ITEM 1. BUSINESS
THE COMPANY AND ITS SUBSIDIARIES
Consolidated Natural Gas Company is a Delaware corporation organized on July 21, 1942, and a public utility holding company registered under the Public Utility Holding Company Act of 1935. It is engaged solely in the business of owning and holding all of the outstanding equity securities of sixteen directly owned subsidiary companies.
Consolidated Natural Gas Company and its subsidiaries ("Consolidated" or the "Company") at December 31, 1993, are listed below. The subsidiary companies are engaged in, and their total operating revenues are derived from, all phases of the natural gas business -- exploration, production, purchasing, gathering, transmission, storage, distribution, and marketing, together with by-product operations (see Note 2 to the Financial Statements, page 57). At December 31, 1993, Consolidated had 7,625 regular employees.
The principal cities served at retail by Consolidated's gas distribution subsidiaries (East Ohio Gas, River Gas, West Ohio Gas, Peoples Natural Gas, Virginia Natural Gas and Hope Gas) are: Cleveland, Akron, Youngstown, Canton, Warren, Lima, Ashtabula and Marietta in Ohio; Pittsburgh (a portion), Altoona and Johnstown in Pennsylvania; Norfolk, Newport News, Virginia Beach, Chesapeake, Hampton and Williamsburg in Virginia; and Clarksburg and Parkersburg in West Virginia. At December 31, 1993, Consolidated served at retail approximately 1,777,000 residential, commercial and industrial gas sales customers in Ohio, Pennsylvania, Virginia and West Virginia. With 98 percent of their residential and commercial customers using gas for space heating, variations in weather conditions can materially affect the volume of gas delivered by the distribution subsidiaries of the Company.
ITEM 1. BUSINESS (Continued)
CNG Transmission is the Company's interstate gas transmission subsidiary. CNG Transmission operates a regional interstate pipeline system serving each of the Company's distribution subsidiaries, and nonaffiliated utility and end-user customers in the Midwest, the Mid-Atlantic states and the Northeast. Regulatory efforts intended to increase competition in the natural gas industry have resulted in significant changes in the operations of CNG Transmission over the past several years. Under the most recent regulatory initiative, Federal Energy Regulatory Commission ("FERC") Order 636, interstate pipeline companies, including CNG Transmission, were required to revise customer contracts and service tariffs and further "unbundle" their services into separate sales, transportation and storage transactions, with such services offered and priced separately. CNG Transmission implemented FERC Order 636 on October 1, 1993 (see "FERC Order 636," page 39) and thereby abandoned its traditional "bundled" sales service. CNG Transmission now offers a number of gas transportation and storage service options, along with related services, to a broad range of customers. Because a substantial part of its gas deliveries is ultimately used by space-heating customers, variations in weather conditions can materially affect the volume of gas transported and stored by CNG Transmission.
Through its wholly owned subsidiary, CNG Iroquois, Inc., CNG Transmission holds a 9.4 percent general partnership interest in the Iroquois Gas Transmission System, L.P., a Delaware limited partnership formed to construct, own and operate an interstate natural gas pipeline extending from the Canada-United States border near Iroquois, Ontario, to Long Island, New York. The Iroquois pipeline transports Canadian gas to utility and power generation customers in metropolitan New York and New England.
CNG Producing is Consolidated's exploration and production subsidiary. Gas and oil exploration and production activities are conducted by this subsidiary primarily in the Gulf of Mexico, the southern and western United States, the Appalachian region, and in Canada. In addition, CNG Producing participates in coalbed methane projects throughout the United States.
CNG Energy develops new business opportunities for the Company in energy-re- lated markets. It invests in and develops independent power producer projects and conducts a gas liquids business.
CNG Gas Services (formerly CNG Trading Company) is Consolidated's unregulated gas marketing subsidiary. CNG Gas Services markets a portion of Company-owned production and, during 1993, began offering the equivalent of the "bundled" services previously provided by CNG Transmission. CNG Gas Services offers an array of gas sales, transportation, storage and other services that can be arranged separately or in various combinations to meet the individual needs of customers in the post-Order 636 environment.
CNG Storage was formed to engage in providing natural gas storage facilities and a wide range of storage-related services to affiliates and other customers, including the sale or lease of base gas, and the sale, lease or brokerage of gas storage capacity obtained from third parties.
Consolidated LNG was organized to import and regasify liquefied natural gas ("LNG") for sale to CNG Transmission. However, Consolidated LNG has ended its involvement in LNG operations and is currently recovering its undepreciated investment in LNG-related facilities, plus carrying charges and taxes, through a FERC approved amortization surcharge.
CNG Research administers the Company's proprietary research activities. Amounts spent on research activities in the calendar years 1991 through 1993 by all of the subsidiary companies were not material.
CNG Coal owns Consolidated's coal reserves and a related plant site. The Company's recoverable raw coal reserves are approximately 615 million tons, as estimated by John T. Boyd Company, Mining and Geological Engineers. Most of these coal reserves are located in Greene County, Pennsylvania, principally in the Sewickley and Pittsburgh coal seams. The Company has various options under review with respect to these properties.
ITEM 1. BUSINESS (Continued)
Service Company is a subsidiary service company, authorized by the Securities and Exchange Commission ("SEC") under the Public Utility Holding Company Act of 1935 ("PUHCA"). It advises and assists the other subsidiary companies on administrative and technical matters and manages centralized activities and facilities for their benefit. It also provides services to the Parent Company.
CNG Financial was formed to engage in certain financing transactions, but has not yet engaged in any such transactions.
GOVERNMENTAL REGULATION
The Company and its subsidiaries are subject to regulation by the SEC pursuant to the PUHCA.
CNG Transmission and Consolidated LNG are "natural-gas companies" subject to the Natural Gas Act of 1938, as amended. Their sales in interstate commerce for resale and interstate transportation and storage activities are regulated under such Act and are made in accordance with gas tariffs and service agreements on file with the FERC. The distribution subsidiaries of the Company are subject to regulation by the respective utility commissions in the states within which they operate.
Certain subsidiaries are subject to various provisions of the five statutes which are referred to as the National Energy Act of 1978. One of these statutes, the Natural Gas Policy Act of 1978 ("NGPA"), established maximum lawful wellhead prices for various categories of natural gas and provided for decontrol of certain natural gas prices at various times. However, the Decontrol Act of 1989 effected the total decontrol of natural gas wellhead prices on January 1, 1993. Another statute, the National Energy Conservation Policy Act, requires utilities to offer home energy audits and other assistance to residential customers.
The Natural Gas Pipeline Safety Act of 1968 (which, among other things, author- izes the establishment and enforcement of federal pipeline safety standards) subjects the interstate pipeline of CNG Transmission to the safety jurisdiction of the Department of Transportation. Intrastate facilities remain within the safety jurisdiction of the state regulatory agencies, presuming compliance by such agencies with certain prerequisites contained in such Act.
Consolidated is subject to the provisions of various federal laws dealing with the protection of the environment. In addition, the subsidiary companies are subject to the environmental laws and regulations of state and local governmental authorities in the areas within which the subsidiaries have operations or facilities. Reference is made to "Environmental Matters" on page 42, and to Notes 15 and 16 to the Financial Statements, for additional information on environmental-related matters. (See "LEGAL PROCEEDINGS," page 25.)
CAPITAL EXPENDITURES
Consolidated's current capital budget for 1994 is estimated at $439.6 million, a 28 percent increase over the $342.6 million spent in 1993. The 1994 budget reflects increased projected expenditures for all of the Company's major business components.
Expenditures for the exploration and production operations are estimated to be $153.0 million in 1994, up from $110.7 million in 1993. The higher amount in 1994 includes funds for development of the "Popeye" deep-water project in the Gulf of Mexico, and provides for an increased level of exploratory drilling. Distribution operations spending in 1994 is expected to be $141.8 million, compared with $115.4 million in 1993. The increased level of spending will allow for continued growth, as well as improvements in the gas distribution system and related facilities. Although the multi-year expansion program of the transmission operations is substantially complete, the Company continues to make
ITEM 1. BUSINESS (Continued)
enhancements to its pipeline network to better serve customers. Transmission expenditures in 1994 are budgeted at $124.4 million, up from $113.4 million spent in 1993. The 1994 capital budget also includes $17.9 million in connection with CNG Energy's investment in the Lakewood cogeneration project in New Jersey.
CNG Transmission and certain of the Company's distribution subsidiaries are subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments of 1990 ("1990 amendments") which added significantly to the existing requirements established by the Federal Clean Air Act. These subsidiaries operate compressor stations that are covered by the new nitrogen oxide emission standard established as a result of the 1990 amendments. The Company will have until May 31, 1995, to comply with the emission standard. The Company expects that compliance will require significant capital expenditures to modify the compressor engines along the Company's pipeline system. However, the actual cost of compliance will be dependent upon the requirements imposed by the environmental agencies of the states in which the compressor stations are located. Based on the Company's preliminary estimates and analyses, approximately $46 million of capital expenditures may be required over the next two years. The actual amounts required to comply with the 1990 amendments are expected to be recoverable through future regulatory proceedings.
Consolidated's capital budget will be reviewed during the year in light of market conditions and is subject to revision. (See "Capital Spending," page 44.)
COMPETITIVE CONDITIONS
Various regulatory and market trends have combined to increase competition for Consolidated in recent years, and for the gas industry in general. The factors affecting the Company include regulatory efforts, such as the FERC's various initiatives to increase competition in the industry; the overall availability of gas nationwide; competition from local producers and other sellers and brokers of gas for the retail and wholesale markets; competition with existing and proposed pipelines, and projects to import gas from Canada and other foreign countries; and competition with other energy forms, such as electricity, fuel oil and coal.
RESTRUCTURING OF INTERSTATE PIPELINE INDUSTRY
During 1993, the final portion of the FERC's plan to restructure the interstate natural gas pipeline industry was set in motion as pipeline companies began implementing the provisions of FERC Order 636. Similar to previous FERC actions to enable more direct access to gas supplies and open access to pipeline transportation systems, Order 636 has significantly increased competition in the natural gas industry. Order 636 required interstate pipelines, including CNG Transmission, to "unbundle" their services into separate sales, transportation and storage services and to offer and price such services separately. In the restructured marketplace, local gas utilities and large-volume end-users, including former pipeline sales customers, now bear all the responsibilities and risks for arranging the procurement of their gas supplies and contracting with pipelines to transport purchases. Other significant changes required by Order 636 included a basic change in the way rates are designed. Under the new rate design, return on equity and related income taxes are recovered as part of a fixed monthly charge. Previously, these costs were recovered through usage or commodity rates. As the result of Order 636, each pipeline company was required to revise its customer contracts and service tariffs. The Order allows pipelines to recover 100 percent of all prudently incurred costs resulting from the transition to the new rules. CNG Transmission implemented FERC Order 636 on October 1, 1993 (see "FERC Order 636," page 39) and thereby abandoned its traditional "bundled" sales service. CNG Transmission now offers a number of gas transportation and storage service options, along with related services, to a broad range of customers.
ITEM 1. BUSINESS (Continued)
The restructuring of the interstate natural gas pipeline industry has also affected the distribution subsidiaries. Industrial and large commercial gas users now purchase a large portion of their gas supplies directly from producers, from marketers, or on the spot market. The distribution subsidiaries have, for the most part, however, been able to retain these customers by providing transportation service for such supplies. The most significant effect on local distribution companies of Order 636 has been on their gas supply procurement and storage practices. Since bundled pipeline sales service is no longer available, these companies now bear all the responsibilities and risks for arranging the acquisition, delivery and storage of their own gas supplies. As a result of previous FERC initiatives, Consolidated's distribution subsidiaries have been managing a part of their own gas supplies for the last several years. Therefore, the transition to the more competitive environment under Order 636 did not have a significant impact on their operations. Additionally, as a result of Order 636, storage facilities owned and operated by the Company's distribution and transmission operations as well as storage capacity acquired will be even more important factors in gas supply management.
Also, as a result of the restructuring, gas producers throughout the industry, including CNG Producing, now face a more diverse and active market with purchasers seeking to balance the advantage of lower-cost spot market supplies with the security of higher-priced, longer-term contracts.
DISTRIBUTION
Consolidated's distribution subsidiaries generally operate in long-established service areas and have extensive facilities already in place. Growth in the Company's traditional service areas in Ohio, Pennsylvania and West Virginia is limited in that natural gas is already the fuel of choice for heating and for most significant industrial applications. These areas have experienced minimal population growth in the past, and almost all customers have become more energy efficient, resulting in lower gas usage per customer. In addition, the economies of these areas, which were formerly based mainly on heavy industry, have diversified with increased emphasis on high technology and service oriented firms.
However, opportunities for growth in the Company's distribution operations are expected to continue at Virginia Natural Gas. This subsidiary offers the potential for future growth through its expanding service territory and the prospect of conversion of space-heating customers and commercial and industrial applications to gas. The completion in 1992 of the intrastate pipeline in Virginia has provided Virginia Natural Gas and its customers with new gas supply sources through access to Consolidated's transmission system and storage facilities, and has afforded additional opportunities for growth in both gas sales and transportation, especially in the power generation markets.
The Clean Air Act may also provide opportunities for increased throughput in the Company's distribution markets. Consolidated is promoting the use of natural gas as a means for industrial customers and electric generators to reduce emissions. The Clean Air Act and the more recent Energy Policy Act of 1992 contain a number of provisions relating to the use of alternative fuel vehicles. Consolidated is participating in various programs to demonstrate the advantages and environmental benefits of natural gas powered vehicles.
The Company's distribution markets continue to be competitive. As the gas industry has restructured and government regulations have changed, a marketplace has evolved with new and traditional competitors -- the usual oil and electric companies, other gas companies, local producers seeking to gain direct access to the Company's customers, and gas brokers and dealers seeking to supplant supplies with spot market gas. Natural gas faces price competition with other energy forms, and certain of the distribution companies' industrial customers have the ability to switch to fuel oil or coal if desired. Local distribution companies operate in what are essentially dual markets -- a traditional utility market, where a utility has an obligation to provide service and offers a "bundled" package of services to all
ITEM 1. BUSINESS (Continued)
customers; and a "contract" market, where obligations are defined by contract terms and large customers can elect individually or in various combinations whatever gas supplies, storage and/or transportation services they require. Consolidated has responded to this competitive environment by offering an expanded range of services to its customers. The Company's distribution subsidiaries now routinely provide a variety of firm and interruptible services, including gas transportation, storage, supply pooling and balancing, and brokering, to industrial and commercial customers.
TRANSMISSION
CNG Transmission operates a regional interstate pipeline system with the principal pipeline and storage facilities located in Ohio, Pennsylvania, West Virginia and New York. Regulatory efforts intended to increase competition in the natural gas industry have resulted in significant changes in the operations of CNG Transmission over the past several years. Beginning with open access transportation and culminating with the significant service restructuring required by FERC Order 636, the role of the Company's transmission operations has changed from primarily that of a merchant, or wholesaler, of gas to one that provides a wide range of services. Although CNG Transmission no longer provides its traditional bundled sales service, it continues to offer gas transportation, storage and related services to its affiliates, as well as to utilities and end-users in the Northeast, Mid-Atlantic and Mid-West regions of the country.
The changing regulatory policies have provided CNG Transmission and other pipeline companies with unique opportunities for expansion. CNG Transmission has directed its expansion efforts toward potential high-volume, weather- sensitive markets and areas with growing power generation needs. This expansion has occurred in many directions, with particular emphasis on Northeast and East Coast markets. CNG Transmission's large underground storage capacity and the location of its pipeline system as a link between the country's major gas pipelines and large markets on the East Coast have been key factors in the success of these expansion efforts.
CNG Transmission competes with domestic as well as Canadian pipeline companies and gas marketers seeking to provide or arrange transportation, storage and other services for customers. Also, certain end users have the ability to switch to fuel oil or coal if desired. Although competition is based primarily on price, the range of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain longline pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system, enables CNG Transmission to tailor its services to meet the individual needs of customers.
On October 1, 1993, CNG Transmission implemented Order 636 in accordance with the terms of a comprehensive settlement reached with customers and others (see "FERC Order 636," page 39). CNG Transmission's former wholesale sales customers now have the responsibility and risk inherent in contracting for their own gas supplies. However, since customers have greater access to the Company's pipeline and storage capacity, both increased gas transportation and storage service are expected to help offset the impact of lower gas sales. Consolidated continues to provide the equivalent of bundled services through its unregulated marketing subsidiary, CNG Gas Services. This company offers a range of gas sales, transportation, storage and other service options that can be arranged separately or in various combinations to meet the individual needs of customers.
EXPLORATION AND PRODUCTION
Consolidated's exploration and production operations are conducted by CNG Producing in several of the major gas and oil producing basins in the United States, both onshore and offshore. In this highly competitive business, Consolidated competes with a large number of companies ranging in size from large international oil companies with extensive financial resources to small, cash flow-driven independent producers.
ITEM 1. BUSINESS (Continued)
CNG Producing faces significant competition in the bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. Since CNG Producing is the operator of a number of properties, it also faces competition in securing drilling equipment and supplies for exploration and development. From the production perspective, the marketing of gas and oil is also highly competitive with price being the most significant factor. When the economics warrant, Consolidated attempts to sell its gas production under long- term contracts to customers such as electric power generators and others that require a secure source of supply. These arrangements generally command a premium over spot market prices. Further, the implementation by pipeline companies of the FERC's Order 636 could impact the deliverability of gas produced due to increased competition for limited downstream pipeline transportation capacity. In response to the unbundling of sales services previously offered by pipelines, CNG Producing and CNG Gas Services have taken actions to expand and diversify the Company's customer base. These subsidiaries continue to develop new marketing strategies and contracts to address customer needs for intermediate and long-term gas supplies as well as other services in the post-Order 636 era.
The exploration for and production of gas and oil is subject to various federal and state laws and regulations which may, among other things, limit well drilling activity and volumes produced. Changes in these laws and regulations can impact Consolidated's exploration and production operations.
GAS SUPPLY
GENERAL INFORMATION
Consolidated's gas supply is obtained from various sources including: purchases from major and independent producers in the Southwest and Midwest regions; purchases from local producers in the Appalachian area; purchases from gas marketers; purchases on the spot market; production from Company-owned wells in the Appalachian area, the Southwest, and the Midwest; and withdrawals from the Company's underground storage fields.
Regulatory actions, economic factors, and changes in customers and their preferences over the past several years have reshaped the Company's gas sales markets. A significant number of industrial customers and some commercial customers now purchase a large portion of their gas supplies from producers, marketers, or on the spot market, and contract with the Company's transmission and distribution subsidiaries for transportation and other services. Since these customers are less reliant on the distribution subsidiaries for sales service, the volume of gas that these subsidiaries must obtain to meet sales requirements has been reduced. In addition, the implementation of FERC Order 636 by CNG Transmission in effect removed that subsidiary from its merchant role thereby eliminating its need to purchase gas for resale. The former merchant service contracted for by wholesale customers was converted to transportation and storage services in 1993. Since CNG Transmission no longer provides traditional sales service, its former sales customers, including the Company's distribution subsidiaries, now have the responsibility and risk for obtaining their own gas supplies.
Consolidated's available gas supply in 1993 was again in a surplus position -- where available supplies exceed sales requirements. Considering the Company's large storage capacity, the volumes obtainable under its gas purchase contracts, Company-owned gas reserves, and assuming the future availability of spot market gas, the Company believes that supplies will be available to meet requirements for several years. Gas supply statistics for the past five years are on page 13.
ITEM 1. BUSINESS (Continued)
GAS PURCHASED
Purchased gas volumes were 485.2 billion cubic feet in 1993, representing 75 percent of the Company's total 1993 gas supply of 648.2 billion cubic feet. Spot market gas purchases were 392.2 billion cubic feet, or about 61 percent of the total 1993 supply. Volumes purchased under contracts with producers, primarily in the Appalachian area, totaled 79.4 billion cubic feet, or 12 percent of the 1993 supply. Purchases from pipeline companies were 13.6 billion cubic feet in 1993, or 2 percent of the 1993 supply.
In response to the regulatory and market changes over the past several years, the Company has been converting its long-term gas purchase contracts with interstate pipelines to firm transport contracts. As a result of these contract conversions, gas volumes purchased from the pipeline companies have declined and have been replaced, in large part, with contracts directly with producers and lower-cost spot market gas. As pipelines implemented FERC Order 636 in 1993, the Company's remaining long-term purchase contracts with these companies were converted to firm transportation.
While spot market gas supplies have historically been obtained at lower prices, the availability of spot market gas supplies to distribution companies can be severely impacted by sudden swings in supply and demand. The distribution subsidiaries now must weigh the benefits of generally lower-cost spot market purchases with the security of longer-term contract arrangements. To ensure a secure supply in the post-Order 636 market, the Company's distribution subsidiaries anticipate purchasing a larger portion of their gas supplies directly from producers on a firm basis. Although the volume of gas obtained on the spot market by the distribution subsidiaries is expected to decline, spot market gas will continue to be an important part of the Company's supply mix, particularly for CNG Gas Services.
Gas purchased from producers and on the spot market is delivered to the subsidiaries using their firm transport capacity on interstate pipelines. At December 31, 1993, the subsidiaries had 425 billion cubic feet of firm transport capacity on upstream pipelines, yielding deliveries of up to 1,174 million cubic feet a day. These upstream pipelines include Tennessee Gas Pipeline Company, Panhandle Eastern Pipe Line Company, Texas Eastern Transmission Corporation, ANR Pipeline Company, Texas Gas Transmission Corporation, Transcontinental Gas Pipe Line Corporation and Columbia Gas Transmission Corporation.
GAS STORAGE
Consolidated's vast underground storage complex plays an important part in balancing gas supply with sales demand and is essential to servicing the Company's large volume of space heating business. The Company operates 26 underground gas storage fields located in Ohio, Pennsylvania, West Virginia and New York. The Company owns 21 of these storage fields and has joint-ownership with other companies in 5 of the fields. The total designed capacity of the storage fields is approximately 885 billion cubic feet. The Company's share of the total capacity is about 669 billion cubic feet. About one-half of the total capacity is base gas which remains in the reservoirs at all times to provide the primary pressure which enables the balance of the gas to be withdrawn as needed.
CNG Transmission operates 710 billion cubic feet of the total storage capacity and owns 503 billion cubic feet of the Company's capacity. CNG Transmission utilizes a large portion of its turnable capacity to provide approximately 252 billion cubic feet of gas storage service for others. This service is provided to pipelines and utilities whose primary service areas are along the East Coast. CNG Transmission also provides storage service to affiliates, end-users and to many of its former wholesale gas sales customers.
