ITEM 1. BUSINESS
OVERVIEW
Cabot Oil & Gas is an independent oil and gas company engaged in the exploration, development, acquisition and exploitation of oil and gas properties located in four areas of the United States:
- The onshore Texas and Louisiana Gulf Coast - The Rocky Mountains - Appalachia - The Mid-Continent or Anadarko Basin
Administratively, we operate in three regions - the Gulf Coast region, the Western region, which is comprised of the Rocky Mountains and Mid-Continent areas, and the Appalachian region.
Our asset base combines the opportunity for production and reserve growth from shorter life, higher margin properties with a core of stable, long-lived reserves. Since our initial public offering in 1990, when our reserves were located only in the longer-lived, lower-growth Appalachian and Mid-Continent areas, we have acquired two new core areas that we believe have higher growth potential - the onshore Gulf Coast and the Rocky Mountains - and we have divested certain non-strategic properties, primarily in Appalachia. As a result, we have focused our capital budget on projects that we believe have more favorable risk/reward potential. We deploy the relatively stable excess cash flows from our Appalachian and Mid-Continent properties to fund activities in our higher growth, higher rate of return areas of the Gulf Coast and the Rocky Mountains.
As of December 31, 1999, our proved reserves totaled 978.7 Bcfe, and natural gas comprised 95% of our reserves. We operate approximately 83% of the wells in which we have an interest. Despite the second and third quarter divestiture of non-strategic properties producing 13.5 Mmcfe per day primarily in Appalachia, our average daily net production for 1999 was 195.3 Mmcfe per day, an increase of 4% over 1998. Exploration and exploitation success in the Gulf Coast region has largely accounted for the production increase. Production from the region rose 60% for 1999 compared to 1998, with average daily volumes from the region increasing from 32.6 Mmcfe per day to 52.0 Mmcfe per day. The following table presents certain information as of December 31, 1999.
- ---------- (1) Reserve Life Index is equal to year-end reserves divided by annual production.
GULF COAST. Our Gulf Coast activities are concentrated in south Louisiana and south Texas. Principal producing intervals are in the Wilcox and Vicksburg formations in Texas and the Miocene age formations in Louisiana. Capital expenditures were $36.8 million in 1999, or 42% of our total 1999 capital expenditures and $128.7 million for 1998, which included a $70.1 million acquisition in southern Louisiana from Oryx Energy Company. Our drilling and acquisition program has increased average daily production in the region from 15.6 Mmcfe per day in 1994, when we acquired our first Gulf Coast properties from Washington Energy, to 52.0 Mmcfe per day in 1999. For 2000, we have budgeted $49.8 million (57% of our total 2000 capital budget) for capital expenditures in the region.
ROCKY MOUNTAINS. Our Rocky Mountains activities are concentrated in the Green River Basin of Wyoming. Since our initial acquisition in the region in 1994 from Washington Energy, we have increased reserves from 171.6 Bcfe at December 31, 1994, to 257.7 Bcfe at December 31, 1999. Capital expenditures, including $17.4 million in property acquisitions, were $29.5 million for 1999, or 33% of our total 1999 capital expenditures and $32.3 million for 1998. For 2000, we have budgeted $20.0 million (23% of our total 2000 capital budget) for capital expenditures in the region.
MID-CONTINENT. Our Mid-Continent activities are concentrated in the Anadarko Basin in southwestern Kansas, Oklahoma and the panhandle of Texas. Capital expenditures were $4.1 million for 1999, or 5% of our total 1999 capital expenditures and $20.2 million for 1998. For 2000, we have budgeted $1.8 million (2% of our total 2000 capital budget) for capital expenditures in the region.
APPALACHIA. Our Appalachian activities are concentrated in Pennsylvania, Ohio, West Virginia and Virginia. We believe that our large undeveloped acreage position, high concentration of wells, natural gas gathering and pipeline systems, and storage capacity give us a competitive advantage in the region. We have achieved a drilling success rate of 89% in the region since 1991. Capital expenditures were $14.6 million for 1999, or 17% of our total 1999 capital expenditures and $43.2 million for 1998. For 2000, we have budgeted $16.0 million (18% of our total 2000 capital budget) for capital expenditures in the region.
EXPLORATION, DEVELOPMENT AND PRODUCTION
Cabot Oil & Gas is one of the largest producers of natural gas in the Appalachian Basin, where we have operated for more than a century. We have operated in the Anadarko Basin (Mid-Continent) for more than 60 years. Our Rocky Mountains and Gulf Coast activities were added with the acquisition of Washington Energy Resources Company in 1994.
GULF COAST REGION
Our exploration, development and production activities in the Gulf Coast region are concentrated in south Louisiana and south Texas. A regional office in Houston manages operations. At December 31, 1999, we had 123.9 Bcfe of proved reserves (77.8% natural gas) in the Gulf Coast region, constituting 13% of our total proved reserves.
We had 367 productive wells (264.1 net) in the Gulf Coast region as of December 31, 1999, of which 220 wells are operated by us. Principal producing intervals in the Gulf Coast are in the Wilcox and Vicksburg formations in Texas, and Miocene age formations in Louisiana at depths ranging from 3,000 to 18,000 feet. Average net daily production in 1999 was 52.0 Mmcfe.
In 1999, we drilled 16 wells (10.3 net) in the Gulf Coast region, of which 13 wells (9.2 net) were development wells. Capital and exploration expenditures for the year were $36.8 million. Our most significant discovery occurred in the first well drilled on the south Louisiana Etouffee prospect, a project in which we have a 33% working interest. At year end, this field had 17.1 Bcfe of net proved reserves. Production is expected to commence on the first well in Etouffee during March 2000. The Gulf Coast region plans to drill 24 wells and spend 57% of our $88.9 million capital budget in 2000.
At December 31, 1999, we had 113,716 net acres in the region, including 50,746 net developed acres. At the end of 1999, we had identified 17 proved undeveloped drilling locations.
WESTERN REGION
Our exploration, development and production activities in the Western region are primarily focused in the Rocky Mountains within the Green River Basin of Wyoming and in the Mid-Continent within the Anadarko Basin in southwestern Kansas, Oklahoma and the panhandle of Texas. A regional office in Denver manages the operations. At December 31, 1999, we had 471.0 Bcfe of proved reserves (96.0% natural gas) in the Western region, constituting 48% of our total proved reserves.
ROCKY MOUNTAINS. We had 469 productive wells (210.1 net) in the Rocky Mountains area as of December 31, 1999, of which 225 wells are operated by us. Principal producing intervals in the Rocky Mountains area are in the Frontier and Dakota formations at depths ranging from 9,000 to 13,000 feet. Average net daily production in 1999 was 48.6 Mmcfe.
In 1999, we drilled 19 wells (10.4 net) in the Rocky Mountains, of which 18 wells (9.4 net) were development and extension wells. Capital and exploration expenditures for the year were $29.5 million. In 2000, we plan to drill 45 wells and spend 23% of our capital budget in this area.
At December 31, 1999, we had 142,192 net acres in the area, including 75,062 net developed acres. At the end of 1999, we had identified 83 proved undeveloped drilling locations.
MID-CONTINENT. As of December 31, 1999, we had 661 productive wells (433.5 net) in the Mid-Continent area, of which 491 wells are operated by us. Principal producing intervals in the Mid-Continent are in the Chase, Morrow, Red Fork and Chester formations at depths ranging from 1,500 to 13,000 feet. Average net daily production in 1999 was 37.2 Mmcfe.
In 1999, we drilled four wells (1.2 net) in the Mid-Continent, of which three wells (0.8 net) were development and extension wells. Capital and exploration expenditures for the year were $4.1 million. In 2000, we plan to drill four wells and spend 2% of our capital budget in this area.
At December 31, 1999, we had 204,966 net acres in the area, including 180,352 net developed acres. At the end of 1999, we had identified 67 proved undeveloped drilling locations.
APPALACHIAN REGION
Our exploration, development and production activities in the Appalachian region are concentrated in Pennsylvania, Ohio, West Virginia and Virginia. A regional office in Pittsburgh manages operations. At December 31, 1999, we had 383.8 Bcfe of proved reserves (substantially all natural gas) in the Appalachian region, constituting 39% of our total proved reserves.
At December 31, 1999, we had 2,270 productive wells (2,105.8 net), of which 2,187 wells are operated by us. There are multiple producing intervals that include the Devonian Shale, Oriskany, Berea and Big Lime formations at depths primarily ranging from 1,500 to 9,000 feet. Average net daily production in 1999 was 57.4 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 1999, we drilled 34 wells (23.5 net) in the Appalachian region, of which 27 wells (19.5 net) were development wells. Capital and exploration expenditures, including pipeline expenditures, were $14.6 million for the year. In 2000, we plan to drill 38 wells and spend 18% of our capital budget in this region.
At December 31, 1999, we had 1,042,196 net acres in the region, including 745,346 net developed acres. At the end of 1999, we had identified 216 proved undeveloped drilling locations.
We own and operate two natural gas storage fields in West Virginia with a combined working gas capacity of 4 Bcf.
Ancillary to our exploration and production operations, we own and operate two brine treatment plants that process and treat waste fluid generated during the drilling, completion and production of oil and gas wells. The first plant, near Franklin, Pennsylvania, began operating in 1985. It provides services primarily to other oil and gas producers in southwestern New York, eastern Ohio and western Pennsylvania. In April 1998, we acquired a second brine treatment plant in Indiana, Pennsylvania that had been in existence since 1987.
We believe that we gain operational efficiency in the Appalachian region because of our large acreage position, high concentration of wells, contiguous natural gas gathering and pipeline systems and storage capacity.
GAS MARKETING
We are engaged in a wide array of marketing activities offering our customers long-term, reliable supplies of natural gas. Utilizing our pipeline and storage facilities, gas procurement ability and transportation and natural gas risk management expertise, we provide a menu of services that includes gas supply and transportation management, short-term and long-term supply contracts, capacity brokering and risk management alternatives.
The marketing of natural gas has changed significantly as a result of FERC Order 636, which was issued by the Federal Energy Regulatory Commission (FERC) in 1992. FERC Order 636 required pipelines to unbundle their gas sales, storage and transportation services. As a result, local distribution companies and end-users separately contract these services from gas marketers and producers. FERC Order 636 has had the effect of creating greater competition in the industry while also providing us the opportunity to serve broader markets. Since FERC Order 636 was issued, there has been an increase in the number of third-party producers that use us to market their gas. Additionally, as a result of FERC Order 636, we have experienced increased competition for markets, which has placed pressure on the premiums we have received.
GULF COAST REGION
Our principal markets for Gulf Coast region natural gas are in the industrialized Gulf Coast areas and the northeastern United States. Our marketing subsidiary, Cabot Oil & Gas Marketing Corporation, purchases all of our natural gas production in the Gulf Coast region. The marketing subsidiary sells the natural gas to intrastate pipelines, natural gas processors and marketing companies.
Currently, all of our natural gas sales volumes in the Gulf Coast region are sold at market-responsive prices under contracts with terms of one to three years. The Gulf Coast properties are connected to various processing plants in Texas and Louisiana with multiple interstate and intrastate deliveries, affording us access to multiple markets.
We also produce and market approximately 1,500 barrels a day of crude oil/condensate in the Gulf Coast region at market-responsive prices.
WESTERN REGION
Our principal markets for Western region natural gas are in the northwestern, midwestern and northeastern United States. Cabot Oil & Gas Marketing purchases all of our natural gas production in the Western region. The marketing subsidiary sells the natural gas to cogenerators, natural gas processors, local distribution companies, industrial customers and marketing companies.
Currently, most of our natural gas production in the Western region is sold primarily under contracts with a term of one year or less at market-responsive prices. Through 1999, approximately 20% of the Western region's production was sold under a 15-year cogeneration contract due to expire in 2009 that escalated 5% in price per year. In December 1999, the contract was bought out for a cash payment of $12 million to Cabot Oil & Gas. Accordingly, our obligation to deliver natural gas to the cogeneration facility was terminated and we have no other obligation under the contract. The Western region properties are connected to the majority of the midwestern and northwestern interstate and intrastate pipelines, affording us access to multiple markets. We also produce and market approximately 900 barrels of crude oil/condensate a day in the Western region at market-responsive prices.
APPALACHIAN REGION
The principal markets for our Appalachian region natural gas are in the northeastern United States. Cabot Oil & Gas Marketing purchases our 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. Our marketing subsidiary sells natural gas to industrial customers, local distribution companies and gas marketers both on and off our pipeline and gathering system.
Most of our natural gas sales volume in the Appalachian region is 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 10% of Appalachian production is sold on fixed price contracts that typically renew annually.
