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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF
1934
FOR THE YEAR ENDED DECEMBER 31, 1995
COMMISSION FILE NUMBER 1-3196
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CONSOLIDATED NATURAL GAS COMPANY
A DELAWARE CORPORATION
CNG TOWER, 625 LIBERTY AVENUE, PITTSBURGH, PA 15222-3199
TELEPHONE (412) 227-1000
IRS EMPLOYER IDENTIFICATION NUMBER 13-0596475
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SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
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Common Stock: Registered:
$2.75 Par Value New York Stock Exchange
Common Stock Purchase Rights New York Stock Exchange
Debentures:
7 3/8 % Debentures Due April 1, 2005 New York Stock Exchange
6 5/8 % Debentures Due December 1, 2013 New York Stock Exchange
5 3/4 % Debentures Due August 1, 2003 New York Stock Exchange
5 7/8 % Debentures Due October 1, 1998 New York Stock Exchange
8 3/4 % Debentures Due October 1, 2019 New York Stock Exchange
8 3/4 % Debentures Due June 1, 1999 New York Stock Exchange
9 3/8 % Debentures Due February 1, 1997 New York Stock Exchange
8 5/8 % Debentures Due December 1, 2011 New York Stock Exchange
Convertible Subordinated Debentures:
7 1/4 % Convertible Subordinated Debentures
Due December 15, 2015 New York Stock Exchange
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SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. /X/
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
The aggregate market value of the voting stock held by non-affiliates of
the registrant amounted to $4,217,017,725 as of January 31, 1996. It was assumed
in this calculation that the registrant's affiliates are all of its directors
and/or officers, and they beneficially owned 298,744 shares of voting stock at
that date.
Number of shares of Common Stock, $2.75 Par Value, outstanding at January
31, 1996: 94,010,249.
The registrant's "Notice of Annual Meeting and Proxy Statement, 1996" is
hereby incorporated by reference into Part III of this Form 10-K.
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CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1995
TABLE OF CONTENTS
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Page
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PART I
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ITEM 1. BUSINESS
The Company........................................................ 1
Governmental Regulation............................................ 3
Capital Expenditures............................................... 3
Competitive Conditions............................................. 4
Gas Supply......................................................... 7
Gas Sales and Transportation....................................... 10
Gas Sales, Supply and Transportation Statistics.................... 12
Market Expansion................................................... 13
Rate Matters....................................................... 14
Executive Officers of the Company.................................. 16
ITEM 2. PROPERTIES
General Information on Facilities.................................. 17
Map - Principal Facilities......................................... 18
Map - Exploration and Production Areas............................. 19
Gas and Oil Producing Activities................................... 20
ITEM 3. LEGAL PROCEEDINGS.................................................... 22
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.................. 22
PART II
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ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS................................................ 22
ITEM 6. SELECTED FINANCIAL DATA.............................................. 23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS................................ 24
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................... 39
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE................................ 74
PART III
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ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY...................... 74
ITEM 11. EXECUTIVE COMPENSATION............................................... 74
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT......................................................... 74
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS....................... 74
PART IV
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ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K........................................................ 74
SIGNATURES ..................................................................... 78
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CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1995
PART I
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ITEM 1. BUSINESS
THE COMPANY
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 (PUHCA). 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 (the Company) at December
31, 1995, are listed below. In addition to operating in all phases of the
natural gas business, the Company explores for and produces oil and provides a
variety of energy marketing services (see Note 18 to the consolidated financial
statements, page 65). At December 31, 1995, the Company had 6,600 regular
employees.
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State of
Name of Company Incorporation
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CONSOLIDATED NATURAL GAS COMPANY (Parent Company)........................... Delaware
All wholly owned subsidiaries of the Parent Company:
Consolidated Natural Gas Service Company, Inc. (Service Company).......... Delaware
CNG Transmission Corporation (CNG Transmission)........................... Delaware
The East Ohio Gas Company (East Ohio Gas)................................. Ohio
The Peoples Natural Gas Company (Peoples Natural Gas)..................... Pennsylvania
Virginia Natural Gas, Inc. (Virginia Natural Gas)......................... Virginia
Hope Gas, Inc. (Hope Gas)................................................. West Virginia
West Ohio Gas Company (West Ohio Gas)..................................... Ohio
CNG Producing Company (CNG Producing)..................................... Delaware
CNG Energy Services Corporation (CNG Energy Services)..................... Delaware
CNG Power Company (CNG Power)*............................................ Delaware
CNG Power Services Corporation (CNG Power Services)....................... Delaware
CNG Storage Service Company (CNG Storage)................................. Delaware
Consolidated System LNG Company (Consolidated LNG)........................ Delaware
CNG Research Company (CNG Research)....................................... Delaware
CNG Coal Company (CNG Coal)............................................... Delaware
CNG Financial Services, Inc. (CNG Financial).............................. Delaware
<FN>
*Formerly CNG Energy Company.
