Annual Report (Form 10-K), fiscal year 1994

ITEM 1. BUSINESS
GENERAL
Cabot Oil & Gas Corporation (the "Company") explores for, develops, produces, purchases, 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 Western Region, including the Anadarko Basin of southwestern Kansas, Oklahoma and the Texas Panhandle, in the Green River Basin of Wyoming and South Texas. At December 31, 1994, the Company had 1,001.3 Bcfe of total proved reserves, 95% 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 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, 1994, 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, 1994. For additional information regarding the Company's estimates of proved reserves and other data, see "Business -- Reserves", and the 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, including properties located in Anadarko, the Rocky Mountains and the Gulf Coast areas.
EXPLORATION, DEVELOPMENT AND PRODUCTION
The Company is one of the largest producers of natural gas in the Appalachian basin, where it has conducted operations for more than a century. The Company has had operations in the Anadarko basin for over 50 years. The Company acquired its operations in the Rocky Mountains and the Gulf Coast pursuant to the merger of Washington Energy Resources Company with the Company which was completed in May of 1994. Historically, the Company has maintained its reserve base through low-risk development drilling and strategic acquisitions. The Company continues to focus its operations in the Appalachian and Western Regions through development of undeveloped reserves and acreage, acquisition of oil and gas producing properties and, to a lesser extent, exploration.
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, 1994, the Company had approximately 562 Bcfe of proved reserves (substantially all natural gas) in the Appalachian Region, constituting 56% of the Company's total proved reserves.
The Company has 4,125 productive wells (3,779.2 net) of which 4,022 wells are operated by the Company. There are multiple producing intervals which include the Medina, Berea, and Big Lime trend formations at depths primarily ranging from 1,500 to 6,000 feet. Average net daily production in 1994 was 8l.6 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.
In 1994, the Company drilled 142 wells (135.2 net) in the Appalachian Region, of which 140 were development wells (134.7 net). Capital and exploration expenditures, including pipeline expenditures for the year were approximately 49.6 million. In the 1995 drilling program year, the Company has plans to drill 11.9 net wells.
During 1995, the Company intends to curtail development activity in Appalachia to focus on higher potential return opportunities in the Western Region.
At December 31, 1994, the Company had 1,141,930 million net acres in the region, including 758,238 net developed acres.
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 in the Appalachian Region because of its large acreage position, its high concentration of wells, its natural gas gathering and pipeline systems and its storage capacity.
WESTERN REGION
On January 26, 1995, the Company announced that it intended to consolidate the management of its non-Appalachian holdings (Anadarko, Rocky Mountains and Gulf Coast) into a single Western Region. This allows the Company to reduce regional office and administrative costs, improve operating effectiveness and better control the capital allocation process. Operations for the Western Region will be managed from a regional office in Denver.
The Company's exploration, development and production activities in the Western Region are primarily focused in the Anadarko basin in Kansas, Oklahoma and the Panhandle of Texas, in the Green River Basin of Wyoming and in South Texas. At December 31, 1994, the Company had approximately 439.8 Bcfe of proved reserves (89.3% natural gas) in the Western Region, constituting 44% of the Company's total proved reserves.
Anadarko
The Company has 991 productive wells (549.2 net) in Anadarko of which 684 wells are operated by the Company. Principal producing intervals in Anadarko are in the Chase, Chester and Morrow formations at depths ranging from 1,500 to 11,000 feet. Average net daily production in 1994 was 56.3 MMcfe.
In 1994, the Company drilled 34 wells (25.3 net) in Anadarko (32 development wells, 24.8 net). Capital and exploration expenditures for the year were $49.6 million. In the 1995 drilling program year, the Company currently has plans to drill 3.3 net wells.
At December 31, 1994, the Company had 207,443 net acres in Anadarko, including approximately 181,428 net developed acres. At year end, the Company had identified 56.4 net proved undeveloped drilling locations.