ITEM 1. BUSINESS (Continued)
Two of the Company's distribution subsidiaries, East Ohio Gas and Peoples Natural Gas, own and operate the remaining 166 billion cubic feet of storage capacity. In addition to owning their own storage, these companies, as well as most of the Company's other subsidiaries have ready access to a part of the storage capacity operated by CNG Transmission. Certain distribution subsidiaries also have capacity available in storage fields owned by others. In the post-Order 636 environment, available storage capacity will be an important element in the effective management of both gas supply and pipeline transport capacity.
Consolidated controls other acreage in the Appalachian area suitable for the development of additional storage facilities which would enable further expansion of capacity to meet possible future storage needs.
GAS AND OIL PRODUCING ACTIVITIES
Over the past several years, Consolidated's exploration and production operations have been affected by the generally adverse conditions in the industry. The effects of persistent warm weather, the lingering gas oversupply situation, and low gas and oil wellhead prices have all contributed to a difficult operating environment. Also during this time, the level of capital spending for exploration and development activities was reduced as a greater proportion of capital resources was devoted to the Company's pipeline expansion projects. As a result of these conditions, Consolidated reduced its exploration and production activities. During 1992, natural gas market conditions improved as spot market prices rebounded after falling to a low of about $1.00 per thousand cubic feet in February 1992. The improving conditions continued in 1993 as gas prices firmed generally above $2.00. Conditions in oil markets, however, worsened during 1993.
Consolidated's gas wellhead prices in 1993 averaged $2.24 a thousand cubic feet, up from $2.05 in 1992. Gas wellhead prices were strong throughout most of 1993 and were above 1992 levels for most of the year. Consolidated's average gas wellhead prices are generally higher, and less volatile than industry spot prices since its average price reflects a mix of longer-term contracts. However, due to market-sensitive contracts, Consolidated's prices generally follow industry trends. Consolidated's average oil wellhead price in 1993 was $15.66 per barrel, down from $18.15 in 1992. Oil prices were weak through most of the year and fell sharply near year-end, reflecting the trend in world prices.
The Company's total gas production in 1993 was 129.5 billion cubic feet, up from 128.0 billion cubic feet produced in 1992. Oil production was 3.9 million barrels, down 13 percent from 4.5 million barrels in 1992. Although gas production was up slightly in 1993, it was limited somewhat due to reduced deliverability at certain properties and the sale of selected properties in the Appalachian area. The lower oil production in 1993 was attributable primarily to normal production declines at older properties.
In light of the difficult industry conditions of the past few years, Consolidated has restructured its exploration and production operations and refocused its efforts into selected geographic areas. These efforts are currently directed to moderate- and low-risk prospects, principally in the Gulf of Mexico.
The Company has also taken steps to address the recent declines in short-term deliverability. During 1993, the Company completed a series of well workovers and a compression project that had been postponed in prior years due to the low level of gas prices. While these efforts have helped restore short-term deliverability, any significant increases will be dependent primarily on future exploratory successes.
ITEM 1. BUSINESS (Continued)
During 1993, Consolidated participated in the drilling of 65 gross wells (22 net), compared with 106 gross wells (68 net) drilled in 1992. The following table sets forth 1993 drilling activity by region: _______________________________________________________________________________ Gross Wells Drilled Exploratory Development _______________________________________________________________________________
Onshore (Southwest and West). . . . . . . 7 32 Gulf of Mexico . . . . . . . . . . . 15 7 Canada . . . . . . . . . . . . . . - 4 __ __ Total. . . . . . . . . . . . . . 22 43 == == _______________________________________________________________________________
Of the total 65 wells in which the Company participated during 1993, 46 were successful, a 71 percent success rate. Of the 22 exploratory wells drilled, 6 were successful.
Although Consolidated's drilling program was reduced in 1993, it resulted in a number of successful completions. An exploratory well drilled at South Marsh Island Block 154 in the Gulf of Mexico resulted in a natural gas and oil discovery. Consolidated is the operator of this property and owns a 50 percent working interest. The South Marsh Island 154 discovery was brought onto production in just seven months by using a refitted production platform from one of the Company's depleted fields. Another significant success in the Gulf in 1993 was at the West Cameron Block 76 field. After doubling the Company's interest in the field to 40 percent in 1992, a new development well resulted in the largest single addition to Consolidated's reserves in 1993. Other successes offshore included wells drilled at Vermilion Block 255 and at West Cameron Block 293.
A large part of the Company's development drilling in 1993 occurred at the Sand Dunes field located in the New Mexico portion of the Permian Basin. Consolidated participated in the drilling of 26 development wells in this area and has added approximately 900 barrels of oil a day to the Company's production. Consolidated's working interest in these wells averaged about 26 percent. Development drilling is expected to continue in this field during 1994.
Also during 1994, development will continue at "Popeye," a deep-water natural gas discovery in the Green Canyon area of the Gulf of Mexico. Consolidated entered into an agreement in 1992 with Shell Offshore, Inc., under which the Company acquired half of Shell's 75 percent interest in this property. In return, Consolidated will pay some $60 million for development of the field. Other participants in the joint venture are Mobil Oil Exploration and Producing Southeast and BP Exploration Inc. Participation in the Popeye project is providing Consolidated access to a new technology and the experience necessary to better evaluate future deep-water opportunities.
Despite difficult industry conditions, Consolidated remains committed to its exploration and production operations. The Company plans to increase its exploration and production spending by 38 percent in 1994 to $153.0 million. The anticipated expenditures include funds for the development of Popeye and provide for an increased level of exploratory drilling.
ITEM 1. BUSINESS (Continued)
Consolidated did not participate in drilling activity in the Appalachian Basin during 1993, and there is no drilling planned for this area in 1994. In the past, gas from this area commanded a higher price because of its location in proximity to major gas markets. However, as a result of industry changes and revised rate structures, pipeline companies can transport gas to these markets at low commodity rates that negate somewhat the location premium associated with these reserves. The Company expects to continue production from these properties and plans to maintain its strong acreage position in the Appalachian Basin. Drilling activity can be resumed with very short lead times if market and economic conditions warrant. Selected Appalachian properties were sold during 1993, but the acreage and reserves were not material.
Total Company-owned proved gas reserves at year-end were 960 billion cubic feet, down from 998 billion cubic feet at the end of 1992. Proved oil reserves were 27.9 million barrels, compared with 29.5 million barrels in 1992. Because of the low level of drilling activity, new reserves added during 1993 were not sufficient to replace the volumes of gas produced during the year. (See "Company-Owned Reserves," page 22.)
Consolidated was the successful bidder on nine leases offered in the federal government's Gulf of Mexico lease sales in 1993, acquiring five blocks off Louisiana and four blocks off Texas. At year-end 1993, Consolidated held 2.6 million net acres of exploration and production properties, down from 2.7 million at year-end 1992. The Company's lease holdings include about 1.8 million net acres in the Appalachian area, 386,000 in the offshore Gulf of Mexico, and 495,700 in the inland areas of the Southwest, Gulf Coast and West.
The Company will continue to review its property inventory during 1994, and sales of selected properties are possible depending on economic conditions. Included in the properties which may be sold is Consolidated's 21 percent interest in heavy oil properties in Alberta, Canada. Proved reserves associated with the Canadian properties approximated 1.1 billion cubic feet of gas and 5.7 million barrels of oil at December 31, 1993. On an energy- equivalent basis, these reserves represent about 3 percent of Consolidated's total proved reserves at that date.
GAS SALES AND TRANSPORTATION
Total gas sales in 1993 were 604 billion cubic feet, up 35 percent from the 449 billion cubic feet sold in 1992. Transportation volumes were 587 billion cubic feet in 1993, a 4 percent decrease from the 613 billion cubic feet transported in 1992. (Five-year statistics are on page 13.)
GAS SALES CUSTOMERS
At December 31, 1993, the Company's distribution subsidiaries served almost 1.7 million residential customers, over 118,000 commercial customers and more than 1,800 industrial customers in Ohio, Pennsylvania, Virginia and West Virginia. _______________________________________________________________________________ Residential Customers Total and Commercial Industrial Wholesale Nonregulated _______________________________________________________________________________ December 31, 1993 1,777,320 1,774,922 1,851 31 516 1992 1,759,428 1,757,139 1,838 32 419 1991 1,738,098 1,735,803 1,849 31 415 1990 1,718,016 1,715,824 1,787 32 373 1989 1,543,845 1,541,680 1,750 36 379 _______________________________________________________________________________
ITEM 1. BUSINESS (Continued)
RESIDENTIAL AND COMMERCIAL SALES
Sales of gas to residential customers in 1993 were 212 billion cubic feet, up 4 billion cubic feet from 1992, while sales to commercial customers were 73 billion cubic feet, virtually unchanged compared with 1992. Residential gas sales volumes increased as slightly colder weather in 1993 resulted in higher gas usage by space-heating customers. The weather in the Company's retail service areas in 1993 was 2 percent colder than in 1992 but still warmer than normal. Also contributing to the increase was the net addition of about 17,800 residential and commercial customers, including about 7,800 at Virginia Natural Gas.
INDUSTRIAL SALES
Industrial sales in 1993 were 12 billion cubic feet, about the same as in 1992. Due to both availability and price, many of the Company's industrial customers now buy gas directly from producers, from marketers, or on the spot market, and contract with the subsidiary companies for transportation service. The total gas deliveries (sales and transportation) to industrial customers was 128 billion cubic feet in 1993, compared with 127 billion cubic feet in 1992.
WHOLESALE SALES
Total wholesale sales were 81 billion cubic feet in 1993, up from 21 billion cubic feet in 1992. The increase in sales volumes was due to the sale by CNG Transmission of approximately 58 billion cubic feet of gas from storage inventory in anticipation of the transition to restructured services under FERC Order 636. These sales, which were made primarily to customers outside the Company's traditional Northern Market area at reduced prices under alternative FERC-approved tariff schedules, increased available capacity to provide future storage service and reduced certain transition costs under Order 636.
NONREGULATED SALES
Nonregulated gas sales in 1993 were 226 billion cubic feet, up from 134 billion cubic feet in 1992. Sales of Company-produced gas to nonaffiliates was 88 billion cubic feet, compared with 109 billion cubic feet in 1992. Gas sales by CNG Gas Services were 100 billion cubic feet in 1993, its first year of operations. Volumes related to gas brokering activity were 38 billion cubic feet in 1993, up from 25 billion cubic feet in 1992.
GAS TRANSPORTATION
Total transportation volumes in 1993 amounted to 587 billion cubic feet, down from 613 billion cubic feet in 1992. Increased wholesale sales volumes, due largely to CNG Transmission's sales from storage inventory prior to its transition to FERC Order 636, was the principal reason for the lower transportation volumes in 1993. In the fourth quarter of 1993, following CNG Transmission's implementation of Order 636, gas transportation volumes increased due primarily to volumes transported for customers in the Northern Market area and Virginia. Total volumes transported by the distribution subsidiaries for commercial, industrial and off-system customers were up 2 billion cubic feet over 1992.
ITEM 1. BUSINESS (Continued)
GAS SALES, SUPPLY AND TRANSPORTATION STATISTICS (Excludes affiliated transactions)
ITEM 1. BUSINESS (Continued)
MARKET EXPANSION
For the past several years Consolidated has pursued a broad program designed to expand its interstate pipeline system and extend its marketing territory. Consolidated's principal objective has been to build long-term supply relationships with customers in the growing markets at the perimeter of its system, markets which offer opportunities for growth in throughput due to their increasing demand for energy. Consolidated has concentrated its transmission expansion efforts toward potentially high-volume, weather sensitive markets and areas with growing power generation needs located primarily in the Northeast and along the East Coast. These markets are particularly attractive in that gas space heating is not yet as widely used in these areas as in the Company's traditional service areas of western Pennsylvania, eastern Ohio, West Virginia and upstate New York. Because of its large gas storage capacity and the location of its gridlike pipeline system in close proximity to these markets, Consolidated has an opportunity to be an important gas supplier to utilities with growing space heating markets and for customers seeking an environmentally clean, efficient fuel for electric generation.
Consolidated is also developing and promoting additional uses for natural gas. These technologies provide opportunities for the use of natural gas in markets that are not sensitive to the weather. The more stringent air quality standards required under the Federal Clean Air Act and the various provisions of the Energy Policy Act of 1992 should help advance the development and use of these and other technologies.
TRANSMISSION EXPANSION
During 1993, the final phase of the expansion of CNG Transmission's interstate pipeline between Lebanon, Ohio, and its storage field at Leidy, Pennsylvania, was completed. This $240 million project was the primary, and largest, component of the Company's $600 million multi-year transmission expansion program. The new pipeline and additional compressor facilities added to this main line will be used to transport up to 370 million cubic feet of gas a day on behalf of Transcontinental Gas Pipe Line Corporation and customers of ANR Pipeline Company for ultimate delivery to East Coast markets.
Also in 1993, CNG Transmission expanded its market area further to the south. On November 1, 1993, CNG Transmission began providing a combination of storage and transportation service to Public Service Company of North Carolina, Inc. Under this 20-year contract, CNG Transmission is providing about 30 million cubic feet of gas a day. Since the Company's pipeline system does not extend into North Carolina, CNG Transmission delivers the gas to Transcontinental Gas Pipe Line Corporation at Nokesville in northern Virginia, and Transcontinental delivers the gas by displacement in North Carolina.
With the transmission construction program essentially complete, the Company is now pursuing new growth opportunities available for its expanded pipeline system. In March 1994, Consolidated announced plans to create a new gas market center that will offer service at points along CNG Transmission's pipeline system to utilities, interstate pipelines, large end-users and marketers throughout the Mid-Atlantic and the East Coast. This market center is being developed by CNG Transmission and Texaco's Sabine Pipe Line Company. The hub is expected to begin operating in 1994 offering services such as intra-hub transfers, parking and wheeling, together with a new service designed to reduce the administrative burden associated with buying and selling gas. These services are designed to help minimize transaction costs and give buyers and sellers more options for trading. The CNG/Sabine Center is expected to further increase throughput and also offer new marketing opportunities for CNG Gas Services.
ITEM 1. BUSINESS (Continued)
TECHNOLOGY-BASED MARKETS
During 1993, Consolidated continued its involvement with a number of relatively new gas burning technologies. These applications provide opportunities to improve customer efficiency while promoting the use of natural gas in market sectors that are not sensitive to the weather or economic downturn. The future advancement of such technologies also appears promising as business entities strive to comply with provisions of the Federal Clean Air Act. This legislation applies strict anti-pollution standards to factories, fleet and mass transit vehicles, and to electric power plants. The law is likely to increase demand for natural gas, but the extent thereof will depend on how the Act is implemented and enforced. Gas demand could also increase as the result of the Energy Policy Act of 1992. This Act requires and encourages large vehicle fleets to operate on alternative fuels such as natural gas. The Energy Policy Act also created a new class of independent power producers exempt from utility regulation, which could lead to the construction of additional gas- fueled generating facilities.
With regard to these market expansion efforts, Consolidated has participated extensively in developing and marketing a technology called "cofiring," in which a small amount of gas is burned along with coal in an electric utility or industrial boiler. Cofiring has resulted in improved boiler efficiency and has reduced certain emissions which are responsible for acid rain. Consolidated is also promoting "reburn," which is a more advanced version of cofiring. Under this technique, natural gas is injected into the upper part of a boiler, creating a fuel-rich zone where nitrogen oxide is transformed into harmless nitrogen.
Consolidated is also pursuing other technological opportunities, including gas cooling equipment, fuel cell power generation, coal drying processes and the promotion of natural gas powered vehicles ("NGVs"). Fleet operators and mass transit authorities are turning to NGVs for both fuel cost efficiencies and as a way to reduce environmental pollution. Despite the environmental benefits of NGVs, it appears unlikely that such vehicles will replace a significant number of gasoline powered vehicles in the near future, given the lack of a nationwide network of refueling facilities and the current cost of retrofitting individual vehicles. However, beginning in 1997, the Clean Air Act could require 22 of the country's most polluted regions to convert a portion of their fleet vehicles to natural gas. Consolidated supplies natural gas to utilities that serve Baltimore, Washington, D.C., and New York, three metropolitan areas directly affected by this provision of the Act.
ITEM 1. BUSINESS (Continued)
RATE MATTERS (See Note 3 to the Financial Statements, page 57.)
The Company's average unit selling price of gas to its customers was $4.33 per thousand cubic feet in 1993, compared with $4.35 in 1992 and $4.29 in 1991. Average sales prices in 1993 were higher for all retail categories and for Company-produced gas. However, CNG Transmission's sales from storage inventory had a significant influence on the overall average unit selling price since such sales were made at lower rates under alternative FERC-approved tariff schedules in anticipation of the implementation of Order 636. The higher average selling price in 1992 compared with 1991 reflects the upward industry trend in gas wellhead prices experienced in 1992.
The Company's utility subsidiaries continue to seek general rate increases on a timely basis to recover increased operating costs and to ensure that rates of return are compatible with the cost of raising capital. In addition to general rate increases, subsidiary companies make separate filings with their respective regulatory commissions to reflect changes in the costs of purchased gas.
The following is a summary of rate activity during 1993 and to date.
CNG TRANSMISSION
In April 1992, the FERC issued Order 636, a comprehensive set of regulations designed to encourage competition and continue the significant restructuring of the interstate natural gas pipeline industry that the FERC first set in motion with its Order 436. As the result of Order 636, each pipeline company was required to revise its customer contracts and service tariffs. On November 2, 1992, CNG Transmission filed with the FERC a revised service tariff complying with the provisions of the Order. On March 31, 1993 (as amended June 15, 1993), CNG Transmission filed a comprehensive stipulation and agreement ("Settlement") which revised substantially the November 2, 1992, filing. On July 16, 1993, the FERC issued an order approving CNG Transmission's amended Settlement, subject to certain modifications, clarifications and justifications. Following a series of Commission orders relating to these matters, CNG Transmission implemented Order 636 in accordance with the terms of the Settlement (Docket No. RS92-14) on October 1, 1993. (See "FERC Order 636," page 39.)
On December 30, 1993, CNG Transmission filed a general rate filing with the FERC requesting an annual revenue increase of $106.6 million. CNG Transmission requested an 11.78 percent overall rate of return and a 14.00 percent return on equity. The rate increase request is intended to cover higher operating costs, increased plant investment, and the recovery of $9.2 million in transition costs related to stranded facilities because of Order 636. The increase is expected to become effective, after the suspension period, on July 1, 1994, subject to refund.
VIRGINIA NATURAL GAS
On June 22, 1993, the Virginia State Corporation Commission approved a $10.4 million annual revenue increase for Virginia Natural Gas. The new rates were effective retroactive to September 4, 1992, and reflect an 11.75 percent return on equity. In its April 1992 filing, Virginia Natural Gas had requested a $14.1 million annual increase in revenues and a 12.25 percent return on equity.
ITEM 1. BUSINESS (Continued)
PEOPLES NATURAL GAS
On October 28, 1993, Peoples Natural Gas filed with the Pennsylvania Public Utility Commission for a $28.4 million increase in base rates. In its filing, Peoples Natural Gas requested a 10.00 percent overall rate of return and a 12.25 percent return on equity. The rate increase request is intended to cover higher operating expenses. If approved, the new rates would become effective on August 6, 1994. Peoples Natural Gas also filed to recover, over four years, $20.1 million in estimated transition costs related to FERC Order 636.
HOPE GAS
On October 29, 1993, the Public Service Commission of West Virginia granted Hope Gas an indicated $1.9 million annual revenue increase effective November 1, 1993. The approved rates reflect an 8.78 percent overall rate of return and a 10.20 percent return on equity. In its March 1993 filing, Hope Gas had requested an $8.2 million increase in revenues and an estimated 12.30 percent return on equity. On November 8, 1993, Hope Gas filed a petition for rehearing in the case.
EAST OHIO GAS
On January 18, 1994, East Ohio Gas filed with the Public Utilities Commission of Ohio ("PUCO") for a $99.1 million increase in base rates. East Ohio Gas is seeking a 10.95 percent overall rate of return and a 12.50 percent return on equity. The rate increase request is intended to cover higher operating costs and increases in plant investment. The filing also reflects the proposed merger of River Gas into East Ohio Gas and the combining of the operations and service areas of the two subsidiary companies. A decision by the PUCO is expected in October 1994. In addition, East Ohio Gas is negotiating with customers and the PUCO staff as to the future recovery of transition costs to be incurred under FERC Order 636.
ITEM 1. BUSINESS (Concluded)
EXECUTIVE OFFICERS OF THE COMPANY (Note 1) _______________________________________________________________________________ Name, Age and Business Experience Position (Note 2) During Past Five Years _______________________________________________________________________________
George A. Davidson, Jr. (55) Mr. Davidson was elected to his present Chairman of the Board and position on May 19, 1987, and has been a Chief Executive Officer, Director since October 1985. and Director
Lester D. Johnson (62) Mr. Johnson was elected to his present Executive Vice President and position on March 1, 1992, and has been Chief Financial Officer, a Director since May 1992. He served as and Director Senior Vice President and Chief Financial Officer from January 1986 to March 1992.
David E. Weatherwax (63) Mr. Weatherwax was elected to his Senior Vice President, present position on January 1, 1993. He Administration served as Senior Vice President, Administration and General Counsel from March 1992 to January 1993 and Senior Vice President and General Counsel from July 1987 to March 1992.
Stephen E. Williams (45) Mr. Williams was elected to his present Senior Vice President and position on January 1, 1993. He served General Counsel as Associate General Counsel from September 1992 to January 1993. From April 1987 to September 1992, he served as General Counsel and Secretary of CNG Transmission.
David J. Dzuricky (42) Mr. Dzuricky was elected to his present Vice President and Treasurer position on August 1, 1993. He served as Vice President and Treasurer of Virginia Natural Gas from July 1992 to August 1993, and as its Vice President, Treasurer and Controller from January 1991 to July 1992, and Vice President, Treasurer, Secretary and Controller from June 1990 to January 1991. From January 1988 to June 1990, he served as Treasurer of CNG Transmission.
Stephen R. McGreevy (43) Mr. McGreevy was elected to his present Vice President, Accounting position on March 1, 1993. He served as and Financial Control Controller from January 1986 to March 1993.
Laura J. McKeown (35) Ms. McKeown was elected to her present Secretary position on May 16, 1989. She served as Assistant Secretary from August 1987 to May 1989.
Thomas F. Garbe (41) Mr. Garbe was elected to his present Controller position on March 1, 1993. He served as Senior Assistant Controller from May 1991 to March 1993 and Assistant Controller from January 1986 to May 1991. _______________________________________________________________________________
Notes: (1) The Company has been advised that there are no family relationships between any of the officers listed, and there is no arrangement or understanding between any of them and any other person pursuant to which the individual was elected as an officer. (2) The By-Laws of the Company provide that each officer shall hold office until a successor is chosen and qualified.