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The principal cities served at retail by the gas distribution subsidiaries (East
Ohio 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, 1995, the
Company served at retail approximately 1,824,000 residential, commercial and
industrial gas sales customers in Ohio, Pennsylvania, Virginia and West
Virginia. Variations in weather conditions can materially affect the volume of
gas delivered by the distribution subsidiaries, as 98 percent of their
residential and commercial customers use gas for space heating.
CNG Transmission is an interstate gas transmission subsidiary that operates a
regional interstate pipeline system serving each of the distribution
subsidiaries, and nonaffiliated utility and end-user customers in
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ITEM 1. BUSINESS (Continued)
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 decade.
Under 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. Having implemented Order 636 on October 1, 1993
(see "FERC Order 636," page 34), CNG Transmission has abandoned its traditional
"bundled" sales service and offers a number of gas transportation and storage
service options, along with related services, to a broad range of customers.
Variations in weather conditions can materially affect the volume of gas
transported and stored by CNG Transmission, since a substantial portion of its
gas deliveries is ultimately used by space-heating customers. However, under the
straight fixed variable rate design prescribed by Order 636, operating results
are less influenced by changes in throughput than in the past.
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 that owns and operates 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 a gas and oil exploration and production subsidiary whose
activities are conducted primarily in the Gulf of Mexico, the southern and
western United States, the Appalachian region, and in Canada. In addition, CNG
Producing participates in several coalbed methane projects.
CNG Energy Services is a nonregulated energy marketing subsidiary that 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. CNG Energy Services markets Company-owned gas production and also
offers the equivalent of the "bundled" services previously provided by CNG
Transmission prior to Order 636.
CNG Power develops new business opportunities in energy-related markets. It
invests in and develops independent power producer projects and conducts a gas
liquids business. CNG Power holds a 34% limited partnership interest in Lakewood
Cogeneration, L.P. (Lakewood Partnership), which operates a 237-megawatt
cogeneration facility in Lakewood, New Jersey.
CNG Power Services is a power marketing subsidiary with FERC approval to
purchase and resell electricity at market-based rates. CNG Lakewood, Inc., a
wholly owned subsidiary of CNG Power Services, owns a 1% general partnership
interest in the Lakewood Partnership.
CNG Storage is engaged 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 ended its
involvement in LNG operations in 1982 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 proprietary research activities. Amounts spent on
research activities in the calendar years 1993 through 1995 by all the
subsidiary companies were not material.
CNG Coal owns coal reserves and a related plant site. Most of these coal
reserves are located in Greene County, Pennsylvania, principally in the
Sewickley and Pittsburgh coal seams. In the second quarter of 1995, the Company
recognized a pretax charge of $31.3 million in connection with a write-down of
the value of these coal properties. In addition, the Company has entered into a
letter of intent for the
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ITEM 1. BUSINESS (Continued)
proposed sale of the properties to a third party (see Note 3 to the consolidated
financial statements, page 50).
Service Company is a subsidiary service company, authorized by the Securities
and Exchange Commission (SEC) under the 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 is subject to regulation by the SEC pursuant to the PUHCA. After an
in-depth study of the PUHCA in the context of fundamental changes in the energy
industry over the past decade, the SEC's Division of Investment Management
issued a report in June 1995 on the regulation of public utility holding
companies. This report contains recommendations for legislative action,
including repeal of the PUHCA with more oversight responsibility borne by the
FERC and state commissions. The report also proposes reform to remove a
substantial portion of the administrative burden inherent in the current PUHCA
regulatory policies and procedures. The SEC initiated action in 1995 to
implement such reform.
CNG Transmission and Consolidated LNG are "natural-gas companies" subject to the
Natural Gas Act of 1938, as amended. CNG Transmission's interstate
transportation and storage activities are regulated under such Act and are
conducted in accordance with tariffs and service agreements on file with the
FERC. The distribution subsidiaries are subject to regulation by the respective
utility commissions in the states within which they operate. CNG Power Services,
a public utility as defined by section 201 of the Federal Power Act, is subject
to FERC regulation.
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 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,
authorizes 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.
