MARCH 31, DECEMBER 31,
2001 2000
---------- ------------
(In thousands)

Unproved Oil and Gas Properties................................. $ 40,633 $ 31,780
Proved Oil and Gas Properties................................... 1,024,963 993,397
Gathering and Pipeline Systems.................................. 128,778 128,257
Land, Building and Improvements................................. 4,543 4,538
Other........................................................... 25,715 25,601
---------- ----------
1,224,632 1,183,573
Accumulated Depreciation, Depletion and Amortization............ (576,509) (560,399)
---------- ----------
$ 648,123 $ 623,174
========== ==========

3. ADDITIONAL BALANCE SHEET INFORMATION

Certain balance sheet amounts are comprised of the following:

MARCH 31, DECEMBER 31,
2001 2000
---------- ------------
(In thousands)

Accounts Receivable
Trade Accounts.................................................. $ 69,071 $ 79,773
Joint Interest Accounts......................................... 4,608 4,074
Current Income Tax Receivable................................... 37 37
Other Accounts.................................................. 382 4,347
---------- ----------
74,098 88,231
Allowance for Doubtful Accounts.................................. (2,954) (2,554)
---------- ----------
$ 71,144 $ 85,677
========== ==========

MARCH 31, DECEMBER 31,
2001 2000
--------- ------------
(In thousands)

Accounts Payable
Trade Accounts................................................... $17,291 $20,855
Natural Gas Purchases............................................ 11,052 12,525
Wellhead Gas Imbalances.......................................... 2,329 2,185
Royalty and Other Owners......................................... 23,642 22,858
Capital Costs.................................................... 21,479 13,486
Taxes Other Than Income.......................................... 3,923 2,654
Drilling Advances................................................ 3,863 456
Other Accounts................................................... 6,622 6,547
------- -------
$90,201 $81,566
======= =======

Accrued Liabilities
Employee Benefits................................................ $ 4,820 $ 5,441
Taxes Other Than Income.......................................... 14,022 11,363
Interest Payable................................................. 4,253 2,478
Income Taxes Payable............................................. 9,371 --
Unrealized Loss - Change in Derivative Fair Value - Short-Term... 2,067 --
Other Accrued.................................................... 1,417 1,260
------- -------
$35,950 $20,542
======= =======

Other Liabilities
Postretirement Benefits Other Than Pension....................... $ 1,609 $ 1,497
Accrued Pension Cost............................................. 6,925 6,743
Unrealized Loss - Change in Derivative Fair Value - Long-Term.... 1,384 --
Taxes Other Than Income and Other................................ 4,949 5,607
------- -------
$14,867 $13,847
======= =======

4. LONG-TERM DEBT

At March 31, 2001, the Company had $67 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 presently ends in
December 2003 and is subject to renewal.

5. EARNINGS PER SHARE

Basic earnings per share for the first three months of the year were based
on the year-to-date weighted average shares outstanding of 29,318,262 in 2001
and 24,797,986 in 2000. The diluted earnings per share amounts are based on
weighted average shares outstanding plus common stock equivalents. Common
stock equivalents include both stock awards and stock options, and totaled
396,431 in 2001 and 213,525 in 2000.

6. ENVIRONMENTAL LIABILITY

The EPA notified the Company in February 2000 that it might have 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 1989. The EPA stated that federal, state and local
governmental agencies along with the numerous private entities that used the
Site for waste disposal will be expected to pay the clean-up costs which could
total as much as several hundred million dollars. The EPA is also pursuing the
owners/operators of the Site to pay for remediation.

Documents received with the notification from the EPA indicate that the
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 stemmed 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, has had extensive settlement discussions with
the EPA. However, the parties have yet to reach an agreement.

The Company has a reserve that it believes to be adequate to cover this
potential environmental liability 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, management does not believe it would
materially impact the Company's financial position. The Company will continue
to monitor the facts and its assessment of its liability related to this claim.