ITEM 2.

ITEM 2. PROPERTIES
GENERAL INFORMATION ON FACILITIES (Maps are on pages 20 and 21.)
The total gross investment of the Company and its subsidiaries in property, plant and equipment was $7.3 billion at December 31, 1993. The largest portion of this investment (62%) is in facilities located in the Appalachian area. Another significant portion (22%) is located in the Gulf of Mexico.
Of the $7.3 billion investment, $3.3 billion is in production and gathering systems, of which 56 percent is invested in the Gulf of Mexico and the Gulf coast and 29 percent in the Appalachian area. The Company's production subsidiary, CNG Producing, accounts for $2.7 billion of the $3.3 billion investment, and CNG Transmission and the distribution subsidiaries account for the remaining $600 million. In addition to the wells and acreage listed elsewhere in ITEM 2, this investment includes 7,188 miles of gathering lines which are located almost entirely within the Appalachian area.
The Company's investment in its gas distribution network includes 28,165 miles of pipe, exclusive of service pipe, the cost of which represents 61% of the $1.5 billion invested in the total function.
The Company's storage operation, the largest in the industry, consists of 26 storage fields, 331,848 acres of operated leaseholds, 2,032 storage wells and 828 miles of pipe. The investment in storage properties is $644 million, including $124 million of cushion gas stored.
Of the $1.5 billion invested in transmission facilities, 69% represents the cost of 7,402 miles of pipe required to move large volumes of gas throughout the Company's operating area.
The Company has 111 compressor stations with 452,157 installed compressor horsepower. Some of the stations are used interchangeably for several functions.
The Company's investment in its fully integrated natural gas system is considered suitable to do all things necessary to bring gas to the consumer. The Company's properties provided the capacity to meet a record system peak day sendout, including transportation service, of 9.1 Bcf on January 18, 1994. The system peak day sendout in 1993 was 7.9 Bcf on February 24.
Map of Principal Facilities at December 31, 1993 (GRAPHIC MATERIAL OMITTED)
Map of Exploration and Production Areas at December 31, 1993 (GRAPHIC MATERIAL OMITTED)
ITEM 2. PROPERTIES (Continued)
GAS AND OIL PRODUCING ACTIVITIES (See Note 17(A) to the Financial Statements, page 72.)
Properties and activities subject to cost-of-service rate regulation are shown together with non-cost-of-service properties (those subject to contractual arrangements, and Canadian properties) and activities in the statistical presentations which follow.
COMPANY-OWNED RESERVES
Estimated net quantities of proved gas and oil reserves at December 31, 1991 through 1993, follow:
CNG Producing, East Ohio Gas, Hope Gas, Peoples Natural Gas and CNG Transmission file Form EIA-23 with the Department of Energy. The reserves reported at December 31, 1992, as well as those which will be reported at December 31, 1993, are not reconcilable with Company-owned reserves because they are calculated on an operated basis and include working interest reserves of all parties.
QUANTITIES OF GAS AND OIL PRODUCED
Net quantities (net before royalty) of gas and oil produced during each of the last three years follow: _______________________________________________________________________________ Years Ended December 31, 1993 1992 1991 _______________________________________________________________________________
Gas Production (Bcf) Non-cost-of-service . . . . . . . . . 124 121 126 Cost-of-service . . . . . . . . . . 6 7 7 _____ _____ _____ Total . . . . . . . . . . . . . 130 128 133 ===== ===== =====
Oil Production (000 Bbls) Non-cost-of-service . . . . . . . . . 3,907 4,508 5,246 Cost-of-service . . . . . . . . . . 29 31 33 _____ _____ _____ Total . . . . . . . . . . . . . 3,936 4,539 5,279 ===== ===== ===== _______________________________________________________________________________
The average sales price (including transfers to other operations as determined under Financial Accounting Standards Board rules) per Mcf of non-cost-of- service gas produced during the calendar years 1991 through 1993 was $1.96, $2.05 and $2.24, respectively. The respective average sales prices for oil were $19.53, $18.15 and $15.66 per barrel. The average production (lifting) cost per Mcf equivalent of non-cost-of-service gas and oil produced during the years 1991 through 1993 was $.37, $.37 and $.33, respectively.
ITEM 2. PROPERTIES (Continued)
PRODUCTIVE WELLS
The number of productive gas and oil wells in which the subsidiary companies have an interest at December 31, 1993, follow: _______________________________________________________________________________ Gas Wells Oil Wells Gross Net Gross Net _______________________________________________________________________________
Non-cost-of-service* . . . . . . . . 5,601 4,715 853 407 Cost-of-service . . . . . . . . . . 2,181 1,811 3 3 _____ _____ ___ ___ Total. . . . . . . . . . . . . 7,782 6,526 856 410 ===== ===== === === _______________________________________________________________________________ * Includes 46 gross (12 net) multiple completion gas wells and 5 gross (2 net) multiple completion oil wells.
ACREAGE
The following table sets forth the gross and net developed and undeveloped acreage of the subsidiary companies at December 31, 1993: _______________________________________________________________________________ Developed Acreage Undeveloped Acreage Gross Net Gross Net _______________________________________________________________________________
Non-cost-of-service. . . . 1,621,117 1,227,844 1,309,456 933,323 Cost-of-service . . . . . 440,912 439,179 42,124 37,775 _________ _________ _________ _________ Total. . . . . . . . 2,062,029 1,667,023 1,351,580 971,098 ========= ========= ========= ======== _______________________________________________________________________________
Approximately 32% of the foregoing non-cost-of-service undeveloped net acreage and 100% of the cost-of-service undeveloped net acreage is located in the Appalachian area.
NET WELLS DRILLED IN THE CALENDAR YEAR
The number of non-cost-of-service net wells completed during each of the last three years follow (there were no cost-of-service wells completed during this three-year period): _______________________________________________________________________________ Exploratory Development Total Productive Dry Productive* Dry Productive Dry _______________________________________________________________________________
Years Ended December 31, 1993 . . . . . . . 2 6 13 1 15 7 1992 . . . . . . . 1 3 54 10 55 13 1991 . . . . . . . 3 7 39 7 42 14 _______________________________________________________________________________ * Includes Canadian completions: 1993 - 1 well, 1992 - 0 wells and 1991 - 4 wells.
As of December 31, 1993, 4 gross (2 net) non-cost-of-service wells were in process of drilling, including wells temporarily suspended. As of December 31, 1993, Consolidated was engaged in waterflood projects in Oklahoma and Texas and an enhanced oil recovery program in Alberta, Canada.
ITEM 2. PROPERTIES (Concluded)
GAS PURCHASE CONTRACT RESERVES (AT DECEMBER 31, 1993) AND AVAILABILITY OF SUPPLY (CALENDAR YEAR 1994)
Gas purchase reserves under contract with independent producers in the Appalachian area total 960 billion cubic feet at December 31, 1993. In addition, at December 31, 1993, Consolidated had gas supply contracts with various other producers and marketers with contract lengths ranging from a few months to ten years. The volume of gas available to Consolidated under these supply contracts totals 458 billion cubic feet if all volumes are requested. These gas purchase contract reserve and gas supply contract volume amounts are as contained in the February 15, 1994 report of Ralph E. Davis Associates, Inc. Of the total 960 billion cubic feet under contract from Appalachian producers, the volume of gas expected to be purchased in 1994 under such contracts is not estimable as such contracts are generally life-of-the-well arrangements and contain provisions adaptable to changing market conditions. Of the total 458 billion cubic feet available under contract from other producers and marketers, approximately 229 billion cubic feet of gas will be available to Consolidated in 1994, assuming all volumes are requested. During 1993, Consolidated converted its remaining gas purchase contracts with interstate pipeline companies to firm transportation contracts, and no gas purchases from pipeline companies are expected in 1994.
The Company anticipates that substantial volumes of gas will be available for purchase during 1994 on the spot market. Due to the nature of spot market transactions, the volumes of such gas available to Consolidated in 1994 cannot be reasonably estimated. However, for the calendar year 1994, Consolidated expects its distribution subsidiaries to have approximately 409 billion cubic feet of firm transport capacity available on upstream pipelines and 57 billion cubic feet of storage capacity available to meet their customer requirements.
The volumes expected to be available from Company-owned wells in 1994 amount to 139 billion cubic feet of gas and 4,124 thousand barrels of oil. Included in these amounts are 133 billion cubic feet of gas and 4,095 thousand barrels of oil expected to be available from the Company's non-cost-of-service properties. The foregoing volumes are based on the Company's current production estimates of proved gas and oil reserves. Actual production may differ from these amounts due to a number of factors, including changing market conditions and the acquisition or sale of reserves.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
As previously reported, in June 1993, CNG Transmission received a Notice of Violation from the Pennsylvania Department of Environmental Resources ("DER") alleging violations of the Pennsylvania Clean Streams Law and three Earth Disturbance Permits issued thereunder. CNG Transmission was assessed a penalty of $405,450 by the DER, which was paid in December 1993. CNG Transmission is seeking recovery of a substantial portion of the penalty paid in this matter from third party contractors under contractual indemnification provisions.
Reference is made to "Environmental Matters," page 42, and to Notes 15 and 16 to the Financial Statements, page 70, for additional environmental-related information.
Reference is made to "Rate Matters," page 16, for descriptions of certain regulatory proceedings.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable
PART II
ITEM 5.

ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
This information is included in Note 17(C) to the Financial Statements, page 77, and reference is made thereto.
ITEM 6.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
NET INCOME
Net income in 1993 was $206 million, a 6 percent increase over the $195 million earned in 1992. On a per share basis, 1993 net income was $2.22 compared with $2.19 in 1992. The earnings per share amounts reported for 1993 and 1992 reflect the sale of 4.6 million shares of common stock in September 1992. Net income in 1991 was $169 million, or $1.94 a share.
Colder weather, higher prices for natural gas production, increased gas deliveries resulting from pipeline expansion projects, higher by-product revenues and reduced interest expense were major factors for the earnings improvement in 1993. While weather in Consolidated's retail service areas was colder than in 1992, it was still warmer than normal for the fourth consecutive year. Normal weather represents a measure of temperature experienced over a 30- year period. Normal weather in 1993 would have added about $.06 a share to the $2.22 a share reported.
Earnings in both 1993 and 1992 included the positive impact of deferred tax benefits. In 1993, deferred tax benefits of $17.4 million, or $.19 a share, resulting from the mandatory adoption of Statement of Financial Accounting Standards (SFAS) No. 109 are reported as a separate component of net income as the cumulative effect of the accounting change. By contrast, deferred tax benefits recognized in 1992 under the previously applicable accounting standard reduced income tax expense in that year by $13.0 million, or $.15 a share.
The positive factors in 1993 were offset in part, however, by higher income taxes due to the increase in the federal corporate income tax rate from 34 percent to 35 percent enacted in August 1993. The effects of this rate change included an $11.4 million, or $.12 a share, adjustment to previously recorded deferred tax balances and a $2.7 million, or $.03 a share, increase in current taxes to reflect the new tax law retroactive to January 1, 1993.
Colder weather compared with 1991, the continued expansion of the Company's transmission operations, increased gas storage service revenues, and higher wellhead prices for gas were major factors for the earnings improvement in 1992 compared with 1991. Although weather in Consolidated's retail service areas was colder than in 1991, the weather was warmer than normal. If weather in the retail service areas had been normal in 1992, earnings would have been $.16 a share higher than the $2.19 reported. Gas wellhead prices fell sharply early in 1992, but recovered and strengthened as gas demand increased due to cold spring weather and concerns over possible supply shortages following Hurricane Andrew. The increase in average gas wellhead prices for the year was offset to a large extent by lower gas and oil production and lower average oil wellhead prices. The net income comparison of the two years was also affected by the recognition in 1991 of interest revenues related to the settlement of federal income tax issues from prior years.
In 1991, warm weather depressed the level of earnings throughout all three of Consolidated's major business components. If weather in Consolidated's retail service areas had been normal in 1991, earnings would have been $.33 a share higher than the $1.94 reported for that year. Reduced gas demand, declining gas field prices and the curtailment of gas production resulted in sharply lower exploration and production earnings. Higher other income, including interest revenues related to the settlement of federal income tax issues from prior years, was also a significant factor contributing to earnings in 1991.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
INCOME FROM OPERATIONS
Operating income for Consolidated's business components for the last three years is shown in the following table. Operating income is presented on an after-tax basis consistent with the Statement of Income where income taxes are classified as an operating expense.
Effective January 1, 1993, Consolidated's CNG Trading Company subsidiary was renamed CNG Gas Services Corporation. In addition to continuing its predecessor's role of marketing a portion of Company-owned production, CNG Gas Services arranges gas supplies, transportation, storage and related services for customers. The demand for these services was created by Federal Energy Regulatory Commission (FERC) Order 636, which has restructured the natural gas marketplace. As a result of this new role, amounts pertaining to the operations of CNG Gas Services are included in the caption "Other" in the following table, as well as in the other tables presented in this discussion and analysis. Amounts applicable to CNG Trading for 1992 and 1991 remain in the exploration and production component.
______________________________________________________________________________ OPERATING INCOME 1993 1992 1991 ______________________________________________________________________________ (In Millions) Distribution . . . . . . . . . . . $122.5 $130.0 $110.7 Transmission . . . . . . . . . . . 98.0 84.0 79.9 Exploration and production . . . . . . 35.3 50.7 37.6 Other* . . . . . . . . . . . . . .3 8.7 1.1 Intercompany eliminations and adjustments . 1.3 .2 .8 ______ ______ ______ Total . . . . . . . . . . . . $257.4 $273.6 $230.1 ====== ====== ====== ______________________________________________________________________________ * Includes CNG Gas Services, CNG Energy, Consolidated System LNG, CNG Research, CNG Coal and Parent companies.
Due to the regulated nature of the distribution and transmission components of Consolidated's business, operating results can be affected by regulatory delays when price increases are sought through general rate filings to recover certain higher costs of operation. Weather is also an important factor since a major portion of the gas sold or transported by the distribution and transmission operations is ultimately used for space heating.
DISTRIBUTION
"Distribution" represents the results of Consolidated's six retail gas distribution subsidiaries, including their minor gas and oil production activities. These subsidiaries are subject to price regulation by their respective state utility commissions.
Operating income for the gas distribution operations in 1993 was down $7.5 million, or 6 percent, from 1992. Higher costs of operations and the increase during 1993 in the federal corporate income tax rate more than offset the impact of slightly colder weather and a minor increase in throughput in 1993. Overall, weather in Consolidated's retail service areas was 2 percent colder than in 1992, but 1 percent warmer than normal. The colder weather, the net addition of about 17,800 residential and commercial gas sales customers and the full year impact of general rate increases placed into effect by two subsidiaries in the latter part of 1992 contributed favorably to 1993 results. To help mitigate the effect of rising non-gas operating costs and to enable a return to be earned on new facilities placed in service, Consolidated's two largest distribution subsidiaries, The East Ohio Gas Company and The Peoples Natural Gas Company, have filed for general rate increases. However, resolution of these proceedings is not expected until the latter part of 1994.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Operating income in 1992 increased $19.3 million, or 17 percent, over 1991 due in large part to colder weather in the 1992 period. Overall, weather in Consolidated's retail service areas was 12 percent colder than in 1991, but 3 percent warmer than normal. However, due to the seasonality of their operations, the overall deviation from normal weather in 1992 was not entirely indicative of the weather's financial impact on the distribution operations. Specifically, in the five principal heating months of 1992, weather in Consolidated's retail service areas was 3 percent colder than in 1991 and 8 percent warmer than normal. The net addition of some 21,000 residential and commercial gas sales customers also contributed to the improved operating results. Further, the distribution operations benefited from a full year of general rate increases granted to two subsidiaries during 1991, and the impact of general rate increases placed into effect by two subsidiaries in the latter part of 1992.
Exceptionally warm weather in 1991 had a particularly noticeable impact on gas distribution operations, limiting the level of gas deliveries and holding operating income in that year to a relatively low level. Weather in Consolidated's retail service areas was 14 percent warmer than normal in 1991.
TRANSMISSION
"Transmission" includes the results of the gas transmission, storage, by- product and certain other activities of CNG Transmission Corporation and the activities of CNG Storage Service Company. Gas and oil production activities of CNG Transmission are included in exploration and production operations. The interstate gas transmission and related operations of CNG Transmission are regulated by the FERC.
Operating income of the gas transmission operations in 1993 increased $14.0 million, or 17 percent, over 1992. The improvement was due partly to expanded service to customers in the Northeast as a result of the Company's pipeline construction program, increased throughput to affiliated distribution companies, and higher gas storage service and by-product revenues. Colder weather also contributed to the increased operating income in 1993. The operating results of the transmission operations in the year were also favorably affected, but to a lesser extent, by sales of gas from storage inventory and certain other steps taken to facilitate the transition to FERC Order 636.
Operating income in 1992 was up $4.1 million, or 5 percent, over 1991. The expansion of transportation service to both new customers and existing wholesale customers and end-users on the East Coast, including power generation customers, and increased demand by traditional Northern Market customers were the most significant factors affecting the 1992 results. Colder weather and increased storage service revenues also contributed to the improvement. The increased transportation to utilities and end-users in the Northeast and along the East Coast was the result of the completion of several of the Company's pipeline expansion projects. The impact of these positive factors was partially offset by higher operating costs in 1992.
The operating results in 1991 were influenced to a large extent by the implementation of restructured service agreements in connection with the settlement with the FERC of CNG Transmission's 1988 general rate case. The impact of this settlement included a significant increase in storage service revenues resulting from customers' increased access to CNG Transmission's storage facilities and increased gas transportation volumes due to the conversion by some customers from sales service to firm transportation.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
EXPLORATION AND PRODUCTION
"Exploration and production" includes the results of CNG Producing Company, the gas and oil production activities of CNG Transmission, and, in 1992 and 1991, the results of CNG Trading Company.
The adjustment to deferred income tax balances to reflect the increase in the federal corporate income tax rate had a significant impact on the operating income of Consolidated's exploration and production operations in 1993. Operating income of the exploration and production operations was $35.3 million in 1993, down from $50.7 million in 1992. These amounts are on an after-tax basis consistent with the Statement of Income where income taxes are classified as an operating expense. However, as a result of the implementation of SFAS No. 109 and the increase in the federal tax rate, the comparison of 1993 operating results with 1992 is significantly distorted. Deferred tax benefits resulting from the adoption of SFAS No. 109 in 1993 are included separately as a component of net income below the operating income line as part of the cumulative effect of the accounting change. In addition, operating income in 1993 for the exploration and production operations was reduced by $8.8 million due to the tax rate increase, including the adjustment to existing deferred tax balances required by SFAS No. 109 and the current year effect of applying the new higher rate retroactive to January 1, 1993. By contrast, operating income in 1992 reflected an increase for certain deferred tax benefits that had been recognized under the previous accounting standard. On a pretax basis, operating income of the exploration and production operations was $47.3 million in 1993, up $8.5 million, or 22 percent, compared with $38.8 million in 1992. Positive factors affecting operating results in 1993 included higher wellhead prices for natural gas and slightly higher gas production. Consolidated's gas wellhead prices in 1993 averaged $2.24 per thousand cubic feet, a 9 percent increase from 1992. The positive factors were offset by higher income taxes, lower oil prices and production, and lower margins on the brokering of gas. The average oil wellhead price realized of $15.66 per barrel was 14 percent below 1992 levels.
Operating income in 1992 rose $13.1 million, an increase of 35 percent over 1991. The impacts of higher gas wellhead prices and reduced operation and maintenance expense were offset somewhat by lower gas and oil production and lower wellhead oil prices. Gas wellhead prices followed industry trends, falling early in the year but recovering and strengthening as the year progressed. Consolidated's gas wellhead prices in 1992 averaged $2.05 per thousand cubic feet, up 5 percent from 1991. The decline in operation and maintenance expense resulted from cost containment programs and, to a lesser extent, the lower gas and oil production levels. Overall, gas production for 1992 was down 4 percent and oil production was down 14 percent.
The generally adverse conditions in natural gas markets nationwide -- including excess supply, reduced demand due to the warmer-than-normal weather and the dramatically low level of wellhead prices -- were the primary reasons for the relatively low operating income in 1991. The average gas wellhead price realized was $1.96 per thousand cubic feet in 1991, the lowest level on an annual basis in over 10 years. The shut-in of certain high-deliverability offshore gas production for a portion of the year, and lower oil production and prices also contributed to the low 1991 operating income.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
UTILITY GAS SALES AND TRANSPORTATION VOLUMES
During 1993, the final portion of the FERC's plan to restructure the interstate natural gas pipeline industry was set in motion as pipeline companies began implementating the provisions of FERC Order 636. Similar to previous FERC actions to enable more direct access to gas supplies and open access to pipeline transportation systems, Order 636 has significantly increased competition in the natural gas industry. In the restructured marketplace, local gas utilities and other large-volume end-users, including former pipeline sales customers, now bear all the responsibilities and risks for arranging the procurement and delivery of their gas supplies.
On October 1, 1993, CNG Transmission implemented Order 636 with the required "unbundled" services and new rate structure. Since Consolidated's utility subsidiaries had already been managing a part of their own gas supplies, the transition to the more competitive environment under Order 636 did not have a significant impact on their operations. In addition, Consolidated, through its CNG Gas Services subsidiary, continues to offer the equivalent of bundled services previously provided by CNG Transmission.
The gas sales and transportation volumes of the distribution and transmission operations for the last three years are presented in the following table. Since distribution sales largely represent retail sales for space heating, changes in sales volumes from one period to another are primarily a function of the weather. "Normal weather," as the term is used in the gas industry, represents the mean of temperatures experienced, measured in terms of degree days, over a 30-year period. A degree day is a measure of the coldness of the weather based on the extent to which the daily mean temperature falls below 65 degrees Fahrenheit. The 30-year average, which is calculated by a federal agency, is updated approximately every 10 years. For Consolidated, "normal weather" is determined using the weighted average of the normal degree days experienced in its retail service territories.
Variations in weather conditions can also have a significant impact on the throughput of the transmission operations, since a substantial portion of the gas deliveries of these operations is ultimately used by space-heating customers. The distribution and transmission operations provide gas transportation services to a wide range of customers, including commercial and industrial end-users, electric power generators and local utility companies. Therefore, the volume of gas transported can also be affected by changes in economic and market conditions.