The Company is subject to the provisions of various federal laws dealing with
the protection of the environment. CNG Transmission and certain of the
distribution subsidiaries are subject to the Federal Clean Air Act and the
Federal Clean Air Act Amendments of 1990 which added significantly to the
existing requirements established by the Federal Clean Air Act. 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 Note 16 to the
consolidated financial statements, page 63, for additional information on
environmental-related matters.
CAPITAL EXPENDITURES
The Company's current capital budget for 1996 is estimated at $455.2 million, a
4 percent increase over the $439.4 million spent in 1995. The 1996 budget
reflects increased expenditures for the nonregulated and transmission operations
and a reduction in spending for the distribution operations.
Expenditures for the exploration and production operations are estimated to be
$180.6 million in 1996, up from $176.8 million in 1995. The higher amount in
1996 includes funds for development of Neptune at Viosca Knoll 826, the
Company's second deep-water project in the Gulf of Mexico. Transmission
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ITEM 1. BUSINESS (Continued)
expenditures in 1996 are budgeted at $89.3 million, up from $81.6 million spent
in 1995. Distribution operations spending in 1996 is expected to be $147.6
million, compared with $160.5 million in 1995. Transmission and distribution
operations expenditures will primarily be limited to spending for enhancements
and improvements in the pipeline system and related facilities. Planned
expenditures for the energy marketing services component in 1996 total $33.2
million and include funds for the development, through partnerships with other
energy companies, of offshore gas and oil gathering systems for two production
areas in the Gulf of Mexico. The 1996 capital budget also includes $4.5 million
allocated to "corporate and other," including expenditures to upgrade
information systems technology. The capital budget will be reviewed during the
year and is subject to revision. (See "Capital Spending," page 37.)
RESTRICTIONS UNDER CERTAIN DEBT AGREEMENTS
At December 31, 1995, the Company had senior debentures outstanding under a 1971
indenture between the Company and Chemical Bank, as trustee (the 1971
Indenture). The 1971 Indenture contains covenants which limit, among other
things, the incurrence of funded debt. As a result of charges in 1995 for
workforce reduction costs and write-downs of gas and oil producing properties
and coal properties, the Company's ability to issue funded debt is expected to
be restricted through May 1996. Reference is made to Note 13 to the consolidated
financial statements, page 61, for further details regarding this restriction.
COMPETITIVE CONDITIONS
Various regulatory and market trends have combined to increase competition for
the Company 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 at relatively low prices; competition from local producers and
other sellers and brokers of gas for the retail and wholesale markets; expansion
of competition among distribution companies for industrial and commercial
customers; 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
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 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.
CNG Transmission implemented Order 636 on October 1, 1993 (see "FERC Order 636,"
page 34) 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.
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. However, the distribution
subsidiaries have, for the most part, 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,
4
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ITEM 1. BUSINESS (Continued)
these companies now bear all the responsibilities and risks for arranging the
acquisition, delivery and storage of their own gas supplies. However, as a
result of previous FERC initiatives, the distribution subsidiaries have been
managing a part of their own gas supplies for a number of 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 distribution and transmission
operations as well as storage capacity acquired have become even more important
factors in gas supply management.
As a result of the restructuring under Order 636, gas producers throughout the
industry, including CNG Producing, are faced with 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. The
continued emergence of gas and energy marketing firms has added to the
competition for CNG Producing. As a result, effective January 1, 1995, CNG
Energy Services became the primary marketing agent for all of the Company's
nonregulated gas production (see "Energy Marketing Services," page 7).
DISTRIBUTION
The 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 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 the Company's transmission and storage facilities, and has
afforded additional opportunities for growth in both gas sales and
transportation, especially in the power generation markets.
The Federal Clean Air Act may also provide opportunities for increased
throughput in the Company's distribution markets. The Company is promoting the
use of natural gas as a means for industrial customers and electric generators
to reduce emissions. The Federal 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. The Company is participating in various programs to demonstrate
the advantages and environmental benefits of natural gas powered vehicles.
Competition in the markets served by the distribution subsidiaries continues to
increase. 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.
In addition, competition is increasing among local distribution companies to
provide gas sales and transportation services to commercial and residential
customers. 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 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. The Company has
responded to this competitive environment by offering an expanded range of
services to its customers. The distribution subsidiaries now routinely provide a
variety of firm and interruptible services,
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ITEM 1. BUSINESS (Continued)
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. As a result of deregulation, the role of the 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 Midwest 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, with particular emphasis
on Northeast and East Coast markets. CNG Transmission's large underground
storage capacity and the location of its gridlike 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.