Our Appalachian natural gas production is generally sold at a higher realized price, or premium, compared to production from other producing regions due to its close proximity to eastern markets. While year-to-year fluctuations in that premium are normal due to changes in market conditions, this premium has typically been in the range of $0.40 to $0.50 per Mmbtu above the Henry Hub cash price throughout the 1990s. In 1999, however, the average premium declined to $0.27 per Mmbtu due to increases in supply in the eastern market. We expect that the premium will remain at this lower level for the near future.
Ancillary to our exploration and production operations, we operate a number of gas gathering and transmission pipeline systems, made up of approximately 2,390 miles of pipeline with interconnects to three interstate transmission systems and seven local distribution companies as of the end of 1999. The majority of our pipeline infrastructure in West Virginia is regulated by the FERC. As such, the transportation rates and terms of service of our pipeline subsidiary, Cranberry Pipeline Corporation, are subject to the rules and regulations of the FERC. Our natural gas gathering and transmission pipeline systems enable us 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 our gathering and transmission pipeline systems also enables us to purchase, transport and sell natural gas produced by third parties. In addition, we can take part in development drilling operations without relying upon third parties to transport our natural gas while incurring only the incremental costs of pipeline and compressor additions to our system.
We have two natural gas storage fields located in West Virginia, with a combined working capacity of approximately 4 Bcf. We use 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 us to periodically increase the volume of natural gas that we can deliver by more than 40% above the volume that we could deliver solely from our production in the Appalachian region. The pipeline systems and storage fields are fully integrated with our operations.
RISK MANAGEMENT
In 1999, we used certain financial instruments, called derivatives, to manage price risks associated with our production and brokering activities. The impact of these derivatives on our financial results was not material. While there are many different types of derivatives available, we primarily used natural gas and oil price swap agreements to attempt to manage price risk more effectively. These price swaps call for payments to, or receipts from, counterparties based on the differential between a fixed and a variable gas price. We will continue to evaluate the benefit of this strategy in the future. Please read Management's Discussion and Analysis of Financial Condition and Results of Operations - Commodity Price Swaps for further discussion concerning our use of derivatives.
RESERVES
CURRENT RESERVES
The following table presents our estimated proved reserves at December 31, 1999.
- ---------- (1) Liquids include crude oil, condensate and natural gas liquids (Ngl). (2) Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.
The proved reserve estimates presented here were prepared by our petroleum engineering staff and reviewed by Miller and Lents, Ltd., independent petroleum engineers. For additional information regarding estimates of proved reserves, the review of such estimates by Miller and Lents, Ltd., and other information about our oil and gas reserves, see the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8. A copy of the review letter by Miller and Lents, Ltd. has been filed as an exhibit to this Form 10-K. Our estimates of proved reserves in the table above do not differ materially from those filed by us with other federal agencies. Our reserves are sensitive to natural gas sales prices and their effect on economic producing rates. Our reserves are based on oil and gas prices in effect for December 1999.
There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control. Therefore, the reserve information in this Form 10-K represents 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. 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 revising the original 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 depends primarily on the accuracy of the assumptions upon which they were based. In general, the volume of production from oil and gas properties declines as reserves are depleted. Except to the extent we acquire additional properties containing proved reserves or conduct successful exploration and development activities or both, our proved reserves will decline as reserves are produced.
HISTORICAL RESERVES
The following table presents our estimated proved reserves for the periods indicated.
Gulf = Gulf Coast Rocky Mtn = Rocky Mountains Mid-Cont = Mid-Continent or Anadarko Total West = Rocky Mountains and Mid-Continent combined App = Appalachia
Gulf = Gulf Coast Rocky Mtn = Rocky Mountains Mid-Cont = Mid-Continent or Anadarko Total West = Rocky Mountains and Mid-Continent combined App = Appalachia - ---------- (1) Includes natural gas and natural gas equivalents determined by using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or natural gas liquids.
VOLUMES AND PRICES; PRODUCTION COSTS
The following table presents regional historical information about our net wellhead sales volume for natural gas and oil (including condensate and natural gas liquids) produced natural gas and oil sales prices and production costs per equivalent.
- --------------- (1) Equal to the aggregate of production and the net changes in storage and exchanges. (2) The decline in the Appalachian region natural gas sales volume is attributed to the sale of the Meadville properties effective September 1, 1997. Prior to the sale, these properties produced 3.6 Bcf, or 14.7 Mmcf per day, during the eight-month period ending August 31, 1997. In addition, a further decline is associated with the sale of properties in the Clarksburg district effective October 1, 1999. Prior to this sale, those properties produced approximately 7 Mmcf per day. (3) Represents the average sales prices for all production volumes (including royalty volumes) sold by Cabot Oil & Gas during the periods shown net of related costs (principally purchased gas royalty, transportation and storage). (4) 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 applicable to capitalized lease acquisition, exploration and development expenditures.
ACREAGE
The following tables summarize our gross and net developed and undeveloped leasehold and mineral acreage at December 31, 1999. Acreage in which our interest is limited to royalty and overriding royalty interests is excluded.
LEASEHOLD ACREAGE
MINERAL FEE ACREAGE
TOTAL NET ACREAGE BY REGION OF OPERATION
PRODUCTIVE WELL SUMMARY
The following table presents our ownership at December 31, 1999, in natural gas and oil wells in the Gulf Coast region (consisting of various fields located in Louisiana and Texas), in the Western region (consisting of various fields located in Oklahoma, Kansas, Colorado and Wyoming) and in the Appalachian region (consisting of various fields located in West Virginia, Pennsylvania, New York, Ohio, Virginia and Kentucky). We consider productive wells to be producing wells and wells capable of production in which we have a working interest or a reversionary interest as in the case of certain Section 29 tight sands wells.
DRILLING ACTIVITY
We drilled, participated in the drilling of, or acquired wells presented by region in the table below for the periods indicated.
- ---------- (1) Includes the acquisition of net interest in certain wells in which we already held an ownership interest. Does not include certain interests in Section 29 tight sands wells purchased and then resold during 1999.
COMPETITION
Competition in our primary producing areas is intense. Price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery records, affect competition. We believe that our extensive acreage position and existing natural gas gathering and pipeline systems and storage fields give us a competitive advantage over other producers in the Appalachian region who do not have similar systems or facilities in place. We believe that our competitive position in the Appalachian region is enhanced by the lack of significant competition from major oil and gas companies. We also actively compete against other companies with substantially larger financial and other resources, particularly in the Western and Gulf Coast regions. We believe that marketing our own gas through the operation of Cabot Oil & Gas Marketing Corporation enhances our competitive position.
OTHER BUSINESS MATTERS
MAJOR CUSTOMER
We had no sales to any customer that exceeded 10% of our total gross revenues in 1999 or 1998.
SEASONALITY
Demand for natural gas has historically been seasonal, with peak demand and typically higher prices during the colder winter months.
REGULATION OF OIL AND NATURAL GAS PRODUCTION EXPLORATION AND PRODUCTION
Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units and the density of wells which may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations where we can drill. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. Cabot Oil & Gas, however, does not believe it is affected materially differently by these regulations than others in the industry.
NATURAL GAS MARKETING, GATHERING AND TRANSPORTATION
Federal legislation and regulatory controls have historically affected the price of the natural gas produced and the manner in which such production is transported and marketed. Under the Natural Gas Act of 1938, the FERC regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. The FERC's jurisdiction over interstate natural gas sales was substantially modified by the Natural Gas Policy Act, under which the FERC continued to regulate the maximum selling prices of certain categories of gas sold in "first sales" in interstate and intrastate commerce. Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (Decontrol Act) deregulated natural gas prices for all "first sales" of natural gas, including all sales of our own production. As a result, all of our produced natural gas may now be sold at market prices, subject to the terms of any private contracts, which may be in effect. The FERC's jurisdiction over natural gas transportation was not affected by the Decontrol Act.
Natural gas sales are affected by intrastate and interstate gas transportation regulation. Beginning in 1985, the FERC adopted regulatory changes that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, transforming the role of interstate pipeline companies from wholesaler marketers of gas to the primary role of gas transporters. All gas marketing by the pipelines was required to be divested to a marketing affiliate, which operates separately from the transporter and in direct competition with all other merchants. As a result of the various omnibus rulemaking proceedings in the late 1980s and the individual pipeline restructuring proceedings of the early to mid-1990s, the interstate pipelines are now required to provide open and nondiscriminatory transportation and transportation-related services to all producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking service. Through similar orders affecting intrastate pipelines that provide similar interstate services, the FERC expanded the impact of open access regulations to intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have affected natural gas marketing. Most notable are (1) the large-scale divestiture of interstate pipeline-owned gas gathering facilities to affiliated or non-affiliated companies, (2) further development of rules governing the relationship of the pipelines with their marketing affiliates, (3) the publication of standards relating to the use of electronic bulletin boards and electronic data exchange by the pipelines to make available transportation information on a timely basis and to enable transactions to occur on a purely electronic basis, (4) further review of the role of the secondary market for released pipeline capacity and its relationship to open access service in the primary market, and (5) development of policy and promulgation of orders pertaining to its authorization of market-based rates (rather than traditional cost-of-service based rates) for transportation or transportation-related services upon the pipeline's demonstration of lack of market control in the relevant service market. It remains to be seen what effect the FERC's other activities will have on access to markets, the fostering of competition and the cost of doing business.
As a result of these changes, sellers and buyers of gas have gained direct access to the particular pipeline services they need and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities.
In the past, Congress has been very active in the area of gas regulation. However, as discussed above, the more recent trend has been in favor of deregulation and the promotion of competition in the gas industry. Thus, in addition to "first sale" deregulation, Congress also repealed incremental pricing requirements and gas use restraints that were previously applicable. There are other legislative proposals pending in the Federal and state legislatures which, if enacted, would significantly affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, and despite the trend toward federal deregulation of the natural gas industry, whether or to what extent that trend will continue, or what the ultimate effect will be on our sales of gas, cannot be predicted.
Our pipeline systems and storage fields are regulated for safety compliance by the U.S. Department of Transportation, the West Virginia Public Service Commission and the Pennsylvania Department of Natural Resources. Our pipeline systems in each state operate independently and are not interconnected.
FEDERAL REGULATION OF PETROLEUM
Sales of oil and natural gas liquids by the Company are not regulated and are at market prices. The price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines. Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may tend to increase the cost of transporting oil and natural gas liquids by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. These regulations have generally been approved on judicial review. Every five years, the FERC will examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. The first such review is scheduled for 2000. The Company is not able to predict with certainty the effect upon it of these relatively new federal regulations or of the periodic review by FERC of the index.
ENVIRONMENTAL REGULATIONS
GENERAL. Our 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 Cabot Oil & Gas facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions, or both. Government regulations can increase the cost of planning, designing, installing and operating oil and gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are parts of oil and gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production would result in substantial costs and liabilities to us.
SOLID AND HAZARDOUS WASTE. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other solid wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become stricter over time. Under these more stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination.
We generate some hazardous wastes that are already subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. We could, therefore, be subject to more rigorous and costly disposal requirements.
SUPERFUND. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of a hazardous substance into the environment. These persons include the owner and operator of a site and any party that disposed of or arranged for the disposal of the hazardous substance found at a site. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In the course of business, we have generated and will continue to generate wastes that may fall within CERCLA's definition of hazardous substances. Cabot Oil & Gas may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such wastes have been disposed.
OIL POLLUTION ACT. The federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term "waters of the United States" has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages.
CLEAN WATER ACT. The Federal Water Pollution Control Act (FWPCA or Clean Water Act) and resulting regulations, which are implemented through a system of permits, also govern discharge of certain contaminants to waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act requirements are generally resolved by payment of fines and correction of any identified deficiencies, but regulatory agencies could require us to cease construction or operation of certain facilities that are the sources of water discharges. We believe that we comply with the Clean Water Act and related federal and state regulations in all material respects.
CLEAN AIR ACT. Our operations are subject to local, state and federal laws and regulations to control emissions from sources of air pollution. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require Cabot Oil & Gas to cease construction or operation of certain facilities that are air emission sources. We believe that we substantially comply with the emission standards under local, state, and federal laws and regulations.
EMPLOYEES
As of December 31, 1999, Cabot Oil & Gas had 332 active employees. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. The Company and its employees are not represented by a collective bargaining agreement. In January 1999, we instituted a reorganization plan that resulted in a 6% reduction in the number of active employees. In September 1999, we completed the divestiture of certain properties in the Appalachian region that effectively transferred 19 active employees to the acquiring company.