Washington Energy Resources Company Acquisition
On May 2, 1994, the Company completed the merger between a Company subsidiary and Washington Energy Resources Company ("WERCO"), formerly a subsidiary of Washington Energy Company. The Company acquired the stock of WERCO in a tax-free exchange. The Company issued 2,133,000 shares of common stock and 1,134,000 shares of 6% convertible redeemable preferred stock ($50 per share stated value) to Washington Energy Company in exchange for the capital stock of WERCO. In addition, the Company advanced cash to repay intercompany indebtedness between WERCO and Washington Energy Company of $63.7 million.
Exploration, development and production activities acquired from WERCO are located primarily in the Green River Basin in Wyoming (Rocky Mountains). At December 31, 1994, the Rocky Mountains accounted for approximately 172 Bcfe of proved reserves (82% natural gas), constituting 17% of the Company's total proved reserves.
The Company has 461 productive wells (110.6 net) in the Rocky Mountains of which 125 are operated by the Company. Principal producing formations are the Frontier and the Dakota at depths ranging from 10,000 to 14,000 feet. Average net daily production in 1994 was 34.1 MMcfe.
In 1994, the Company drilled 21 wells (6.8 net) in the Rocky Mountains. Capital and exploration expenditures for the year, excluding the WERCO acquisition cost, were approximately $8.4 million. In the 1995 drilling program year, the Company currently has plans to drill 4.5 net wells.
At December 31, 1994, the Company had approximately 206,700 net acres in the Rocky Mountains, including 41,136 net developed acres. At year end, the Company had identified 13.3 net proved undeveloped drilling locations.
In addition, as part of the WERCO transaction, the Company acquired certain assets in South Texas (the Gulf Coast). The Company expects that the Gulf Coast area will have significant growth potential in exploration and development. At December 31, 1994 the Gulf Coast area accounted for approximately 22.6 Bcfe of proved reserves (75 % natural gas), constituting 2% of the Company's total proved reserves. The Company is primarily drilling in the Wilcox and Vicksburg formations.
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 risk management expertise, the Company provides a menu of services that includes gas supply management, short and long-term supply contracts, capacity brokering and risk management alternatives. Sales volumes grew substantially in 1994 as the Company increased the amount of natural gas purchased for resale. This increase was primarily due to an increase in gas purchased from producers and marketers in the Gulf of Mexico that was then transported and sold using the Company's Appalachian pipeline system. Volumes purchased and sold in this manner increased from approximately 6 Bcf in 1993 to approximately 16 Bcf in 1994.
The marketing of natural gas has changed significantly as a result of Order 636 ("Order 636"), which was issued by the Federal Energy Regulatory Commission in 1992. Order 636 required 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. Order 636 has had the effect of creating greater competition in the industry and it has also provided the Company the opportunity to reach broader markets. In 1993 and 1994, there was both an increase in the number of third-party producers that use the Company to market their gas. In addition, the Company has experienced, as a result of Order 636, increased competition for markets which has placed pressure on margins.
APPALACHIAN REGION
The Company's principal markets for its Appalachian Region natural gas are in the northeastern United States. The Company's marketing subsidiary purchases all of the Company's natural gas production in the Appalachian Region as well as production from local third-party producers and other suppliers to aggregate larger volumes of natural gas for resale. This marketing subsidiary sells natural gas to industrial customers, local distribution companies and gas marketers both on and off the Company's pipeline system.
A majority of the Company's natural gas sales volume in the Appalachian Region is being sold at market responsive prices under contracts with a term of one year or less. Of these short term sales, spot market sales are made under month-to-month contracts while industrial and utility sales generally are made under year-to-year contracts. Approximately 40% of the Appalachian production is sold on fixed price contracts which typically renew annually.
The Company's Appalachian production is generally sold at a premium price to production from 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 and Order 636.