7. WYOMING ROYALTY LITIGATION

In June 2000, two overriding royalty owners sued the Company in Wyoming
State court. The plaintiffs have requested class certification under the
Wyoming Rules of Civil Procedure and allege that the Company has deducted
impermissible 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.

While the Company believes that it has substantial defenses to this claim
and intends to vigorously assert such defenses, the investigation into this
claim has not been completed and, accordingly, the Company can not presently
determine the likelihood or range of any potential loss.

8. ADOPTION OF SFAS 133

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 instruments,
which represent hedge ineffectiveness and changes in the time value component of
the fair value, are included in Change in Derivative Fair Value 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 March 31, 2001, the Company had two types of cash flow hedges open: a series
of eight costless collar arrangements and one natural gas price swap. At March
31, 2001, a $2.8 million pre-tax unrealized loss was recorded to Other
Comprehensive Income along with a $3.5 million derivative liability, a
derivative asset of $6.9 million and a non-cash gain of $6.2 million. The
ineffective portion of the cash flow hedges, a $0.3 million gain at March 31,
2001, was

recorded as a component of the Change in Derivative Fair Value in the
income statement. The remainder of the Change in Derivative Fair Value was a
$5.9 million gain at March 31, 2001, representing the time value component of
the costless collar arrangement.

As of March 31, 2001 $0.9 million, net of tax, of deferred net losses on
derivative instruments recorded in accumulated other comprehensive earnings are
expected to be reclassed to earnings during the next twelve-month period. For
2001, the Company has entered into costless collar arrangements for 24.4 Bcf of
its natural gas production with weighted average floor and ceiling prices of
$5.59/Mcf and $9.68/Mcf. In addition, the Company had entered into a natural
gas price swap covering 0.9 Bcf of production for 2001 at a weighted average
price of $3.75/Mcf. This swap also covers 0.7 Bcf of production in 2002 at
$3.11/Mcf, and 0.4 Bcf in 2003 at $2.81/Mcf.

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 accumulated 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 quarter of 2001, losses of $0.8 million ($0.5 million after
tax) were transferred from accumulated other comprehensive loss and the fair
value of outstanding liabilities decreased $0.7 million ($0.4 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.

9. COMPREHENSIVE INCOME

Comprehensive income includes net income and certain items recorded directly
to shareholders' equity and classified as Other Comprehensive Income. The
Company recorded Other Comprehensive Income for the first time in the first
quarter of 2001. Following the adoption of SFAS 133, the Company recorded an
after-tax charge to Other Comprehensive Income of $1.7 million 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 quarter ended March 31, 2001:

(In thousands)
--------------

Accumulated Other Comprehensive Income - December 31, 2000... $ --
Net Income................................................... $39,062

Other Comprehensive Loss (net of tax)
Cumulative effect of change in accounting principle -
January 1, 2001 (2,617)
Reclassification adjustment for settled contracts 487
Changes in fair value of outstanding hedging positions 424
-------
Other Comprehensive Loss..................................... $(1,706)
-------

Comprehensive Income......................................... $37,356
=======

There were no items in Other Comprehensive Income/Loss during 2000.

REPORT OF INDEPENDENT ACCOUNTANTS

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

We have reviewed the accompanying condensed consolidated balance sheet of Cabot
Oil & Gas Corporation (the "Company") as of March 31, 2001, and the related
condensed consolidated statements of operations and cash flows for the three-
month periods ended March 31, 2001 and March 31, 2000. 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, 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, 2001 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, 2000,
is fairly stated in all material respects in relation to the consolidated
balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Houston, Texas
April 23, 2001

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

The following review of operations for the first quarter of 2001 and 2000
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.