OTHER
Our profitability depends on certain factors that are beyond our control, such as natural gas and crude oil prices. Please see Item 7. We face a variety of hazards and risks that could cause substantial financial losses. Our business involves a variety of operating risks, including blowouts, cratering, explosions and fires, mechanical problems, uncontrolled flows of oil, natural gas or well fluids, formations with abnormal pressures, pollution and other environmental risks, and natural disasters. We conduct operations in shallow offshore areas, which are subject to additional hazards of marine operations, such as capsizing, collision and damage from severe weather.
Our operation of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks. At December 31, 1999, we owned or operated approximately 2,590 miles of natural gas gathering and transmission pipeline systems throughout the United States. As part of our normal maintenance program, we have identified certain segments of our pipelines that we believe may require repair, replacement or additional maintenance. Any of these events could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial losses to us. In accordance with customary industry practice, we maintain insurance against some, but not all, of these risks and losses. The occurrence of any of these events not fully covered by insurance could have a material adverse effect on our financial position and results of operations.
The sale of our oil and gas production depends on a number of factors beyond our control. The factors include the availability and capacity of transportation and processing facilities. Our failure to access these facilities and obtain these services on acceptable terms could materially harm our business.
ITEM 2.
ITEM 2. PROPERTIES
See Item 1. Business.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
We are a party to various legal proceedings arising in the normal course of our business, none of which, in management's opinion, should result in judgments which would have a material adverse effect on us.
The EPA notified us in February 2000 that we may have potential liability for waste material disposed of at the Casmalia Superfund Site ("Site), located on a 252-acre parcel in Santa Barbara County, California. Over 10,000 separate parties disposed of waste at the Site while it was operational from 1973 to 1989. The EPA stated that federal, state and local governmental agencies along with the numerous private entities that used the Site for waste disposal will be expected to pay for the clean-up costs which could total as much as several hundred million dollars. The EPA is also pursuing the owner(s)/operator(s) of the Site to pay for remediation.
The total amount of environmental investigation and cleanup costs that we may incur with respect to the foregoing is not known at this time and, accordingly, we have not recorded a reserve related to this possible liability. While the potential impact to the quarterly or annual financial results may be material, we do not believe it would materially impact our financial position.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the period from October 1, 1999 to December 31, 1999.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information about our executive officers as of March 1, 2000, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.
All officers are elected annually by our Board of Directors. Except for the following, all of the executive officers have been employed by Cabot Oil & Gas for at least the last five years.
Ray R. Seegmiller joined Cabot Oil & Gas as Vice President, Chief Financial Officer and Treasurer in August 1995. Mr. Seegmiller served in this position until March 1997 when he was promoted to Executive Vice President and Chief Operating Officer. In September 1997, Mr. Seegmiller was promoted to President and Chief Operating Officer and was elected as a Director. Mr. Seegmiller replaced Charles Siess as Chief Executive Officer upon the retirement of Mr. Siess in May 1998. Mr. Seegmiller was named Chairman of the Board in May 1999. From May 1988 until 1993, Mr. Seegmiller served as President and Chief Executive Officer of Terry Petroleum Company. Prior to that, Mr. Seegmiller held various officer positions with Marathon Manufacturing Company.
Abraham D. Garza joined Cabot Oil & Gas in August 1995 as Director, Human Resources. He was named to his current position as Vice President, Human Resources in May 1998. Previously, Mr. Garza served as Human Resources Director at Texfield, Inc. and in various management positions of increasing responsibility at Marathon Manufacturing Company.
Scott C. Schroeder has been Vice President and Treasurer since April 1998. From May 1997 to that time he served as Treasurer. From October 1995 to May 1997, Mr. Schroeder served as Assistant Treasurer. Prior to joining Cabot Oil & Gas, Mr. Schroeder held various managerial positions with Pride Petroleum Services (now known as Pride International). Prior to that, Mr. Schroeder served as Manager, Treasury Operations and Planning of DeKalb Energy Company.
Robert R. McBride joined Cabot Oil & Gas as Vice President and Regional Manager in September 1999. Prior to his current position, he served as President and General Manager for Pennzoil Venezuela Corporation S.A. He previously held positions of increasing responsibility at American Exploration Company and Tenneco.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Common Stock is listed and principally traded on the New York Stock Exchange under the ticker symbol "COG". The following table presents the high and low sales prices per share of the Common Stock during certain periods, as reported in the consolidated transaction reporting system. Cash dividends paid per share of the Common Stock are also shown.
As of January 31, 2000, there were 1,087 registered holders of the Common Stock. Shareholders include individuals, brokers, nominees, custodians, trustees, and institutions such as banks, insurance companies and pension funds. Many of these hold large blocks of stock on behalf of other individuals or firms.
ITEM 6.
ITEM 6. SELECTED HISTORICAL FINANCIAL DATA
The following table summarizes selected consolidated financial data for Cabot Oil & Gas for the periods indicated. This information should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations, and the Consolidated Financial Statements and related Notes.
- ---------- (1) See "Earnings per Common Share" under Note 15 of the Notes to the Consolidated Financial Statements.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying notes included elsewhere in this Form 10-K contain additional information that should be referred to when reviewing this material.
Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed. Please read "Forward-Looking Information" on page 27.
We operate in one segment, natural gas and oil exploration and exploitation. Prior to 1998, we operated in two regions: the Appalachian region and the Western region, which included the Mid-Continent, Rocky Mountains and Gulf Coast areas. Beginning in 1998, a third region was created with the formation of the Gulf Coast region, leaving the Mid-Continent and Rocky Mountains areas in the Western region. For purposes of the comparisons below, prior period results have been restated to conform to this three-region structure.
OVERVIEW
Our financial results depend upon many factors, particularly the price of natural gas and our ability to market our production on economically attractive terms. Price volatility in the natural gas market has remained prevalent in the last few years. From the third quarter of 1998 through the first quarter of 1999, we experienced a decline in energy commodity prices, resulting in lower revenues and net income during this period. However, in the summer of 1999 and continuing into early 2000, prices improved. This more favorable price environment helped us improve from a $3.3 million net loss in the first quarter of 1999 to net income of $4.6 million in the fourth quarter.
We reported earnings of $0.21 per share, or $5.1 million, for 1999. This is up from the $0.08 per share, or $1.9 million, reported in 1998. The improvement is partially credited to the stronger commodity price environment during the last half of the year, accompanied by a 4% increase in equivalent production. Our realized natural gas price for the fourth quarter of $2.61 per Mcf was 21% higher than last year's fourth quarter price of $2.16 per Mcf. Our price for the entire year of $2.22 per Mcf was 3% higher than the 1998 price of $2.16 per Mcf. Also contributing to our 1999 results were the following selected items:
- $12 million in revenue received for the monetization of a long-term gas sales contract in December 1999 - A $4 million gain realized on the sale of non-strategic assets, primarily in Appalachia - The recognition of a $7 million impairment of long-lived assets - The $1.2 million pre-tax provision for certain wells no longer deemed to be eligible for the Section 29 tight gas sands credit following a recent industry tax court ruling.
A discussion of these selected items can be found in the Results of Operations section, beginning on page 28.
Total equivalent production for 1999 was 71.3 Bcfe, an increase of 4% over 1998, despite the Appalachian divestiture and the significantly reduced drilling program in place for 1999 compared to 1998. This increase was due primarily to production from the December 1998 Oryx acquisition and new production brought on by the 1998 and 1999 drilling programs of a combined 278 gross (189.1 net) wells.
During 1999, we entered into several property sales intended to high grade our reserve base. In September 1999, we sold Appalachian properties with reserves of 58.8 Bcfe for $46.3 million. Subsequent to this sale, we used part of the proceeds from this divestiture of non-strategic properties to purchase $17.4 million of proved reserves adjacent to our existing properties in Wyoming's Green River Basin and the balance of the proceeds to reduce debt by $28.6 million. These acquired properties added 15.8 Bcfe of proved reserves and approximately 43,000 undeveloped acres. Additionally, we sold other non-strategic properties in several smaller transactions during the year for $10 million. In total, 1999 assets sales resulted in a gain of $4 million. These actions eliminated approximately 22% of our total well count but reduced our production by only 5%.
We purchased producing oil and gas properties and other assets located in south Louisiana from Oryx Energy Company for $70.1 million in December 1998. These properties included interests in 10 fields covering 34,345 net acres with 68 producing wells. The acquisition also included a 160 square mile 3-D seismic inventory. Proved reserves acquired were approximately 72 Bcfe. By reworking certain non-producing wells, we have increased the daily production rate from 11.5 Mmcfe in December 1998 to an average rate of 15.8 Mmcfe in 1999. In addition, we plan to commence our exploration and development drilling program on these properties in 2000.
We drilled 73 gross wells with a success rate of 84% in 1999 compared to 205 gross wells and an 89% success rate in 1998. Total capital expenditures were $88.1 million for 1999 compared to $225.9 million in 1998, which included $70.1 million for the acquisition of the south Louisiana properties. We reduced our 1999 budgeted capital and exploration expenditures in response to the weak energy price environment in the fourth quarter of 1998 and in early 1999. However, we front-end loaded the 1999 development and exploration plan to maximize production from this year's drilling program and to provide more flexibility to drill more wells if cash flows improved later in the year, which they did. Accordingly, during the year, we increased our 1999 capital and exploration expenditure program by approximately $35 million in response to the improving natural gas prices during the third quarter.
As mentioned earlier, we received $12 million in December 1999 to monetize a long-term gas sales contract, which had been sourced by production from our Rocky Mountains area. The contract provided for a fixed natural gas price that escalated 5% annually. The contract had a remaining term of less than nine years. We have entered into certain forward-sale agreements with other counterparties to deliver a similar quantity of gas at prices similar to those of the monetized contract. These forward-sale contracts had a remaining life of 16 months at the end of 1999.
During the fourth quarter of 1999, we experienced a significant production decline from the only well in our Chimney Bayou field located in the Texas Gulf Coast. This decline, along with an unsuccessful workover in our Lawson field in Louisiana, resulted in a $7 million impairment of long-lived assets.
We remain focused on our strategies to grow through the drill bit, concentrating on the highest return opportunities, and from synergistic acquisitions. We believe these strategies are appropriate in the current industry environment, enabling us to add shareholder value over the long-term.
The preceding paragraphs, discussing our strategic pursuits and goals, contain forward-looking information. Please read "Forward-Looking Information" on page 27.
FINANCIAL CONDITION
CAPITAL RESOURCES AND LIQUIDITY
Our capital resources consist primarily of cash flows from our oil and gas properties and asset-based borrowing supported by oil and gas reserves. Our level of earnings and cash flows depends on many factors, including the price of oil and natural gas and our ability to control and reduce costs. Demand for natural gas has historically been subject to seasonal influences characterized by peak demand and higher prices in the winter heating season. Natural gas prices were unseasonably low during much of 1998 and into the first half of 1999. In late spring and into the summer of 1999, prices began to show improvement and by the fourth quarter, we experienced the highest quarterly realized price in two years.
The primary sources of cash for us during 1999 were funds generated from operations, proceeds from the sale of non-strategic oil and gas properties and the proceeds from the monetization of the long-term gas sales contract. Funds were used primarily for exploration and development expenditures, proved property acquisitions, dividend payments and the repayment of borrowings under the credit facility.
We had net cash outflows of $0.5 million during 1999. The net cash inflow from operating activities of $92.5 million substantially offsets the $93.7 million of cash used for capital and exploration expenditures. The cash proceeds from asset sales of $56.3 million effectively funded the debt reduction and dividend payment.
Cash flows provided by operating activities in 1999 were $5.3 million higher than in 1998. This improvement was a result of increased revenues from higher realized commodity prices and the monetization of the long-term gas sales contract. Partially offsetting this benefit was the less favorable change in the balance sheet as we reduced the balance in accounts payable between year ends.
Cash flows provided by operating activities in 1998 were $7.8 million lower than in 1997, due predominantly to lower natural gas and oil prices, partially offset by a significant increase in the accounts payable balance resulting mainly from higher fourth quarter spending activity.
Cash flows used by investing activities in 1999 were attributable to capital and exploration expenditures of $93.7 million, offset by the receipt of $56.3 million in proceeds received from the sale of non-strategic oil and gas properties. Cash flows used by investing activities in 1998 were substantially attributable to capital and exploration expenditures of $223.2 million, offset by the receipt of $1.1 million in proceeds from the sale of certain oil and gas properties.
Cash flows used by investing activities in 1998 were $183.7 million higher than in 1997, due primarily to the capital and exploration expenditures that increased $135.8 million over 1997, and the receipt in 1997 of $47.7 million in net proceeds from the sale of producing properties located in northwest Pennsylvania. These 1998 expenditures included:
- $70.1 million used to purchase south Louisiana properties from Oryx in December. - $6.6 million spent as part of the joint exploration agreement with Union Pacific Resources. - $12 million used to acquire 21.8 Bcfe of proved reserves in the Mid-Continent and Rocky Mountains areas of the Western region.