The Company operates a number of gas gathering and pipeline systems, made up of approximately 3,600 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 pipeline and compressor additions to its system.
The Company has two natural gas storage fields located in West Virginia, with a combined working capacity of approximately 4 Bcf of natural gas. 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 production at a nearly constant rate throughout the year. The storage fields also enable the Company to periodically increase 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.
WESTERN REGION
The Company's principal markets for Western Region natural gas are in the northwestern and midwestern United States. The Company's marketing subsidiaries purchase all of the Company's natural gas production in the Western Region. These marketing subsidiaries sell the natural gas to natural gas processors, LDCs, industrial customers and marketing companies.
Currently, a majority of the Company's natural gas production in the Western Region is being sold primarily under contracts with a term of one year or less at market-responsive prices. Approximately 20% of the Western Region's production is sold under a 14-year cogeneration contract under which the price escalates at 5% per year. The Western Region properties are connected to the majority of the midwestern and northwestern interstate pipelines, affording the Company access to multiple markets.
RISK MANAGEMENT
In 1994, the Company entered into certain price swap transactions to manage price risks associated with the purchase and sale of natural gas. The Company utilized certain natural gas price swap agreements ("price swaps") to attempt to manage price risk more effectively and improve the Company's realized natural 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 5,875,000 MMbtu of natural gas at December 31, 1994. The Company plans to continue this strategy in the future.
RESERVES CURRENT RESERVES
The Company's drilling program, combined with the WERCO Acquisition created a 21% increase in proved reserves. The following table sets forth information regarding the Company's estimates of its net proved reserves at December 31, 1994.
(1) Liquids include crude oil, condensate and natural gas liquids (NGL). (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. (3) Includes proved reserves attributable to Anadarko, Rocky Mountains and the Gulf Coast areas.
The reserve estimates presented herein were prepared by the Company's petroleum engineering staff and audited 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 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 natural 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, 1994.
There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company, and, therefore, the reserve information set forth in this Form 10-K is estimated. 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 were 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.
HISTORICAL RESERVES
The following table sets forth certain information regarding the Company's estimated proved reserves for the periods indicated.
(1) For the years ended December 31, 1991, 1992 and 1993 the Western reserves are attributable to Anadarko only.
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.
APP = Appalachian Region WEST = Western Region (1)
VOLUMES AND PRICES; PRODUCTION COSTS
The following table sets forth historical information regarding the Company's sales and production volumes and average sales prices received for, and average production costs associated with, its sales of natural gas and crude oil, condensate and natural gas liquids (NGL) for the periods indicated.
(1) Equal to the aggregate of production and the net changes in storage and exchanges. (2) Includes information regarding Anadarko, Rocky Mountains and Gulf Coast for the year ended December 31, 1994; includes Anadarko only for the years ended December 31, 1992 and 1993. (3) Represents the average sales prices for all volumes (including royalty volumes) sold by the Company during the periods shown. (4) Production costs include direct lifting costs (labor, repairs, 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 applicable 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, 1994. 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 Average
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, 1994 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 Western Region (consisting of various fields located in Louisiana, Oklahoma, Texas, Kansas, North Dakota, Utah, Colorado, Wyoming and Canada).
(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) Includes the acquisition of net interest in certain wells in the Appalachian Region and in the Western Region in 1994, 1993 and 1992 in which the Company already held an ownership interest. (2) The years ended December 31, 1992 and 1993 included information for Anadarko only.
COMPETITION
The Company has experienced significant competition in its primary producing areas. The Company actively competes against some companies with substantially larger financial and other resources, particularly in the Western Region. 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 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.
OTHER BUSINESS MATTERS
MAJOR CUSTOMER
The Company had no sales to any customer that exceeded 10% of the Company's total revenues in 1994.
SEASONALITY
Demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices occurring during the colder winter months.
REGULATION OF OIL AND NATURAL 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.
