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)
- ---------------
(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.
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
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
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
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.
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.
- ---------------
(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.
THREE-YEAR RESERVES
The following table sets forth certain information regarding the Company's estimated proved reserves for the periods indicated.
- ---------------
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.
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.
- ---------------
(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.
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
MINERAL FEE ACREAGE
TOTAL NET ACREAGE BY AREA OF OPERATION
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).
- ---------------
(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:
- ---------------
(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.
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.
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.
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.


ITEM 2. PROPERTIES
See "Item 1. Business."
ITEM 3.
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.
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.
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.
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.
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.
ITEM 6.
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.
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.

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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10.


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.
ITEM 11. EXECUTIVE COMPENSATION
The information appearing under the caption "II. Executive Compensation" in the Proxy Statement is incorporated herein by reference.
ITEM 12.
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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES AND REPORTS ON FORM 8-K
A. INDEX
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.
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.
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.
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.
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
SCHEDULE V
CABOT OIL & GAS CORPORATION
PROPERTY, PLANT AND EQUIPMENT (DOLLARS IN THOUSANDS)
- ---------------
(1) Includes a reclassification to accumulated depreciation, depletion and amortization (Schedule VI).
S-2
SCHEDULE VI
CABOT OIL & GAS CORPORATION
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT (DOLLARS IN THOUSANDS)
- ---------------
(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
SCHEDULE X
CABOT OIL & GAS CORPORATION
SUPPLEMENTAL INCOME STATEMENT INFORMATION (DOLLARS IN THOUSANDS)
S-4