_______________________________________________________________________________ UTILITY GAS SALES AND TRANSPORTATION 1993 1992 1991 _______________________________________________________________________________ (In Billion Cubic Feet)
DISTRIBUTION OPERATIONS Sales. . . . . . . . . . . . . 297.8 293.6 273.3 Transportation. . . . . . . . . . 145.4 143.5 134.4 _____ _____ _____ Throughput . . . . . . . . . . 443.2 437.1 407.7 ===== ===== ===== TRANSMISSION OPERATIONS Sales. . . . . . . . . . . . . 100.1 42.4 142.3 Transportation. . . . . . . . . . 610.9 596.8 403.7 _____ _____ _____ Throughput* . . . . . . . . . . 711.0 639.2 546.0 ===== ===== =====
* Includes intercompany activity. _______________________________________________________________________________
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
DISTRIBUTION
Sales growth in Consolidated's residential service areas in Ohio, Pennsylvania and West Virginia has generally been limited since such areas have experienced minimal population growth, and the vast majority of households in these areas already use natural gas for space heating. Opportunity for growth in the retail sales market is expected to continue at Virginia Natural Gas, Inc., due to customer conversions from other energy sources and the past and potential future expansion of its service territory. Since Consolidated's acquisition of this subsidiary in 1990, it has experienced an annual customer growth rate of about 4 percent, well above the 1 percent rate for Consolidated's other distribution subsidiaries. In 1993, Virginia Natural Gas connected about 7,800 new residential and commercial customers. The completion in 1992 of the 135- mile intrastate pipeline in Virginia has provided Virginia Natural Gas and its customers with new gas supply sources through access to Consolidated's transmission system and storage facilities and has afforded additional opportunities for growth in both gas sales and transportation, especially in the power generation markets. Additional growth in distribution operations may also occur as industrial customers and electric generators turn to natural gas as a means to ensure compliance with the provisions of the Clean Air Act. In this connection, the development of new gas-burning technologies for industry and the wider acceptance of natural gas as a fuel for motor vehicles provide opportunities for increased gas usage in market sectors that are not weather- sensitive.
Gas sales of the distribution subsidiaries were somewhat higher in 1993 due to slightly colder weather while transportation volumes remained relatively unchanged from 1992. The net addition of approximately 17,800 customers in 1993 also contributed to the higher sales volumes. The weather in 1993 was 2 percent colder than in 1992, resulting in higher space-heating sales. Residential gas sales increased 4.2 Bcf to 212.3 Bcf in 1993, and commercial sales volumes were virtually unchanged at 72.7 Bcf. Industrial sales volumes were flat with 1992 at 12.5 Bcf, while transportation volumes for industrial customers were up 1.5 Bcf to 116.0 Bcf. Gas transported for commercial customers was 21.1 Bcf in 1993, up 1.4 Bcf compared with 1992, while transportation to off-system customers declined by 1.0 Bcf to 8.3 Bcf in 1993.
Significantly colder weather and increased economic activity were the primary reasons for the increased gas deliveries by the distribution operations in 1992 compared with 1991. The weather, which overall was 12 percent colder than in 1991, resulted in increased gas usage by space-heating customers. Residential gas sales volumes increased 15.8 Bcf in 1992 to 208.1 Bcf, while sales to commercial customers were up 3.2 Bcf to 72.6 Bcf. Sales to industrial customers were 12.5 Bcf, up 1.3 Bcf over 1991, and transportation volumes for these customers increased 4.8 Bcf to 114.5 Bcf. Transportation for commercial customers was also higher in 1992, increasing by 2.5 Bcf.
TRANSMISSION
Changing regulatory policies intended to increase competition in the natural gas industry have been the principal factor affecting the transmission operations over the past several years. Beginning with open access transportation and culminating with the significant service restructuring required by FERC Order 636, the role of the Company's transmission operations has changed from that of primarily a merchant, or wholesaler, of gas to one that provides a range of gas transportation, storage, and other related services. The changing regulatory environment has also created a number of opportunities for pipeline companies to expand and serve new markets. The Company has taken advantage of selected market expansion opportunities, concentrating the efforts toward potentially high-volume, weather-sensitive markets and areas with growing power generation needs located primarily in the Northeast and along the East Coast. This expansion takes advantage of Consolidated's network of underground storage facilities and the location and nature of its gridlike pipeline system as a link between the country's major longline gas pipelines and the increasing energy demands of East Coast markets.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
CNG Transmission implemented Order 636 effective October 1, 1993 and, as required by the Order, "unbundled" its services and revised its customer contracts and service tariffs. Customers now have even greater access to the Company's pipeline and storage capacity, together with a range of options available with respect to gas transportation and storage services. With the implementation of Order 636, CNG Transmission abandoned its traditional sales service which consisted of various elements of gas sales, transportation and storage that were offered and priced as a single bundled service. However, Consolidated continues to provide the equivalent of "bundled" services through its unregulated CNG Gas Services subsidiary.
Consolidated's transmission operations achieved a record level of throughput in 1993. Total transmission throughput volumes were 711.0 billion cubic feet (Bcf), an increase of 71.8 Bcf compared with 639.2 Bcf in 1992. Wholesale gas sales volumes increased 57.7 Bcf in 1993 to 100.1 Bcf. The increase in sales volumes was due to the sale by CNG Transmission of approximately 58 Bcf of gas from storage inventory in anticipation of the transition to restructured services. These sales, which were made primarily to customers outside the traditional Northern Market area at reduced prices under alternative FERC- approved tariff schedules, increased available capacity to provide future storage service and reduced certain transition costs under Order 636. Total gas transportation volumes in 1993 increased 14.1 Bcf to 610.9 Bcf. The increase in transportation volumes occurred in the fourth quarter of 1993 following CNG Transmission's implementation of Order 636 and was due primarily to volumes transported for customers in the Northern Market area and Virginia.
Total transmission throughput volumes in 1992 were 639.2 Bcf, an increase of 93.2 Bcf compared with 1991. Market expansion, increased demand in the Northern Market area, and higher deliveries to power generation customers, were the major factors affecting gas sales and transportation volumes in 1992. Wholesale gas sales volumes declined 99.9 Bcf to 42.4 Bcf as utility customers switched from sales to transportation service under the restructured service agreements which resulted from the settlement of CNG Transmission's previous rate filings. The decline in sales volumes also reflects the sale-in-place during 1991 of 13.7 Bcf of gas inventories. Total gas transportation volumes were up 193.1 Bcf over 1991 to 596.8 Bcf. The expansion of service to new and existing customers, colder weather, and renewed demand in the Northern Market were the major factors for the increase.
GAS AND OIL PRODUCTION AND PRICES
The following table sets forth Consolidated's gas and oil production and average wellhead prices for the exploration and production operations for the last three years: _______________________________________________________________________________ PRODUCTION 1993 1992 1991 _______________________________________________________________________________ GAS (BCF) Nonregulated. . . . . . . . . . 123.5 121.3 125.7 Regulated (Cost-of-service). . . . . 6.0 6.7 7.1 _______ _______ _______ Total. . . . . . . . . . . 129.5 128.0 132.8 ======= ======= =======
OIL (000 BBLS) Nonregulated. . . . . . . . . . 3,906.8 4,507.7 5,245.6 Regulated (Cost-of-service). . . . . 29.1 31.3 33.3 _______ _______ _______ Total. . . . . . . . . . . 3,935.9 4,539.0 5,278.9 ======= ======= =======
AVERAGE WELLHEAD PRICES (NONREGULATED ONLY) Gas (per Mcf) . . . . . . . . . $ 2.24 $ 2.05 $ 1.96 Oil (per Bbl) . . . . . . . . . $ 15.66 $ 18.15 $ 19.53 _______________________________________________________________________________
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Although gas production increased slightly in 1993 compared with 1992, reduced deliverability at certain properties and the sale of selected properties in the Appalachian area held production below the level achieved in 1991. The reduced deliverability was due in part to the postponement in past years of workover activity due to the weak prices in gas markets. Gas wellhead prices remained strong in 1993 and were above 1992 levels for most of the year. For the year, Consolidated's average gas wellhead price was up $.19 a thousand cubic feet over 1992. The lower oil production in 1993 was attributable primarily to normal production declines at older properties. Following world oil price trends, Consolidated's average oil price declined in 1993 as prices remained weak through most of the year and fell sharply near year-end.
Gas production in 1992 was down 4 percent and oil production declined 14 percent from 1991. The lower production was due to a combination of factors, including the selective shut-in of wells, particularly early in 1992 when prices were low, the interruption of operations caused by Hurricane Andrew, and reduced deliverability at certain properties. Gas spot market prices for the industry dropped to a low of about $1.00 a thousand cubic feet in February 1992, but strengthened considerably in the second and third quarters of the year due to cold spring weather and concerns over supply shortages following the hurricane. Consolidated's gas wellhead prices in 1992 were up $.09 a thousand cubic feet, while average oil prices declined in 1992, as prices remained lower throughout most of the year reflecting the trend in world oil prices.
OPERATING REVENUES
Operating revenues, which include revenues from gas and oil sales, transportation of gas, storage service, brokering activities and by-product operations, are shown below by business component:
______________________________________________________________________________ OPERATING REVENUES 1993 1992 1991 ______________________________________________________________________________ (In Millions) Distribution. . . . . . . . . $1,773.9 $1,603.1 $1,531.0 Transmission. . . . . . . . . 983.8 642.7 878.9 Exploration and production . . . . 536.4 519.4 502.6 Other . . . . . . . . . . . 357.8* 85.7 77.8 Intercompany eliminations and adjustments . . . . . . . (467.8) (330.0) (383.3) ________ ________ ________ Total. . . . . . . . . . $3,184.1 $2,520.9 $2,607.0 ======== ======== ========
* Includes $325.7 million of revenues of CNG Gas Services. ______________________________________________________________________________
Total operating revenues were up $663.2 million in 1993 with the increase due to higher gas sales revenues. Total gas sales revenues increased $663.5 million due to higher retail sales volumes and rates, the sale of gas from storage inventory, higher gas wellhead prices and production, and the initial year of marketing activities by CNG Gas Services. Other operating revenues declined slightly from 1992. Increased gas transportation and storage service revenues and higher revenues from by-product sales were offset by the impact of lower oil and condensate revenues.
Lower gas sales revenues were the primary reason for the decline in total operating revenues in 1992 compared with 1991. Total gas sales revenues in 1992 were down $131.4 million due primarily to the shift by wholesale customers from sales to transportation service. Revenues from oil production and brokering and from by-product sales were also lower in 1992. Increases in retail sales volumes, gas transportation revenues, gas wellhead prices, gas brokering activity, and storage service revenues only partially offset the impact of these revenue declines.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
The total average unit selling price of gas in 1993 was $4.33 per thousand cubic feet, down slightly from $4.35 in 1992. In 1991, the average unit selling price was $4.29 per thousand cubic feet. Average sales prices in 1993 were higher for all retail categories and for sales of the Company's gas production. However, CNG Transmission's sales from storage inventory had a significant influence on the overall average unit selling price since such sales were made at lower rates under alternative FERC-approved tariff schedules. The higher selling price in 1992 compared with 1991 reflects the upward industry trend in gas wellhead prices experienced in 1992.
Operating revenues of the gas distribution operations in 1993 increased $170.8 million. Gas sales revenues rose $171.6 million due to both higher sales volumes and rates. Colder weather and an increase in the number of customers served were the principal reasons for the sales volume increase. The full year impact of general rate increases placed into effect in late 1992 by Peoples Natural Gas and Virginia Natural Gas, and an increase which became effective in 1993 for Hope Gas, Inc., contributed approximately $21.8 million to sales revenues in 1993. The recovery in current rates of previously incurred gas cost increases also contributed to the higher revenues in 1993. Other operating revenues declined $.8 million due primarily to lower storage service revenues.
Revenues of the gas distribution operations rose $72.1 million in 1992 compared with 1991. Gas sales revenues increased $59.0 million as colder weather resulted in higher residential and commercial sales volumes. The general rate increase granted to Hope Gas in 1991 and rate increases placed into effect by Peoples Natural Gas and Virginia Natural Gas in the latter part of 1992 contributed about $8.2 million to sales revenues in 1992. Other operating revenues were up $13.1 million in 1992, primarily as the result of increased transportation revenues due to higher deliveries to industrial and commercial customers and facilities use charges associated with the Virginia intrastate pipeline.
Operating revenues of the gas transmission operations over the past three years have fluctuated as CNG Transmission moved toward the implementation of FERC Order 636. In 1993, operating revenues were up $341.1 million, a significant portion of which is attributable to higher gas sales revenues. Wholesale gas sales revenues rose $290.0 million due chiefly to billings by CNG Transmission of its October 1, 1993, balance of certain Order 636 transition costs and the sales of approximately 58 Bcf of gas from storage inventory in anticipation of the implementation of Order 636. Gas transportation revenues were up $35.7 million and storage service revenues increased $12.6 million, both reflecting the increased level of services provided customers under Order 636. Revenues from the sale of by-products were also higher in 1993, increasing $4.5 million primarily as the result of higher propane and ethane sales volumes.
Operating revenues of the gas transmission operations in 1992 and 1991 reflect the impact of the restructured service agreements which resulted from CNG Transmission's 1988 rate case settlement. Wholesale sales revenues were reduced in both years and transportation revenues were higher in 1992 as customers switched from sales to transportation service. The effect on sales revenues, however, does not parallel the change in transportation revenues due to the commodity cost associated with the gas sales volumes. In 1992, operating revenues of the transmission operations were down $236.2 million compared with 1991. Sales revenues declined $304.0 million and transportation revenues rose $54.4 million primarily as a result of the volumetric changes. The comparison of transportation revenues is also affected by a $10.3 million refund reclassification charge related to prior years, which was recorded in 1991 as part of a rate settlement. Storage service revenues in 1992 increased $11.7 million due to the increased access by customers to the Company's storage facilities.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
Operating revenues from exploration and production operations increased $17.0 million in 1993. Gas sales revenues rose $43.5 million due to higher prices received, an increase in the volume of gas brokering activity and slightly higher gas production. However, a large portion of this gain was offset by lower oil and condensate revenues. Oil and condensate revenues declined $35.5 million as lower prices and volumes adversely affected revenues from both oil production and brokering activities. Revenues from the sale of oil and condensate production declined $20.8 million, while revenues from oil brokering were down $14.7 million. Other revenues of the exploration and production operations were up $9.0 million in 1993 as the result of increased royalties received due to the higher gas prices and business interruption insurance reimbursements related to Hurricane Andrew.
Exploration and production revenues in 1992 were up $16.8 million compared with 1991. Gas revenues increased $46.9 million due to increased gas brokering activity and higher prices received for both the sale of Company production and volumes brokered. The impact of lower gas production only partially offset these gains. Oil and condensate revenues fell $34.8 million in 1992. Revenues from the sale of oil and condensate production were down $20.0 million due to lower production and wellhead prices, while revenues from the Company's brokered oil program declined $14.8 million due to lower volumes and prices. Hurricane Andrew did not have a significant effect on 1992 operating revenues due to business interruption insurance coverage.
OPERATING EXPENSES
Operating expenses, including taxes, increased 30 percent in 1993 to $2.93 billion. Operating expenses in 1992 were $2.25 billion, down 5 percent from $2.38 billion in 1991.
Purchased gas costs consistently represent the largest expense item for Consolidated. Purchased gas costs were $1,603.0 million in 1993, $990.6 million in 1992 and $1,157.1 million in 1991. These costs are influenced primarily by changes in gas sales requirements, the price and mix of gas supplies, and the timing of recoveries of deferred purchased gas costs. Increased volume requirements, CNG Transmission's billing of its October 1, 1993, balance of unrecovered gas and transportation costs under Order 636 and higher spot market gas prices were the principal reasons for the increased costs in 1993. The sales of approximately 58 Bcf of gas from storage inventory by CNG Transmission and increased recoveries of previously deferred gas costs by the distribution subsidiaries also contributed to the higher level of expense in 1993. Lower volume requirements and the resulting lower recoveries of gas costs previously deferred were the major factors for the decline in overall purchased gas costs in 1992.
"Other purchased products" includes the cost of liquids and by-products purchased for resale and, beginning in 1992, the cost of pipeline capacity not associated with gas purchased. The decrease in these costs in 1993 and 1992 generally reflects the lower volumes of oil purchased and resold in connection with the Company's brokered oil program.
Consolidated's combined operation expense and maintenance increased $23.5 million, or 4 percent, in 1993 to $685.7 million. Operation expense was up $15.4 million to $598.5 million principally due to increased payroll and benefit expenses and gas and oil production-related costs. Maintenance expense in 1993 was up $8.1 million to $87.2 million largely because of additional work performed with respect to distribution and transmission mains, compressor station maintenance and environmental-related costs. The adoption in 1993 of SFAS No. 106, which requires the accrual of postretirement health care and life insurance costs, did not have a significant impact on operation expense since the vast majority of the increased costs under SFAS No. 106 has been deferred pending recovery in future rates. Reference is made to Note 6 to the consolidated financial statements for additional information regarding this new accounting standard. In 1992, combined operation expense and maintenance
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
increased 4 percent to $662.2 million. Operation expense increased $16.4 million to $583.1 million primarily as the result of higher payroll and overhead costs and increased environmental-related costs. These higher costs were partially offset by a decline in production-related expenses due to lower gas and oil production volumes and cost containment efforts. Maintenance increased $6.3 million to $79.1 million in 1992 due chiefly to additional work performed to ensure service reliability of distribution mains.
The following table presents the depreciation and amortization expense for Consolidated's business components for the last three years: _______________________________________________________________________________ DEPRECIATION AND AMORTIZATION 1993 1992 1991 _______________________________________________________________________________ (In Millions) Distribution. . . . . . . . . . . $ 65.3 $ 61.0 $ 56.9 Transmission. . . . . . . . . . . 50.4 43.8 39.2 Exploration and production . . . . . . 176.7 180.8 186.3 Other . . . . . . . . . . . . . 2.2 2.2 2.3 ______ ______ ______ Total. . . . . . . . . . . . $294.6 $287.8 $284.7 ====== ====== ====== _______________________________________________________________________________
Depreciation expense for the distribution operations increased in both 1993 and 1992 due to the higher level of plant investment. These higher amounts reflect, for the most part, depreciation charges for the Virginia intrastate pipeline which was placed in service during 1992. The increased expense in 1993 and 1992 for transmission operations reflects the higher plant investment resulting from the completion of substantially all of its major pipeline expansion projects. Amortization charges of the exploration and production operations decreased in 1993 and 1992 due primarily to lower oil production.
Taxes, other than income taxes, increased by $11.7 million in 1993 compared with an $8.7 million increase in 1992. These increases were due in large part to higher property taxes.
Income taxes for 1993 reflect the implementation of SFAS No. 109, while taxes for 1992 and 1991 were determined under the previous accounting standard. Reference is made to Note 7 to the consolidated financial statements for information regarding the adoption of SFAS No. 109, as well as for information on the effects of the increase in 1993 in the federal corporate income tax rate. "Income taxes - estimated" increased $31.3 million in 1993. Additional deferred income taxes recorded in 1993 as a result of the tax rate increase and higher pretax earnings were the primary reasons for the increased tax expense. Certain deferred tax benefits which reduced income tax expense in 1992 under the previous accounting standard were also a significant factor in the comparison. Income taxes in 1992 increased compared with 1991 due to higher pretax earnings and increased state income taxes.
NEW ACCOUNTING STANDARD
In November 1992, the FASB issued Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits." This Statement establishes the accounting for certain benefits provided to inactive and former employees prior to retirement. Consolidated will adopt the provisions of this standard in the first quarter of 1994 as required. Based on management's current estimates and assumptions, the adoption of the standard is not expected to have a material effect on Consolidated's financial position, results of operations or cash flows.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
LIMITATION ON CAPITALIZED COSTS
As indicated in Note 1 to the consolidated financial statements, CNG Producing and CNG Transmission follow the full cost method of accounting for their gas and oil producing activities prescribed by the Securities and Exchange Commission (SEC). Under this method, the total capitalized costs, net of related deferred taxes, are subject to a limitation based on the present value of estimated future net revenues expected to be received from the production of proved reserves. If net capitalized costs exceed this amount at the end of any quarter, a permanent impairment of the assets is required to be charged to expense in that period.
Consolidated has never been required to recognize such an impairment under the SEC full cost rules. There are a number of factors, including prices, that determine whether or not an impairment is required. Gas wellhead prices remained strong during 1993, and have continued to be firm in the early part of 1994 due in part to higher demand caused by the colder weather. However, since gas wellhead prices are subject to sudden fluctuations, the impairment of these gas and oil properties is a possibility at any quarterly measurement date, unless other factors such as lower production costs or proved reserve additions mitigate the impact of the price decline.
OTHER INCOME AND INTEREST CHARGES
Total other income was $10.5 million in 1993, $4.7 million in 1992 and $26.3 million in 1991. Interest revenues were up $1.5 million in 1993 due primarily to the recognition of interest in connection with certain regulatory programs. Interest revenues in 1992 reflect lower revenues in connection with take-or-pay recoveries by the subsidiaries and the lower interest rates which prevailed during that year. Interest revenues were unusually high in 1991 due primarily to the recognition of $13.9 million of interest income in connection with refunds resulting from the settlement of certain tax matters related to prior years. The changes in "Other (net)" in the Statement of Income for 1993 and 1992 reflect the differing levels of income recognized from the Company's external investments. Income realized from the disposition of certain nonregulated assets also contributed to the higher amount in 1991.
