- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-K

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

FOR THE YEAR ENDED DECEMBER 31, 1993 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)

15375 MEMORIAL DRIVE, HOUSTON, TEXAS 77079
(Address of principal executive offices including Zip Code)

(713) 589-4600
(Registrant's telephone number)

Securities registered pursuant to Section 12(b) of the Act:

NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
- --------------------------------------------------------------------------------------------

CLASS A COMMON STOCK, PAR VALUE $.10 PER SHARE NEW YORK STOCK EXCHANGE
RIGHTS TO PURCHASE PREFERRED STOCK NEW YORK STOCK EXCHANGE

Securities registered pursuant to Section 12(g) of the Act: NONE

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 / /

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. / /

The aggregate market value of Class A Common Stock, par value $.10 per
share ("Common Stock"), held by non-affiliates (based upon the closing sale
price on the New York Stock Exchange on March 1, 1994), was approximately
$433,197,000.

As of March 1, 1994, there were 20,583,930 shares of Common Stock
outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the following documents are incorporated herein by reference in
portions of the parts of this report indicated below:

DOCUMENT INCORPORATED AS OF
Annual Report to Stockholders for Parts I, II, and IV.
the Registrant's Fiscal Year Ended
December 31, 1993
Proxy Statement for the 1994 Annual Meeting Part III, Items 10, 11, 12, and 13.
of Stockholders (to be filed not later than
120
days after December 31, 1993).

- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
2

PART I
ITEM 1. BUSINESS
GENERAL

Cabot Oil & Gas Corporation (or, the "Company") develops, produces,
explores for, stores, transports, purchases and markets natural gas and, to a
lesser extent, produces and sells crude oil. Substantially all of the Company's
operations are in the Appalachian Region of West Virginia, Pennsylvania and New
York, and in the Anadarko Region of southwestern Kansas, Oklahoma and the Texas
Panhandle. At December 31, 1993, the Company had approximately 825 Bcfe of
proved reserves, 98% of which was natural gas. A significant portion of the
Company's natural gas reserves is located in long-lived fields with extended
production histories.

The Company, a Delaware corporation, was organized in 1989 as the successor
to the oil and gas business of Cabot Corporation ("Cabot"), which was founded in
1891. In 1990, the Company completed its initial public offering of
approximately 18% of the outstanding common stock held by Cabot. Cabot
distributed the remaining common stock of the Company to the shareholders of
Cabot in 1991. Since that time, the Company has been widely held and publicly
traded on the New York Stock Exchange. See Note 1 of the Notes to the
Consolidated Financial Statements incorporated herein by reference in Item 8
hereof for further discussion.

Unless the context otherwise requires, all references herein to the Company
include Cabot Oil & Gas Corporation, its predecessors and subsidiaries.
Similarly, all references to Cabot include Cabot Corporation and its affiliates.
All references to wells are gross, unless otherwise stated.

The following table summarizes certain information, at December 31, 1993,
regarding the Company's proved reserves, productive wells, developed and
undeveloped acreage and infrastructure.

SUMMARY OF RESERVES, PRODUCTION, ACREAGE AND OTHER INFORMATION BY AREAS OF
OPERATION (1)(2)

TOTAL APPALACHIAN ANADARKO
COMPANY REGION REGION(3)
------- ----------- ----------

Reserves/Production:
Proved reserves
Developed (Bcfe).................................... 683.7 459.5 224.2
Undeveloped (Bcfe).................................. 141.5 97.2 44.3
Total (Bcfe)........................................ 825.2 556.7 268.5
Daily production (MMcfe)............................... 131.8 72.0 59.8
Gross productive wells................................. 5,180.0 4,017.0 1,163.0
Net productive wells................................... 4,235.4 3,688.4 547.0
Percent of wells operated.............................. 90% 97% 60%
Acreage/Infrastructure:
Net acreage (thousands of acres)
Developed acreage................................... 935 759 176
Undeveloped acreage................................. 501 469 32
Total............................................... 1,436 1,228 208
Gathering and Pipeline mileage......................... 3,601 3,546 55
Storage field working capacity (Bcf)................... 3.8 3.8 0

- ---------------

(1) As of December 31, 1993. For additional information regarding the Company's
estimates of proved reserves and other data, see "Business -- Reserves,"
"Business -- Acreage," "Business -- Productive Well Summary" and
"Supplemental Oil and Gas Information to the Consolidated Financial
Statements."

(2) Certain numbers may not add due to rounding.

(3) Includes all properties outside the Appalachian Region, most notably
properties located in the Anadarko Region.

1
3

EXPLORATION, DEVELOPMENT AND PRODUCTION

The Company is one of the largest producers of natural gas in the
Appalachian Region, where it has conducted operations for more than a century.
The Company has had operations in the Anadarko Region for over 50 years.
Historically, the Company has maintained its reserve base through low-risk
development drilling. The Company continues to focus its operations in the
Appalachian and Anadarko Regions through development of undeveloped reserves and
acreage, acquisition of oil and gas producing properties and, to a lesser
extent, exploration. However, the Company has adopted a strategic plan to
continue the exploitation of its existing asset base, exploring possible
acquisition opportunities both within and outside of the Company's core areas
and expanding its marketing capabilities.

APPALACHIAN REGION

The Company's exploration, development and production activities in the
Appalachian Region are concentrated in Pennsylvania, West Virginia and New York.
Operations are managed by a regional office in Pittsburgh. At December 31, 1993,
the Company had approximately 557 Bcfe of proved reserves (substantially all
natural gas) in the Appalachian Region, constituting 67% of the Company's total
proved reserves. The Appalachian Region also accounted for 55 percent of the
Company's 1993 production.

The Company has 4,017 productive wells (3,688.4 net) of which 3,905 wells
are operated by the Company. There are multiple producing intervals which
include the Medina, Berea and Big Line trend formations at depths ranging from
1,500 to 8,700 feet. Average net daily production in 1993 was 72.0 MMcfe.

While natural gas production volumes from Appalachian reservoirs are
relatively low on a per-well basis compared to other areas of the United States,
the productive life of Appalachian reserves is relatively long. The Company's
finding and development costs for its Appalachian reserves are lower than the
U.S. industry average because of the comparatively shallow reservoir depths and
a lower incidence of dry holes.

In 1993, the Company drilled 126 wells (122.1 net) wells in the Appalachian
Region (122 development wells). Capital and exploration expenditures for the
year were approximately $86.5 million, including the $46.4 million EMAX
Acquisition (described in "Acquisitions" below). In the 1994 drilling program
year, the Company has plans to drill approximately 158 wells.

At December 31, 1993, the Company had approximately 1.23 million net acres,
including 759 thousand net developed acres. At year end, the Company had
identified 298.5 additional net development drilling locations.

The Company also owns and operates a brine treatment plant near Franklin,
Pennsylvania. The plant, which began operating in 1985, processes and treats
waste fluid generated during the drilling, completion and subsequent production
of oil and gas wells. The plant provides services to the Company and certain
other oil and gas producers in southwestern New York, eastern Ohio and western
Pennsylvania.

The Company believes that it gains operational efficiency, and therefore
maximizes the return on its investment in the Appalachian Region because of its
large acreage position, its high concentration of wells, its substantial ongoing
drilling program conducted over a number of years, its natural gas gathering and
pipeline systems and its storage capacity.