Cash flows used by financing activities in 1999 included $50 million used to reduce the year-end debt balance to $293 million from $343 million in 1998 and cash used to pay cash dividends to stockholders.
Cash flows provided by financing activities in 1998 were increases in borrowings on the revolving credit facility related to the 1998 drilling program and $83.6 million in property acquisitions. Financing activities in 1998 also included the payment of stock dividends and the purchase of shares in the open market under our share repurchase program. The purchased shares are held as treasury shares.
Cash flows used by financing activities from 1997 consist primarily of the $49.0 million net reduction in borrowings on the revolving credit facility as well as dividend payments.
We have a revolving credit facility with a group of banks, the revolving term of which runs to December 2003. The available credit line under this facility, currently $250 million, is subject to adjustment on the basis of the present value of estimated future net cash flows from proved oil and gas reserves (as determined by the banks' petroleum engineer) and other assets. Accordingly, oil and gas prices are an important part of this computation. Oil and gas prices also affect the calculation of the financial ratios for debt covenant compliance. While we do not currently believe that our credit availability is likely to be significantly reduced, management cannot predict how current price levels may change the banks' long-term price outlook. Therefore, we can give no assurance that our available credit line will not be adversely impacted in 2000 or as to the amount of credit that will continue to be available under this facility. To reduce the impact of any redetermination, we strive to manage our debt at a level below the available credit line in order to maintain excess borrowing capacity. At year end, this excess capacity totaled $105 million, or 42% of the total available credit line. Management believes that we have the ability to finance, if necessary, our capital requirements, including acquisitions. Please read Note 5 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our revolving credit facility.
In the event that the available credit line is adjusted below the outstanding level of borrowings, we have a period of 180 days to reduce our outstanding debt to the adjusted credit line. The revolving credit agreement also includes a requirement to pay down half of the debt in excess of the adjusted credit line within the first 90 days of any adjustment.
Our interest expense for 2000 is projected to be $23.3 million. In May 2000, a $16.0 million principal payment is due on our 10.18% Notes. The amount is reflected as "Current Portion of Long-Term Debt" on our balance sheet. The payment is expected to be made with cash from operations and, if necessary, from increased borrowings under our revolving credit facility.
CAPITALIZATION
Our capitalization information is as follows:
During 1999, dividends were paid on our common stock totaling $4.0 million and on our 6% convertible redeemable preferred stock totaling $3.4 million. We have paid quarterly common stock dividends of $0.04 per share since becoming publicly traded in 1990. The amount of future dividends is determined by our board of directors and is dependent upon a number of factors, including future earnings, financial condition and capital requirements.
We have entered into an agreement with Puget Sound Energy, Inc., the holder of our preferred stock, to repurchase their preferred shares by November 1, 2000. As outlined in the agreement, the preferred shares that are recorded on our balance sheet for $56.7 million will be repurchased for $51.6 million. Cash flow from operations, additional borrowings or proceeds from the sale of equity may be used to fund this transaction. Please read Note 10 of the Notes to the Consolidated Financial Statements for further discussion of this agreement.
CAPITAL AND EXPLORATION EXPENDITURES
On an annual basis, we generally fund most of our capital and exploration activities, excluding major oil and gas property acquisitions, with cash generated from operations. We budget these capital expenditures based on our projected cash flows for the year.
The following table presents major components of our capital and exploration expenditures for the three years ended December 31, 1999.
- ---------- (1) Includes $70.1 million in oil and gas properties acquired from Oryx Energy Company in December 1998. (2) Includes $45.2 million in oil and gas properties acquired from Equitable Resources Energy Company in a like-kind exchange transaction with a portion of the assets sold in the Meadville property sale.
Total capital and exploration expenditures for 1999 decreased $137.8 million compared to 1998, primarily as a result of this year's reduced drilling program and the $70.1 million acquisition of proved properties from Oryx in December 1998. Additionally in 1998, we made an initial $5.0 million leasehold acquisition in connection with our joint exploration program with Union Pacific Resources and also purchased 9.3 Bcfe of proved resources in the Mid-Continent for $6.6 million. During the last half of 1999, we acquired $17.4 million of oil and gas properties in the Moxa Arch in the Rocky Mountains area, including 27 gross wells, approximately 16 Bcfe of proved reserves and approximately 43,000 net undeveloped acres that complement our existing Moxa Arch development.
We plan to drill 110 gross wells in 2000 compared with 73 gross wells drilled in 1999. This 2000 drilling program includes $88.9 million in total capital and exploration expenditures, up from $88.1 million in 1999. Expected spending in 2000 includes $49.1 million for drilling and facilities, and $25.2 million in exploration expenses. In addition to the drilling and exploration program, other 2000 capital expenditures are planned primarily for lease acquisitions and for gathering and pipeline infrastructure maintenance and construction. We will continue to assess the natural gas price environment and may increase or decrease the capital and exploration expenditures accordingly.
YEAR 2000
Many computer systems were built using software that processed transactions using two digits to represent the year. This type of software generally required modifications to function properly with dates after December 31, 1999 or to become year 2000 compliant. The same issue applied to microprocessors embedded in machinery and equipment, such as gas compressors and pipeline meters. The impact of failing to identify those computer systems operated by us or our business partners that are not year 2000 compliant and to correct the problem could have been significant to our ability to operate and report results, as well as potentially expose us to third-party liability. We did not experience any computer system failures as a result of entering the year 2000. Cabot Oil & Gas will continue to monitor its computer systems for any potential errors that may have resulted from this change.
Prior to January 1, 2000, we completed all of the necessary modifications to our computer systems and embedded microprocessors. This project was completed on schedule and the total related costs were $2.2 million, funded by cash from operations or borrowings on our revolving credit facility. Of the total project cost, $2.0 million was attributable to the purchase of new software and equipment that was capitalized. The remaining $0.2 million was expensed.
Prior to the end of 1999, we contacted our significant customers and suppliers in order to determine our exposure to their potential failure to become year 2000 compliant. Although we are not aware of any year 2000 compliance problems with any of our customers or suppliers, we cannot guarantee that their systems have been operating or will continue to operate without interruption in the new millennium.
OTHER ISSUES AND CONTINGENCIES
CORPORATE INCOME TAX. Cabot Oil & Gas generates tax credits for the production of certain qualified fuels, including natural gas produced from tight sands formations and Devonian Shale. The credit for natural gas from a tight sand formation (tight gas sands) amounts to $0.52 per Mmbtu for natural gas sold prior to 2003 from qualified wells drilled in 1991 and 1992. A number of wells drilled in the Appalachian region during 1991 and 1992 qualified for the tight gas sands tax credit. The credit for natural gas produced from Devonian Shale is $1.07 per Mmbtu in 1999. In 1995 and 1996, Cabot Oil & Gas completed three transactions to monetize the value of these tax credits, resulting in revenues of $1.3 million in 1999 and approximately $5.4 million over the remaining three years. See Note 13 of the Notes to the Consolidated Financial Statements for further discussion.
Cabot Oil & Gas has benefited in the past and may benefit in the future from the alternative minimum tax (AMT) relief granted under the Comprehensive National Energy Policy Act of 1992 (the Act). The Act repealed provisions of the AMT requiring a taxpayer's alternative minimum taxable income to be increased on account of certain intangible drilling costs (IDC) and percentage depletion deductions. The repeal of these provisions generally applies to taxable years beginning after 1992. The repeal of the excess IDC preference cannot reduce a taxpayer's alternative minimum taxable income by more than 40% of the amount of such income determined without regard to the repeal of such preference.
REGULATIONS. The Company's operations are subject to various types of regulation by federal, state and local authorities. See Regulation of Oil and Natural Gas Production and Transportation and Environmental Regulations in the Other Business Matters section of Item 1 Business for a discussion of these regulations.
RESTRICTIVE COVENANTS. The Company's ability to incur debt, to pay dividends on its common and preferred stock, and to make certain types of investments is subject to certain restrictive covenants in the Company's various debt instruments. Among other requirements, the Company's Revolving Credit Agreement and 7.19% Notes specify a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0. At December 31, 1999, the calculated ratio for 1999 was 4.6 to 1. In the unforeseen event that Cabot Oil & Gas fails to comply with these covenants, it may apply for a temporary waiver with the bank, which, if granted, would allow the Company a period of time to remedy the situation. See further discussion in Capital Resources and Liquidity and Note 5 of the Notes to the Consolidated Financial Statements for further discussion.
CONCLUSION
Our financial results depend upon many factors, particularly the price of natural gas and oil and our ability to market gas on economically attractive terms. The average produced natural gas sales price received in 1999 was up 3% over 1998, after declining 15% from 1997 to 1998. The volatility of natural gas prices in recent years remains prevalent in 2000 with wide price swings in day-to-day trading on the NYMEX futures market. Given this continued price volatility, we cannot predict with certainty what pricing levels will be in the future. Because future cash flows are subject to these variables, we cannot assure you that our operations will provide cash sufficient to fully fund our planned capital expenditures.
While our 2000 plans now include $88.9 million in capital spending, we will periodically assess industry conditions and adjust our 2000 spending plan to ensure the adequate funding of our capital requirements, including, among other things, reductions in capital expenditures or common stock dividends.
We believe our capital resources, supplemented with external financing if necessary, are adequate to meet our capital requirements.
The preceding paragraphs contain forward-looking information. See Forward-Looking Information in the following paragraph.
* * *
FORWARD-LOOKING INFORMATION
The statements regarding future financial performance and results, and market prices and other statements that are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast," "predict" and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.
RESULTS OF OPERATIONS
For the purpose of reviewing our results of operations, "Net Income" is defined as net income available to common stockholders.
SELECTED FINANCIAL AND OPERATING DATA
The table below presents the after-tax effects of certain selected items on our results of operations for the three years ended December 31, 1999.
These selected items impacted our 1999 financial results. Because they are not a part of our normal business, we have isolated their effects in the table above. These selected items were as follows:
- We had a 15-year cogeneration contract under which we sold approximately 20% of our Western region natural gas per year. The contract was due to expire in 2008, but during 1999 we reached an agreement with the counterparty under which the counterparty bought out the remainder of the contract for $12 million. This transaction, completed in December 1999, accelerated the realization of any future price premium that may have been associated with the contract and added $12 million of pre-tax other revenue. We simultaneously sold forward a similar quantity of Western region gas for the next 16 months at similar prices to those in the monetized contract.
- In the fourth quarter of 1999, we recorded impairments totaling $7 million on two of our producing fields in the Gulf Coast region. The Chimney Bayou field was impaired by $6.6 million due to a significant reserve revision on the Broussard-Middleton 1R well in connection with a decline in its natural gas production accompanied by a marked increase in water production. The Broussard-Middleton 1R was the only producing well in this field. The Lawson field was impaired by $0.4 million due to an unsuccessful workover on one of its wells. - We recorded a $4 million gain on the sale of certain non-strategic oil and gas assets, most notably the Clarksburg properties in the Appalachian region sold to EnerVest effective October 1999. - We recorded a $1.2 million reserve against other revenue for certain wells no longer deemed to be eligible for the Section 29 tight gas sands credit following a recent industry tax court ruling. The FERC recently issued a rule proposal that may ultimately restore the eligibility for some or all of the wells in question. We will continue to monitor other tax court decisions and announcements from the FERC regarding this issue.
1999 AND 1998 COMPARED
NET INCOME AND REVENUES. We reported net income in 1999 of $0.4 million, or $0.02 per share, excluding the impact of the selected items. During 1998, we reported net income of $1.9 million, or $0.08 per share. Excluding the pre-tax effect of the selected items, operating income increased $4.4 million, or 16%, and operating revenues increased $11.5 million, or 7%, in 1999. Natural gas production made up 87%, or $145.5 million, of net operating revenue. The improvement in operating revenues was mainly a result of the $7.4 million rise in crude oil and condensate sales, due to both price improvements and production volume increases. Price and production volume increases in natural gas also contributed to the higher operating revenues. Operating income was similarly impacted by these revenue changes. Net income was reduced by a $7.2 million increase in interest expense.