OVERVIEW

In the first quarter of 2001, we realized the highest natural gas prices for
any quarter and the highest oil prices for any first quarter in our Company's
history. Furthermore, oil production for the first quarter of 2001, a new
Company record, was 36% higher than the next highest quarter. The overall
increase in production from the comparable quarter of 2000 was largely
attributable to the Company's discoveries in South Louisiana. Operating
revenues increased $69.8 million, or 82%, and net income increased $34.6
million, mainly as a result of this improved price environment. Operating cash
flows were similarly impacted, improving by $74.2 million over last year,
contributing to the $70 million reduction in debt.

Our first quarter net income was $39.1 million, or $1.33 per share,
including a $6.2 million non-cash gain realized from the change in the fair
value of our derivatives under the newly adopted SFAS 133 (see Note 8). This
selected item increased after-tax net income by $3.8 million, or $0.13 per
share, in the first quarter of 2001. Excluding this selected item, our first
quarter 2001 net income was $35.3 million, or $1.20 per share.

We drilled 43 gross wells with a success rate of 91% compared to 25 gross
wells and an 88% success rate in the first quarter of 2000. For the full year,
we plan to drill approximately 240 gross wells and spend approximately $167.1
million in capital and exploration expenditures compared to 129 gross wells and
$122.6 million of capital and exploration expenditures in 2000. Total
expenditures were $53.5 million for the first quarter of 2001, compared to $20.3
million for the comparable period in 2000.

Natural gas production was 15.3 Bcf, up 0.1 Bcf compared to the 2000 first
quarter. Production from our recent discoveries in the Gulf Coast boosted
production in that region, while anticipated declines in the other regions held
the total natural gas production relatively flat.

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.

The preceding paragraphs, discussing our strategic pursuits and goals,
contain forward-looking information. See Forward-Looking Information on page 16.

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 through the summer
of 2000 and the spring of 2001, reducing the cyclical nature of demand that we
had seen previously in the market.

Our primary source of cash during the first quarter of 2001 was from funds
generated from operations. Another source of cash was the exercise of stock
options. Cash was primarily used to reduce debt, fund exploration and
development expenditures, and pay dividends.

We had a net cash outflow of $2.5 million in the first quarter of 2001. Cash
inflows from operating activities totaled $109.6 million in the current quarter,
substantially funding both the $70 million debt reduction and the $45.5 million
of capital and exploration expenditures.

THREE MONTHS ENDED MARCH 31,
2001 2000
---- ----
(In millions)

Cash Flows Provided by Operating Activities $109.6 $35.4
====== =====

Cash flows from operating activities in the 2001 first quarter were $74.2
million higher than the corresponding quarter of 2000 primarily due to higher
natural gas and oil prices and favorable changes in working capital.

THREE MONTHS ENDED MARCH 31,
2001 2000
---- ----
(In millions)

Cash Flows Used by Investing Activities $45.1 $20.7
===== =====

Cash flows used by investing activities in the first quarters of 2001 and
2000 were substantially attributable to capital and exploration expenditures of
$45.5 million and $22.2 million, respectively. Proceeds from the sale of
certain oil and gas properties in the first quarter were $0.4 in 2001 and $1.5
million in 2000.

THREE MONTHS ENDED MARCH 31,
2001 2000
---- ----
(In millions)

Cash Flows Used by Financing Activities $(67.0) $(15.6)
======= =======

Cash flows used by financing activities in the first quarter included $70
million and $15 million used to reduce borrowings on our revolving credit
facility in 2001 and 2000, respectively. Proceeds from the exercise of stock
options in the first quarter were $4.2 million in 2001 and $1.2 million in 2000.

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 runs to December 2003. Management believes that we have the
ability to finance, if necessary, our capital requirements, including
acquisitions.

Our 2001 interest expense is projected to be approximately $17.3 million. In
May 2001, a $16 million principal payment is due on the 10.18% Notes. This
amount is reflected as "Current Portion of Long-Term Debt" on the balance sheet.
This payment is expected to be made with cash from operations and, if necessary,
from increased borrowings on the revolving credit facility.