ANADARKO REGION

The Company's exploration, development and production activities in the
Anadarko Region are primarily focused in Kansas, Oklahoma and Texas. Operations
are managed by a regional office in Oklahoma City. At December 31, 1993, the
Company had approximately 269 Bcfe of proved

2
4

reserves (substantially all natural gas) in the Anadarko Region, constituting
33% of the Company's total proved reserves.

The Company has an interest in 1,163 productive wells (547 net) of which
701 wells are operated by the Company. Principal producing intervals are in the
Chase, Chester and Marrow formations at depths ranging from 1,500 to 11,000
feet. Average net daily production in 1993 was 59.8 MMcfe.

In 1993, the Company drilled 36 wells (27.7 net) in the Anadarko Region
(all development wells). Capital and exploration expenditures for the year were
approximately $48.7 million, including the non-cash $34.6 million Harvard
Acquisition (described in "Acquisitions" below). In the 1994 drilling program
year, the Company has plans to drill approximately 30 wells.

At December 31, 1993, the Company had approximately 208 thousand net acres,
including 176 thousand net developed acres. At year end, the Company had
identified 54.3 additional net development drilling locations.

ACQUISITIONS

As part of its long-term growth strategy, the Company placed greater
emphasis on acquiring proved oil and gas properties in 1993. The Company's focus
is on the acquisition of producing properties with additional development
drilling potential that would complement the Company's existing operations. The
objective is to acquire properties where low-risk development drilling or
improved production methods can increase proved reserves attributable to
acquired oil and gas properties.

In May 1993, the Company purchased oil and natural gas properties located
in the Anadarko Region of Texas and Oklahoma, and in the East Texas Basin from
Harken Anadarko Partners, L.P. (the "Harvard Acquisition"). The Company issued
692,439 shares of $3.125 convertible preferred stock to Harvard University. The
preferred stock has a total stated value of $34.6 million, or $50 per share, and
is convertible, subject to certain adjustments, into 1,648,662 shares of Common
Stock at $21 per share, also subject to certain adjustments. As of the
acquisition date, the properties had approximately 38.2 billion cubic feet
equivalent of proved reserves which were 80% natural gas and included 518 (166
net) wells. Almost 45% of the wells are operated by the Company. Average net
daily production on these properties in 1993 was 10.95 million cubic feet
equivalent ("MMcfe").

In September 1993, the Company purchased oil and natural gas properties and
related assets located in the Appalachian Region of West Virginia and
Pennsylvania from Emax Oil Company (the "EMAX Acquisition") for approximately
$44.1 million, subject to certain adjustments. As of the acquisition date, the
properties had approximately 47.1 billion cubic feet equivalent of proved
reserves of which 99% were natural gas. The properties include 300 (291 net)
wells, all but one of which are operated by the Company. Average net daily
production on these properties in 1993 was 8.70 MMcfe. As part of the
acquisition, the Company entered into a development agreement that provides for
the acquisition of additional drilling locations for approximately $106 thousand
per location. The agreement provides for the drilling of 78 such wells under a
farmout from a local producer. Total expected drilling costs for these 78 wells
are estimated at $13.6 million. The Company drilled 22 of these wells in 1993,
which added approximately 5.2 Bcfe to the proved reserves acquired and increased
the total acquisition cost by $2.3 million. At year end the Company had
identified 69 future drilling locations, including the remaining locations
associated with the farm-out agreement mentioned above.

On February 25, 1994, the Company entered into a merger agreement with
Washington Energy Company ("WECO") to merge its subsidiary Washington Energy
Resources Company ("WERCO") into COG Acquisition Company, a subsidiary of the
Company (the "Merger Agreement"). The Company will acquire the common stock of
WERCO in a tax-free exchange for total consideration of $180 million, subject to
certain adjustments. As of January 1, 1994, WERCO held

3
5

230 Bcfe of proved reserves located in the Green River Basin of Wyoming and in
South Texas. The reserves are 82% natural gas. WERCO's current net production is
43 mmcf of natural gas, 450 barrels of natural gas liquids and 1,550 barrels of
oil and condensate per day. WERCO produces from 376 wells, 116 net to their
interest and operates 184 wells, 87 net.

The Company will issue 2,133,000 shares of its common stock, par value $.10
(the "Common Stock") and 1,134,000 shares of a 6% Convertible Redeemable
Preferred Stock (the "6% Preferred Stock") in exchange for the common stock of
WERCO. The 6% Preferred Stock has a stated value of $50.00 per share and is
convertible into 1,972,174 shares of Common Stock at $28.75 per share. Because
of the size of WECO's investment in the Company, WECO will be able to nominate
two directors to serve on the Company's Board of Directors. In addition, the
Company will advance cash to repay intercompany indebtedness outstanding at
closing and assume $5.9 of third party debt. The amount of intercompany debt of
WERCO at December 31, 1993 was $69,100,000, as adjusted. The Merger Agreement
contains a provision that WECO may terminate the transaction if the average of
the Company's Common Stock price for the ten trading days ending on the third
business day prior to the closing is less than $19.00; provided, however, that
the Company may cure such deficit in cash up to $10 million.

The closing of the transaction is anticipated to take place three business
days following the satisfaction of the conditions of closing. One closing
condition is that certain firm transportation, storage and other contractual
arrangements be transferred from WERCO's marketing affiliate to a newly formed
subsidiary of WECO. The Company anticipates that the closing of the transaction
will occur in early spring.

GAS MARKETING

The Company is engaged in a wide array of marketing activities designed to
offer its customers long-term reliable supplies of natural gas. Utilizing its
pipeline and storage facilities, gas procurement ability and transportation and
natural gas swap expertise, the Company provides a menu of services that include
gas supply management, short and long-term supply contracts, capacity brokering
and risk management alternatives.

The marketing of natural gas has changed significantly as a result of Order
636 (the "Order"), which was issued by the Federal Energy Regulatory Commission
(the "FERC") in 1992. The Order required interstate pipelines to unbundle their
gas sales, storage and transportation services. As a result, local distribution
companies and end-users will separately contract these services from gas
marketers and producers. The Order has created greater competition in the
industry while providing the Company the opportunity to reach broader markets.
In 1993, this has meant an increase in the number of third-party producers that
use the Company to market their gas and margin pressures from increased
competition for markets.

APPALACHIAN REGION

The Company's principal markets for Appalachian Region natural gas are in
the northeastern United States. The Company's marketing subsidiary purchases
substantially all of the Company's natural gas production as well as production
from local third-party producers and other suppliers in order to aggregate
larger volumes of natural gas for resale. This marketing subsidiary sells
natural gas to industrial customers, interstate pipelines, local distribution
companies and gas marketers.

A substantial portion of the Company's natural gas sales volume in the
Appalachian Region currently is sold under short-term contracts (a year or less)
at market-responsive prices. The Company's spot market sales are made under
month-to-month contracts while the Company's industrial and utility sales
generally are made under year-to-year contracts. Spot market and term sales
constituted 60% and 40%, respectively, of total Appalachian gas sales in 1993.

The Company's Appalachian production is generally sold at a premium price
to production from certain other producing regions due to its close proximity to
markets. However, that premium has

4
6

been reduced from historic levels due to increased competition in the market
place resulting, in part, from changes in transportation and sales arrangements
due to the implementation of pipeline open access tariffs.