Natural gas production volume in the Gulf Coast region was up 4.9 Bcf, or 46%, to 15.5 Bcf primarily due to production from the Oryx acquisition, recent discoveries and development in the Kacee field in south Texas, and the redrilling of certain wells in the Beaurline field. Natural gas production volume in the Western region was down 1.6 Bcf to 29.3 Bcf due primarily to lower levels of drilling activity in the Mid-Continent area during 1998 and 1999. Natural gas production volume in the Appalachian region was down 2.0 Bcf to 20.7 Bcf, as a result of the sale of certain non-strategic assets in the Appalachian region effective October 1, 1999, and a decrease in drilling activity in the region in 1999. Total natural gas production was up 1.3 Bcf, or 2%, yielding a revenue increase of $2.7 million in 1999.
The average Gulf Coast natural gas production sales price rose $0.14 per Mcf, or 7%, to $2.29, increasing net operating revenues by approximately $2.2 million. In the Western region, the average natural gas production sales price increased $0.06 per Mcf, or 3%, to $1.96, increasing net operating revenues by approximately $1.8 million. The average Appalachian natural gas production sales price remained flat to last year at $2.53. The overall weighted average natural gas production sales price increased $0.06 per Mcf, or 3%, to $2.22, increasing revenues by $3.9 million.
The volume of crude oil sold in the year increased by 279 Mbbls, or 43%, to 929 Mbbls, increasing net operating revenues by $3.6 million. The volume increase was largely due to production from the Oryx acquisition. Crude oil prices rose $4.16 per Bbl, or 32%, to $17.22, resulting in an increase to net operating revenues of approximately $3.8 million.
The brokered natural gas margin decreased $1.2 million to $4.4 million. The primary cause was a $0.04 per Mcf reduction to net margin that resulted in a $2.0 million revenue decline. The effect of the lower margin was partially offset by a 6.5 Bcf volume increase, resulting in a $0.8 million increase in brokered natural gas margin.
Excluding the selected items regarding the sales contract monetization and the Section 29 tax credit provision, other net operating revenues decreased $1.3 million to $5.4 million. The decline was a result of decreases in activity in the following areas:
- Transportation revenue declined $0.6 million. - Revenue from our brine treatment plants declined $0.3 million. - Natural gas liquid sales declined $0.2 million due to lower activity levels during 1999. - Section 29 revenues decreased slightly due to normal production decline.
COSTS AND EXPENSES. Total costs and expenses from operations, excluding the selected item related to the impairment of long-lived assets, increased $6.6 million, or 5%, from 1998 due primarily to the following:
- Direct operating expense increased $3.1 million, or 10%, primarily as a result of the incremental cost of operating the Oryx properties acquired in December 1998. On a units-of-production basis, direct operating expense was $0.47 per Mcfe in 1999 versus $0.44 per Mcfe in 1998. - Exploration expense decreased $8.1 million, or 41%, primarily as a result of: o A $5.5 million reduction in dry hole costs from 1998, largely due to a smaller drilling program in 1999 that resulted in seven dry holes compared to 12 dry holes in 1998. o A $2.2 million decrease in geological and geophysical costs over last year largely due to a decline in seismic acquisition costs in the Appalachian region. - Depreciation, depletion, amortization and impairment expense, excluding the select item related to the FAS 121 impairment, increased $11.7 million, or 26%, over 1998. This increase was due to costs associated with the Oryx properties, as well as higher finding costs in 1998 on certain fields in the Gulf Coast region that were largely related to mechanical difficulties associated with drilling. A 4% increase in total natural gas equivalent production, including a 59% production increase in the higher finding cost Gulf Coast region, is the other major component of the DD&A increase. - General and administrative expenses decreased $1.8 million, or 8%, due to: o Lower non-cash stock compensation expense for stock awards ($1.2 million). o Lower outside consulting services ($0.6 million).
Interest expense increased $7.2 million primarily due to the debt increase for the Oryx acquisition in December 1998 and to partially fund the 1998 drilling program.
Income tax expense was up $1.7 million due to the comparable increase in earnings before income tax.
Gain on the sale of assets totaled $4 million for 1999 compared to $0.5 million in 1998. These gains are the result of the non-strategic asset divestitures, primarily the sale of the Clarksburg properties in the Appalachian region to EnerVest effective October 1999.
1998 AND 1997 COMPARED
NET INCOME AND REVENUES. We reported net income in 1998 of $1.9 million, or $0.08 per share, down $21.3 million, or $0.92 per share, compared to 1997. Net operating revenue of $159.6 million was down $25.5 million, or 14%, from 1997. Natural gas sales of $138.9 million accounted for 87% of net operating revenue in 1998. The decrease in net operating revenue was the result of a 15% decline in realized natural gas prices and a 35% reduction in realized oil prices. Operating income and net income were similarly impacted by the decrease in energy commodity prices along with higher expenses attributable to our increased exploration program.
In the Gulf Coast region, natural gas production volume was up 2.2 Bcf, or 26%, to 10.6 Bcf due to results of the 1997 and 1998 drilling programs, and in part to the December 1998 acquisition of the Oryx properties. While production increased over 1997 levels, the region did experience drilling delays and mechanical failures in a significant field that deferred production into 1999 but left the field's total reserves substantially unchanged. Natural gas production volume in the Western region was up 0.7 Bcf, or 2%, to 30.9 Bcf due to increases in Rocky Mountains area production. This increase was the result of both the 1997 purchase of oil and gas producing properties located in the Green River Basin of Wyoming, and new wells brought on-line. Natural gas production volume was down 2.6 Bcf, or 10%, to 22.7 Bcf in the Appalachian region due to the September 1997 sale of producing properties located in northwest Pennsylvania, which we refer to as the Meadville properties.
The average natural gas sales price for the year in the Gulf Coast region decreased $0.37 per Mcf, or 15%, to $2.15, reducing net operating revenue by $3.9 million on 10.6 Bcf of production. In the Western region, the average natural gas sales price decreased $0.24 per Mcf, or 11%, to $1.90, decreasing net operating revenues by $7.4 million on 30.9 Bcf of production. The average natural gas sales price decreased $0.47 per Mcf, or 16%, to $2.53 in the Appalachian region, decreasing net operating revenues by approximately $10.7 million on 22.7 Bcf of production. The overall weighted average natural gas production sales price for the year decreased $0.37 per Mcf, or 15%, to $2.16.
Crude oil and condensate sales increased by 76 Mbbls, or 13%, increasing revenue by $1.5 million over 1997. This increase was due to new production brought on-line, combined with December production from the Oryx properties. However, the 1998 average crude oil price declined 35% from 1997 levels, reducing oil revenue by $4.5 million.
Brokered natural gas margin was up $1.4 million to $5.5 million due to a 26% volume increase over 1997, combined with a $0.01 per Mcf increase in the net margin to $0.13 per Mcf.
OPERATING EXPENSES. Total operating expenses increased $11.3 million, or 9%, to $132.7 million. In December 1998, we recognized a $0.9 million reorganization charge designed to reduce future operating expenses. The reorganization charge was comprised of $0.4 million in direct operating expense, $0.3 million in exploration expense, and $0.2 million in general and administrative expense. The reorganization reduced the number of our employees by 6%. The significant changes in operating expenses are explained as follows:
- Direct operations expense increased $0.9 million, or 3%, due primarily to the $0.4 million direct operations component of the reorganization charge in the fourth quarter and $0.5 million in higher workover costs incurred primarily in the Gulf Coast region. - Exploration expense increased $5.7 million, or 41%, due to: o A $1.5 million increase in geological and geophysical activity including seismic data purchases and consulting fees. o A $2.3 million increase in dry hole cost, resulting from our expanded drilling efforts in the Gulf Coast region where wells are generally drilled at higher costs. o A $1.4 million increase in exploration personnel-related expenses such as salaries, benefits and relocation charges associated with the increase in the exploration program. o $0.3 million for the exploration expense component of the reorganization that was expensed in December 1998. - Depreciation, depletion, amortization and impairment expense increased $2.1 million, or 5%, primarily due to the amortization of a lease option purchased in the second quarter of 1998 related to a joint venture with Union Pacific Resources in the Gulf Coast region. Additionally, this expense increased in part due to higher units of production expense in connection with increased production.
- General and administrative expense increased $2.2 million primarily due to: o $0.5 million for staffing increases in the third and fourth quarters of 1997. o $0.7 million for non-cash stock compensation for stock awards. o $0.5 million accrued for certain executive retirement and severance packages. o $0.3 million due to higher relocation and travel expenses. o $0.2 million recorded for the general and administrative component of the reorganization in December 1998.
Interest expense increased $0.6 million, or 4%, due to higher levels of debt outstanding on our revolving credit facility.
Income tax expense was down $14.1 million due to the comparable decrease in earnings before income tax. Included in income tax expense was the interest charged by the Internal Revenue Service on a deferred tax gain related to the monetization of the Section 29 credits. This interest amount was $0.3 million in 1998 and $0.5 million in 1997.
ITEM 7A.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
Oil and gas prices fluctuate widely, and low prices for an extended period of time are likely to have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for natural gas and, to a lesser extent, oil. Declines in oil and gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil and gas prices also may reduce the amount of oil and gas that we can produce economically. Historically, oil and gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Oil and gas prices declined substantially in 1998 and, despite recent improvement, could decline again. Because our reserves are predominantly natural gas, changes in natural gas prices may have a particularly significant impact on our financial results.
Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control. These factors include:
- The domestic and foreign supply of oil and natural gas. - The level of consumer product demand. - Weather conditions. - Political conditions in oil producing regions, including the Middle East. - The ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls. - The price of foreign imports. - Actions of governmental authorities. - Domestic and foreign governmental regulations. - The price, availability and acceptance of alternative fuels. - Overall economic conditions.
These factors and the volatile nature of the energy markets make it impossible to predict with any certainty the future prices of oil and gas.
In order to reduce our exposure to short-term fluctuations in the price of oil and natural gas, we sometimes enter into hedging arrangements. Our hedging arrangements apply to only a portion of our production and provide only partial price protection against declines in oil and gas prices. These hedging arrangements may expose us to risk of financial loss and limit the benefit to us of increases in prices. Please read the discussion below related to commodity price swaps and Note 11 of the Notes to the Consolidated Financial Statements for a more detailed discussion of our hedging arrangements.
COMMODITY PRICE SWAPS
From time to time, we enter into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of our production. These derivatives are not held for trading purposes. Under these price swaps, we receive a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures. During 1999, we fixed the price at an average of $2.64 per Mmbtu on quantities totaling 3,530,000 Mmbtu, representing 5% of the natural gas production for the period. The notional volume of the crude oil swap transactions was 306,000 Bbls at a price of $20.65 per Bbl, which represents approximately one-third of our total oil production for 1999. During 1998 and 1997 we did not enter into any fixed price swaps to hedge oil or natural gas production.
We use price swaps to hedge the natural gas price risk on brokered transactions. Typically, we enter into contracts to broker natural gas at a variable price based on the market index price. However, in some circumstances, some of our customers or suppliers request that a fixed price be stated in the contract. After entering into these fixed price contracts to meet the needs of our customers or suppliers, we may use price swaps to effectively convert these fixed price contracts to market-sensitive price contracts. These price swaps are held by us to their maturity and are not held for trading purposes.
During 1999, 1998 and 1997, we entered into price swaps with total notional quantities of 4,040,800, 2,226,000 and 1,416,000 Mmbtu, respectively, related to our brokered activities, representing 7%, 5% and 4%, respectively, of our total volume of brokered natural gas sold.
As of the years ending December 31, 1999, and 1998, we had open natural gas and oil price swap contracts as follows:
Financial derivatives related to natural gas reduced revenues by $0.1 million in 1999 and $0.3 million in 1998. These revenue reductions were offset by higher realized revenue on the underlying physical gas sales.
We had open oil price swap contracts as follows:
Financial derivatives related to crude oil reduced revenue by $0.8 million during 1999. This revenue reduction was offset by higher realized revenue on the underlying physical oil sales. There were no crude oil price swaps outstanding at December 31, 1998, or 1997.
We are exposed to market risk on these open contracts, to the extent of changes in market prices of natural gas and oil. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged.
In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). SFAS 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities and measured at fair value. In addition, all hedging relationships must be designated, documented and continually reassessed. This statement is effective for financial statements for fiscal years beginning after June 15, 2000. The Company has not yet completed its evaluation of the impact of the provisions from SFAS 133 on its financial position or results of operations.
FAIR MARKET VALUE OF FINANCIAL INSTRUMENTS
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable and accounts payable approximate fair value. We use available marketing data and valuation methodologies to estimate fair value of debt.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF MANAGEMENT
The management of Cabot Oil & Gas Corporation is responsible for the preparation and integrity of all information contained in the annual report. The consolidated financial statements are prepared in conformity with generally accepted accounting principles and, accordingly, include certain informed judgments and estimates of management.