Interest on long-term debt was lower in 1993 and 1992 due to redemptions and repayments of debenture borrowings. During 1993, the Company called $266.2 million of its higher-cost borrowings, while issuing $300 million of lower rate debentures. Other interest expense declined in both 1993 and 1992 due primarily to lower commercial paper discount rates in both years. Reduced interest charges related to refund obligations to customers also contributed to the decrease in 1992. The amount of interest expense capitalized has declined in the past two years reflecting the completion of pipeline expansion projects and reduced interest costs incurred.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
FOURTH QUARTER RESULTS
Consolidated's net income for the fourth quarter of 1993 was $86.1 million compared with $97.1 million earned in the 1992 fourth quarter, a decrease of $11 million. On a per share basis, the 1993 quarter was $.93 compared with $1.05 in 1992. However, the comparison is somewhat distorted due to the inclusion in the 1992 fourth quarter of the favorable impacts of certain deferred tax benefits under the then-applicable income tax accounting standard and the reversal of a reserve related to the Company's abandoned liquefied natural gas facilities. Excluding these items, fourth quarter net income would show an improvement due primarily to increased gas deliveries by the Company's transmission operations and colder weather. The weather in Consolidated's retail service areas was 3 percent colder than in the 1992 fourth quarter. These positive factors offset lower gas and oil wellhead prices experienced in the quarter by the exploration and production operations. Gas wellhead prices were down $.19 per thousand cubic feet compared with 1992 while oil wellhead prices fell $4.01 per barrel. ______________________________________________________________________________ QUARTERS ENDED DECEMBER 31, 1993 1992 ______________________________________________________________________________ (In Millions) Operating revenues . . . . . . . . . . $1,030.2 $ 790.4 Operating expenses . . . . . . . . . . (930.4) (672.8) ________ _______ Operating income . . . . . . . . . . . 99.8 117.6 Other income/expenses (net) . . . . . . . (13.7) (20.5) ________ _______ Net income . . . . . . . . . . . . . $ 86.1 $ 97.1 ======== ======= Per common share (in dollars). . . . . . . $.93 $1.05 Average shares outstanding (thousands). . . . 92,923 92,473 ______________________________________________________________________________
FEDERAL AND STATE REGULATORY MATTERS
FERC ORDER 636
In April 1992, the FERC issued Order 636, a comprehensive set of regulations designed to encourage competition and continue the significant restructuring of the interstate natural gas pipeline industry that the FERC first set in motion during 1985 with its Order 436. Under Order 636, interstate pipelines were required to "unbundle" their services into separate sales, transportation and storage services and to offer and price such services separately. Order 636 also changed the way in which rates are designed by requiring return on equity and income taxes to be recovered as part of a fixed monthly charge. Under previous rate design, these costs were recovered through usage or commodity rates.
Order 636 allows pipelines to recover 100 percent of all prudently incurred costs resulting from the transition to the new rules (transition costs). The FERC has identified four types of transition costs: (1) purchased gas costs that would have been recovered from customers through the purchased gas adjustment provisions of previous tariffs, but which are unrecovered at the termination of "bundled" services; (2) gas supply realignment (GSR) costs required to reform or terminate contracts to purchase gas from producers; (3) stranded costs, which are the cost of facilities or transportation arrangements no longer necessary or uneconomic after restructuring; and (4) the costs of installing new facilities that may be required to comply with the new rules.
CNG Transmission received FERC approval to implement Order 636 effective October 1, 1993, in accordance with the terms of a comprehensive stipulation and agreement (Settlement) reached with customers and others.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
On November 23, 1993, the FERC issued an Order allowing CNG Transmission to begin collecting its unrecovered purchased gas and sales-related transportation costs which were remaining at the October 1, 1993, implementation date. In December 1993, CNG Transmission billed its customers (through a direct bill mechanism) for these costs. The total principal amount to be collected based on this Order was approximately $177.9 million. In accordance with the FERC Order, CNG Transmission can seek recovery through March 1995 of additional Order 636 transition costs incurred that relate to transactions prior to October 1, 1993.
In accordance with the Settlement, CNG Transmission will absorb up to $3.5 million of GSR costs. GSR costs, however, were minimized since certain of the Company's distribution subsidiaries agreed to the assignment from CNG Transmission of its Appalachian gas purchase contracts in consideration for favorable cost allocation provisions contained in the Settlement. The distribution subsidiaries should generally be able to pass through to their customers the costs associated with the assigned contracts in recognition of the other benefits received in the Settlement.
The full extent of stranded costs for CNG Transmission are unknown at this time. However, CNG Transmission has filed for recovery of $9.2 million of stranded facilities costs in its December 30, 1993, general rate filing. CNG Transmission will incur new facilities costs, including costs for new computer hardware and software. Although a final overall estimate of new facilities costs has not yet been determined, such costs may approach $50 million. Consistent with FERC procedures, the Settlement allows CNG Transmission to file with the FERC for rate increases to recover both stranded costs and new facilities costs. The Settlement also provides CNG Transmission additional rights to defer recognition of certain stranded costs pending rate case review. Parties to the Settlement have also agreed not to challenge certain construction projects that CNG Transmission may determine will assist it in rendering unbundled services.
Although Order 636 applies directly to pipeline companies, it has also affected the way in which gas distribution companies purchase gas supplies and contract for transportation and storage services. The Company's distribution subsidiaries have taken actions designed to adapt to the new environment created by Order 636 and should generally be able to recover transition costs passed through to them by the pipelines. Reference is made to Note 3 to the consolidated financial statements for additional information regarding the effects of Order 636 on the distribution subsidiaries, including the estimated amount of future transition costs.
Other portions of the Company's operations have also been affected by Order 636. CNG Producing and CNG Gas Services have taken action to expand the Company's customer base in response to the unbundling of sales service previously offered by pipelines. New marketing strategies and contracts are being developed to address customer needs for intermediate and long-term gas supplies as well as other services which will be required in this "post-Order 636" era.
As a fully integrated gas system with production, transmission, distribution and marketing subsidiaries, the Company believes it is in a position to compete in new markets and to offer a broad range of unbundled gas services. Based on management's current estimates, the operating environment under Order 636 and any uncertainties pertaining to the recovery of transition costs should not have a material adverse effect on the Company's financial position, results of operations or cash flows.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
CNG TRANSMISSION
On December 30, 1993, CNG Transmission filed a general rate filing with the FERC requesting an annual revenue increase of $106.6 million. The rate increase request is intended to cover higher operating costs, increased plant investment, and the recovery of $9.2 million in transition costs related to stranded facilities because of FERC Order 636. The increase is expected to become effective, after the suspension period, on July 1, 1994, subject to refund.
STATE REGULATORY ISSUES
On June 22, 1993, the Virginia State Corporation Commission approved a $10.4 million annual increase for Virginia Natural Gas. The new rates were effective retroactive to September 4, 1992. In its April 1992 filing, Virginia Natural Gas had requested a $14.1 million annual increase in revenues.
On October 28, 1993, Peoples Natural Gas filed with the Pennsylvania Public Utility Commission for a $28.4 million increase in base rates. The rate increase request is intended to cover higher operating expenses. If approved, the new rates would become effective on August 6, 1994. Peoples Natural Gas also filed to recover, over four years, $20.1 million in estimated transition costs related to FERC Order 636.
On October 29, 1993, the Public Service Commission of West Virginia granted Hope Gas an indicated $1.9 million annual revenue increase effective November 1, 1993. In its March 1993 filing, Hope Gas had requested an $8.2 million increase in revenues. On November 8, 1993, Hope Gas filed a petition for rehearing in the case.
On January 18, 1994, East Ohio Gas filed with the Public Utilities Commission of Ohio for a $99.1 million increase in base rates. The rate increase request is intended to cover higher operating costs and increases in plant investment. A decision by Ohio regulators is expected in October 1994. In addition, East Ohio is negotiating with customers and the Commission staff as to the future recovery of transition costs to be incurred under Order 636.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
ENVIRONMENTAL MATTERS
The Company and its subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations govern both current and future operations and potentially extend to plant sites formerly owned or operated by the Company and its subsidiaries, or their predecessors.
As part of their normal business operations, the subsidiaries periodically monitor their properties and facilities and resolve potential environmental matters so as to remain in compliance with the various environmental laws and regulations. The Company also conducts general environmental surveys on a continuing basis at its operating facilities to assure compliance with these laws and regulations. In this regard, voluntary surveys at subsidiary meter sites were conducted to determine the extent of any possible soil contamination due to mercury spillage. These studies, which are continuing, are not in response to any governmental or regulatory directive, order or settlement agreement and have not disclosed any mercury contamination for which the remediation costs would be considered material to Consolidated's financial position, results of operations or cash flows. On August 16, 1990, CNG Transmission entered into a Consent Order and Agreement with the Commonwealth of Pennsylvania Department of Environmental Resources (DER) in which CNG Transmission has agreed with the DER's determination of certain violations of the Pennsylvania Solid Waste Management Act, the Pennsylvania Clean Streams Law and the rules and regulations promulgated thereunder. It is unknown at this time whether civil penalties will be assessed. Pursuant to the Order and Agreement, CNG Transmission is performing certain sampling, testing and analysis, and conducting a program of remediation at some of its Pennsylvania facilities. Total remediation costs in connection with the Order and Agreement are not expected to be material with respect to Consolidated's financial position, results of operations or cash flows. Based on current knowledge, the Company has recognized a gross estimated liability amounting to $19,661,000 at December 31, 1993, for future costs expected to be incurred to remediate or mitigate hazardous substances at mercury sites and at facilities covered by the Order and Agreement. The estimate for this liability was based on current environmental laws and regulations and existing technology.
Inasmuch as certain environmental-related expenditures are expected to be recoverable in future regulatory proceedings, a regulatory asset amounting to $11,378,000 at December 31, 1993, is included in the Consolidated Balance Sheet under the caption "Deferred charges and other noncurrent assets." Also, uncontested claims amounting to $3,566,000 at December 31, 1993, were recognized for environmental-related costs probable of recovery through joint- interest operating agreements.
The total charges to operating expenses for environmental-related costs were $3,205,000, $7,646,000, and $9,049,000, respectively, for the years ended December 31, 1991 through 1993. Reference is made to Note 15 to the consolidated financial statements for the components of these expenses. The Company's environmental-related capital expenditures for monitoring or complying with laws and regulations for 1991 through 1993 were not material.
The Company has determined that it is associated with 16 former manufactured gas plant sites, five of which are currently owned by the Company. Studies conducted by other utilities at their former manufactured gas plants have indicated that their sites contain coal tar and other potentially harmful materials. None of the 16 former sites with which the Company is associated is under investigation by any state or federal environmental agency, and no investigation or action is currently anticipated. At this time it is not known if, or to what degree, these sites may contain environmental contamination. Therefore, the Company is not able to estimate the cost, if any, that may be required for the possible remediation of these sites.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
The exact nature of environmental issues that the Company may encounter in the future cannot be predicted. Additional environmental liabilities may result in the future as more stringent environmental laws and regulations are implemented and as the Company obtains more specific information about its existing sites and production facilities. At present, no estimate of any such additional liability, or range of liability amounts, can be made.
CNG Transmission and certain of the Company's distribution subsidiaries are subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments of 1990 (1990 amendments) which added significantly to the existing requirements established by the Federal Clean Air Act. These subsidiaries operate compressor stations that are covered by the new nitrogen oxide emission standard established as a result of the 1990 amendments. The Company will have until May 31, 1995, to comply with the emission standard. The Company expects that compliance will require significant capital expenditures to modify the compressor engines along the Company's pipeline system. However, the actual cost of compliance will be dependent upon the requirements imposed by the environmental agencies of the states in which the compressor stations are located. Based on the Company's preliminary estimates and analyses, approximately $46 million of capital expenditures may be required. Actual capital expenditures required to comply with the 1990 amendments are expected to be recoverable through future regulatory proceedings.
EFFECTS OF INFLATION
Although inflation rates have been moderate, any change in price levels has an effect on operating results due to the capital intensive and regulated nature of Consolidated's major business components. Consolidated attempts to minimize the effects of inflation through cost control, productivity improvements and regulatory actions where appropriate.
For the Company's rate-regulated subsidiaries, increases in operating costs are not generally subject to immediate recovery due to the time lag inherent in the rate-making process. Also, only the historical cost of property, plant and equipment is recoverable in revenues through depreciation. While the rate- making process gives no recognition to the current cost of replacing properties, Consolidated believes, based on past regulatory practices, that it will be allowed to earn a return on the increased cost of its property investment as replacement occurs.
For the exploration and production operations, gas and oil prices are based on market supply and demand rather than the level of costs. Therefore, Consolidated's exploration and production operations focus on balancing production and sales levels with operating costs to minimize the effects of inflation.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
FINANCIAL CONDITION
DIVIDEND INCREASE AND COMMON STOCK MATTERS
In December 1993, the Board of Directors raised the annual dividend on the common stock to $1.94 a share from $1.92 a share. The new quarterly rate is 48.5 cents a share, compared with 48 cents a share. This marked the 29th consecutive year in which the dividend has been increased. Total dividends paid to common shareholders in 1993 were $178.1 million compared with $168.5 million in 1992 and $163.1 million in 1991.
During 1993, a total of 376,811 original issue shares were acquired by stockholders and employees through various Company-sponsored plans. Stockholders participating in the Company's Dividend Reinvestment Plan purchased a total of 57,750 shares, representing the reinvestment of $2,856,000 of dividends. A total of 303,561 shares were issued to employees under stock- based incentive plans, including 237,957 shares acquired through the exercise of outstanding stock options. In addition, 15,500 new issue shares were purchased by employees through the System's Thrift Plans. During 1993, certain share requirements of the Thrift Plans, as well as the shares required for the Company's Employee Stock Ownership Plan, were satisfied through open market purchases.
Under the Company's stock repurchase plan, up to 4 million shares of the outstanding common stock can be repurchased through December 31, 1995. The shares may be purchased in the open market from time-to-time, depending on market conditions. The Company may also acquire shares of its common stock through certain provisions of the 1991 Stock Incentive Plan and the Long-Term Incentive Plan. The shares repurchased or acquired are held as treasury stock and are available for reissuance for general corporate purposes or in connection with various employee benefit plans. No treasury shares were held by the Company at December 31, 1992. During 1993, no open market purchases were made by the Company. The Company acquired 29,212 shares in 1993 through the provisions of its incentive plans at a cost of $1.4 million, or an average price of $48.51 a share. All of these shares were sold before year-end to the System's Thrift Plans.
CAPITAL SPENDING
As shown in the table below, capital expenditures were $342.6 million in 1993, compared with $441.5 million in 1992. _______________________________________________________________________________ CAPITAL EXPENDITURES 1994* 1993 1992 _______________________________________________________________________________ (In Millions) Distribution. . . . . . . . . . . $141.8 $115.4 $114.7 Transmission. . . . . . . . . . . 124.4 113.4 225.3 Exploration and production . . . . . . 153.0 110.7 99.1 Other . . . . . . . . . . . . . 20.4 3.1 2.4 ______ ______ ______ Total. . . . . . . . . . . . $439.6 $342.6 $441.5 ====== ====== ====== * Estimated. _______________________________________________________________________________
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Continued)
The current capital budget for 1994 is estimated at $439.6 million, a 28 percent increase compared with spending in 1993. The higher level of capital expenditures anticipated for 1994 reflects increased spending for exploration and production operations, including funds for work on the "Popeye" deep-water development project in the Gulf of Mexico. Expenditures for the distribution and transmission operations will primarily be for enhancements and improvements in the pipeline network and related facilities, and expected capital expenditures to comply with the 1990 Federal Clean Air Act Amendments. The increase in the "Other" category reflects a higher level of expenditures in connection with the Lakewood cogeneration project.
Funds required for the capital spending program, as well as for other general corporate purposes, are expected to be obtained principally from internal cash generation. Additional funds, if necessary, could be obtained through borrowings under the Company's credit agreement or through the issuance of new debt securities.
The following table presents the total gross investment in property, plant and equipment of each of Consolidated's business components at December 31, 1993 and 1992: _______________________________________________________________________________ TOTAL GROSS INVESTMENT IN PROPERTY, PLANT AND EQUIPMENT 1993 1992 _______________________________________________________________________________ (In Millions) Distribution. . . . . . . . . . . . . $2,380.1 $2,281.7 Transmission. . . . . . . . . . . . . 1,916.8 1,812.1 Exploration and production . . . . . . . . 2,983.0 2,929.7 Other . . . . . . . . . . . . . . . 66.1 63.6 ________ ________ Total. . . . . . . . . . . . . . $7,346.0 $7,087.1 ======== ======== _______________________________________________________________________________
Although the Company plans to increase spending in 1994 for its exploration and production operations, it will continue to monitor its investment in these operations in light of changing market conditions. The sale of the Company's remaining interests in gas and oil producing properties in Canada is possible depending on economic conditions. Proved reserves associated with Canadian properties approximated 1.1 Bcf of gas and 5.7 million barrels of oil at December 31, 1993. On an energy-equivalent basis, these reserves represent about 3 percent of Consolidated's total proved reserves at that date.
CAPITAL RESOURCES AND LIQUIDITY
Because of the seasonal nature of the regulated subsidiaries' heating business, a substantial portion of the Company's cash receipts are obtained in the first half of the year. However, cash requirements for capital expenditures, dividends, long-term debt retirement and working capital do not track this pattern of cash receipts. Consequently, additional cash needs are satisfied through the sale of short-term commercial paper notes or by the issuance of long-term debt. As shown in the Statement of Cash Flows, net cash provided by operating activities was $470.9 million, $405.4 million and $497.9 million for the years 1993, 1992 and 1991, respectively. Higher gas sales and transportation revenues in 1993 and refunds made to customers in 1992 amounting to $63 million in connection with the final settlement of a CNG Transmission rate case were the primary factors for the increase in net operating cash flows in 1993 compared with 1992. Federal income tax refunds received in 1991 contributed to that year's operating cash flows.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Concluded)
During 1993, the Company retired $279,650,000 principal amount of its debentures, of which $266,150,000 represents debentures called at the option of the Company. The Company used short-term borrowings and internally-generated funds to redeem an aggregate of $118,150,000 of debentures in May and June of 1993. On August 16, 1993, an additional $148,000,000 of debentures were redeemed. On August 24, 1993, the Company sold $150 million of 5 3/4% debentures, using the net proceeds from the sale, along with available funds, to repay short-term debt incurred in connection with the August 16 redemption. Also, in December 1993, the Company sold $150 million of 6 5/8% debentures. The net proceeds from this sale were used to repay short-term borrowings in connection with the May and June redemptions and to finance capital expenditures.
The Company has a currently effective shelf registration with the SEC that permits the sale of up to $100 million of debentures. The Company plans to file a new shelf registration in 1994 that would permit the sale of an additional $400 million of debentures.
At December 31, 1993, the Company had a $300 million credit agreement with a group of banks. At various times during 1993, the Company utilized borrowings under this agreement primarily to provide temporary financing for capital expenditures. The maximum amount outstanding at any one time during 1993 was $125 million. There were no amounts outstanding under this credit agreement at December 31, 1993 and 1992.
The Company's embedded long-term debt cost, excluding current maturities, at year-end 1993 was 7.75 percent, compared with 8.18 percent for 1992 and 8.38 percent for 1991. The long-term debt to capitalization ratio was 34.7 percent at the end of 1993, and 34.3 percent and 38.0 percent at year-end 1992 and 1991, respectively. Under the provisions of the indenture covering the Company's outstanding senior debenture issues, the ratio cannot exceed 60 percent. The Company's senior debentures are rated A1 by Moody's Investors Service, AA- by Standard & Poor's, AA- by Duff and Phelps, and AA by Fitch Investors Service.
The Company utilizes short-term borrowings to finance gas inventories and other working capital requirements. Funds from the sale of commercial paper notes were used for these purposes in 1993, of which $455 million was outstanding at year-end. Bank lines of credit amounting to $475 million are available to provide backup if the sale of commercial paper notes is not feasible. In addition to these credit lines, the Company may utilize unused portions of its credit agreement to provide support for commercial paper notes.
SUMMARY OF FINANCIAL DATA
The Company's Summary of Financial Data is on page 26.
ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
SUPPLEMENTARY DATA
This information is included in the Notes to Consolidated Financial Statements and reference is made thereto as follows: Gas and Oil Producing Activities -- Note 17(A), page 72; Quarterly Financial Data -- Note 17(B), page 76.
FINANCIAL STATEMENTS
INDEX _______________________________________________________________________________ Page _______________________________________________________________________________
Report of Independent Accountants. . . . . . . . . . . . 48 Consolidated Statement of Income for the Years 1991 through 1993 . 49 Consolidated Balance Sheet at December 31, 1992 and 1993 . . . . 50 Consolidated Statement of Cash Flows for the Years 1991 through 1993 52 Notes to Consolidated Financial Statements. . . . . . . . . 53
Schedule V - Property, Plant and Equipment. . . . . . . . . 78 Schedule VI - Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment. . . . . . . 82 Schedule VIII - Valuation and Qualifying Accounts . . . . . . Note 2 Schedule IX - Short-term Borrowings . . . . . . . . . . . 86 Schedule X - Supplementary Income Statement Information . . . . 87
Notes: (1) Schedules I, II, III, IV, VII, XI, XII, XIII, and XIV have been excluded because they are not applicable. (2) Omitted inasmuch as amounts involved are not significant. _______________________________________________________________________________
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of Consolidated Natural Gas Company
In our opinion, the consolidated financial statements listed in the accompanying index on page 47 present fairly, in all material respects, the financial position of Consolidated Natural Gas Company and subsidiaries at December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. 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 generally accepted auditing standards 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.
As discussed in Note 1 to these consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," and Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," in 1993.
PRICE WATERHOUSE
Price Waterhouse
600 Grant Street Pittsburgh, Pennsylvania 15219-9954 February 16, 1994
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) CONSOLIDATED STATEMENT OF INCOME
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) CONSOLIDATED BALANCE SHEET
ITEM 8. (Cont.)
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) CONSOLIDATED STATEMENT OF CASH FLOWS
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Methods of allocating costs to accounting periods by the subsidiary companies subject to federal or state accounting and rate regulation may differ from methods generally applied by nonregulated companies. However, when the accounting allocations prescribed by regulatory authorities are used for ratemaking, the economic effects thereof determine the application of generally accepted accounting principles. Significant accounting policies of Consolidated Natural Gas Company (the Company) and subsidiaries within this framework are summarized in this Note.
PRINCIPLES OF CONSOLIDATION The Company owns all of the capital stock of its subsidiaries. The consolidated financial statements represent the accounts of the Company and its subsidiaries after the elimination of intercompany transactions.
The subsidiary companies follow the equity method of accounting for investments in partnerships and corporate joint ventures when the subsidiary is able to influence the financial and operating policies of the investee. For investments where the subsidiary is not able to influence the business policies of the investee, the cost method is applied.
REVENUE RECOGNITION Revenues from gas sales and transportation services are recognized in the same period in which the related gas volumes are delivered to customers. The subsidiaries bill and recognize sales revenues from residential and certain commercial and industrial customers on the basis of scheduled meter readings. In addition, revenues are recorded for estimated deliveries of gas to these customers from the meter reading date to the end of the accounting period. For wholesale and other commercial and industrial customers, revenues are based upon actual deliveries of gas to the end of the period.
UNRECOVERED GAS COSTS Where permitted by regulatory authorities, the subsidiaries defer the difference between certain gas costs incurred, including take-or-pay and transportation costs, and the amount of such costs included in current rates. Amounts deferred are recognized as purchased gas costs in future periods when such costs are recovered through adjusted rates.