With respect to the establishment of maximum production rates from natural 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 allowables, a procedure which resulted in substantial excess allowables over volumes actually produced. The Company cannot predict whether other states will adopt similar or other procedures for prorating gas production.
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 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 regulations for rationing gas production will be challenged in the courts or what the outcome of such challenges would be.
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") regulates the maximum selling prices of certain categories of natural gas, when sold in so-called "first sales" in interstate or intrastate commerce, and provides for phased deregulation of price controls of the first sales of several categories of natural gas. These statutes were administered by the Federal Energy Regulatory Commission ("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 but added certain other provisions primarily intended to address take-or-pay contract claims.
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, under Order 636 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 Order 636-A. As a result of these events, individual so-called "restructuring" proceedings are ongoing before the FERC whereby 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 several appeals in the United States Courts of Appeals and to additional action by the FERC. 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 sell 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 Amendment 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 material amounts in relation to its total capital expenditures program by reason of environmental laws and regulations. Because such laws and regulations are frequently changed however, 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 "Business -- Exploration, Development and Production -- Appalachian Region". The plant's operations are regulated by Pennsylvania's Department of Environmental Regulation.
EMPLOYEES
The Company had approximately 495 active employees as of December 31, 1994. The Company believes that its relations with its employees are satisfactory. The Company has not entered into any collective bargaining agreements with its employees.
OTHER
The Company's profitability depends on certain factors that are beyond its control, such as natural gas and crude oil prices. The nature of the oil and gas business involves a variety of risks, including the risk of experiencing certain operating hazards such as fires, explosions, blowouts, cratering, oil spills and encountering formations with abnormal pressures, the occurrence of any of which could result in substantial losses to the Company. The operation of the Company's natural gas gathering and pipeline systems also involves certain risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The proximity of pipelines to populated areas, including residential areas, commercial business centers and industrial sites, could exacerbate such risks. At December 31, 1994, the Company owned or operated approximately 3,600 miles of natural gas gathering and pipeline systems. The Company has identified certain segments of its pipelines which it believes require repair, replacement or additional maintenance. For additional information regarding such segments, see "Business -- Gas Marketing -- Appalachian Region." In accordance with customary industry practices, the Company maintains insurance against some, but not all, of such risks.
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, 1994 to December 31, 1994.
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, 1994 (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 41 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 to 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 16 of the Annual Report and is incorporated herein by reference.
ITEM 7.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS.
The information required by this item appears under the caption "Financial Review" on pages 17 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 41 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 "1. Election of Directors" in the Company's definitive proxy statement ("Proxy Statement") in connection with the 1995 annual stockholders meeting, is incorporated herein by reference.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about the executive officers of the Company as of March 1, 1995, as such term is defined in Rule 3b-7 promulgated under the Securities Exchange Act of 1934.
(1) Mr. Kuwitzky's employment with the Company was terminated effective March 9, 1995 due to a Company-wide reduction in force program.
With the exception of the following, all executive officers of the Company have been employed by the Company and Cabot Corporation prior to the initial public offering in 1990.
John H. Lollar joined the Company in October 1992 being elected President and Director. In January 1993, 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.
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 held various marketing positions with Enron Gas Marketing and several positions in Enron Corporation's law department. From 1978 until 1981, he was an attorney with Minnesota Power.
Gerald F. Reiger joined the Company in May 1994 as Regional Manager, Rocky Mountains. Prior to joining COG, Mr. Reiger managed the Rocky Mountain Region for Washington Energy Resources Company from 1992 to 1994. Previously he was U.S. Operations Manager for DEKALB Energy Company from 1979 to 1992.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION.
The information appearing under the caption "11. 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 "1. 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 AND REPORTS ON FORM 8-K.
2. 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
None
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 8th day of March 1995.
CABOT OIL & GAS CORPORATION
By: /s/ John H. Lollar -------------------------- John H. Lollar Chairman of the Board and Chief Executive Officer
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.