CAPITALIZATION

Our capitalization information is as follows:

MARCH 31, DECEMBER 31,
2001 2000
-------- -----------
(In millions)

Long-Term Debt.............................. $183.0 $253.0
Current Portion of Long-Term Debt........... 16.0 16.0
------ ------
Total Debt................................ 199.0 269.0
------ ------

Stockholders' Equity
Common Stock (net of Treasury Stock)....... 283.1 242.5
------ ------
Total..................................... 283.1 242.5
------ ------

Total Capitalization........................ $482.1 $511.5
====== ======
Debt to Capitalization...................... 41.3% 52.6%

As a result of the requirements of SFAS 133 adopted January 1, 2001 (See
Note 8), our Stockholders' Equity contains a charge of $1.7 million in Other
Comprehensive Income for the quarter ended March 31, 2001.

During the first quarter of 2001, we paid dividends of $1.2 million on the
Common Stock. A regular dividend of $0.04 per share of Common Stock has been
declared for each quarter since we became a public company.

During the first quarter of 2001, we reduced the outstanding balance on our
revolving credit facility by $70 million. The increased cash flow from
operations in the first quarter of 2001 provided the necessary cash for this
debt reduction.

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 while
considering projected cash flows for the year.

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

THREE MONTHS ENDED MARCH 31,
-----------------------------
2001 2000
----- -----
(In millions)
Capital Expenditures
Drilling and Facilities.................... $26.2 $15.1
Leasehold Acquisitions..................... 12.7 0.9
Pipeline and Gathering..................... 0.5 0.4
Other...................................... 3.3 0.7
----- -----
42.7 17.1
Exploration Expenses........................ 10.8 3.2
----- -----
Total...................................... $53.5 $20.3
===== =====

Total capital and exploration expenditures in the first quarter of 2001
increased $33.2 million compared to the same quarter of 2000, primarily as a
result of increased drilling activity as well as increases in leasehold
acquisitions costs consistent with our future drilling plans.

We plan to drill 240 gross wells in 2001 compared with 129 gross wells
drilled in 2000. This 2001 drilling program includes $167.1 million in total
capital and exploration expenditures, up from $122.6 million in 2000, and is our
largest budgeted capital program to date. Expected capital and exploration
spending in 2001 includes $112.4 million for drilling, $16.3 million for lease
acquisition costs and $8.7 million for geological and geophysical expenses
including seismic data costs. In addition to the drilling and exploration
program, other 2001 capital expenditures are planned primarily 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.

RESULTS OF OPERATIONS

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

SELECTED FINANCIAL AND OPERATING DATA

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

Operating Revenues.......................... $154.9 $ 85.1
Operating Expenses.......................... 86.4 70.3
Operating Income............................ 68.5 14.8
Interest Expense............................ 4.7 6.0
Net Income.................................. 39.1 4.5
Earnings Per Share - Basic.................. $ 1.33 $ 0.18
Earnings Per Share - Diluted................ $ 1.32 $ 0.18

Natural Gas Production (Bcf)
Gulf Coast................................. 4.8 3.4
West....................................... 6.4 7.3
Appalachia................................. 4.1 4.5
------ ------
Total Company.............................. 15.3 15.2
====== ======

Natural Gas Production Sales Prices ($/Mcf)
Gulf Coast................................. $ 7.34 $ 2.55
West....................................... $ 6.10 $ 2.26
Appalachia................................. $ 6.44 $ 3.07
Total Company.............................. $ 6.57 $ 2.56

Crude/Condensate
Volume (Mbbl).............................. 405 195
Price ($/Bbl).............................. $28.55 $22.19

Brokered Natural Gas Margin
Volume (Bcf)............................... 4.8 13.9
Margin ($/Mcf)............................. $ 0.26 $ 0.10

The table below presents the after-tax effect of a selected item on our
results of operations for the three months ended March 31, 2001 and 2000.