The Company operates a number of gas gathering and pipeline systems, made
up of approximately 3,500 miles of pipeline with interconnects to four
interstate and five local distribution companies ("LDCs"). The Company's natural
gas gathering and pipeline systems enable the Company to connect new wells
quickly and to transport natural gas from the wellhead directly to interstate
pipelines, local distribution companies and industrial end-users. Control of its
gathering and pipeline systems also enables the Company to purchase, transport
and sell natural gas produced by third parties. In addition, the Company can
undertake development drilling operations without relying upon third parties to
transport its natural gas while incurring only the incremental costs of
additions to its system and lease operations.

The Company has two natural gas storage fields, with a combined working
capacity of approximately 4 Bcf of natural gas, located in West Virginia. The
Company uses these storage fields to take advantage of the seasonal variations
in the demand for natural gas and the higher prices typically associated with
winter natural gas sales, while maintaining its production at a nearly constant
rate throughout the year. The storage fields also enable the Company to increase
periodically the volume of natural gas it can deliver by more than 35% above the
volume that it could deliver solely from its production in the Appalachian
Region. The pipeline systems and storage fields are fully integrated with the
Company's producing operations.

ANADARKO REGION

The Company's principal markets for Anadarko Region natural gas are in the
midwestern United States. The Company's marketing subsidiary purchases
substantially all of the Company's natural gas production. The marketing
subsidiary sells natural gas to interstate pipelines, natural gas processors,
LDCs, industrial customers and marketing companies.

Currently, the Company's natural gas production in the Anadarko Region is
being sold primarily under short-term contracts (a year or less) at
market-responsive prices. The Anadarko Region properties are connected to the
majority of the midwestern interstate pipelines, affording the Company access to
multiple markets.

RISK MANAGEMENT

From time to time, the Company enters into certain transactions to manage
price risks associated with the purchase and sale of oil and gas including,
swaps and options. The Company utilized certain gas price swap agreements
("price swaps") to manage price risk more effectively and improve the Company's
realized gas prices. These price swaps call for payments to (or to receive
payments from) counterparties based upon the differential between a fixed and a
variable gas price. The current price swaps run for periods of a year or less
and have a remaining notional contract amount of 4,080,000 MMbtu of natural gas
at December 31, 1993. The Company plans to continue this strategy in the future.

5
7

RESERVES
CURRENT RESERVES

The Company's drilling program, combined with acquisitions in its core
areas, created a 12 percent increase in proved reserves. Reserve replacement for
the Company's drilling program was 127% in 1993, and the 1993 reserve
replacement including acquisitions was 287 percent. The following table sets
forth information regarding the Company's estimates of its net proved reserves
at December 31, 1993.

NATURAL GAS LIQUIDS(1) NATURAL GAS EQUIVALENTS(2)
-------------------------------- ------------------------------ --------------------------------
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------- --------- ----------- ------ --------- ----------- --------
(MMCF) (MBBL) (MMCFE)

Company Regions:
Appalachian.............. 458,682 97,251 555,933 136 0 136 459,498 97,251 556,749
Anadarko................. 210,990 41,357 252,347 2,210 480 2,690 224,250 44,237 268,487
--------- ----------- -------- --------- --- ------ --------- ----------- --------
Total.................. 669,672 138,608 808,280 2,346 480 2,826 683,748 141,488 825,236
--------- ----------- -------- --------- --- ------ --------- ----------- --------
--------- ----------- -------- --------- --- ------ --------- ----------- --------

- ---------------

(1) Liquids include crude oil and condensate.

(2) Natural Gas Equivalents are determined using the ratio of 6.0 Mcf of natural
gas to 1.0 Bbl of crude oil or condensate.

The reserve estimates presented herein were prepared by the Company and
reviewed by Miller and Lents, Ltd., independent petroleum engineers. For
additional information regarding the Company's estimates of proved reserves, the
review of such estimates by Miller and Lents, Ltd. and certain other information
regarding the Company's oil and gas reserves, see the Supplemental Oil and Gas
information to the Consolidated Financial Statements incorporated herein by
reference in Item 8 hereof. A copy of the review letter by Miller and Lents,
Ltd., has been filed as an exhibit to this Form 10-K. The Company's estimates of
reserves set forth in the foregoing table do not differ materially from those
filed by the Company with other federal agencies. The Company's reserves are
sensitive to gas sales prices and their effect on economic producing rates. The
Company's reserves are based on oil and gas prices in effect at December 31,
1993.

There are numerous uncertainties inherent in estimating quantities of
proved reserves, including many factors beyond the control of the Company. The
reserve data set forth in this Form 10-K represent only estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
crude oil and natural gas that cannot be measured in an exact manner, and the
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. As a result,
estimates of different engineers often vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may justify
revision of such estimate. Accordingly, reserve estimates are often different
from the quantities of crude oil and natural gas that are ultimately recovered.
The meaningfulness of such estimates is highly dependent upon the accuracy of
the assumptions upon which they are based. In general, the volume of production
from oil and gas properties owned by the Company declines as reserves are
depleted. Except to the extent the Company acquires additional properties
containing proved reserves or conducts successful exploration and development
activities or both, the proved reserves of the Company will decline as reserves
are produced.

6
8

THREE-YEAR RESERVES

The following table sets forth certain information regarding the Company's
estimated proved reserves for the periods indicated.

NATURAL GAS OIL, CONDENSATE TOTAL
(MMCF) (MBBL) (MMCFE)
APP = APPALACHIAN REGION --------------------------- ------------------- ---------------------------
ANA = ANADARKO REGION APP ANA TOTAL APP ANA TOTAL APP ANA TOTAL
------- ------- ------- --- ----- ----- ------- ------- -------

Proved Reserves:
December 31, 1990...................... 523,202 203,085 726,287 90 1,226 1,316 523,742 210,441 734,183
Revisions of prior estimates......... (38,521) 3,670 (34,851) (14) (15) (29) (38,605) 3,580 (35,025)
Extensions, discoveries, other
additions.......................... 39,099 27,034 66,133 23 87 110 39,237 27,556 66,793
Production........................... (26,646) (17,041) (43,687) (15) (133) (148) (26,736) (17,839) (44,575)
Purchases of reserves in place....... 2,238 3,756 5,994 0 5 5 2,238 3,786 6,024
Sales of reserves in place........... (3,263) (163) (3,426) (6) (35) (41) (3,299) (373) (3,672)

December 31, 1991...................... 496,109 220,341 716,450 78 1,135 1,213 496,577 227,151 723,728
Revisions of prior estimates......... (1,901) (7,046) (8,947) 44 191 235 (1,637) (5,900) (7,537)
Extensions, discoveries, other
additions.......................... 33,262 23,613 56,875 6 505 511 33,298 26,643 59,941
Production........................... (25,614) (19,852) (45,466) (14) (148) (162) (25,698) (20,740) (46,438)
Purchases of reserves in place....... 3,425 2,346 5,771 2 1 3 3,437 2,352 5,789
Sales of reserves in place........... (17) 0 (17) 0 (1) (1) (17) (6) (23)

December 31, 1992...................... 505,264 219,402 724,666 116 1,683 1,799 505,960 229,500 735,460
Revisions of prior estimates......... (17,621) (649) (18,270) (6) (349) (355) (17,657) (2,743) (20,400)
Extensions, discoveries, other
additions.......................... 35,439 22,826 58,265 1 436 437 35,445 25,442 60,887
Production........................... (26,191) (19,859) (46,050) (13) (332) (345) (26,269) (21,851) (48,120)
Purchases of reserves in place....... 60,508 32,623 93,131 38 1,293 1,331 60,736 40,381 101,117
Sales of reserves in place........... (1,466) (1,996) (3,462) 0 (41) (41) (1,466) (2,242) (3,708)
December 31, 1993...................... 555,933 252,347 808,280 136 2,690 2,826 556,749 268,487 825,236

Proved Developed Reserves:
December 31, 1990.................... 399,545 168,293 567,838 82 1,226 1,308 400,037 175,649 575,686
December 31, 1991.................... 385,629 185,036 570,665 78 1,126 1,204 386,097 191,792 577,889
December 31, 1992.................... 398,895 184,778 583,673 116 1,394 1,510 399,591 193,142 592,733
December 31, 1993.................... 458,682 210,990 669,672 136 2,210 2,346 459,498 224,250 683,748

- ---------------

Note: Natural gas equivalents are determined using the ratio of 6.0 Mcf of
natural gas to 1.0 Bbl of crude oil or condensate.