Management maintains a system of internal accounting and managerial controls and engages internal audit representatives who monitor and test the operation of these controls. Although no system can ensure the elimination of all errors and irregularities, the system is designed to provide reasonable assurance that assets are safeguarded, transactions are executed in accordance with management's authorization, and accounting records are reliable for financial statement preparation.
An Audit Committee of the Board of Directors, consisting of directors who are not employees of the Company, meets periodically with management, the independent accountants and internal audit representatives to obtain assurances to the integrity of the Company's accounting and financial reporting and to affirm the adequacy of the system of accounting and managerial controls in place. The independent accountants and internal audit representatives have full and free access to the Audit Committee to discuss all appropriate matters.
We believe that the Company's policies and system of accounting and managerial controls reasonably assure the integrity of the information in the consolidated financial statements and in the other sections of the annual report.
Ray R. Seegmiller Chairman of the Board, Chief Executive Officer and President
March 10, 2000
REPORT OF INDEPENDENT ACCOUNTANTS
TO THE STOCKHOLDERS AND BOARD OF DIRECTORS OF CABOT OIL & GAS CORPORATION:
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Cabot Oil & Gas Corporation and its subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers LLP
Houston, Texas February 11, 2000
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
CONSOLIDATED BALANCE SHEET
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
- ---------- The accompanying notes are an integral part of these consolidated financial statements.
CABOT OIL & GAS CORPORATION
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION
Cabot Oil & Gas Corporation and its subsidiaries are engaged in the exploration, development, production and marketing of natural gas and, to a lesser extent, crude oil and natural gas liquids. The Company also transports, stores, gathers and purchases natural gas for resale. The Company operates in one segment, natural gas and oil exploration and exploitation within the continental United States.
Comprehensive income for all periods presented is equal to net income, since the Company has no other comprehensive income items.
The consolidated financial statements contain the accounts of the Company after eliminating all significant intercompany balances and transactions.
PIPELINE EXCHANGES
Natural gas gathering and pipeline operations normally include exchange arrangements with customers and suppliers. The volumes of natural gas due to or from the Company under exchange agreements are recorded at average selling or purchase prices, as the case may be, and are adjusted monthly to reflect market changes. The net value of exchanged natural gas is included in inventories in the consolidated balance sheet.
PROPERTIES AND EQUIPMENT
The Company uses the successful efforts method of accounting for oil and gas producing activities. Under this method, acquisition costs for proved and unproved properties are capitalized when incurred. Exploration costs, including geological and geophysical costs, the costs of carrying and retaining unproved properties and exploratory dry hole drilling costs, are expensed. Development costs, including the costs to drill and equip development wells, and successful exploratory drilling costs to locate proved reserves are capitalized.
The impairment of unamortized capital costs is measured at a lease level and is reduced to fair value if it is determined that the sum of expected future net cash flows is less than the net book value. The Company determines if an impairment has occurred through either adverse changes or as a result of the annual review of all fields. During the fourth quarter of 1999, the Company experienced a significant production decline from the Chimney Bayou field located in the Texas Gulf Coast. This decline along with an unsuccessful workover in the Lawson field in Louisiana resulted in a $7 million impairment of long-lived assets. The impairment was measured based on discounted cash flows utilizing a discount rate appropriate for risks associated with the related properties.
Capitalized costs of proved oil and gas properties, after considering estimated dismantlement, restoration and abandonment costs, net of estimated salvage values, are depreciated and depleted on a field basis by the units-of-production method using proved developed reserves. The costs of unproved oil and gas properties are generally combined and amortized over a period that is based on the average holding period for such properties and the Company's experience of successful drilling. Properties related to gathering and pipeline systems and equipment are depreciated using the straight-line method based on estimated useful lives ranging from 10 to 25 years. Certain other assets are also depreciated on a straight-line basis.
Future estimated plug and abandonment costs are accrued over the productive life of the oil and gas properties on a units-of-production basis. The accrued liability for plug and abandonment costs are included in accumulated depreciation, depletion and amortization.
Costs of retired, sold or abandoned properties that make up a part of an amortization base (partial field) are charged to accumulated depreciation, depletion and amortization if the units-of-production rate is not significantly affected. Accordingly, a gain or loss, if any, is recognized only when a group of proved properties (entire field) that make up the amortization base has been retired, abandoned or sold.
REVENUE RECOGNITION AND GAS IMBALANCES
The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers. Natural gas production operations may include joint owners who take more or less than the production volumes entitled to them on certain properties. Production volume is monitored to minimize these natural gas imbalances. A natural gas imbalance liability is recorded in other liabilities in the consolidated balance sheet if the Company's excess takes of natural gas exceed its estimated remaining recoverable reserves for these properties.
INCOME TAXES
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to turn around. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change.
NATURAL GAS MEASUREMENT
The Company records estimated amounts for natural gas revenues and natural gas purchase costs based on volumetric calculations under its natural gas sales and purchase contracts. Variances or imbalances resulting from such calculations are inherent in natural gas sales, production, operation, measurement, and administration. Management does not believe that differences between actual and estimated natural gas revenues or purchase costs attributable to the unresolved variances or imbalances are material.
ACCOUNTS PAYABLE
This account includes credit balances to the extent that checks issued have not been presented to the Company's bank for payment. These credit balances included in accounts payable were $5.9 million at December 31, 1999, and $9.1 million at December 31, 1998.
RISK MANAGEMENT ACTIVITIES
From time to time, the Company enters into derivative contracts, such as natural gas price swaps, as a hedging strategy to manage commodity price risk associated with its inventories, production or other contractual commitments. These transactions are executed for purposes other than trading. Gains or losses on these hedging activities are generally recognized over the period that the inventory, production or other underlying commitment is hedged as an offset to the specific hedged item. Cash flows related to any recognized gains or losses associated with these hedges are reported as cash flows from operations. If a hedge is terminated prior to expected maturity, gains or losses are deferred and included in income in the same period that the underlying production or other contractual commitment is delivered. Unrealized gains or losses associated with any derivative contracts not considered a hedge would be recognized currently in the results of operations.
A derivative instrument qualifies as a hedge if:
- The item to be hedged exposes the Company to price risk. - The derivative reduces the risk exposure and is designated as a hedge at the time the Company enters into the contract. - At the inception of the hedge and throughout the hedge period there is a high correlation between changes in the market value of the derivative instrument and the fair value of the underlying item being hedged.
When the designated item associated with a derivative instrument matures, is sold, extinguished or terminated, derivative gains or losses are recognized as part of the gain or loss on the sale or settlement of the underlying item. When a derivative instrument is associated with an anticipated transaction that is no longer expected to occur or if correlation no longer exists, the gain or loss on the derivative is recognized currently in the results of operations to the extent the market value changes in the derivative have not been offset by the effects of the price changes on the hedged item since the inception of the hedge. See Note 11 Financial Instruments for further discussion.
In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). SFAS 133 requires all derivatives to be recognized in the statement of financial position as either assets or liabilities and measured at fair value. In addition, all hedging relationships must be designated, documented and continually reassessed. This statement is effective for financial statements for fiscal years beginning after June 15, 2000. The Company has not yet completed its evaluation of the impact of the provisions from SFAS 133 on its financial position or results of operations.
CASH EQUIVALENTS
The Company considers all highly liquid short-term investments with original maturities of three months or less to be cash equivalents. At December 31, 1999, and 1998, the majority of cash and cash equivalents is concentrated in one financial institution. The Company periodically assesses the financial condition of the institution and believes that any possible credit risk is minimal.
USE OF ESTIMATES
The preparation of financial statements that conform with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The Company's most significant financial estimates are based on the remaining proved oil and gas reserves (see Supplemental Oil and Gas Information). Actual results could differ from those estimates.
2. PROPERTIES AND EQUIPMENT
Properties and equipment are comprised of the following:
As a component of accumulated depreciation, depletion and amortization, total future plug and abandonment costs, accrued on a units-of-production basis, were $11.5 million at December 31, 1999, and $11.6 million at December 31, 1998. The Company believes that this accrual method adequately provides for its estimated future plug and abandonment costs over the reserve life of the oil and gas properties.
3. ADDITIONAL BALANCE SHEET INFORMATION
Certain balance sheet amounts are comprised of the following:
4. INVENTORIES
Inventories are comprised of the following:
5. DEBT AND CREDIT AGREEMENTS
10.18% NOTES
In May 1990, the Company issued an aggregate principal amount of $80 million of its 12-year 10.18% Notes (10.18% Notes) to a group of nine institutional investors in a private placement offering. The 10.18% Notes require five annual $16 million principal payments each May starting in 1998. The payment due in May 2000, classified as "Current Portion of Long-Term Debt," is a current liability on the Company's Consolidated Balance Sheet. The Company may prepay all or any portion of the debt at any time with a prepayment penalty. The 10.18% Notes contain restrictions on the merger of the Company or any subsidiary with a third party except under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments, including a restriction on the payment of dividends and a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0.
7.19% NOTES
In November 1997, the Company issued an aggregate principal amount of $100 million of its 12-year 7.19% Notes (7.19% Notes) to a group of six institutional investors in a private placement offering. The 7.19% Notes require five annual $20 million principal payments starting in November 2005. The Company may prepay all or any portion of the indebtedness on any date with a prepayment penalty. The 7.19% Notes contain restrictions on the merger of the Company or any subsidiary with a third party other than under certain limited conditions. There are also various other restrictive covenants customarily found in such debt instruments, including a required asset coverage ratio (present value of proved reserves to debt and other liabilities) that must be at least 1.5 to 1.0, and a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0.
REVOLVING CREDIT AGREEMENT
In November 1998, the Company replaced its $135 million Revolving Credit Agreement that utilized five banks with a new $250 million Revolving Credit Agreement (Credit Facility) with 10 banks. The term of the Credit Facility is five years and expires on December 17, 2003. The available credit line is subject to adjustment from time-to-time on the basis of the projected present value (as determined by the banks' petroleum engineer) of estimated future net cash flows from certain proved oil and gas reserves and other assets of the Company. While the Company does not expect a change in the available credit line, in the event that it is adjusted below the outstanding level of borrowings, the Company has a period of 180 days to reduce its outstanding debt to the adjusted credit line. The Credit Facility also includes a requirement to pay down half of the debt in excess of the adjusted credit line within the first 90 days of such an adjustment. Interest rates are principally based on a reference rate of either the rate for certificates of deposit (CD rate) or LIBOR, plus a margin, or the prime rate. For CD rate and LIBOR borrowings, interest rates are subject to increase if the indebtedness under the Credit
Facility is either greater than 60% or 80% of the Company's debt limit of $400 million, as shown below.
The Credit Facility provides for a commitment fee on the unused available balance at an annual rate one-fourth of 1% or three-eighths of 1% depending on the level of indebtedness as indicated above. The Company's effective interest rates for the Credit Facility in the years ended December 31, 1999, 1998 and 1997 were 6.7%, 6.8% and 6.6%, respectively. The Credit Facility contains various customary restrictions, which are the following:
(a) Prohibiting the merger of the Company or any subsidiary with a third party except under certain limited conditions (b) Prohibiting the sale of all or substantially all of the Company's or any subsidiary's assets to a third party (c) Requiring a minimum annual coverage ratio of operating cash flow to interest expense for the trailing four quarters of 2.8 to 1.0
6. EMPLOYEE BENEFIT PLANS
PENSION PLAN
The Company has a non-contributory, defined benefit pension plan for all full-time employees. Plan benefits are based primarily on years of service and salary level near retirement. Plan assets are mainly fixed income investments and equity securities. The Company complies with the Employee Retirement Income Security Act of 1974 and Internal Revenue Code limitations when funding the plan.
The Company has a non-qualified equalization plan to ensure payments to certain executive officers of amounts to which they are already entitled under the provisions of the pension plan, but which are subject to limitations imposed by federal tax laws. This plan is unfunded.
Net periodic pension cost of the Company for the years ended December 31, 1999, 1998 and 1997 are comprised of the following:
The following table illustrates the funded status of the Company's pension plans at December 31, 1999, and 1998, respectively:
The change in the combined projected benefit obligation of the Company's qualified and non-qualified pension plans during the last three years is explained as follows:
The change in the combined plan assets at fair value of the Company's qualified and non-qualified pension plans during the last three years is explained as follows:
The reconciliation of the combined funded status of the Company's qualified and non-qualified pension plans at the end of the last three years is explained as follows:
Assumptions used to determine post-retirement benefit obligations and pension costs are as follows:
- ---------- (1) Represents the rate used to determine the benefit obligation. A 7.0% discount rate was used to compute pension costs in 1999, and a rate of 7.5% was used in 1998 and 1997.