(In millions) 2001 2000
------------------------------------------------ ----- -----
Net Income Before Selected Items $35.3 $ 2.8
Benefit from miscellaneous net revenue (1) 1.7
Change in derivative fair value (2) 3.8
----- -----
NET INCOME $39.1 $ 4.5
===== =====

(1) Represents net benefit, primarily from a natural gas
contract settlement.
(2) See discussion in Note 8.

These selected items impacted our first quarter financial results.
Because they are not a part of our normal business or because they are
unrealized gains or losses on future transactions, we have isolated the effect
in the table above. The discussion below excludes the impact of these selected
items.

FIRST QUARTERS OF 2001 AND 2000 COMPARED

Net Income and Revenues. We reported net income before the selected
item in the first quarter of 2001 of $35.3 million, or $1.20 per share. During
the corresponding quarter of 2000, we reported net income of $2.8 million, or
$0.11 per share. Operating revenues increased by $66.4 million and operating
income increased by $50.4 million. Natural gas sales related to our production
made up 68%, or $100.7 million, of operating revenue. The increase in operating
revenues was primarily due to an average natural gas price that was two and one
half times greater than in 2000. Net income and operating income were similarly
impacted by the increase in the average natural gas price.

The average Gulf Coast natural gas production sales price rose $4.79 per
Mcf, or 188%, to $7.34, increasing operating revenues by approximately $22.9
million. In the Western region, the average natural gas production sales price
increased $3.84 per Mcf, or 170%, to $6.10, increasing operating revenues by
approximately $24.7 million. The average Appalachian natural gas production
sales price increased $3.37 per Mcf, or 110%, to $6.44, increasing operating
revenues by approximately $13.8 million. The overall weighted average natural
gas production sales price increased $4.01 per Mcf, or 157%, to $6.57,
increasing revenues by $61.4 million.

Natural gas production volume in the Gulf Coast region was up 1.4 Bcf,
or 41%, to 4.8 Bcf primarily due to production from wells in south Louisiana
drilled in 2000 and early 2001. Natural gas production volume in the Western
region was down 0.9 Bcf to 6.4 Bcf, primarily due to a decrease in drilling
activity in the Mid-Continent area during 2000. Natural gas production volume
in the Appalachian region was down 0.4 Bcf to 4.1 Bcf, as a result of a decrease
in drilling activity in the region in 2000. The improvement in total natural
gas production of 0.1 Bcf, or 1%, increased revenue by $0.2 million in the first
quarter of 2001.

Crude oil prices rose $6.36 per Bbl, or 29%, to $28.55, resulting in an
increase to operating revenues of approximately $2.6 million. In addition, the
volume of crude oil sold in the quarter increased by 210 Mbbls, or 108%, to 405
Mbbls, increasing operating revenues by $4.6 million.

Brokered natural gas revenue decreased $1.5 million, or 4%, over the first
quarter of last year. The sales price of brokered natural gas rose 175%,
resulting in an increase in revenue of $22.5 million, offset by a 65% decrease
in volume of natural gas brokered this quarter, reducing revenues by $24.0
million. After including the related brokered natural gas costs, we realized a
net margin of $1.3 million in the first quarter of 2001 and $1.5 in the
comparable quarter of 2000.

Excluding the selected item in 2000 regarding the settlement of a natural
gas contract dispute, other operating revenues decreased $0.9 million to $1.0
million. This change was primarily a result of:

. Natural gas liquids revenue rose by $0.4 million as a result of
increased prices.
. A decrease of $0.2 million in transportation due to a decline in activity.
. A total of $0.9 million recorded this year for payout, and gas balancing
issues.

Costs and Expenses. Total costs and expenses from operations increased
$16.0 million in the first quarter of 2001 compared to the same quarter of 2000.
The primary reasons for this fluctuation are as follows:

. Direct operating expense decreased $0.3 million, or 3%, primarily as a
result of costs associated with workovers on wells in the Gulf Coast in
early 2000 that did not recur in 2001. Additionally, costs decreased by
approximately $0.1 million in the Mid-Continent area due to lower field
maintenance expense.