7
9

VOLUMES AND PRICES; PRODUCTION COSTS

The following table sets forth historical information regarding the
Company's sales and production volumes of average sales prices received for, and
average production costs associated with, its sales of natural gas and crude oil
and condensate for the periods indicated.

YEAR ENDED DECEMBER 31,
-----------------------------------
1993 1992 1991
------- ------- -------

Net Wellhead Sales Volume:
Natural Gas (Bcf)(1)
Appalachian Region............................ 23.1 24.0 24.9
Anadarko Region............................... 19.8 19.9 16.8
Crude/Condensate (MBbl)
Appalachia and Anadarko....................... 345 162 148

Purchased Gas
Volumes (Bcf)................................. 21.6 20.6 20.6
Purchase Cost ($/Mcf)......................... $ 2.09 $ 1.90 $ 1.75
Natural Gas Sales Price ($/Mcf)(2)
Appalachian Region............................ $ 2.69 $ 2.50 $ 2.43
Anadarko Region............................... $ 1.94 $ 1.62 $ 1.49
Weighted Average.............................. $ 2.40 $ 2.18 $ 2.12
Crude/Condensate Sales Price ($/Bbl)(2).......... $ 16.58 $ 19.03 $ 19.80
Production Costs ($/Mcfe)(3)..................... $ 0.65 $ 0.57 $ 0.57

- ---------------

(1) Equal to the aggregate of production and the net changes in storage and
exchanges less fuel and line loss.

(2) Represents the average sales prices for all volumes (including royalty
volumes) sold by the Company during the periods shown.

(3) Production costs include direct lifting costs (labor, repairs and
maintenance, materials and supplies), and the costs of administration of
production offices, insurance and property and severance taxes but is
exclusive of depreciation and depletion application to capitalized lease
acquisition, exploration and development expenditures.

8
10

ACREAGE

The following tables summarize the Company's gross and net developed and
undeveloped leasehold and mineral acreage at December 31, 1993. Acreage in which
the Company's interest is limited to royalty and overriding royalty interests is
excluded. The undeveloped mineral fee acreage in West Virginia is unleased.

LEASEHOLD ACREAGE

AT DECEMBER 31, 1993
------------------------------------------------------------------
DEVELOPED UNDEVELOPED TOTAL
-------------------- ------------------- ---------------------
GROSS NET GROSS NET GROSS NET
--------- -------- -------- -------- --------- ---------

State:
Alabama...................... -- -- 12,493 12,350 12,493 12,350
Arkansas..................... -- -- 240 6 240 6
Colorado..................... 13,903 13,040 19,163 12,061 33,066 25,101
Kansas....................... 31,744 28,461 16,533 9,750 48,277 38,211
Kentucky..................... 3,527 1,830 358 335 3,885 2,165
Louisiana.................... 1,673 87 -- -- 1,673 87
Maryland..................... -- -- 5,167 5,167 5,167 5,167
New York..................... 22,311 16,331 30,649 29,800 52,960 46,131
North Dakota................. 160 56 -- -- 160 56
Ohio......................... 42 21 15,404 3,852 15,446 3,873
Oklahoma..................... 127,362 81,337 6,339 2,704 133,701 84,041
Pennsylvania................. 157,683 145,265 211,956 200,600 369,639 345,865
Texas........................ 59,058 37,331 1,635 1,317 60,693 38,648
Utah......................... 280 28 -- -- 280 28
Virginia..................... 10,957 10,332 19,117 18,858 30,074 29,190
West Virginia................ 550,739 521,042 156,864 139,605 707,603 660,647
Wyoming...................... 3,043 1,147 6,141 5,541 9,184 6,688
--------- -------- -------- -------- --------- ---------
Total................... 982,482 856,308 502,059 441,946 1,484,541 1,298,254
--------- -------- -------- -------- --------- ---------
--------- -------- -------- -------- --------- ---------
International:
North Sea.................... -- -- 13,465 718 13,465 718
--------- -------- -------- -------- --------- ---------
Total................... -- -- 13,465 718 13,465 718
--------- -------- -------- -------- --------- ---------
--------- -------- -------- -------- --------- ---------

MINERAL FEE ACREAGE

State:
Colorado..................... -- -- 160 6 160 6
Kansas....................... 160 128 -- -- 160 128
New York..................... -- -- 6,545 1,636 6,545 1,636
Oklahoma..................... 16,093 14,011 -- -- 16,093 14,011
Pennsylvania................. 94 94 1,588 517 1,682 611
Texas........................ 750 532 652 326 1,402 858
West Virginia................ 76,496 63,737 57,910 56,368 134,406 120,105
--------- -------- -------- -------- --------- ---------
Total................... 93,593 78,502 66,855 58,853 160,448 137,355
--------- -------- -------- -------- --------- ---------
--------- -------- -------- -------- --------- ---------
Aggregate Total................ 1,076,075 934,810 582,379 501,517 1,658,454 1,436,327
--------- -------- -------- -------- --------- ---------
--------- -------- -------- -------- --------- ---------

9
11

TOTAL NET ACREAGE BY AREA OF OPERATION

AT DECEMBER 31, 1993
----------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ----------

Appalachian Region.................................... 758,652 469,088 1,227,740
Anadarko Region....................................... 176,158 32,429 208,587
--------- ----------- ----------
Total....................................... 934,810 501,517 1,436,327
--------- ----------- ----------
--------- ----------- ----------

PRODUCTIVE WELL SUMMARY (1)

The following table reflects the Company's ownership at December 31, 1993
in natural gas and oil wells in the Appalachian Region (consisting of various
fields located in West Virginia, Pennsylvania, New York, Ohio, Virginia and
Kentucky) and in the Anadarko Region (consisting of various fields located in
Oklahoma, Texas, Kansas, North Dakota and Wyoming).

NATURAL GAS OIL TOTAL
---------------- -------------- ----------------
GROSS NET GROSS NET GROSS NET
----- ------- ----- ----- ----- -------

Appalachian Region....................... 4,001 3,674.8 16 13.6 4,017 3,688.4
Anadarko Region.......................... 663 409.9 500 137.1 1,163 547.0
----- ------- ----- ----- ----- -------
Total.................................. 4,664 4,084.7 516 150.7 5,180 4,235.4
----- ------- ----- ----- ----- -------
----- ------- ----- ----- ----- -------

- ---------------

(1) "Productive" wells are producing wells and wells capable of production.