HEDGING AND OTHER ENERGY PRICE MANAGEMENT ACTIVITIES The nonregulated subsidiaries utilize natural gas and crude oil futures contracts to hedge a portion of their transactions against the risk of market price fluctuations. Gains and losses on these contracts are deferred and subsequently recognized in the period the related hedged transaction occurs. Cash flows from hedging transactions are included in the Consolidated Statement of Cash Flows as an operating activity -- the same category as the cash flows from the transaction being hedged.
The nonregulated subsidiaries, on occasion, enter into price swap agreements to modify their exposure to natural gas price risk. Under these agreements, the subsidiaries receive payments from, or make payments to, counterparties generally based on the difference between fixed and variable gas prices specified in the contracts. Settlement takes place under the agreements on a monthly basis, and amounts received or paid are recognized as an adjustment to nonregulated gas sales revenues.
PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION The property, plant and equipment accounts are stated at the cost incurred or, where required by regulatory authorities, "original cost." Additions and betterments are charged to the property accounts at cost. Upon normal retirement of a plant asset, its cost is charged to accumulated depreciation together with costs of removal less salvage. The costs of maintenance, repairs and replacing minor items are charged principally to expense as incurred.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
GAS AND OIL PRODUCING ACTIVITIES CNG Producing and CNG Transmission follow the full cost method of accounting for gas and oil producing activities prescribed by the Securities and Exchange Commission (SEC). Under the full cost method, all costs directly associated with property acquisition, exploration, and development activities are capitalized, with the principal limitation that such amounts not exceed the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves.
The gas and oil producing activities of the distribution subsidiaries are subject to cost-of-service rate regulation and are exempt from the accounting methods prescribed by the SEC.
DEPRECIATION AND AMORTIZATION Depreciation and amortization are recorded over the estimated service lives of plant assets by application of the straight-line method or, in the case of gas and oil producing properties, the unit-of-production method.
Under the full cost method of accounting, amortization is also accrued on estimated future costs to be incurred in developing proved gas and oil reserves, including estimated dismantlement and abandonment costs net of projected salvage values. However, the costs of investments in unproved properties and major development projects are excluded from amortization until it is determined whether or not proved reserves are attributable to such properties.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION The subsidiaries subject to cost-of-service rate regulation capitalize the estimated costs of equity funds and/or borrowed funds used during the construction of major projects. Under regulatory practices, those companies are permitted to include the costs capitalized in rate base for rate-making purposes when the completed facilities are placed in service. The remaining subsidiaries capitalize interest costs as part of the cost of acquiring certain assets. Generally, interest is capitalized on unproved properties and major construction and development projects on which amortization is not yet being recorded.
In determining the allowance for funds used during construction, the following ranges of rates reflect the pretax cost of borrowed funds used to finance construction expenditures: 1991 - 5% to 9 3/8%; 1992 - 3 7/8% to 9 1/4% and 1993 - 3 1/4% to 8 7/8%. There were no equity funds capitalized in those years.
INCOME TAXES The current provision for income taxes represents amounts paid or currently payable. Investment tax credits which were deferred where required by regulatory authorities are being amortized as credits to income over the estimated service lives of the related properties.
CHANGE IN ACCOUNTING Effective January 1, 1993, the Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes." The adoption of SFAS No. 109 changed the Company's method of accounting for income taxes from the deferred method to an asset and liability approach. Under SFAS No. 109, deferred tax liabilities and assets are recognized for the expected future tax consequences attributable to temporary differences between the carrying amounts of assets and liabilities and their tax bases. In addition, such deferred tax asset and liability amounts are adjusted for the effects of enacted changes in tax laws or rates. Under the previous income tax accounting principle, deferred income taxes were generally provided for the tax effects of timing differences between the recognition of revenue and expense for income tax purposes and financial reporting purposes. Once recognized, tax balances were not adjusted for subsequent changes in tax laws or rates.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
SFAS No. 109 also requires the recognition of additional deferred tax liabilities and assets for timing differences on which deferred tax treatment had been prohibited in the past by regulatory authorities. Regulatory assets and liabilities corresponding to such additional deferred taxes, representing future amounts collectible from or refundable to customers through the rate- making process, may also be recorded.
The cumulative effect on years prior to 1993 of applying SFAS No. 109 increased 1993 net income by $17,422,000, or $.19 per share. This cumulative effect adjustment resulted primarily from the reduction in deferred income tax balances associated with the Company's nonregulated activities. The application of SFAS No. 109 had no effect on reported pretax earnings.
PENSION AND OTHER BENEFIT PROGRAMS PENSION PROGRAM The subsidiaries have qualified noncontributory defined benefit pension plans covering all employees. Benefits payable under the plans are based primarily on each employee's years of service, age and base salary during the five years prior to retirement. Net pension costs are determined by an independent actuary, and the plans are funded on an annual basis to the extent such funding is deductible under federal income tax regulations. Plan assets consist primarily of equity securities, fixed income securities and insurance contracts. The pension program also includes the payment of supplemental pension benefits to certain retirees depending on retirement dates.
In accordance with the requirements of Statement of Financial Accounting Standards No. 87, "Employers' Accounting for Pensions," Consolidated has recognized a liability for the unfunded accumulated benefit obligation relating to its supplemental pension benefit plans. An amount equal to the liability, less a required reduction in common stockholders' equity, net of applicable deferred taxes, has also been recognized as an intangible asset. Such amounts recognized are subject to future revision based on both changes in assumptions and changes in the financial status of the supplemental pension benefit plans.
OTHER POSTRETIREMENT BENEFITS In addition to pension plans, the subsidiaries sponsor defined benefit postretirement plans covering both salaried and hourly employees and certain dependents. The plans provide medical benefits as well as life insurance coverage. These benefits are provided through insurance companies and other providers with the annual cash outlays based on the claim experience of the related plans.
Employees who retire from System companies on or after attaining age 55 and having rendered at least 15 years of service, or employees retiring on or after attaining age 65, are eligible to receive benefits under the plans. The plans are both contributory and noncontributory, depending on age, retirement date, the plan elected by the employee, and whether the employee is covered under a collective bargaining agreement. Most of the medical plans contain cost- sharing features such as deductibles and coinsurance. For certain of the contributory medical plans, retiree contributions are adjusted annually.
CHANGE IN ACCOUNTING As required, Consolidated adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," effective January 1, 1993. This standard required a change from the practice of recognizing such costs on a pay-as-you-go basis to an accrual method. Under the standard, the estimated future costs of providing postretirement benefits are recognized as an expense and a corresponding liability during the employees' service periods. For the current contributory postretirement medical plans, the calculations under SFAS No. 106 anticipate future changes in cost-sharing that are included in the written plan.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As permitted by the standard, the Company elected to amortize the accumulated postretirement benefit obligation existing at the date of adoption (transition obligation) over a 20-year period. Prior to 1993, amounts paid for postretirement benefits were recognized as an expense in the period paid.
FASB STATEMENT NO. 112 In November 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits." This Statement covers benefits such as salary continuation, severance pay and disability-related benefits provided to inactive and former employees prior to retirement. The standard requires the accrual of a liability for the postemployment benefit obligations if certain specified conditions are met. Statement No. 112 is effective for fiscal years beginning after December 15, 1993. Based on management's current estimates and assumptions, the adoption of the standard is not expected to have a material effect on Consolidated's financial position, results of operations or cash flows.
ENVIRONMENTAL EXPENDITURES Environmental-related expenditures associated with current operations are generally expensed as incurred. Expenditures for the assessment and/or remediation of environmental conditions related to past operations are charged to expense or are deferred pending probable recovery. In this connection, a liability is recognized when the assessment or remediation effort is probable and the future costs are estimable. Estimated future costs for the abandonment and restoration of gas and oil properties are accrued currently through charges to depreciation.
Claims for recovery of environmental-related costs from insurance carriers and other third parties or through regulatory procedures are recognized separately as assets when future recovery is deemed probable.
GAINS AND LOSSES ON REACQUISITION OF DEBT Gains and losses (including redemption premiums) on the purchase or redemption of the Company's debentures are generally deferred and then included in income over the original lives of the applicable debenture issues to give recognition to the economic effect of the rate-making process on certain subsidiaries. The portion not deferred is included in income when realized.
EARNINGS PER SHARE Earnings per share of common stock is computed based on the weighted average number of common shares outstanding during the period. Under the methods prescribed by generally accepted accounting principles, the assumed exercise of outstanding stock options is not considered to have a dilutive effect on earnings per share. Also, the conversion of the Company's outstanding convertible subordinated debentures has not been assumed in determining earnings per share since such conversion would be antidilutive.
TEMPORARY CASH INVESTMENTS Temporary cash investments consist of short-term, highly liquid investments that are readily convertible to cash and present no significant interest rate risk. Such temporary cash investments are stated at cost, which approximates fair value due to their short maturities. For purposes of the Consolidated Statement of Cash Flows, temporary cash investments are considered to be cash equivalents.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. LINE OF BUSINESS Total operating revenues of the subsidiaries are derived from their operations in all phases of the natural gas business. Operations are conducted principally in the United States with CNG Producing also owning a working interest in a heavy oil program in Alberta, Canada.
A substantial portion of total operating revenues and related accounts receivable are generated by the Company's distribution and transmission subsidiaries. The distribution subsidiaries sell gas and/or provide transportation services to residential, commercial and industrial customers in Ohio, Pennsylvania, Virginia and West Virginia. These subsidiaries require deposits from certain customers to obtain utility services. The transmission subsidiary provides gas transportation, storage and related services to affiliates and to utilities and end-users in the Midwest, the Mid-Atlantic states and the Northeast.
3. RATE MATTERS Certain increases in prices by subsidiaries and other rate-making issues are subject to final modification in regulatory proceedings. The related accumulated provisions pertaining to these matters were $52,115,000 and $17,777,000 at December 31, 1992 and 1993, including interest. These amounts are reported in the Consolidated Balance Sheet under "Estimated rate contingencies and refunds" together with $27,271,000 and $39,679,000, respectively, which are primarily refunds received from suppliers and refundable to customers under regulatory procedures.
Pursuant to a November 1993 order from the Federal Energy Regulatory Commission (FERC), in December 1993, CNG Transmission billed its customers, including certain affiliates, $177.9 million, which represented the balance of its unrecovered purchased gas costs and unrecovered sales-related transportation costs existing at October 1, 1993 -- the date CNG Transmission's restructured services under FERC Order 636 became effective. Of the $177.9 million removed from unrecovered gas costs, $75,292,000 is included in the Consolidated Balance Sheet at December 31, 1993, under "Deferred charges and other noncurrent assets" representing the distribution subsidiaries' portion of such billing. The subsidiaries are pursuing the recovery of these costs in state regulatory proceedings.
In addition, at December 31, 1993, an estimated liability and a corresponding regulatory asset amounting to $6,300,000 have been recorded by the distribution subsidiaries for their portion of FERC Order 636 transition costs expected to be billed by nonaffiliated upstream pipeline companies. This liability reflects an estimate of these pipeline companies' unrecovered gas costs approved for billing by the FERC. Additional amounts are likely to be accrued in the future by the distribution subsidiaries for gas supply realignment costs and other Order 636 transition costs once these pipeline companies receive final FERC approval to recover these costs. Based on the pipeline companies' filings with the FERC, the distribution subsidiaries currently estimate that their portion of such costs could be in the range of $75 million. However, since settlement negotiations and regulatory proceedings regarding these costs are still in progress, the ultimate amount billed may vary significantly from this estimate.
Based on the nature of the costs and the past rate-making treatment of similar costs, management believes that the distribution subsidiaries should generally be able to pass through all Order 636 transition costs to their customers.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION Total provisions for depreciation of property, plant and equipment for the years ended December 31, 1991 through 1993, including amounts charged to accounts other than "Depreciation and amortization" in the Consolidated Statement of Income, were equivalent to approximately 4.8%, 4.3% and 4.2%, respectively, of the average capitalized investment subject to depreciation and amortization in those periods.
Amortization of capitalized costs under the full cost method of accounting for Consolidated's exploration and production operations amounted to $1.16 per Mcf (thousand cubic feet) equivalent of gas and oil produced in 1991, $1.19 in 1992, and $1.18 in 1993.
Costs of unproved properties capitalized under the full cost method of accounting that are excluded from amortization at December 31, 1993, and the years in which such excluded costs were incurred, follow: ______________________________________________________________________________ DECEMBER 31, Incurred in Calendar Year 1993 1993 1992 1991 Prior ______________________________________________________________________________ (In Thousands) Property acquisition costs $ 28,920 $ 5,772 $ 1,358 $ 3,902 $ 17,888 Exploration costs . . . 41,002 14,161 6,993 7,659 12,189 Capitalized interest . . 38,641 890 1,485 5,380 30,886 ________ ________ ________ ________ ________ Total . . . . . $108,563 $ 20,823 $ 9,836 $ 16,941 $ 60,963 ======== ======== ======== ======== ======== ______________________________________________________________________________
There are no significant properties, as defined by the SEC, excluded from amortization at December 31, 1993. As gas and oil reserves are proved through drilling or as properties are judged to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation.
5. PENSION COSTS Pension expense (or credits), which includes the costs of defined benefit pension plans and pension supplements, was $822,000, $(1,697,000) and $(4,844,000), respectively, for the years ended December 31, 1991 through 1993. The net pension costs, which were determined by an independent actuary, included the following components: ______________________________________________________________________________ Years Ended December 31, 1993 1992 1991 ______________________________________________________________________________ (In Thousands) Service cost - benefits earned during the period $ 27,266 $ 26,435 $ 26,275 Interest cost on projected benefit obligation . 56,834 54,748 53,713 Return on plan assets . . . . . . . . . (89,441) (73,754) (183,902) Net amortization and deferral . . . . . . (303) (9,926) 103,936 Special voluntary retirement programs. . . . 800 800 800 ________ ________ ________ Net pension cost . . . . . . . . . $ (4,844) $ (1,697) $ 822 ======== ======== ======== ______________________________________________________________________________
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In 1989, Peoples Natural Gas offered special retirement incentives to certain salaried and hourly employees. The additional pension payments resulting from these incentives are being paid from the assets of the applicable pension plans. The estimated cost of these additional benefits, amounting to approximately $8,000,000, was deferred and is being amortized to expense over a 10-year period which began October 1, 1990, in accordance with the rate-making treatment approved by the Pennsylvania Public Utility Commission. The amount amortized to pension expense was $800,000 in each of the years ended December 31, 1991 through 1993.
The following table sets forth the funded status of the plans, as determined by an independent actuary, at December 31, 1992 and 1993:
The projected benefit obligation at December 31, 1992 and 1993, was determined using an annual discount rate of 6.5% and an average assumed annual rate of salary increase of 5.5%. The expected long-term rate of return on plan assets was 8.0% per annum.
The minimum liability recognized relating to the Company's supplemental pension benefit plans amounted to $13,112,000 and $10,067,000 at December 31, 1992 and 1993. The related intangible asset recognized as of those dates amounted to $10,108,000 and $7,572,000, respectively. These amounts are included in the Consolidated Balance Sheet under "Other deferred credits and noncurrent liabilities" and "Deferred charges and other noncurrent assets." Adjustments of the minimum liability and intangible asset due to changes in assumptions or the financial status of the plans resulted in a credit to retained earnings of $216,000 and $361,000 at December 31, 1992 and 1993, respectively.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
6. OTHER POSTRETIREMENT BENEFITS Effective January 1, 1993, the Company adopted the provisions of Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." Statement No. 106 requires that the estimated future costs of providing postretirement benefits, such as health care and life insurance, be recognized as an expense and a liability during the employees' service periods. As permitted under the standard, the Company elected to amortize the accumulated postretirement benefit obligation existing at the date of adoption (transition obligation) of $288,393,000 over a 20-year period.
Net periodic postretirement benefit cost for the year ended December 31, 1993, as determined by an independent actuary, included the following components: ______________________________________________________________________________ Year Ended December 31, 1993 ______________________________________________________________________________ (In Thousands) Service cost - benefits attributed to service during the period $10,549 Interest cost on accumulated postretirement benefit obligation 23,208 Amortization of transition obligation. . . . . . . . . 14,420 _______ Net periodic postretirement benefit cost . . . . . . . $48,177 ======= ______________________________________________________________________________
The following table reconciles the plans' combined funded status, as determined by an independent actuary, with amounts included in the Consolidated Balance Sheet at December 31, 1993: ______________________________________________________________________________ December 31, 1993 ______________________________________________________________________________ (In Thousands) Accumulated postretirement benefit obligation: Retirees. . . . . . . . . . . . . . . . . . $ 165,819 Fully eligible active plan participants . . . . . . . 58,465 Other active plan participants . . . . . . . . . . 102,900 _________ Total accumulated postretirement benefit obligation. . . 327,184 Plan assets at fair value. . . . . . . . . . . . . - _________ Accumulated postretirement benefit obligation in excess of plan assets . . . . . . . . . . . (327,184) Unrecognized net loss . . . . . . . . . . . . . . 22,821 Unrecognized transition obligation. . . . . . . . . . 273,973 _________ Accrued postretirement benefit cost recognized in the Consolidated Balance Sheet . . . . . . . . . . $ (30,390) ========= ______________________________________________________________________________
The weighted average discount rate used in determining the accumulated postretirement benefit obligation was 7.25%. The average assumed annual rate of salary increase for the applicable life insurance plans was 5.5%.
The assumed health care cost trend rate used in measuring the accumulated postretirement benefit obligation for the medical plans is 11% for 1994, declining gradually to 5% in 2003 and remaining at that level thereafter. The health care cost trend rate assumption has a significant effect on the amounts reported. If the health care cost trend rate were increased by 1% in each year, the accumulated postretirement benefit obligation as of December 31, 1993, would be increased by $28.8 million. A 1% change would also increase the aggregate of the service and interest cost components of net periodic postretirement benefit cost for 1993 by $4.2 million.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The majority of the estimated postretirement benefit costs and of the transition obligation is attributable to Consolidated's rate-regulated subsidiaries. Accordingly, these subsidiaries are seeking, or intend to seek as soon as practicable, rate relief from their respective regulatory commissions for the increased level of expense resulting from the adoption of the standard. In this regard, regulatory authorities having jurisdiction over the Company's subsidiaries have indicated their intention to generally allow inclusion in rates of postretirement benefit costs determined on an accrual basis, subject to prudency and certain other conditions. As a result, the Company's rate-regulated subsidiaries have generally deferred the differences between SFAS No. 106 costs and amounts currently included in rates pending expected recovery of Statement No. 106 costs and related deferrals in regulatory proceedings. The amount of SFAS No. 106 costs deferred at December 31, 1993, was $27,662,000, which is included in the Consolidated Balance Sheet under "Deferred charges and other noncurrent assets."
Currently, the subsidiary companies do not prefund postretirement benefit costs, but pay claims as presented. However, the FERC and certain state regulatory authorities have indicated that when SFAS No. 106 costs are recovered in rates, amounts collected must be deposited in irrevocable trust funds dedicated for the sole purpose of paying postretirement benefits.
Prior to the adoption of SFAS No. 106, postretirement benefit costs were expensed as paid. The cost of such benefits amounted to $16,881,000 and $17,948,000 for the years ended December 31, 1991 and 1992, respectively.
7. INCOME TAXES As detailed in Note 1, the Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," effective January 1, 1993. Statement No. 109 required a change from the deferred method to an asset and liability approach for accounting for and reporting of income taxes. The cumulative effect on years prior to 1993 of applying SFAS No. 109 increased net income in 1993 by $17,422,000, or $.19 per share, due primarily to the reduction in deferred tax balances associated with the Company's nonregulated activities.
"Income taxes - estimated" included the following: ______________________________________________________________________________ Years Ended December 31, 1993 1992 1991 ______________________________________________________________________________ (In Thousands) Current provision Federal . . . . . . . . . . $ 99,029 $ 18,378 $ 32,274 State. . . . . . . . . . . 23,279 5,466 3,119 Deferred income taxes (net) Federal . . . . . . . . . . (6,688) 35,941 15,715 State. . . . . . . . . . . (13,094) 11,529 6,375 Investment tax credit . . . . . . (2,620) (2,691) (2,639) ________ ________ ________ Total. . . . . . . . . . . $ 99,906 $ 68,623 $ 54,844 ======== ======== ======== Income before taxes. . . . . . . $288,400 $263,581 $223,457 ======== ======== ======== ______________________________________________________________________________
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
On August 10, 1993, the federal corporate income tax rate was increased from 34% to 35%, retroactive to January 1, 1993. As required by SFAS No. 109, existing deferred tax assets and liabilities were adjusted to reflect this enacted tax rate change. As a result, deferred income tax expense was increased (and operating income was reduced) in the third quarter of 1993 by $11,429,000, or $.12 per share. In addition, income taxes based on pretax earnings for the year 1993 increased by $2,692,000, or $.03 per share because of the higher rate. The total adjustment to the net deferred income tax liability included in the Consolidated Balance Sheet as a result of the increase in the federal corporate income tax rate amounted to $26,707,000.
Income taxes charged to operating income differed from the amounts of $75,975,000, $89,618,000 and $100,940,000 shown in the next table that were computed by applying the statutory federal income tax rate of 34% (1991 and 1992) and 35% (1993) to reported income before taxes. The reasons for the differences follow: ______________________________________________________________________________ Years Ended December 31, 1993 1992 1991 ______________________________________________________________________________ (In Thousands) Computed "expected" tax expense. . . . $100,940 $ 89,618 $ 75,975 Increases (or reductions) in tax resulting from: Production tax credit . . . . . . (8,435) (7,506) (5,349) Investment tax credit . . . . . . (2,620) (2,691) (2,639) Deferred tax reversals . . . . . . - (15,325) (15,803) State income taxes . . . . . . . 6,620 11,217 6,266 Effect of increase in federal corporate income tax rate on deferred income taxes. . . . . 11,429 - - Miscellaneous. . . . . . . . . (8,028) (6,690) (3,606) ________ ________ ________ Income taxes charged to operating income $ 99,906 $ 68,623 $ 54,844 ======== ======== ========
Effective tax rate . . . . . . . 34.6% 26.0% 24.5% ______________________________________________________________________________
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The current and noncurrent deferred income taxes reported in the Consolidated Balance Sheet at December 31, 1993, represent the net expected future tax consequences attributable to temporary differences between the carrying amounts of assets and liabilities and their tax bases. These temporary differences and the related tax effects were as follows: ______________________________________________________________________________ Deferred income Deferred income December 31, taxes taxes-current ______________________________________________________________________________ (In Thousands) Deferred tax liabilities: Excess of tax over book depreciation . . $425,488 $ - Exploration and intangible well drilling costs . . . . . . . . . 276,462 - FERC Order 636 transition costs . . . . 48,404 - Allowance for funds used during construction . . . . . . . 41,089 - Other. . . . . . . . . . . . . 72,695 - ________ _________ Total liabilities . . . . . . . . 864,138 - ________ _________
Deferred tax assets: Deferred investment tax credits . . . . 20,291 - Tax basis step-up in connection with acquisition of subsidiary . . . . . 15,001 - Overheads capitalized for tax purposes. . 12,240 - Supplier and other refunds. . . . . . - 13,959 Unrecovered gas costs . . . . . . . - 3,979 Other. . . . . . . . . . . . . 33,095 5,747 Valuation allowance . . . . . . . . - - ________ _________ Total assets. . . . . . . . . . 80,627 23,685 ________ _________ Total deferred income taxes. . . . . $783,511 $(23,685) ======== ======== ______________________________________________________________________________
A regulatory liability amounting to $72,208,000 has been recorded representing the reduction to previously recorded deferred income taxes associated with rate- regulated activities that are expected to be refundable to customers, net of certain taxes collectible from customers. Also, a regulatory asset corresponding to the recognition of additional deferred income taxes not previously recorded because of past rate-making practices amounting to $113,483,000 has been recorded at December 31, 1993. These regulatory amounts are included in the Consolidated Balance Sheet under "Other deferred credits and noncurrent liabilities" and "Deferred charges and other noncurrent assets," respectively.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. GAS STORED Based upon the average price of gas purchased during 1993, the current cost of replacing the inventory of "Gas stored - current portion" exceeded the amount stated on a LIFO basis by approximately $176,397,000 at December 31, 1993.