SAVINGS INVESTMENT PLAN
The Company has a Savings Investment Plan (SIP) which is a defined contribution plan. The Company matches a portion of employees' contributions. Participation in the SIP is voluntary and all regular employees of the Company are eligible to participate. The Company charged to expense plan contributions of $0.7 million, $0.8 million and $0.6 million in 1999, 1998 and 1997, respectively. The Company's Common Stock is an investment option within the SIP.
DEFERRED COMPENSATION PLAN
In 1998, the Company established a Deferred Compensation Plan. This plan is available to officers of the Company and acts as a supplement to the Savings Investment Plan. The Company matches a portion of the employee's contribution and those assets are invested in instruments selected by the employee. Unlike the SIP, the Deferred Compensation Plan does not have dollar limits on tax deferred contributions. However, the assets of this plan are held in a rabbi trust and are subject to additional risk of loss in the event of bankruptcy or insolvency of the Company. At December 31, 1999, the balance in the Deferred Compensation Plan's rabbi trust was $1.15 million.
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees, including their spouses, eligible dependents and surviving spouses (retirees). These benefits are commonly called postretirement benefits. Most employees become eligible for these benefits if they meet certain age and service requirements at retirement. The Company was providing postretirement benefits to 250 retirees at the end of 1999 and 251 retirees at the end of 1998.
When the Company adopted SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," in 1992, it began amortizing the $16.9 million accumulated postretirement benefit, known as the Transition Obligation, over a period of 20 years.
The amortization benefit of the unrecognized Transition Obligation in 1998 and 1997, presented in the table below, is due to a cost-cutting amendment to the postretirement medical benefits in 1993. The amendment prospectively reduced the unrecognized Transition Obligation by $9.8 million and was amortized over a 5.75 year period beginning in 1993 and ending in 1998.
Postretirement benefit costs recognized during the last three years are as follows:
The health care cost trend rate used to measure the expected cost in 1999 for medical benefits to retirees over age 65 was 8%, graded down to a trend rate of 0% in 2001. The health care cost trend rate used to measure the expected cost in 1999 for retirees under age 65 was also 8%, graded down to a trend rate of 0% in 2001. Provisions of the plan should prevent further increases in employer cost after 2001.
A one-percentage-point increase or decrease in health care cost trend rates for future periods would similarly increase or decrease the accumulated net postretirement benefit obligation by approximately $61,000 and, accordingly, the total postretirement benefit cost recognized in 1999 would have also increased or decreased by approximately $13,000.
The funded status of the Company's postretirement benefit obligation at December 31, 1999, and 1998 is comprised of the following:
The change in the accumulated postretirement benefit obligation during the last three years is explained as follows:
7. INCOME TAXES
Income tax expense is summarized as follows:
In the table above, the $4.5 million refund received in 1999 that applied to a net operating loss carryback to 1997 is reflected in "Current - Federal". The 1998 "Current - Federal" amount includes the effect of a $2.0 million income tax refund received in 1998 that applied to a net operating loss carryback to 1992.
Total income taxes were different than the amounts computed by applying the statutory federal income tax rate as follows:
The tax effects of temporary differences that resulted in significant portions of the deferred tax liabilities and deferred tax assets as of December 31, 1999, and 1998 were as follows:
- ---------- (1) As a result of the monetization of Section 29 tax credits in 1996 and 1995, the Company recorded an asset sale for tax purposes in exchange for a long-term note receivable which will be repaid through 100% working and royalty interest in the production from the sold properties.
At December 31, 1999, the Company has a net operating loss carryforward for regular income tax reporting purposes of $51.2 million that will begin expiring in 2011. In addition, the Company has an alternative minimum tax credit carryforward of $3.0 million which does not expire and can be used to offset regular income taxes in future years to the extent that regular income taxes exceed the alternative minimum tax in any year.
8. COMMITMENTS AND CONTINGENCIES
LEASE COMMITMENTS
The Company leases certain transportation vehicles, warehouse facilities, office space, and machinery and equipment under cancelable and non-cancelable leases. Most of the leases expire within five years and may be renewed. Rent expense under such arrangements totaled $5.0 million, $4.3 million and $4.1 million for the years ended December 31, 1999, 1998 and 1997, respectively. In 1998, the Company entered into a 10-year lease agreement for office space in Houston, Texas, to house the corporate offices and the Gulf Coast regional offices. The lease term commenced in August 1999 for annual rent expense of approximately $2.6 million when the Company occupied the new office space, at which time the lease on the former office space ended.
Future minimum rental commitments under non-cancelable leases in effect at December 31, 1999 are as follows:
Minimum rental commitments are not reduced by minimum sublease rental income of $0.9 million due in the future under non-cancelable subleases.
CONTINGENCIES
The Company is a defendant in various lawsuits and is involved in other gas contract issues. In the Company's opinion, final judgments or settlements, if any, which may be awarded in connection with any one or more of these suits and claims could have a significant impact on the results of operations and cash flows of any period. However, there would not be a material adverse effect on the Company's financial position.
9. CASH FLOW INFORMATION
Cash paid for interest and income taxes is as follows:
At December 31, 1999, and 1998, the Accounts Payable balance on the Consolidated Balance Sheet included payables for capital expenditures of $10.1 million and $20.2 million, respectively.
10. CAPITAL STOCK
INCENTIVE PLANS
On May 12, 1998, the Amended and Restated 1994 Long-Term Incentive Plan and the Amended and Restated 1994 Non-Employee Director Stock Option Plan were approved by the shareholders. The Company has two other stock option plans: the 1990 Incentive Stock Option Plan and the 1990 Non-Employee Director Stock Option Plan. Under these four plans (Incentive Plans), incentive and non-statutory stock options, stock appreciation rights (SARs) and stock awards may be granted to key employees and officers of the Company, and non-statutory stock options may be granted to non-employee directors of the Company. A maximum of 3,860,000 shares of Common Stock, par value $0.10 per share, may be issued under the Incentive Plans. All stock options have a maximum term of five or 10 years from the date of grant, with most vesting over time. The options are issued at market value on the date of grant. The minimum exercise period for stock options is six months from the date of grant. No SARs have been granted under the Incentive Plans.
Information regarding the Company's Incentive Plans is summarized below:
For each of the three most recent years, the price range for outstanding options was $13.25 to $26.00 per share. The following tables provide more information about the options by exercise price and year.
Options with exercise prices between $13.25 and $20.00 per share:
Options with exercise prices between $20.01 and $26.00 per share:
Under the Amended and Restated 1994 Long-Term Incentive Plan, the Compensation Committee of the Board of Directors may grant awards of performance shares of stock to members of the executive management group. Each grant of performance shares has a three-year performance period, measured as the change from July 1 of the initial year of the performance period to June 30 of the third year. The number of shares of Common Stock received at the end of the performance period is based mainly on the relative stock price growth between the two measurement dates of Common Stock compared to that of a group of peer companies. The performance shares that were granted on July 1, 1994, expired on June 30, 1997, without issuing any Common Stock of the Company. The performance shares granted in July 1995 were converted to 21,692 shares of the Company's Common Stock in 1998, and the performance shares granted in July 1996 were converted to 19,090 shares of the Company's Common Stock in 1999. The Board of Directors has not issued performance shares since July 1996 and, currently, there are no performance shares outstanding.
Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based Compensation," outlines a fair value based method of accounting for stock options or similar equity instruments. The Company has opted to continue using the intrinsic value based method, as recommended by Accounting Principles Board (APB) Opinion No. 25, to measure compensation cost for its stock option plans.
If the Company had adopted SFAS 123, the pro forma results of operations would be as follows:
- ---------- (1) Calculated using the fair value based method.
The fair value of stock options included in the pro forma results for each of the three years is not necessarily indicative of future effects on net income and earnings per share.
DIVIDEND RESTRICTIONS
The Board of Directors of the Company determines the amount of future cash dividends, if any, to be declared and paid on the Common Stock depending on, among other things, the Company's financial condition, funds from operations, the level of its capital and exploration expenditures, and its future business prospects. The Company's 10.18% Note Agreement restricts certain payments associated with the following:
(a) Purchasing, redeeming, retiring or otherwise acquiring any capital stock of the Company or any option, warrant or other right to acquire such capital stock. (b) Declaring any dividend, if immediately prior to or after making payments, the dividend exceeds consolidated net cash flow (as defined) and the ratio of proved reserves to debt is less than 1.7 to 1, or there has been an event of default under the Note Agreement.
As of December 31, 1999, these restrictions did not impact the Company's ability to pay regular dividends. The 7.19% Note Agreement issued in 1997 does not have a restricted payment provision.
TREASURY STOCK
In August 1998, the Board of Directors authorized the Company to repurchase up to two million shares of outstanding Common Stock at market prices. The timing and amount of these stock purchases are determined at the discretion of management. The Company may use the repurchased shares to fund stock compensation programs presently in existence, or for other corporate purposes. As of December 31, 1998, the Company had repurchased 302,600 shares, or 15% of the total authorized number of shares, for a total cost of approximately $4.4 million. No additional shares were repurchased during 1999. The stock repurchase plan was funded from increased borrowings on the revolving credit facility. No treasury shares were delivered or sold by the Company during the year.
PURCHASE RIGHTS
On January 21, 1991, the Board of Directors adopted the Preferred Stock Purchase Rights Plan and declared a dividend distribution of one right for each outstanding share of Common Stock. Each right becomes exercisable, at a price of $55, when any person or group has acquired, obtained the right to acquire or made a tender or exchange offer for beneficial ownership of 15 percent or more of the Company's outstanding Common Stock. An exception to the right occurs following a tender or exchange offer for all outstanding shares of Common Stock determined to be fair and in the best interests of the Company and its stockholders by a majority of the independent Continuing Directors (as defined in the plan). Each right entitles the holder, other than the acquiring person or group, to purchase one one-hundredth of a share of Series A Junior Participating Preferred Stock (Junior Preferred Stock), or to receive, after certain triggering events, Common Stock or other property having a market value (as defined in the plan) of twice the exercise price of each right. The rights become exercisable if the Company is acquired in a merger or other business combination in which it is not the survivor, or 50 percent or more of the Company's assets or earning power are sold or transferred. Once it becomes exercisable, each right entitles the holder to purchase common stock of the acquiring company with a market value (as defined in the plan) equal to twice the exercise price of each right. At December 31, 1999, and 1998, there were no shares of Junior Preferred Stock issued or outstanding.
The rights, which expire on January 21, 2001, and the exercise price are subject to adjustment and may be redeemed by the Company for $0.01 per right at any time before they become exercisable. Under certain circumstances, the Continuing Directors may opt to exchange one share of Common Stock for each exercisable right.
PREFERRED STOCK
At December 31, 1999, and 1998, 1,134,000 shares of 6% convertible redeemable preferred stock (6% preferred stock) were issued and outstanding. Each share has voting rights equal to approximately 1.7 shares of Common Stock and a stated value of $50. At any time, the stock is convertible by the holder into Common Stock at a conversion price of $28.75 per share. While the 6% preferred stock does not have a mandatory redemption requirement, it is redeemable for cash at $50 per share plus accrued dividends due on the shares redeemed.
The Company has entered into a letter agreement with the holder of the 6% preferred stock to repurchase these shares before November 1, 2000, for a total price of $51.6 million. Cash flow from operations, additional borrowings or proceeds from the sale of equity may be used to fund this transaction. The value of these shares on the Company's balance sheet is $56.7 million. This repurchase will retire all of the preferred stock outstanding and will simplify the Company's capital structure.
The Company had 692,439 shares of $3.125 cumulative convertible preferred stock ($3.125 preferred stock) issued and outstanding until October 1997 when these shares were converted into 1,648,664 shares of Common Stock. Each share had a stated value of $50 and could be converted any time by the holder into Common Stock at a conversion price of $21 per share. While there was no mandatory requirement, these shares could also be redeemed under certain provisions and fixed redemption prices. The Company had the option to convert the $3.125 preferred stock into shares of Common Stock valued at the conversion price if the closing price of the Common Stock was at least equal to the conversion price for 20 consecutive trading days.
11. FINANCIAL INSTRUMENTS
The estimated fair value of financial instruments is the amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value. The Company uses available marketing data and valuation methodologies to estimate fair value of debt.
LONG-TERM DEBT
The fair value of long-term debt is the estimated cost to acquire the debt, including a premium or discount for the difference between the issue rate and the year-end market rate. The fair value of the 10.18% Notes and the 7.19% Notes is based on interest rates currently available to the Company. The Credit Facility approximates fair value because this instrument bears interest at rates based on current market rates.
COMMODITY PRICE SWAPS
From time to time, the Company enters into natural gas and crude oil swap agreements with counterparties to hedge price risk associated with a portion of its production. These derivatives are not held for trading purposes. Under these price swaps, the Company receives a fixed price on a notional quantity of natural gas and crude oil in exchange for paying a variable price based on a market-based index, such as the NYMEX gas and crude oil futures.