. Exploration expense increased $7.5 million, or 233%, primarily as a result
of four dry holes recorded in 2001 for a total of $4.0 million. Another $2.6
million of the increase was due to geological and geophysical expenses
primarily in the Gulf Coast region related to the increased activity
primarily in south Louisiana. Other employee compensation costs accounted
for the remainder of the increase.

. Depreciation, depletion, amortization and impairment expense increased $3.8
million, or 28%, due to the increase in natural gas and oil production this
quarter and the higher influence of the Gulf Coast rate on the weighted
average due to the higher production contribution of this region.

. General and administrative costs rose $1.1 million, or 22%, as a result of
an additional $0.4 million in bad debt expense related to the fourth quarter
2000 bankruptcy of two customers, $0.2 million in payroll taxes related to
certain employee compensation paid in March and $0.2 million related to the
timing of payments for annual service agreements.

. Taxes other than income rose $5.3 million, or 115%, as a result of higher
commodity prices realized this quarter.

Interest expense decreased $1.3 million as a result of a lower average
level of outstanding debt during the first quarter of 2001 when compared to the
first quarter of 2000.

Income tax expense was up $20.0 million due to the comparable increase in
earnings before income tax.

* * *

FORWARD-LOOKING INFORMATION

The statements regarding future financial and operating performance and
results, market prices, future hedging activities 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
quarter of 2001 was two and one-half times higher than in 2000. The volatility
of natural gas prices in recent years remains prevalent in 2001 with wide price
swings in day-to-day trading on the NYMEX futures market. 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 contains forward-looking information. See Forward-
Looking Information above.

ITEM 3A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

COMMODITY PRICE SWAPS

HEDGES ON OUR PRODUCTION

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 quarter of 2001,
natural gas price swaps covered 261 Mmcf, fixing the sales price of this gas at
$4.31/Mcf. During the first quarter of 2000, we did not enter into any natural
gas price swaps on our production. We entered into no oil price swaps covering
the first quarter of 2001. In the first quarter of 2000, the notional volume of
the crude oil swap transactions was 182 Mbbls at a price of $22.25 per Bbl,
which represented most of our oil production for the period.

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. The natural gas price hedges
include several costless collar arrangements based on eight price indexes at
which we sell a portion of our production. These hedges are in place for the
months of February through October 2001 and cover approximately half of our
anticipated natural gas production during this period. For the first quarter of
2001, these collars covered 5,274 Mmcf of production. All indexes were within
the collars during February, but some fell below the floor in March, resulting
in a $0.1 million hedge gain for the first quarter. No production was covered
by collar arrangements in the first quarter of 2000.

HEDGES ON BROKERED TRANSACTIONS

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 quarter of 2001, we had no price swaps on brokered
transactions. For the first quarter of 2000, we entered into price swaps with
total notional quantities of 1,030 Mmcf related to our brokered activities,
representing 8% of our total volume of brokered natural gas sold.

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

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. This new pronouncement impacts the accounting for the Company's natural
gas costless collar arrangements and natural gas price swap.

The Company uses hedges to reduce the impact of changing commodity prices on
its financial results. At March 31, 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 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 hedge was proven to
be effective. For the first quarter of 2001, a $1.7 million ($2.8 million pre-
tax) unrealized loss was recorded to Other Comprehensive Income. Ineffectiveness
arises when the change in fair value 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, a $0.3 million gain in the first
quarter 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 $5.9 million gain in the first quarter of 2001, was recognized entirely
as part of the Change in Derivative Fair Value.

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 16.

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

15.1 - Awareness letter of independent accountants.

(b) Reports on Form 8-K
None

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)

April 27, 2001 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)