A portion of gas in underground storage used as a pressure base for operations is included in "Property, Plant and Equipment" in the amounts of $120,270,000 and $123,564,000 at December 31, 1992 and 1993.
9. OTHER ASSETS UNAMORTIZED ABANDONED FACILITIES In 1988, Consolidated LNG received FERC approval for the abandonment of its interest in liquefied natural gas facilities at Cove Point, Maryland. In connection with the abandonment, Consolidated LNG recorded a deferred asset in accordance with the provisions of FASB Statement No. 90, "Accounting for Abandonments and Disallowances of Plant Costs." This deferred asset, which represents the present value of allowable costs expected to be recovered, is being amortized over the 10-year recovery period which began March 1, 1988, as prescribed in the FERC order.
LAKEWOOD COGENERATION PROJECT CNG Energy holds directly a 34% limited partnership interest in Lakewood Cogeneration, L.P. (Lakewood Partnership), a partnership formed to construct, own and operate a cogeneration facility in Lakewood, New Jersey. CNG Lakewood, Inc., a wholly owned subsidiary of CNG Energy, owns a 1% general partnership interest in the Lakewood Partnership. Using natural gas, the facility will produce electricity for sale to an electric utility and steam for sale primarily to customers in an industrial park.
In November 1992, the Lakewood Partnership entered into a credit agreement with a group of banks and an institutional investor that will provide up to $262,000,000 in construction financing through non-recourse loans made to the partnership. A portion of the proceeds from the construction loans was used to reimburse the partners for certain expenditures previously made in connection with the project. Construction of the facility began in late 1992 and is expected to be completed by the end of 1994. At December 31, 1993, CNG Energy's total investment in the project amounted to $7,186,000.
10. COMMON STOCKHOLDERS' EQUITY A summary of the changes in stockholders' equity follows:
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
COMMON STOCK OFFERING In September 1992, the Company issued, through a public offering, 4,600,000 shares of its common stock at a price to the public of $43.50 per share. The net proceeds of the offering, after deducting the underwriting discount and expenses, were $193,612,000. The proceeds from the stock sale were used to finance capital expenditures of the subsidiaries.
UNISSUED SHARES At December 31, 1993, 107,066,172 shares of common stock were unissued. Of these, a total of 18,436,115 shares have been registered with the SEC for possible issuance under various employee benefit plans including the 1991 Stock Incentive Plan, the Long-Term Incentive Plan and the System Thrift Plans. Shares acquired by these plans can consist of original issue shares, treasury shares or shares purchased in the open market. In addition, 741,356 shares have been registered with the SEC for possible issuance to shareholders under the Dividend Reinvestment Plan and 4,629,629 shares have been registered for issuance upon conversion of the Company's convertible subordinated debentures.
TREASURY STOCK Under a stock repurchase plan approved by the Board of Directors, the Company can purchase in the open market up to 4,000,000 shares of its common stock through December 31, 1995. The Company may also acquire shares of its common stock through certain provisions of the 1991 Stock Incentive Plan and the Long- Term Incentive Plan. Shares repurchased or acquired are held as treasury stock and are available for reissuance for general corporate purposes or in connection with various employee benefit plans. When treasury shares are reissued, the difference between the market value at reissuance and the cost of shares is reflected in "Capital in excess of par value." The cost of any shares held as treasury stock is shown as a reduction in common stockholders' equity in the Consolidated Balance Sheet.
STOCK AWARDS AND STOCK OPTIONS 1991 STOCK INCENTIVE PLAN The 1991 Stock Incentive Plan provides for the granting of stock awards, stock options and other stock-based awards to employees of the Company and its subsidiaries. The maximum number of shares available for issuance in each calendar year is determined in accordance with a formula contained in the plan. During 1993, 3,056,107 shares were available for issuance under the plan.
Stock awards granted under the plan may be in the form of restricted stock or deferred stock. Shares issued as restricted stock awards are held by the Company until the attached restrictions lapse. Deferred stock awards generally consist of a right to receive shares at the end of specified deferral periods. The market value of the stock award on the date granted is recorded as compensation expense over the applicable restriction or deferral period.
Stock options granted under the plan allow the purchase of common shares at a price not less than fair market value at the date of grant and not less than par value.
Stock appreciation rights may also be granted, either alone or in tandem with stock options. These rights permit the recipient to receive, upon exercise, the excess of the fair market value of a share on the date of exercise over the grant price. The grant price is generally the fair market value of the stock on the date of grant. As of December 31, 1993, no stock appreciation rights have been granted under the plan.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The 1991 Stock Incentive Plan also provides for the granting of performance awards, dividend equivalents, or other awards which may be based on, or related to, shares of the Company's common stock. The granting of stock awards constitutes a non-cash financing activity of the Company.
LONG-TERM INCENTIVE PLAN The Company's Long-Term Incentive Plan, which provided for the issuance of common shares to key employees as either restricted stock awards or stock options, terminated by its terms on November 9, 1991. However, the provisions of the plan continue with respect to any restricted stock awards and stock options granted prior to the termination date.
Shares of common stock issued as restricted stock awards under the plan are held by the Company until certain restrictions lapse, which ordinarily occurs equally on the third through sixth award anniversaries. The market value of the stock when awarded is recorded as compensation expense over the six-year period.
Stock options granted under the plan allow the purchase of common shares at a price not less than fair market value at the date of grant and not less than par value. The options generally are exercisable in four equal annual installments commencing with the second anniversary of the grant and expire after 10 years from the date of grant.
A summary of stock option activity under both plans for the years ended December 31, 1991 through 1993, follows: _______________________________________________________________________________ Number Option Price of Shares Per Share _______________________________________________________________________________ (In Thousands) Shares under option: At January 1, 1991 . . . . . . . 843 $32.50 - $50.75 Granted in 1991 . . . . . . . . 509 $41.13 - $43.88 Exercised in 1991. . . . . . . . (67) $34.38 - $40.00 Cancelled in 1991. . . . . . . . (59) $34.38 - $50.75 _____ At December 31, 1991. . . . . . . 1,226 $32.50 - $50.75
Granted in 1992 . . . . . . . . 659 $34.75 - $47.25 Exercised in 1992. . . . . . . . (113) $34.38 - $44.00 Cancelled in 1992. . . . . . . . (59) $34.38 - $50.75 _____ At December 31, 1992. . . . . . . 1,713 $32.50 - $50.75
Granted in 1993 . . . . . . . . 552 $44.88 - $55.00 Exercised in 1993. . . . . . . . (238) $33.25 - $50.75 Cancelled in 1993. . . . . . . . (65) $34.75 - $50.75 _____ At December 31, 1993. . . . . . . 1,962 $32.50 - $55.00 ===== _______________________________________________________________________________
At December 31, 1993, options were exercisable for the purchase of 295,077 shares. Stock options become exercisable for the purchase of 381,164 shares in 1994, 456,311 in 1995, 402,394 in 1996, and 426,618 shares thereafter.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
11. PREFERRED STOCK The Company's authorized cumulative preferred stock consists of 2,500,000 shares at a par value of $100 each. There were no shares of preferred stock issued or outstanding at December 31, 1992 and 1993.
12. DIVIDEND RESTRICTIONS The indenture relating to the Company's senior debenture issues and the preferred stock provisions of its Certificate of Incorporation contain restrictions on dividend payments by the Company and acquisitions of its capital stock. Under the indenture provisions (there being no preferred stock outstanding), $664,756,000 of consolidated retained earnings was free from such restrictions at December 31, 1993. The indenture also imposes dividend limitations on the subsidiaries, but at December 31, 1993, these limitations did not restrict their ability to pay dividends to the Company.
13. LONG-TERM DEBT Long-term debt, excluding current maturities, follows: ______________________________________________________________________________ December 31, 1993 1992 ______________________________________________________________________________ (In Thousands) Debentures 6 5/8%, Due December 1, 2013 . . . . . . $ 150,000 $ - 5 3/4%, Due August 1, 2003. . . . . . . 150,000 - 5 7/8%, Due October 1, 1998 . . . . . . 150,000 150,000 8 3/4%, Due October 1, 2019 . . . . . . 150,000 150,000 8 3/4%, Due June 1, 1999 . . . . . . . 100,000 100,000 9 3/8%, Due February 1, 1997 . . . . . . 100,000 100,000 8 5/8%, Due December 1, 2011 . . . . . . 100,000 100,000 7 5/8%, Due April 1, 1996 . . . . . . . - 100,000 8 1/8%, Due June 1, 1997 . . . . . . . - 18,600 8 3/8%, Due September 1, 1996. . . . . . - 13,900 9 1/4%, Due July 1, 1995 . . . . . . . - 12,500 8 5/8%, Due March 1, 1999 . . . . . . . - 20,000 7 3/4%, Due June 1, 1998 . . . . . . . - 18,000 7 5/8%, Due May 1, 1997. . . . . . . . - 16,000 7 3/4%, Due October 1, 1996 . . . . . . - 7,000 8 3/8%, Due May 1, 1996. . . . . . . . - 11,200 7 7/8%, Due December 1, 1995 . . . . . . - 10,800 9%, Due July 1, 1995. . . . . . . . . - 9,600 8 1/4%, Due November 1, 1994 . . . . . . - 6,000 7 3/4%, Due July 1, 1994 . . . . . . . - 6,000 Unamortized debt discount, less premium . . (9,252) (5,413) Convertible Subordinated Debentures 7 1/4%, Due December 15, 2015. . . . . . 250,000 250,000 Unamortized debt discount . . . . . . . (2,100) (2,231) 9.94% Unsecured loan due January 1, 1999. . . 20,000 20,000 __________ __________ Total . . . . . . . . . . . . . $1,158,648 $1,111,956 ========== ========== ______________________________________________________________________________
The estimated fair value of the Company's debentures, including current maturities, was $1,208,719,000 and $1,235,351,000 at December 31, 1992 and 1993. Fair value was estimated based on closing transactions and/or quotations for the Company's debentures as of those dates.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
There are no debentures maturing in the years 1994 and 1995. The aggregate principal amounts of the Company's debentures maturing in the years 1996 through 1998 are: $6,250,000; $106,250,000 and $156,250,000.
Discounts and premiums and the expenses incurred in connection with the issuance of debentures are being amortized on a basis which will equitably distribute the net amount to "Interest on long-term debt," over the life of each debenture issue.
The Company's 7 1/4% Convertible Subordinated Debentures, which mature on December 15, 2015, are convertible into shares of the Company's common stock at any time prior to maturity at an initial conversion price of $54 per share. Under additional terms of the issue, on December 15, 2000, the Company is obligated to purchase, at the option of the holder, any Debenture then outstanding for 100% of the principal amount plus accrued interest.
The 9.94% unsecured loan due January 1, 1999, is an obligation of Virginia Natural Gas. This $20,000,000 loan, which is to be repaid in five annual installments of $4,000,000 each, beginning January 1, 1995, has been guaranteed by the Company.
In March 1991, the Company entered into a credit agreement with a group of banks that provides for the borrowing of up to $300,000,000. The 1991 Credit Agreement initially was to expire on March 31, 1994; however, each year the term of the agreement has, with the approval of the banks, been extended for a period of one additional year. In February 1994, the term was extended to March 31, 1997. The loans under the 1991 Credit Agreement are in the form of revolving credits and may, at the option of the Company, be structured either as syndicated loans by a group of participating banks or money market loans by individual participating banks. The loans may be borrowed, paid or prepaid and reborrowed on a few days notice. Varying interest rate options are available for syndicated loans, while the interest rate on money market loans is determined from quotes rendered by the participating banks. A commitment fee of 1/8 of 1% per annum is charged under the 1991 Credit Agreement. No revolving credit loans were outstanding at December 31, 1992 or 1993.
14. SHORT-TERM BORROWINGS The weighted average interest rate on the Company's $455,000,000 of commercial paper notes outstanding at December 31, 1993, was 3.35%. Because of the short maturities of commercial paper notes, the carrying amount represents a reasonable estimate of fair value.
Commercial paper notes are supported by unused lines of credit totaling $475,000,000. These lines may be used if the sale of commercial paper is not feasible. Each of the lines bears a commitment fee, but such fees, in the aggregate, are not significant. In addition to these credit lines, the Company may utilize unused portions of its 1991 Credit Agreement to provide support for commercial paper notes.
There are no agreements or arrangements requiring compensating balances with respect to either lines of credit or outstanding bank loans. Under the Company's policy, bank deposits are maintained for normal operating purposes.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. ENVIRONMENTAL MATTERS The Company and its subsidiaries are subject to various federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations govern both current and future operations and potentially extend to plant sites formerly owned or operated by the Company and its subsidiaries, or their predecessors.
As part of their normal business operations, the subsidiaries periodically monitor their properties and facilities and resolve potential environmental matters so as to remain in compliance with the various environmental laws and regulations. The Company also conducts general environmental surveys on a continuing basis at its operating facilities to assure compliance with these laws and regulations. In this regard, voluntary surveys at subsidiary meter sites were conducted to determine the extent of any possible soil contamination due to mercury spillage. These studies, which are continuing, are not in response to any governmental or regulatory directive, order or settlement agreement and have not disclosed any mercury contamination for which the remediation costs would be considered material to Consolidated's financial position, results of operations or cash flows. On August 16, 1990, CNG Transmission entered into a Consent Order and Agreement with the Commonwealth of Pennsylvania Department of Environmental Resources (DER) in which CNG Transmission has agreed with the DER's determination of certain violations of the Pennsylvania Solid Waste Management Act, the Pennsylvania Clean Streams Law and the rules and regulations promulgated thereunder. It is unknown at this time whether civil penalties will be assessed. Pursuant to the Order and Agreement, CNG Transmission is performing certain sampling, testing and analysis, and conducting a program of remediation at some of its Pennsylvania facilities. Total remediation costs in connection with the Order and Agreement are not expected to be material with respect to Consolidated's financial position, results of operations or cash flows. Based on current knowledge, the Company has recognized a gross estimated liability amounting to $19,661,000 at December 31, 1993, for future costs expected to be incurred to remediate or mitigate hazardous substances at mercury sites and at facilities covered by the Order and Agreement. The estimate for this liability was based on current environmental laws and regulations and existing technology.
Inasmuch as certain environmental-related expenditures are expected to be recoverable in future regulatory proceedings, a regulatory asset amounting to $11,378,000 at December 31, 1993, is included in the Consolidated Balance Sheet under the caption "Deferred charges and other noncurrent assets." Also, uncontested claims amounting to $3,566,000 at December 31, 1993, were recognized for environmental-related costs probable of recovery through joint- interest operating agreements.
The total amounts included in operating expenses for remediation and other environmental-related costs were $3,205,000, $7,646,000, and $9,049,000, respectively, for the years ended December 31, 1991 through 1993. The components of such costs are as follows: ______________________________________________________________________________ Years Ended December 31, 1993 1992 1991 ______________________________________________________________________________ (In Thousands) Recurring costs for ongoing operations $3,381 $4,032 $1,601 Mandated remediation and other compliance costs . . . . . . . 3,963 2,816 1,493 Voluntary remediation costs . . . . 1,185 703 4 Other . . . . . . . . . . . 520 95 107 ______ ______ ______ Total. . . . . . . . . . . $9,049 $7,646 $3,205 ====== ====== ====== ______________________________________________________________________________
The Company's environmental-related capital expenditures for monitoring or complying with laws and regulations for 1991 through 1993 were not material.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company has determined that it is associated with 16 former manufactured gas plant sites, five of which are currently owned by the Company. Studies conducted by other utilities at their former manufactured gas plants have indicated that their sites contain coal tar and other potentially harmful materials. None of the 16 former sites with which the Company is associated is under investigation by any state or federal environmental agency, and no investigation or action is currently anticipated. At this time it is not known if, or to what degree, these sites may contain environmental contamination. Therefore, the Company is not able to estimate the cost, if any, that may be required for the possible remediation of these sites.
The exact nature of environmental issues that the Company may encounter in the future cannot be predicted. Additional environmental liabilities may result in the future as more stringent environmental laws and regulations are implemented and as the Company obtains more specific information about its existing sites and production facilities. At present, no estimate of any such additional liability, or range of liability amounts, can be made.
16. COMMITMENTS AND CONTINGENCIES Lease arrangements of the subsidiaries are principally for office space, business machines and transportation equipment. None of these arrangements, individually or in the aggregate, are material capital leases. Rental expense incurred in the years 1991 through 1993 was not material, and future rental payments required under leases in effect at December 31, 1993, are not material.
CNG Transmission and certain of the Company's distribution subsidiaries are subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments of 1990 (1990 amendments) which added significantly to the existing requirements established by the Federal Clean Air Act. These subsidiaries operate compressor stations that are covered by the new nitrogen oxide emission standard established as a result of the 1990 amendments. The Company will have until May 31, 1995, to comply with the emission standard. The Company expects that compliance will require significant capital expenditures to modify the compressor engines along the Company's pipeline system. However, the actual cost of compliance will be dependent upon the requirements imposed by the environmental agencies of the states in which the compressor stations are located. Based on the Company's preliminary estimates and analyses, approximately $46 million of capital expenditures may be required. Actual capital expenditures required to comply with the 1990 amendments are expected to be recoverable through future regulatory proceedings. Reference is made to Note 15 for additional information on environmental matters.
It is estimated that Consolidated's 1994 capital budget will amount to $439,600,000, and that approximately $153,000,000 of that amount will be directed to gas and oil producing activities. In connection with the capital budget, the subsidiaries have entered into certain contractual commitments.
The subsidiaries have claims and suits pending against them, but, in the opinion of management and counsel, the ultimate liability will not have a material effect on Consolidated's financial position, results of operations or cash flows.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. SUPPLEMENTARY FINANCIAL INFORMATION -- UNAUDITED (A) GAS AND OIL PRODUCING ACTIVITIES (EXCLUDING COST-OF-SERVICE RATE- REGULATED ACTIVITIES) This information has been prepared in accordance with Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities," and related SEC pronouncements. Statement No. 69 is a comprehensive, standard set of required disclosures about the gas and oil producing activities of publicly traded companies. The following disclosures exclude the gas and oil producing activities subject to cost-of-service rate regulation. Certain disclosures about these gas and oil activities, which are exempt from the accounting methods prescribed by the SEC, are included under "Cost-of-Service Properties" in this Note (A).
CAPITALIZED COSTS The aggregate amounts of costs capitalized by subsidiaries for their gas and oil producing activities, and related aggregate amounts of accumulated depreciation and amortization, follow: _______________________________________________________________________________ December 31, 1993 1992 _______________________________________________________________________________ (In Thousands) Capitalized costs of Proved properties. . . . . . . . . $2,685,856 $2,673,042 Unproved properties . . . . . . . . 232,312 194,189 __________ __________ Total . . . . . . . . . . . . $2,918,168 $2,867,231 ========== ==========
Accumulated depreciation of Proved properties. . . . . . . . . $1,723,113 $1,609,850 Unproved properties . . . . . . . . 78,352 68,444 __________ __________ Total . . . . . . . . . . . . $1,801,465 $1,678,294 ========== ========== _______________________________________________________________________________
TOTAL COSTS INCURRED The following costs were incurred by subsidiaries in their gas and oil producing activities during the years 1991 through 1993: _______________________________________________________________________________ Years Ended December 31, 1993 1992 1991 _______________________________________________________________________________ (In Thousands) Property acquisition costs Proved properties. . . . . . . . . $ 132 $ 7,926 $ - Unproved properties . . . . . . . . 18,224 14,378 20,879 ________ ________ ________ Subtotal . . . . . . . . . . . 18,356 22,304 20,879 Exploration costs . . . . . . . . . 47,934 30,860 30,420 Development costs . . . . . . . . . 40,516 42,059 63,413 ________ ________ ________ Total . . . . . . . . . . . . $106,806 $ 95,223 $114,712 ======== ======== ======== _______________________________________________________________________________
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
RESULTS OF OPERATIONS The elements of the "results of operations for gas and oil producing activities" that follow are as required and defined by the FASB. Consolidated cautions that these standardized disclosures do not represent the results of operations based on its historical financial statements. In addition to requiring different determinations of revenues and costs, the disclosures exclude the impact of interest expense and corporate overheads.