DRILLING ACTIVITY

The Company drilled, participated in the drilling of, or acquired wells as
set forth in the table below for the periods indicated:

YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1993(1) 1992 1991
---------------- --------------- ----------------
GROSS NET GROSS NET GROSS NET
----- ------ ----- ----- ----- ------

Appalachian Region:
Development Wells
Natural Gas........................... 117 114.5 69 62.7 106 103.0
Oil................................... 0 0.0 0 0.0 0 0.0
Dry................................... 5 5.0 3 2.5 7 7.0
Exploratory Wells
Natural Gas........................... 1 0.3 0 0.0 0 0.0
Oil................................... 0 0.0 0 0.0 0 0.0
Dry................................... 3 2.3 1 1.0 2 2.0
----- ------ ----- ----- ----- ------
Total............................ 126 122.1 73 66.2 115 112.0
----- ------ ----- ----- ----- ------
----- ------ ----- ----- ----- ------
Wells Acquired(2)
Natural Gas........................... 396 397.8 8 36.2 9 34.7
Oil................................... 6 6.0 0 0.0 0 0.0
----- ------ ----- ----- ----- ------
Total............................ 402 403.8 8 36.2 9 34.7
----- ------ ----- ----- ----- ------
----- ------ ----- ----- ----- ------
Wells in Progress
at End of Period...................... 0 0.0 1 1.0 0 0.0
(Table continued on following page)

10
12

Anadarko Region:
Development Wells
Natural Gas........................... 26 19.2 23 19.3 25 21.2
Oil................................... 5 3.6 4 4.0 0 0.0
Dry................................... 5 4.9 4 2.7 3 3.0
Exploratory Wells
Natural Gas........................... 0 0.0 1 0.5 0 0.0
Oil................................... 0 0.0 0 0.0 0 0.0
Dry................................... 0 0.0 3 2.1 1 1.0
----- ------ ----- ----- ----- ------
Total............................ 36 27.7 35 28.6 29 25.2
----- ------ ----- ----- ----- ------
----- ------ ----- ----- ----- ------
Wells Acquired(2)
Natural Gas........................... 218 106.5 2 3.7 7 7.3
Oil................................... 303 63.6 0 0.0 0 0.0
----- ------ ----- ----- ----- ------
Total............................ 521 170.1 2 3.7 7 7.3
----- ------ ----- ----- ----- ------
----- ------ ----- ----- ----- ------
Wells in Progress
at End of Period...................... 3 3.0 0 0.0 0 0.0

- ---------------

(1) At December 31, 1993, the Company had no waterfloods in the process of
installation and was not conducting any pressure maintenance operations.

(2) Includes the acquisition of net interest in certain wells in the Appalachian
Region and in the Anadarko Region in 1993, 1992 and 1991 in which the
Company already held an ownership interest.

COMPETITION

Competition in the Company's primary producing areas is intense. The
Company believes that its competitive position is affected by price, contract
terms and quality of service, including pipeline connection times, distribution
efficiencies and reliable delivery record. The Company believes that its
extensive acreage position, substantial ongoing drilling program and existing
natural gas gathering and pipeline systems and storage fields give it a
competitive advantage over certain other producers in the Appalachian Region
which do not have such systems or facilities in place. The Company also believes
that its competitive position in the Appalachian Region is enhanced by the
absence of significant competition from major oil and gas companies. The Company
also actively competes against some companies with substantially larger
financial and other resources, particularly in the Anadarko Region.

OTHER BUSINESS MATTERS

MAJOR CUSTOMER

The Company had no sales to any customer that exceeded 10% of the Company's
total revenues in 1993.

SEASONALITY

Demand for natural gas is seasonal in nature, with peak demand and
typically higher prices occurring during the colder winter months.

11
13

REGULATION OF OIL AND GAS PRODUCTION

The Company's oil and gas production and transportation operations are
subject to various types of regulation, including regulation by state and
federal agencies. Although such regulations have an impact on the Company and
others in the oil, gas and pipeline industry, the Company does not believe that
it is affected in a significantly different manner by these regulations than
others in the oil and gas industry.

Legislation affecting the oil and gas industry is under constant review for
amendment or expansion. Numerous departments and agencies, both federal and
state, are authorized by statute to issue, and have issued, rules and
regulations binding on the oil and gas industry and its individual members. The
failure to comply with such rules and regulations can result in substantial
penalties. Many states require permits for drilling operations, drilling bonds
and reports concerning operations. Many states also have statutes or regulations
addressing, conservation matters, including provisions for the utilization or
pooling of oil and gas properties, the establishment of maximum rates of
production from oil and gas wells and the regulation of spacing, plugging and
abandonment of such wells. Some state statutes and regulations limit the rate at
which oil and gas can be produced from the Company's properties.

With respect to the establishment of maximum production rates from gas
wells, certain producing states, in an attempt to limit production to market
demand, have recently adopted (Texas and Oklahoma) or are considering adopting
(Louisiana) measures that alter the methods previously used to prorate gas
production from wells located in these states. For example, the new Texas rules
provide for reliance on information filed monthly by well operators, in addition
to historical production data for the well during comparable past periods, to
arrive at an allowable. This is in contrast to historic reliance on forecasts of
upcoming takes filed monthly by purchasers of natural gas in formulating
allowable, a procedure which resulted in substantial excess allowable over
volumes actually produced. The Company cannot predict whether other states will
adopt similar or other gas prorationing procedures.

While it is still unclear how these new regulations will be administered,
the effect of these regulations could be to decrease allowable production on the
Company's properties, and thereby to decrease revenues. However, management
believes that such regulation would not have a significant impact on the
Company's revenues. By decreasing the amount of natural gas available in the
market, such regulations could also have the effect of increasing prices of
natural gas, although there can be no assurance that any such increase will
occur. The company cannot predict whether these new prorationing regulations
will be challenged in the courts or the outcome of such challenges.

The Natural Gas Act of 1938 (the "NGA") regulates the interstate
transportation and certain sales for resale of natural gas. The Natural Gas
Policy Act of 1978 (the "NGPA") regulated the maximum selling prices of certain
categories of natural gas, when sold in so-called "first sales" in interstate or
intrastate commerce and provided for phased deregulation of price controls of
the first sales of several categories of natural gas. These statutes are
administered by the FERC.

As a result of the enactment of the Natural Gas Wellhead Decontrol Act of
1989 ("Decontrol Act") on July 26, 1989, all remaining "first sales" price
regulations imposed by the NGA and NGPA terminated on January 1, 1993.

Commencing in late 1985 and early 1986, the FERC issued a series of orders
which significantly altered the marketing and pricing of natural gas. Among
other things, the new regulations require interstate pipelines that elect to
transport natural gas for others under self-implementing authority to provide
transportation services to all shippers (e.g., producers, marketers, local
distributors and end-users) on an open and non-discriminatory basis, and permit
each existing firm sales customer of such pipelines to modify, over at least a
five-year period, its existing firm purchase obligations.

12
14

Order No. 500 was issued by the FERC on August 7, 1989, in response to the
remand of Order No. 436 by the United States Court of Appeals for the District
of Columbia. Order No. 500 repromulgated most of the provisions of Order No. 436
and resulted in an almost complete affirmation of the Order No. 500 "open
access" rules, with the exception of the pregranted abandonment issue and the
use of certain types of pass through mechanisms by interstate pipelines to
recover take-or-pay costs.