The Company uses price swaps to hedge the natural gas price risk on brokered transactions. Typically, the Company enters into contracts to broker natural gas at a variable price based on the market index price. However, in some circumstances, some customers or suppliers request that a fixed price be stated in the contract. After entering into these fixed price contracts to meet the needs of customers or suppliers, the Company may use price swaps to effectively convert these fixed price contracts to market-sensitive price contracts. These price swaps are held to their maturity and are not held for trading purposes.
As of the years ending December 31, 1999, and 1998, the Company had open natural gas and oil price swap contracts as follows:
Financial derivatives related to natural gas reduced revenues by $0.1 million in 1999 and by $0.3 million in 1998. These revenue reductions were offset by higher realized revenue on the underlying physical gas sales.
We had open oil price swap contracts as follows:
Financial derivatives related to crude oil reduced revenue by $0.8 million during 1999. This revenue reduction was offset by higher realized revenue on the underlying physical oil sales. There were no crude oil price swaps outstanding at December 31, 1998 or 1997.
For a detailed discussion about derivative instruments, please read Item 7A, "Quantitative and Qualitative Disclosures about Market Risk" in the Company's Form 10-K.
CREDIT RISK
Although notional contract amounts are used to express the volume of natural gas price agreements, the amounts that can be subject to credit risk in the event of non-performance by third parties are substantially smaller. The Company does not anticipate any material impact on its financial results due to non-performance by the third parties. The Company had no sales to any customer that exceeded 10% of total gross revenues in 1999 or 1998.
12. OIL AND GAS PROPERTY TRANSACTIONS
In September and December 1999, the Company purchased oil and gas producing properties in the Moxa Arch of the Green River Basin in southwest Wyoming for $8.9 and $8.5 million, respectively. The assets included approximately 16 Bcfe of proved reserves, approximately 43,000 undeveloped net acres, and 27 wells producing a net 3.8 Mmcfe per day at the time of the acquisition.
Also in September 1999, the Company sold non-strategic oil and gas properties located in Pennsylvania and West Virginia to EnerVest Appalachia, L.P. for approximately $46 million. These properties represented 716 wells and 62.2 Bcfe of proved reserves. A portion of this transaction and the two previously mentioned were completed as a tax-deferred exchange deferring a taxable gain of $8.9 million.
In the second quarter of 1999, the Company sold certain non-strategic properties in the Gulf Coast region's Provident City field. These properties were producing 3.5 Mmcfe per day from eight wells. The sales price was $9 million, and the transaction contributed to a gain of approximately $1.0 million on the Company's second quarter income statement.
Effective December 1, 1998, the Company purchased onshore southern Louisiana properties and 3-D seismic inventory from Oryx Energy Company for approximately $70.1 million. The purchased assets included 10 fields covering over 34,000 net acres with 68 producing wells. Total proved reserves are approximately 72 Bcfe. This transaction was funded by the Company's newly expanded revolving line of credit. See discussion in Note 5 Debt and Credit Agreements.
In the fourth quarter of 1998, the Company purchased oil and gas producing properties in the Lookout Wash Unit of Wyoming from Oxy USA, Inc. for $5.2 million. The properties acquired included 11.2 Bcfe of proved reserves and more than 10 potential drilling locations. Additionally in 1998, the Company acquired oil and gas producing properties in Oklahoma during the second quarter for $6.6 million. Included in the purchase were 9.3 Bcfe of proved reserves, 10 wells and undeveloped acreage.
In the fourth quarter of 1997, the Company closed two notable asset transactions. Properties in Northwest Pennsylvania (the Meadville properties), including 912 wells and 15 Mmcfe per day of production, were sold to Lomak Petroleum Incorporated (now known as Range Resources Corporation) for $92.9 million. In a like-kind exchange transaction, the Company matched a portion of the Meadville properties sold with approximately $45 million in oil and gas producing properties acquired from Equitable Resources Energy Company, including 63 wells and 10 Mmcfe per day of production.
13. OTHER REVENUE
The Company had a 15-year cogeneration contract under which approximately 20% of the Western region natural gas was sold per year. The contract was due to expire in 2008, but during 1999 the Company reached an agreement with the counterparty under which the counterparty bought out the remainder of the contract for $12 million. This transaction was completed in December 1999, adding $12 million of pre-tax other revenue. Simultaneously, Cabot Oil & Gas sold forward a similar quantity of Western region gas for the next 16 months at prices similar to those in the monetized contract.
Since 1995, other revenue has included an income source generated from two transactions in September and November 1995 and a third transaction in August 1996 to monetize the value of Section 29 tax credits (monetized credits) from most of our qualifying Appalachian and Rocky Mountains properties. The transactions provided up-front cash of $2.8 million in 1995 and $0.6 million in 1996, which was recorded as a reduction to the net book value of natural gas properties. Revenue from these monetized credits was $1.3 million in 1999, $2.7 million in 1998 and $3.6 million in 1997. These transactions are expected to generate future revenues through 2002 of $5.4 million. Using a volumetric production payment structure, the production, revenues, expenses and proved reserves for these properties will continue to be reported by the Company as Other Revenue until the production payment is satisfied.
During 1999, an industry tax court ruling concluded that the Section 29 tight sands tax credits would not be available on wells not certified by the FERC. Because the FERC discontinued the certification process for qualifying wells in 1992, there is currently no avenue to obtain the well certifications. Accordingly, the Company stopped recording revenue on non-certified wells and established a reserve related to previously recorded amounts on these wells. This resulted in a $1.2 million reduction to other revenue in 1999.
14. SUPPLEMENTAL FULL COST ACCOUNTING INFORMATION
U.S. oil and gas producing entities may utilize one of two methods of financial accounting: successful efforts or full cost. Given the current composition of the Company's properties, management considers the successful efforts method to be more appropriate than the full cost method primarily because the successful efforts method results in moderately better matching of costs and revenues. It has come to management's attention that certain users of the Company's financial statements believe that information about the Company prepared under the full cost method would also be useful. As a result, the following supplemental full cost information is also included.
Successful efforts methodology is explained in Note 1 Summary of Significant Accounting Policies.
Under the full cost method of accounting, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized. These capitalized costs and estimated future development and dismantlement costs are amortized on a units-of-production method based on proved reserves. Net capitalized costs of oil and gas properties are limited to the lower of unamortized cost or the cost center ceiling, defined as the following:
- The present value (10% discount rate) of estimated unescalated future net revenues from proved reserves, plus - The cost of properties not being amortized, plus - The lower of cost or estimated fair value of unproved properties included in the costs being amortized, minus - The deferred tax liabilities for the temporary differences between the book and tax basis of oil and gas properties
Proceeds from the sale of oil and gas properties are applied to reduce the costs in the cost center unless the sale involves a significant quantity of reserves in relation to the cost center. In this case, a gain or loss is recognized. Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties totaled $32.3 million, $42.4 million and $24.6 million at December 31, 1999, 1998 and 1997, respectively.
Because of the capital cost limitations described above, full cost entities are not subject to the impairment test prescribed by SFAS 121.
The full cost method of accounting allows for the capitalization of general and administrative, region office and interest expense. Pre-tax capitalizable administrative expenses were $4.6 million in 1999, $4.6 million in 1998 and $4.2 million in 1997. Pre-tax capitalizable interest expense was $2.7 million in 1999, $2.0 million in 1998 and $1.4 million in 1997.
15. EARNINGS PER COMMON SHARE
Full year basic earnings per share for the Company were $0.21, $0.08 and $1.00 in 1999, 1998 and 1997, respectively, and were based on the weighted average shares outstanding of 24,726,030 in 1999, 24,733,465 in 1998, and 23,272,432 in 1997. Diluted earnings per share for the Company were $0.21, $0.08 and $0.97 in 1999, 1998 and 1997, respectively. The diluted earnings per share amounts are based on weighted average shares outstanding plus common stock equivalents. Common stock equivalents include stock awards and stock options, and totaled 225,177 in 1999, 372,937 in 1998 and 649,632 in 1997.
Both the $3.125 cumulative convertible preferred stock and the 6% convertible redeemable preferred stock issued May 1993 and May 1994, respectively, had an antidilutive effect on earnings per common share. The preferred stock was determined not to be a common stock equivalent when it was issued. As such, no adjustments were made to reported net income in the computation of earnings per share. The Company, under the provisions of the stock, converted the $3.125 cumulative convertible preferred stock to Common Stock in October 1997. See Note 10 Capital Stock for further discussion.
16. SUBSEQUENT EVENT
The Company was notified by the EPA in February 2000 that it may have potential liability for waste material disposed of at the Casmalia Superfund Site ("Site), located on a 252-acre parcel in Santa Barbara County, California. Over 10,000 separate parties disposed of waste at the Site while it was operational from 1973 to 1989. The EPA stated that federal, state and local governmental agencies along with the numerous private entities that used the Site for waste disposal will be expected to pay for the clean-up costs which could total as much as several hundred million dollars. The EPA is also pursuing the owner(s)/operator(s) of the Site to pay for remediation.
The total amount of environmental investigation and cleanup costs that the Company may incur with respect to the foregoing is not known at this time and, accordingly, we have not recorded a reserve related to this possible liability. While the potential impact to the Company may materially affect the quarterly or annual financial results, management does not believe it would materially impact the Company's financial position.
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
OIL AND GAS RESERVES
Users of this information should be aware that the process of estimating quantities of "proved" and "proved developed" natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made.
Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.
Estimates of proved and proved developed reserves at December 31, 1999, 1998 and 1997 were based on studies performed by the Company's petroleum engineering staff. The estimates were reviewed by Miller and Lents, Ltd., who indicated in their letter dated February 4, 2000, that based on their investigation and subject to the limitations described in their letter, they believe the results of those estimates and projections were reasonable in the aggregate.
No major discovery or other favorable or unfavorable event after December 31, 1999, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
The following table illustrates the Company's net proved reserves, including changes, and proved developed reserves for the periods indicated, as estimated by the Company's engineering staff. All reserves are located in the United States.
CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES
The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization.
COSTS INCURRED IN OIL AND GAS PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES
Costs incurred in property acquisition, exploration and development activities were as follows:
HISTORICAL RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The results of operations for the Company's oil and gas producing activities were as follows:
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
The following information has been developed utilizing SFAS 69 procedures and based on natural gas and crude oil reserve and production volumes estimated by the Company's engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account when reviewing the following information:
- Future costs and selling prices will probably differ from those required to be used in these calculations. - Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations. - Selection of a 10% discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues. - Future net revenues may be subject to different rates of income taxation.
Under the Standardized Measure, future cash inflows were estimated by applying year-end oil and gas prices adjusted for fixed and determinable escalations to the estimated future production of year-end proved reserves.
The average prices related to proved reserves at December 31, 1999, 1998 and 1997 were for natural gas ($ per Mcf) $2.36, $2.26 and $2.62, respectively, and for oil ($ per Bbl) $24.15, $10.23 and $19.02, respectively. Future cash inflows were reduced by estimated future development and production costs based on year-end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year-end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved. SFAS 69 requires the use of a 10% discount rate.
Management does not use only the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of probable as well as proved reserves, and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.
Standardized Measure is as follows:
- ---------- (1) Includes the future cash inflows, production costs and development costs, as well as the tax basis, relating to the properties included in the transactions to monetize the value of Section 29 tax credits. See Note 13 of the Notes to the Consolidated Financial Statements. (2) Future income taxes before discount were $457,256, $446,980 and $582,639 for the years ended December 31, 1999, 1998 and 1997, respectively. (3) Future income tax expense decreased as a result of tax benefits realized on property acquisitions and drilling activity late in 1998.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
The following is an analysis of the changes in the Standardized Measure:
CABOT OIL & GAS CORPORATION
SELECTED DATA (UNAUDITED)
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
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 under the caption "Election of Directors" in the Company's definitive Proxy Statement in connection with the 2000 annual stockholders' meeting is incorporated by reference.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information under the caption "Executive Compensation" in the definitive Proxy Statement is incorporated by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information under the captions "Beneficial Ownership of Over Five Percent of Common Stock" and "Beneficial Ownership of Directors and Executive Officers" in the definitive Proxy Statement is incorporated 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
1. Consolidated Financial Statements
See Index on page 34.
2. Financial Statement Schedules
None.
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
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 18th of March 2000.
CABOT OIL & GAS CORPORATION
By: /s/ Ray Seegmiller ------------------------------------- Ray Seegmiller Chairman of the Board, Chief Executive Officer 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.