______________________________________________________________________________ Years Ended December 31, 1993 1992 1991 ______________________________________________________________________________ (In Thousands) Revenues (net of royalties) from: Sales to unaffiliated companies . . . $204,614 $155,481 $187,662 Transfers to other operations. . . . 88,241 135,280 110,351 ________ ________ ________ Total . . . . . . . . . . . 292,855 290,761 298,013 ________ ________ ________ Less: Production (lifting) costs . . . 49,177 55,281 58,253 Depreciation and amortization . . 173,171 176,463 183,027 Income tax expense. . . . . . 18,400 13,509 20,144 ________ ________ ________ Results of operations . . . . . . . $ 52,107 $ 45,508 $ 36,589 ======== ======== ======== ______________________________________________________________________________
COMPANY-OWNED RESERVES (NON-COST-OF-SERVICE RESERVES) Estimated net quantities of proved gas and oil (including condensate) reserves in the United States and Canada at December 31, 1991 through 1993, and changes in the reserves during those years, are shown in the two schedules which follow: ______________________________________________________________________________ Years Ended December 31, 1993 1992 1991 ______________________________________________________________________________ (In Bcf) PROVED DEVELOPED AND UNDEVELOPED RESERVES* - GAS At January 1 . . . . . . . . . . . 918 918 1,017 Changes in reserves Revisions of previous estimates . . . . 46 (23) (17) Purchases of gas in place . . . . . . - 19 - Extensions, discoveries and other additions 55 141 79 Production . . . . . . . . . . . (124) (121) (126) Sales of gas in place. . . . . . . . (10) (16) (35) _____ _____ _____ At December 31. . . . . . . . . . . 885 918 918 ===== ===== =====
PROVED DEVELOPED RESERVES* - GAS At January 1 . . . . . . . . . . . 794 855 920 At December 31. . . . . . . . . . . 761 794 855
* Net before royalty. ______________________________________________________________________________
Included in the caption "Extensions, discoveries and other additions" for 1992 are 79 Bcf of proved undeveloped reserves for which development costs will be incurred in future years. The preceding proved developed and undeveloped gas reserves at December 31, 1991 through 1993, include United States reserves of 917, 917 and 884 Bcf which, together with the Canadian reserves and the gas reserves reported under "Cost-of-Service Properties," are as contained in reports of Ralph E. Davis Associates, Inc., independent geologists.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) ______________________________________________________________________________ Years Ended December 31, 1993 1992 1991 ______________________________________________________________________________ (In Thousand Bbls) Proved developed and undeveloped reserves* - Oil At January 1 . . . . . . . . . . . 29,238 31,014 37,881 Changes in reserves Revisions of previous estimates . . . . 290 390 (3,300) Purchases of oil in place . . . . . . - 245 - Extensions, discoveries and other additions 1,978 2,104 3,410 Production . . . . . . . . . . . (3,907) (4,508) (5,246) Sales of oil in place. . . . . . . . (3) (7) (1,731) ______ ______ ______ At December 31. . . . . . . . . . . 27,596 29,238 31,014 ====== ====== ======
Proved developed reserves* - Oil At January 1 . . . . . . . . . . . 27,449 30,070 36,541 At December 31. . . . . . . . . . . 21,936 27,449 30,070
* Net before royalty. ______________________________________________________________________________
The foregoing proved developed and undeveloped oil reserves at December 31, 1991 through 1993, include United States reserves of 25,623, 23,493 and 21,917 thousand barrels, respectively. These, together with the Canadian reserves and the oil reserves reported under "Cost-of-Service Properties," are as contained in reports of Ralph E. Davis Associates, Inc.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN The following tabulation has been prepared in accordance with the FASB's rules for disclosure of a standardized measure of discounted future net cash flows relating to Company-owned proved gas and oil reserve quantities. ______________________________________________________________________________ December 31, 1993 1992 1991 ______________________________________________________________________________ (In Thousands) Future cash inflows . . . . . . . . $2,336,553 $2,421,422 $2,570,408 Less: Future development and production costs . . . . . 529,592 572,576 496,389 Future income tax expense. . . . 537,966 473,475 608,264 __________ __________ __________ Future net cash flows . . . . . . . 1,268,995 1,375,371 1,465,755 Less annual discount (10% a year) . . . 500,732 557,019 584,624 __________ __________ __________ Standardized measure of discounted future net cash flows . . . . . . . . . $ 768,263 $ 818,352 $ 881,131 ========== ========== ========== ______________________________________________________________________________
In the foregoing determination of future cash inflows, sales prices for gas were based on contractual arrangements or market prices at each year end. Prices for oil were based on average prices received from sales in the month of December each year. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year end, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the appropriate year-end or future statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, or permanent differences and tax credits.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of Consolidated's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, present costs and prices are used in the determinations and no value may be assigned to probable or possible reserves.
The following tabulation is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of each year.
COST-OF-SERVICE PROPERTIES As previously stated, activities subject to cost-of-service rate regulation are excluded from the foregoing information. At December 31, 1992 and 1993, net capitalized costs of cost-of-service properties amounted to $30,645,000 and $27,320,000, respectively. Related proved reserves of gas and oil are located in the United States, and at December 31, 1991 through 1993, amounted to 87, 80 and 75 Bcf of gas and 313, 283 and 287 thousand barrels of oil, respectively. Production for the years 1991 through 1993 amounted to 7, 7 and 6 Bcf of gas and 33, 31 and 29 thousand barrels of oil, respectively.
Future revenues associated with production of the foregoing gas and oil reserves would be based upon cost-of-service ratemaking and historical asset costs, with rate of return levels determined by various state regulatory commissions.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(B) QUARTERLY FINANCIAL DATA A summary of the quarterly results of operations for the years 1992 and 1993 follows. Because a major portion of the gas sold or transported by the Company's distribution and transmission operations is ultimately used for space heating, both revenues and earnings are subject to seasonal fluctuations, and third quarter results are usually the least significant of the year for Consolidated. Seasonal fluctuations are further influenced by the timing of price relief granted under regulation to compensate for certain past cost increases.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
(C) COMMON STOCK MARKET PRICES AND RELATED MATTERS At December 31, 1993, there were 41,648 holders of the Company's common stock. The principal market for the stock is the New York Stock Exchange. Quarterly price ranges and dividends declared on the common stock for the years 1992 and 1993 follow. Restrictions on the payment of dividends are discussed in Note 12. ______________________________________________________________________________ Quarter First Second Third Fourth ______________________________________________________________________________ Market Price Range 1993 - High . . . . . . . $49 7/8 $53 5/8 $55 3/8 $53 1/4 - Low. . . . . . . . $43 1/2 $48 5/8 $48 3/8 $42 5/8
1992 - High . . . . . . . $43 1/2 $43 7/8 $48 5/8 $48 3/8 - Low. . . . . . . . $33 5/8 $35 $42 3/8 $44 3/8
Dividends Declared per Share 1993. . . . . . . . . . $.48 $.48 $.48 $.485 1992. . . . . . . . . . $.475 $.475 $.475 $.48 ______________________________________________________________________________
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (Note 1)
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (Note 1) (Continued)
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (Note 1) (Continued)
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT (Note 1) (Concluded) Notes:
(1) In view of the variety of properties and the large number of depreciation rates applied by subsidiary companies, it is considered impractical to set forth the rates used in computing provisions. However, the total provisions for depreciation of property, plant and equipment for the years ended December 31, 1991 through 1993, including amounts charged to accounts other than depreciation and amortization expense, were equivalent to approximately 4.8%, 4.3% and 4.2%, respectively, of the average capitalized investment subject to depreciation and amortization in those periods.
(2) Includes transfers between utility and exploration and production operations and: 1993 1992 1991 (a) The change in the quantity of gas stored underground classified as gas plant in accordance with provisions of the systems of accounts prescribed by regulatory authorities . . . . . $3,294 $(35) $ -
(b) Subsequent adjustments to a gas plant acquisition adjustment arising from Consolidated's purchase of Virginia Natural Gas, Inc. in 1990 . - - 893 ______ ____ ______
Total utility and exploration and production operations . . . . $3,294 $(35) $ 893 ====== ==== ======
(3) Plant in service for the utility operations includes gas stored underground in the amounts of $108,180,000, $120,270,000 and $123,564,000 at December 31, 1991 through 1993, respectively, of which $10,355,000 at the end of 1991 and $10,342,000 at the end of 1992 and 1993 represents base gas required under joint operating agreements.
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT (Continued)
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT (Continued)
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT (Concluded) Notes:
(1) Includes depreciation and amortization charged to other income and expense accounts for the years 1991 through 1993 amounting to $107,000, $135,000 and $365,000, respectively.
(2) Includes transfers between utility and exploration and production operations. Also includes charges to miscellaneous clearing and appointment accounts: 1993 1992 1991 Utility operations . . . . . . . . $4,970 $5,666 $6,329 Exploration and production operations. . 187 212 162 ______ ______ ______
Total utility and exploration and production operations . . . . . . $5,157 $5,878 $6,491 ====== ====== ======
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Cont.) SCHEDULE IX - SHORT-TERM BORROWINGS
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES (Concl.) SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
_______________________________________________________________________________ Charged to Costs and Expenses _______________________________________________________________________________ Year Year Year Item 1993 1992 1991 _______________________________________________________________________________ (Thousands of Dollars) Maintenance and repairs: Charged to income account as maintenance $ 87,207 $ 79,128 $ 72,865 Charged to operation expense . . . . 656 826 962 ________ ________ ________ $ 87,863 $ 79,954 $ 73,827 ======== ======== ========
Depreciation and amortization of intangible assets, preoperating costs and similar deferrals . . . . . . (Note) (Note) (Note)
Taxes, other than payroll and income taxes, charged to income account as other taxes: Real and personal property taxes . . $ 55,933 $ 52,563 $ 48,066 Excise taxes on gross receipts. . . 75,803 70,743 69,459 Other . . . . . . . . . . . 26,795 24,191 21,691 ________ ________ ________ $158,531 $147,497 $139,216 ======== ======== ========
Royalties . . . . . . . . . . . $ 55,523 $ 54,400 $ 55,617 Advertising costs . . . . . . . . (Note) (Note) (Note) _______________________________________________________________________________ Note: Omitted inasmuch as amount is not in excess of one percent of total sales and revenues as reported in the Consolidated Statement of Income.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable
PART III
ITEM 10.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
Information concerning the directors of the Company is hereby incorporated by reference to the Company's definitive proxy statement filed with the Commission pursuant to Regulation 14A within 120 days after the close of the Company's fiscal year. Information concerning the executive officers of the Company is on page 18 of this Report.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
This information is hereby incorporated by reference to the Company's definitive proxy statement filed with the Commission pursuant to Regulation 14A within 120 days after the close of the Company's fiscal year.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
This information is hereby incorporated by reference to the Company's definitive proxy statement filed with the Commission pursuant to Regulation 14A within 120 days after the close of the Company's fiscal year.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
This information is hereby incorporated by reference to the Company's definitive proxy statement filed with the Commission pursuant to Regulation 14A within 120 days after the close of the Company's fiscal year.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the last quarter of the calendar year 1993, the year for which this Form 10-K is being filed.
DOCUMENTS FILED AS A PART OF THIS REPORT
Financial Statements Financial Statement Schedules
All of the financial statements and financial statement schedules filed as a part of this Report are included in ITEM 8 and reference is made to the index on page 47.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
Consent of Independent Accountants
We hereby consent to the incorporation by reference in the Prospectuses con- stituting part of the Registration Statements on Form S-3 (Nos. 33-1040, 33- 49469 and 33-52585) and Form S-8 (Nos. 2-77204, 2-97948, 33-40478 and 33-44892) of Consolidated Natural Gas Company of our report dated February 16, 1994, appearing on page 48 of this Form 10-K. We also consent to the references to us under the heading "Experts" in such Prospectuses.
PRICE WATERHOUSE
Price Waterhouse
600 Grant Street Pittsburgh, Pennsylvania 15219-9954 March 28, 1994
EXHIBITS _______________________________________________________________________________ SEC Exhibit Number Description of Exhibit _______________________________________________________________________________
(3) Articles of Incorporation and By-Laws: (3A) Certificate of Incorporation of Consolidated Natural Gas Company, restated October 4, 1990 (incorporated by reference to Exhibit A-1 to the Application-Declaration of Consolidated Natural Gas Company on Form U-1, File No. 70-7811)
(3B) By-Laws of Consolidated Natural Gas Company, last amended March 1, 1993 (incorporated by reference to Exhibit (3B) filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1992, File No. 1-3196)
(4) Instruments Defining the Rights of Security Holders, Including Indentures: (4A) (1) Indentures of Consolidated Natural Gas Company: Indentures of Consolidated Natural Gas Company are incorporated by reference to previously filed material as indicated on the list filed herewith
(2) Note Purchase Agreement of Virginia Natural Gas: Note Purchase Agreement dated as of January 1, 1989, between Virginia Natural Gas, Inc. and the Aid Association for Lutherans relating to $20,000,000 principal amount of 9.94% Senior Notes, Series A, due January 1, 1999 (incorporated by reference to Exhibit B-1 to the Application-Declaration of Consolidated Natural Gas Company on Form U-1, File No. 70-7667)
(4B) Section 203 of the Delaware General Corporation Law, "Business Combinations With Interested Stockholders," effective February 2, 1988 (incorporated by reference to Exhibit (4B) filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1987, File No. 1-3196)
Other portions of the Delaware General Corporation Law affecting security holder rights are considered routine and are not filed hereunder
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Continued)
EXHIBITS (Continued) _______________________________________________________________________________ SEC Exhibit Number Description of Exhibit _______________________________________________________________________________
(10) Material Contracts: (Exhibits (10A) through (10G) listed below are incorporated by reference to the Exhibit with the same designation filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1987, File No. 1-3196; Exhibits (10H) and (10I) listed below are incorporated by reference to the Exhibit with the same designation filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1989, File No. 1-3196; Exhibit (10J) listed below is incorporated by reference to the Exhibit with the same designation filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1991, File No. 1-3196; Exhibit (10K) listed below is incorporated by reference to the Exhibit with the same designation filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1992, File No. 1-3196)
(10A) Form of Split Dollar Insurance Agreement between Consolidated Natural Gas Company and certain employees and Directors
(10B) Form of Supplemental Death Benefit Payment Agreement between Consolidated Natural Gas Company and certain employees and Directors
(10C) Consolidated Natural Gas Company Supplemental Retirement Benefit Plan
(10D) System Supplemental Retirement Plan for Certain Management Employees of Consolidated Natural Gas Company and Its Participating Subsidiaries
(10E) Form of agreement between Consolidated Natural Gas Company and nonemployee Directors for deferral of payment of retainer and attendance fees, effective before 1987
(10F) Deferred Compensation Plan for Directors of Consolidated Natural Gas Company, effective for years beginning with 1987
(10G) Consolidated Natural Gas Company Cash Incentive Bonus Deferral Plan
(10H) Form of Change of Control Employment Agreement between Consolidated Natural Gas Company and certain employees
(10I) Form of Change of Control Salary Continuation Agreement between Consolidated Natural Gas Company and certain employees
(10J) Description of Consolidated Natural Gas Company Annual Executive Incentive Program
(10K) Unfunded Supplemental Benefit Plan for Employees of Consolidated Natural Gas Company and Its Participating Subsidiaries Who Are Not Represented by a Recognized Union
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (Concluded)
EXHIBITS (Concluded) _______________________________________________________________________________ SEC Exhibit Number Description of Exhibit _______________________________________________________________________________
(11) Statement re Computation of Per Share Earnings: Computations of Earnings Per Share of Common Stock, Primary Earnings Per Share, and Fully Diluted Earnings Per Share of Consolidated Natural Gas Company and Subsidiaries for the years ended December 31, 1991 through 1993, are filed herewith
(12) Statement re Computation of Ratios: Ratio of Earnings to Fixed Charges of Consolidated Natural Gas Company and Subsidiaries for the calendar years 1989-1993, inclusive, are filed herewith
(21) Subsidiaries of the Registrant: Subsidiaries of Consolidated Natural Gas Company, is filed herewith
(23) Consents of Experts and Counsel: (23A) Report of Ralph E. Davis Associates, Inc., independent geologists, dated February 15, 1994, and consent letter authorizing the filing of such report as an exhibit to Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1993, are filed herewith
(23B) Consent letter of John T. Boyd Company, Mining and Geological Engineers, authorizing the use of coal reserve estimates in Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1993, is filed herewith
(23C) Consent of Price Waterhouse - included as part of this ITEM 14 _______________________________________________________________________________
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
CONSOLIDATED NATURAL GAS COMPANY ________________________________ (Registrant)
GEORGE A. DAVIDSON, JR. By___________________________
(George A. Davidson, Jr.) Chairman of the Board March 28, 1994 and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 28, 1994.
GEORGE A. DAVIDSON, JR. THEODORE LEVITT ________________________________ ________________________________ (George A. Davidson, Jr.) (Theodore Levitt) Chairman of the Board Director and Chief Executive Officer, and Director STEVEN A. MINTER ________________________________ L. D. JOHNSON (Steven A. Minter) ________________________________ Director (L. D. Johnson) Executive Vice President and Chief Financial Officer, WALTER R. PEIRSON and Director ________________________________ (Walter R. Peirson) Director S. R. MCGREEVY ________________________________ (S. R. McGreevy) RICHARD P. SIMMONS Vice President, Accounting ________________________________ and Financial Control (Richard P. Simmons) Director
J. W. CONNOLLY ________________________________ A. A. SOMMER, JR. (J. W. Connolly) ________________________________ Director (A. A. Sommer, Jr.) Director
PAUL E. LEGO ________________________________ LOIS WYSE (Paul E. Lego) ________________________________ Director (Lois Wyse) Director
APPENDIX TO FORM 10-K
The following graphic material which appeared in the paper format version of the document is omitted from this electronic format document:
Map of Principal Facilities at December 31, 1993 (Page 20)
This map shows the primary operating areas of Consolidated Natural Gas Company in Ohio, Pennsylvania, Virginia and West Virginia. The map shows the principal cities served at retail including Cleveland, Akron, Youngstown, Canton, Warren, Lima, Ashtabula and Marietta in Ohio; Pittsburgh (a portion), Altoona and Johnstown in Pennsylvania; Norfolk, Newport News and Williamsburg in Virginia; and Clarksburg and Parkersburg in West Virginia. The map also shows the general location of Consolidated's pipelines and joint venture pipelines, including gas sale or transport connections with wholesale customers and gas purchase or transport connections with other pipelines. Also shown on the map are the general location of certain compressor facilities and the general location of underground storage fields.
Map of Exploration and Production Areas at December 31, 1993 (Page 21)
This United States map shows the general areas in which Consolidated conducts its exploration and production activities. These areas include: the Gulf of Mexico, offshore Louisiana and Texas; the Gulf Coast Basin; Permian Basin; Anadarko Basin; Arkoma Basin; Black Warrior Basin; San Juan Basin; Williston Basin; Michigan Basin; Rocky Mountain Basins and the Appalachian Region. Also shown is the general location of Consolidated's Canadian exploration and production properties in Alberta, Canada.
EXHIBIT INDEX
_______________________________________________________________________________ SEC Exhibit Number Description of Exhibit _______________________________________________________________________________
(3) Articles of Incorporation and By-Laws: (3A) Certificate of Incorporation of Consolidated Natural Gas Company, restated October 4, 1990 (incorporated by reference to Exhibit A-1 to the Application-Declaration of Consolidated Natural Gas Company on Form U-1, File No. 70-7811)
(3B) By-Laws of Consolidated Natural Gas Company, last amended March 1, 1993 (incorporated by reference to Exhibit (3B) filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1992, File No. 1-3196)
(4) Instruments Defining the Rights of Security Holders, Including Indentures: (4A) (1) Indentures of Consolidated Natural Gas Company: Indentures of Consolidated Natural Gas Company are incorporated by reference to previously filed material as indicated on the list filed herewith
(2) Note Purchase Agreement of Virginia Natural Gas: Note Purchase Agreement dated as of January 1, 1989, between Virginia Natural Gas, Inc. and the Aid Association for Lutherans relating to $20,000,000 principal amount of 9.94% Senior Notes, Series A, due January 1, 1999 (incorporated by reference to Exhibit B-1 to the Application-Declaration of Consolidated Natural Gas Company on Form U-1, File No. 70-7667)
(4B) Section 203 of the Delaware General Corporation Law, "Business Combinations With Interested Stockholders," effective February 2, 1988 (incorporated by reference to Exhibit (4B) filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1987, File No. 1-3196)
Other portions of the Delaware General Corporation Law affecting security holder rights are considered routine and are not filed hereunder
(10) Material Contracts: (Exhibits (10A) through (10G) listed below are incorporated by reference to the Exhibit with the same designation filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1987, File No. 1-3196; Exhibits (10H) and (10I) listed below are incorporated by reference to the Exhibit with the same designation filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1989, File No. 1-3196; Exhibit (10J) listed below is incorporated by reference to the Exhibit with the same designation filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1991, File No. 1-3196; Exhibit (10K) listed below is incorporated by reference to the Exhibit with the same designation filed with Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1992, File No. 1-3196)
(10A) Form of Split Dollar Insurance Agreement between Consolidated Natural Gas Company and certain employees and Directors
(10B) Form of Supplemental Death Benefit Payment Agreement between Consolidated Natural Gas Company and certain employees and Directors
(10C) Consolidated Natural Gas Company Supplemental Retirement Benefit Plan
_______________________________________________________________________________ SEC Exhibit Number Description of Exhibit _______________________________________________________________________________
(10) Material Contracts (Continued): (10D) System Supplemental Retirement Plan for Certain Management Employees of Consolidated Natural Gas Company and Its Participating Subsidiaries
(10E) Form of agreement between Consolidated Natural Gas Company and nonemployee Directors for deferral of payment of retainer and attendance fees, effective before 1987
(10F) Deferred Compensation Plan for Directors of Consolidated Natural Gas Company, effective for years beginning with 1987
(10G) Consolidated Natural Gas Company Cash Incentive Bonus Deferral Plan
(10H) Form of Change of Control Employment Agreement between Consolidated Natural Gas Company and certain employees
(10I) Form of Change of Control Salary Continuation Agreement between Consolidated Natural Gas Company and certain employees
(10J) Description of Consolidated Natural Gas Company Annual Executive Incentive Program
(10K) Unfunded Supplemental Benefit Plan for Employees of Consolidated Natural Gas Company and Its Participating Subsidiaries Who Are Not Represented by a Recognized Union
(11) Statement re Computation of Per Share Earnings: Computations of Earnings Per Share of Common Stock, Primary Earnings Per Share, and Fully Diluted Earnings Per Share of Consolidated Natural Gas Company and Subsidiaries for the years ended December 31, 1991 through 1993, are filed herewith
(12) Statement re Computation of Ratios: Ratio of Earnings to Fixed Charges of Consolidated Natural Gas Company and Subsidiaries for the calendar years 1989-1993, inclusive, are filed herewith
(21) Subsidiaries of the Registrant: Subsidiaries of Consolidated Natural Gas Company, is filed herewith
(23) Consents of Experts and Counsel: (23A) Report of Ralph E. Davis Associates, Inc., independent geologists, dated February 15, 1994, and consent letter authorizing the filing of such report as an exhibit to Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1993, are filed herewith
(23B) Consent letter of John T. Boyd Company, Mining and Geological Engineers, authorizing the use of coal reserve estimates in Consolidated Natural Gas Company's Form 10-K for the year ended December 31, 1993, is filed herewith
(23C) Consent of Price Waterhouse - included as part of ITEM 14 _______________________________________________________________________________