In April 1992, the FERC issued Order 636, a complex regulation which is
expected to have a major impact on natural gas pipeline operations, services and
rates. Among other things, Order 636 requires each interstate pipeline company
to "unbundle" its traditional wholesale services and create and make available
on an open and nondiscriminatory basis numerous constituent services (such as
gathering services, storage services, firm and interruptible transportation
services, and stand-by sales services) and to adopt a new rate making
methodology to determine appropriate rates for those services. To the extent the
pipeline company or its sales affiliate makes gas sales as a merchant in the
future, it will do so in direct competition with all other sellers pursuant to
private contracts; however, pipeline companies are not required to remain
"merchants" of gas, and many of the interstate pipeline companies have or will
become "transporters only." On August 3, 1992, the FERC issued Order 636-A,
which largely reaffirmed Order 636 and denied a stay of the implementation of
the new rules pending judicial review. On November 27, 1992, the FERC issued
Order 636-B which uniformly upheld the requirements and regulations adopted in
Order 636 and 636-A. As a result of these events, individual so-called
"restructuring" proceedings are on-going before FERC by which each interstate
pipeline company will develop and propose particularized features and procedures
for its system to implement Order 636 requirements. These new rules are already
the subject of appeals in the United States Courts of Appeals. The Company
cannot predict whether Order 636 will be affirmed on appeal. However "open
access" transportation under Order 636 has provided the Company with the
opportunity to market gas to a wide variety of markets.

The Company's pipeline systems and storage fields are regulated for safety
compliance by the Department of Transportation, the West Virginia Public Service
Commission, the Pennsylvania Department of Natural Resources and the New York
Department of Public Service. The Company's pipeline systems in each state
operate independently and are not interconnected.

ENVIRONMENTAL REGULATIONS

The Company's operations are subject to extensive federal, state and local
laws and regulations relating to the generation, storage, handling, emission,
transportation and discharge of materials into the environment. Permits are
required for the operation of various facilities of the Company, and these
permits are subject to revocation, modification and renewal by issuing
authorities. Governmental authorities have the power to enforce compliance with
their regulations, and violations are subject to fines, injunctions or both. It
is possible that increasingly strict requirements will be imposed by
environmental laws and enforcement policies thereunder. The Company is also
subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments of
1990 which added significantly to the existing requirements established by the
Federal Clean Air Act. It is not anticipated that the Company will be required
in the near future to expend amounts that are material in relation to its total
capital expenditures program by reason of environmental laws and regulations,
but inasmuch as such laws and regulations are frequently changed, the Company is
unable to predict the ultimate cost of such compliance.

The Company owns and operates a brine treatment plant in Pennsylvania which
processes fluids generated by drilling and production operations. See
"Exploration, Development and Production -- Appalachian Region." The plant's
operations are regulated by Pennsylvania's Department of Environmental
Regulation.

13
15

EMPLOYEES

The Company had approximately 433 active employees as of December 31, 1993.
The Company believes that its relations with its employees are satisfactory. The
Company has not entered into any collective bargaining agreements with its
employees.

ITEM 2. PROPERTIES

See "Item 1. Business."

ITEM 3. LEGAL PROCEEDINGS

The Company and its subsidiaries are defendants or parties in numerous
lawsuits or other governmental proceedings arising in the ordinary course of
business. See Note 10 of the Notes to the Consolidated Financial Statements
incorporated herein by reference in Item 8 hereof for a discussion of Company
contingencies.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the
period from October 1, 1993 to December 31, 1993.

EXECUTIVE OFFICERS OF THE REGISTRANT

The following table shows certain information about the executive officers
of the Company as of March 1, 1994, as such term is defined in Rule 3b-7
promulgated under the Securities Exchange Act of 1934, as amended.

OFFICER
NAME AGE POSITION SINCE
- -------------------------- ----- ---------------------------------------------------- -------

John H. Lollar............ 55 Chairman of the Board, Chief Executive Officer and 1992
President
John U. Clarke............ 41 Executive Vice President, Chief Financial Officer 1993
Jim L. Batt............... 58 Vice President, Land 1988
Curtis P. Cook............ 51 Vice President and Regional Manager 1987
Kirk O. Kuwitzky.......... 40 Vice President, Marketing 1994
Richard T. Parrish........ 47 Vice President, Engineering 1993
James M. Trimble.......... 45 Vice President, Business Development 1987
H. Baird Whitehead........ 43 Vice President and Regional Manager 1987
Thomas L. Gage............ 57 Controller, Assistant Treasurer and Assistant 1981
Secretary
Steven W. Tholen.......... 42 Treasurer 1992
Lisa A. Machesney......... 38 Secretary 1991

With the exception of the following, all officers of the Company have been
employed by the Company for more than the last five years.

John H. Lollar joined the Company in October 1992 being elected President
and Director. In January 1994. Mr. Lollar was elected Chairman of the Board and
Chief Executive Officer. Prior to joining the Company, Mr. Lollar was President
and Chief Operating Officer of Transco Exploration and Production Company from
1982 to 1992 and Executive Vice President and Chief Operating Officer, in
addition to holding other positions, of Gulf Resources & Chemical Corporation
from 1968 to 1982.

14
16

John U. Clarke joined the Company in August 1993 as Executive Vice
President -- Chief Financial Officer and Chief Administrative Officer. Prior to
joining the Company, he was employed by Transco Energy Company from April 1981
to May 1993, most recently in the position of Senior Vice President, Chief
Financial Officer and Treasurer. Previously, he was employed by Tenneco Inc. in
the finance department.

Richard T. Parrish joined the Company in August 1993 as Vice President,
Engineering. Prior to joining the Company, Mr. Parrish was Vice President,
Engineering and Planning, for Transco Exploration and Production Company from
1977 to 1992 and Assistant District Engineer, Reservoir and Production for
Texaco, Inc. from 1974 to 1977. Prior thereto, Mr. Parrish was employed in
various engineering capacities with Texaco, Inc. from 1969 to 1974.

Kirk O. Kuwitzky joined the Company in January, 1994 as Vice President,
Marketing. Prior to joining the Company, he was employed by Enron Corp. from
1981-1993, most recently as Vice President-Marketing for Enron Gas Marketing. In
addition, he previously held various marketing positions with Enron Gas
Marketing and several positions in Enron Corp.'s law department. From 1978 until
1981, he was an attorney with Minnesota Power.

Steven W. Tholen has been Treasurer of the Company since June 1992. Prior
thereto, Mr. Tholen was Assistant Treasurer from January 1992 to June 1992 and
was Manager, Treasury Operations from May 1990 to January 1992. Prior to joining
the Company, Mr. Tholen was employed in a treasury capacity for Reading & Bates
Corporation from February 1989 to May 1990.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The Company has furnished to the Securities and Exchange Commission
pursuant to Rule 14a-3(c) an annual report to security holders for the year
ended December 31, 1993 (the "Annual Report"), that contains the information
required by Rule 14a-3. The information required by this item appears under the
caption "Price Range of Common Stock and Dividends" on page 42 of the Annual
Report, which is incorporated herein by reference, and in Note 12 of the Notes
to the Consolidated Financial Statements incorporated herein by reference in
Item 8 hereof.

15
17

ITEM 6. SELECTED HISTORICAL FINANCIAL DATA

The information required by this item appears under the caption "Selected
Historical Financial Data" on page 17 of the Annual Report and is incorporated
herein by reference.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The information required by this item appears under the caption "Financial
Review" on pages 18 through 23 of the Annual Report and is incorporated herein
by reference.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item appears on pages 24 through 43 of the
Annual Report and is incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information to be set forth under the caption "I. Election of
Directors" in the Company's definitive proxy statement ("Proxy Statement") in
connection with the 1994 annual stockholders meeting, is incorporated herein by
reference.

ITEM 11. EXECUTIVE COMPENSATION

The information appearing under the caption "II. Executive Compensation" in
the Proxy Statement is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information appearing under the caption "I. Election of Directors" in
the Proxy Statement is incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

16
18

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K

A. INDEX

PAGE REFERENCE TO
----------------------
1993
ANNUAL
1993 10-K REPORT
--------- ------

1. Consolidated Financial Statements:
Report of Independent Accountants.................................. 24
Consolidated Statement of Income................................... 25
Consolidated Balance Sheet......................................... 26
Consolidated Statement of Cash Flows............................... 27
Consolidated Statement of Stockholders' Equity..................... 28
Notes to Consolidated Financial Statements......................... 29
Supplemental Oil and Gas Information............................... 39
Quarterly Financial Information (unaudited)........................ 43
2. Financial Statement Schedules:
Report of Independent Accountants.................................. S-1
Schedule V -- Property, Plant and Equipment....................... S-2
Schedule VI -- Accumulated Depreciation, Depletion and Amortization
of Property, Plant and Equipment.................... S-3
Schedule X -- Supplemental Income Statement Information........... S-4

Other financial statement schedules have been omitted because they are
inapplicable or the information required therein is included elsewhere in the
consolidated financial statements or notes thereto.

17
19

3. EXHIBITS

The following instruments are included as exhibits to this report. Those
exhibits below incorporated by reference herein are indicated as such by the
information supplied in the parenthetical thereafter. If no parenthetical
appears after an exhibit, copies of the instrument have been included herewith.

EXHIBIT
NUMBER DESCRIPTION
- ---------------------------------------------------------------------------------------------

3.1 -- Certificate of Incorporation of the Company (Registration Statement No.
33-32553).
3.2 -- Amended and Restated Bylaws of the Company (Registration Statement No.
33-32553).
4.1 -- Form of Certificate of Common Stock of the Company (Registration Statement
No. 33-32553).
4.2 -- Certificate of Designation for Series A Junior Participating Preferred Stock
(included in Exhibit 4.3).
4.3 -- Rights Agreement dated as of March 28, 1991 between the Company and The First
National Bank of Boston, as Rights Agent, which includes as Exhibit A the
form of Certificate of Designation of Series A Junior Participating Preferred
Stock (Form 8-A, File No. 1-10477).
(a) Amendment No. 1 to Rights Plan dated February 23, 1994 (included in Exhibit
10.13).
4.4 -- Certificate of Designation for $3.125 Convertible Preferred Stock.
4.5 -- Amended and Restated Credit Agreement dated as of December 10, 1990 among the
Company, Morgan Guaranty Trust Company, as agent and the banks named therein
(Registration Statement No. 33-37455).
(a) Amendment No. 1 to Credit Agreement dated February 1, 1992 (Form 10-K for
1991).
(b) Amendment No. 2 to Credit Agreement dated May 28, 1992
(c) Amendment No. 3 to Credit Agreement dated June 1, 1993.
(d) Amendment No. 4 to Credit Agreement dated October 29, 1993.
4.6 -- Note Purchase Agreement dated May 11, 1990 among the Company and certain
insurance companies parties thereto (Form 10-Q for the quarter ended June 30,
1990).
10.1 -- Agreement dated October 1, 1981 between Cabot Oil & Gas Corporation of
Delaware and Cabot Corporation, relating to the supply of certain quantities
of gas to Cabot Corporation free of the costs of production (Registration
Statement No. 33-32553).
10.2 -- Gas Sales Agreement dated December 2, 1986 between Cabot Oil & Gas
Corporation of West Virginia and Cabot Corporation, granting Cabot
Corporation the right to purchase one-third of the gas produced by certain
wells (Registration Statement No. 33-32553).
10.3 -- Letter Agreement dated January 11, 1990 between Morgan Guaranty Trust Company
of New York and the Company.
10.4 -- Form of Annual Target Cash Incentive Plan of the Company (Registration
Statement No. 33-32553).
10.5 -- Form of Incentive Stock Option Plan of the Company (Registration Statement
No. 33-32553).
(a) First Amendment to the Incentive Stock Option Plan (Post-Effective Amendment
No. 1 to S-8 dated April 26, 1993).

18
20

EXHIBIT
NUMBER DESCRIPTION
- ---------------------------------------------------------------------------------------------

10.6 -- Form of Stock Subscription Agreement between the Company and certain
executive officers and directors of the Company (Registration Statement No.
33-32553).
10.7 -- Transaction Agreement between Cabot Corp. and the Company dated February 1,
1991 (Registration Statement No. 33-37455).
10.8 -- Tax Sharing Agreement between Cabot Corp. and the Company dated February 1,
1991 (Registration Statement No. 33-37455).
10.9 -- Amendment Agreement (amending the Transaction Agreement and the Tax Sharing
Agreement) dated March 25, 1991. (incorp. by ref. from Cabot Corp.'s Schedule
13E-4, Am. No. 6, File No. 5-30636).
10.10 -- Savings Investment Plan & Trust Agreement of the Company (Form 10-K for
1991).
(a) First Amendment to the Savings Investment Plan & Trust Agreement dated May
21, 1993 (Form S-8 dated November 1, 1993)
(b) Second Amendment to the Savings Investment Plan & Trust Agreement dated May
21, 1993 (Form S-8 dated November 1, 1993)
10.11 -- Supplemental Executive Retirement Agreements of the Company (Form 10-K for
1991).
10.12 -- Settlement Agreement and Mutual Release (Tax Issues) between Cabot Corp. and
the Company dated July 7, 1992 (Form 10-Q for the quarter ended June 30,
1992).
10.13 -- Agreement of Merger dated February 25, 1994 among Washington Energy Company,
Washington Energy Resources Company, the Company and COG Acquisition Company.
10.14 -- 1990 NonEmployee Director Stock Option Plan of the Company (Form S-8 dated
June 23, 1990).
(a) First Amendment to 1990 NonEmployee Director Stock Option Plan (Post-
Effective Amendment No 2 to Form S-8 dated March 7, 1994).
13 -- Annual Report to stockholders for its fiscal year ending December 31, 1993 is
included as an exhibit to this report for the information of the Securities
and Exchange Commission and except for those portions thereof specifically
incorporated by reference elsewhere herein, such Annual Report should not be
deemed filed as a part of this report.
21.1 -- Subsidiaries of Cabot Oil & Gas Corporation.
23.1 -- Consent of Coopers & Lybrand.
23.2 -- Consent of Miller and Lents, Ltd.
28.1 -- Miller and Lents, Ltd. Review Letter dated February 11, 1994.

B. REPORTS ON FORM 8-K

(1) Form 8-K/A, Amendment No. 1 to Current Report, dated September 30, 1993.
Filed on November 15, 1993.

(2) Form 8-K/A, Amendment No. 2 to Current Report, dated September 30, 1993.
Filed on December 14, 1993.

19
21

SIGNATURES

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, in the City of Houston, State of Texas,
on the 25th day of February 1994.

CABOT OIL & GAS CORPORATION

By: /s/ JOHN H. LOLLAR
John H. Lollar,
Chairman of the Board and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons in the capacities and on
the dates indicated.

SIGNATURE TITLE DATE
- --------------------------------------------- --------------------------- ------------------

/s/ JOHN H. LOLLAR Chairman of the Board and February 25, 1994
John H. Lollar President
/s/ JOHN U. CLARKE Executive Vice President, February 25, 1994
John U. Clarke Chief Financial Officer
and Administrative
Officer
/s/ THOMAS L. GAGE Controller, Assistant February 25, 1994
Thomas L. Gage Treasurer and Assistant
Secretary
/s/ SAMUEL W. BODMAN Director February 25, 1994
Samuel W. Bodman
/s/ HENRY O. BOSWELL Director February 25, 1994
Henry O. Boswell
/s/ PHILIP J. BURGUIERES Director February 25, 1994
Philip J. Burguieres
/s/ JOHN G. L. CABOT Director February 25, 1994
John G. L. Cabot
/s/ WILLIAM R. ESLER Director February 25, 1994
William R. Esler
/s/ WILLIAM H. KNOELL Director March 8, 1994
William H. Knoell
/s/ CARL M. MUELLER Director February 25, 1994
Carl M. Mueller
/s/ C. WAYNE NANCE Director February 25, 1994
C. Wayne Nance
/s/ CHARLES P. SIESS, JR. Director February 25, 1994
Charles P. Siess, Jr.

20
22

REPORT OF INDEPENDENT ACCOUNTANTS
ON FINANCIAL STATEMENT SCHEDULES

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

Our report on the consolidated financial statements of Cabot Oil & Gas
Corporation has been incorporated by reference in this Form 10-K from page 24 of
the 1993 Annual Report to Stockholders. In connection with our audits of such
financial statements, we have also audited the related financial statement
schedules listed in the index on page 17 of this Form 10-K.

In our opinion, the financial statement schedules referred to above, when
considered in relation to the basic financial statements taken as a whole,
present fairly, in all material respects, the information required to be
included therein.

COOPERS & LYBRAND

Houston, Texas
February 25, 1994

S-1
23

SCHEDULE V

CABOT OIL & GAS CORPORATION

PROPERTY, PLANT AND EQUIPMENT
(DOLLARS IN THOUSANDS)

OTHER
BALANCE AT CHANGES BALANCE
BEGINNING ADDITIONS RETIREMENTS ADD AT END
CLASSIFICATION OF PERIOD AT COST OR SALES (DEDUCT) OF PERIOD
- -------------------------------------- ---------- --------- ----------- -------- ---------

December 31, 1993
Unproved oil and gas properties..... $ 12,485 $ 3,902 $ (4,035) $ (75) $ 12,277
Proved oil and gas properties....... 432,880 115,145 (15,017) 102 533,110
Gathering and pipeline systems...... 127,595 6,656 (13) 24 134,262
Land, buildings and improvements.... 5,580 2,414 (618) -- 7,376
Other............................... 10,872 880 (147) (51) 11,554
---------- --------- ----------- -------- ---------
$ 589,412 $ 128,997 $ (19,830) $ -- $ 698,579
---------- --------- ----------- -------- ---------
---------- --------- ----------- -------- ---------
December 31, 1992
Unproved oil and gas properties..... $ 15,233 $ 1,840 $ (4,070) $ (518) $ 12,485
Proved oil and gas properties....... 406,965 21,712 (1,851) 6,054 432,880
Gathering and pipeline systems...... 118,199 8,214 (69) 1,251 127,595
Land, buildings and improvements.... 5,406 174 -- -- 5,580
Other............................... 7,556 5,026 (464) (1,246) 10,872
---------- --------- ----------- -------- ---------
$ 553,359 $ 36,966 $ (6,454) $ 5,541(1) $ 589,412
---------- --------- ----------- -------- ---------
---------- --------- ----------- -------- ---------
December 31, 1991
Unproved oil and gas properties..... $ 18,449 $ 2,610 $ (5,299) $ (527) $ 15,233
Proved oil and gas properties....... 382,800 30,410 (7,038) 793 406,965
Gathering and pipeline systems...... 108,684 11,196 (1,422) (259) 118,199
Land, buildings and improvements.... 5,024 382 -- -- 5,406
Other............................... 6,109 1,496 (42) (7) 7,556
---------- --------- ----------- -------- ---------
$ 521,066 $ 46,094 $ (13,801) $ -- $ 553,359
---------- --------- ----------- -------- ---------
---------- --------- ----------- -------- ---------

- ---------------

(1) Includes a reclassification to accumulated depreciation, depletion and
amortization (Schedule VI).

S-2
24

SCHEDULE VI

CABOT OIL & GAS CORPORATION

ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
(DOLLARS IN THOUSANDS)

December 31, 1993
Unproved oil and gas properties..... $ 5,988 $ 2,834 $ (4,028) $ -- $ 4,794
Proved oil and gas properties....... 209,599 22,874 (14,084) 43 218,432
Gathering and pipeline systems...... 59,990 6,646 (1) -- 66,635
Land, buildings and improvements.... 3,026 445 (578) -- 2,893
Other............................... 4,086 1,656 (144) (43) 5,555
---------- --------- ----------- -------- ---------
$ 282,689 $ 34,455 $ (18,835) $ -- $ 298,309
---------- --------- ----------- -------- ---------
---------- --------- ----------- -------- ---------
December 31, 1992
Unproved oil and gas properties..... $ 6,502 $ 3,575 $ (4,060) $ (29) $ 5,988
Proved oil and gas properties....... 186,159 19,952 (2,096) 5,584 209,599
Gathering and pipeline systems...... 52,400 6,571 (69) 1,088 59,990
Land, buildings and improvements.... 2,593 433 -- -- 3,026
Other............................... 4,639 1,010 (461) (1,102) 4,086
---------- --------- ----------- -------- ---------
$ 252,293 $ 31,541 $ (6,686) $ 5,541(1) $ 282,689
---------- --------- ----------- -------- ---------
---------- --------- ----------- -------- ---------
December 31, 1991
Unproved oil and gas properties..... $ 8,507 $ 2,650 $ (5,256) $ 601 $ 6,502
Proved oil and gas properties....... 174,805 17,328 (5,351) (623) 186,159
Gathering and pipeline systems...... 47,530 6,124 (1,283) 29 52,400
Land, buildings and improvements.... 2,171 422 -- -- 2,593
Other............................... 3,984 675 (13) (7) 4,639
---------- --------- ----------- -------- ---------
$ 236,997 $ 27,199 $ (11,903) $ -- $ 252,293
---------- --------- ----------- -------- ---------
---------- --------- ----------- -------- ---------

- ---------------

(1) Includes a reclassification to accumulated depreciation, depletion and
amortization (Schedule VI).

(2) Accumulated depreciation, depletion and amortization of property, plant and
equipment includes a reserve for dismantlement, restoration and abandonment
of proved oil and gas properties. Accordingly, actual expenditures will
result in a retirement on Schedule VI without any corresponding retirement
on Schedule V.

S-3
25

SCHEDULE X

CABOT OIL & GAS CORPORATION

SUPPLEMENTAL INCOME STATEMENT INFORMATION
(DOLLARS IN THOUSANDS)

YEAR ENDED DECEMBER 31,
-------------------------------
1993 1992 1991
------- ------- -------

Item
Charged to Costs and Expenses:
Maintenance and repairs................................... $ 6,267 $ 4,490 $ 4,467
Taxes other than payroll and income taxes:
Real estate and personal property......................... $ 2,550 $ 2,041 $ 2,297
Severance and production.................................. $ 4,932 $ 3,758 $ 2,873

S-4