With CNG Transmission's implementation of Order 636, 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 have offset the impact of CNG Transmission's abandonment of its
traditional sales service.
EXPLORATION AND PRODUCTION
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, the Company competes with a large
number of entities ranging in size from large international oil companies with
extensive financial resources to small, cash flow-driven independent producers.
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
highly competitive with price being the most significant factor. Effective
January 1, 1995, CNG Energy Services became the primary marketing agent for all
of the Company's nonregulated gas production. When the economics warrant, the
Company 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 deliverability of gas produced is also influenced by
competition for downstream pipeline transportation capacity. In response to the
unbundling of sales services previously offered by pipelines, CNG Producing and
CNG Energy Services have taken actions to expand and diversify the Company's
customer base. CNG Energy Services continues to
6
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ITEM 1. BUSINESS (Continued)
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 the exploration and production operations.
ENERGY MARKETING SERVICES
The Company's energy marketing services operations, comprised of CNG Energy
Services, CNG Power, CNG Power Services and CNG Storage, are engaged in a
variety of energy-related activities in highly competitive markets. These
activities, which were under a single management team in 1995, include fuel
management, gas trading, energy price risk management, pipeline capacity and
storage management, power marketing and electric generation.
Energy marketing services competes with the marketing operations of both
independent and major energy companies in addition to electric utilities,
independent power producers, local distribution companies, and various energy
brokers. As a result of the continuing efforts to deregulate both natural gas
and electric utility operations, the economic differences among different forms
of energy are expected to be reduced in the future. Competition is based largely
upon pricing, availability and reliability of supply, technical and financial
capabilities, regional presence and international experience. In addition,
several companies have combined resources via merger or strategic alliances to
enhance their ability to meet customer demands both domestically and
internationally. Reference is made to "International Activities," page 13,
regarding the Company's actions in this area.
GAS SUPPLY
GENERAL INFORMATION
The Company'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 many commercial
customers now purchase a large portion of their gas supplies from producers,
marketers, or on the spot market, and contract with the 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. Since CNG Transmission no longer provides traditional sales
service, its former sales customers, including the distribution subsidiaries,
have the responsibility and risk for obtaining their own gas supplies. Overall,
the Company's gas supply requirements have grown due largely to the increase in
nonregulated gas sales by CNG Energy Services.
The Company's available gas supply in 1995 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
and gas supply contracts, Company-owned gas reserves, and assuming the future
availability of spot market gas, the Company believes that supplies will be
available to meet sales requirements for several years. Gas supply statistics
for the past five years are on page 12.
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ITEM 1. BUSINESS (Continued)
GAS PURCHASED
Purchased gas volumes were 771.1 billion cubic feet (Bcf) in 1995, representing
86 percent of the Company's total 1995 gas supply of 897.5 Bcf. Spot market and
short-term purchases were 701.8 Bcf, or about 78 percent of the total 1995
supply. Volumes purchased under contracts with Appalachian area producers
totaled 69.3 Bcf, or 8 percent of the 1995 supply.
In response to the regulatory and market changes over the past several years,
including Order 636, the Company converted its long-term gas purchase contracts
with interstate pipelines to firm transport contracts. As a result, gas volumes
purchased from the pipeline companies have been eliminated and replaced, in
large part, with contract volumes purchased directly with producers and
marketers.
While spot market gas supplies have historically been obtained at lower prices,
the availability and price of such supplies to distribution companies can be
severely impacted by sudden market 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 distribution subsidiaries have
purchased a larger portion of their gas supplies directly from producers on a
firm basis. However, spot market gas will continue to be part of the Company's
supply mix, particularly for CNG Energy Services.
Gas purchased from producers and on the spot market is delivered to the
distribution subsidiaries using the firm transport capacity contracted for on
interstate pipelines. At December 31, 1995, the subsidiaries had 415 Bcf of firm
transport capacity on upstream pipelines, yielding deliveries of up to 1.1 Bcf
of gas a day. These upstream pipelines include Tennessee Gas Pipeline Company,
Panhandle Eastern Pipe Line Company, Texas Eastern Transmission Corporation
(Texas Eastern), ANR Pipeline Company, Texas Gas Transmission Corporation,
Transcontinental Gas Pipe Line Corporation and Columbia Gas Transmission
Corporation.
GAS STORAGE
The Company's 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 Bcf. The Company's share of the total capacity is about 669
Bcf. 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 719 Bcf of the total designed storage capacity and
owns 503 Bcf of the Company's capacity. CNG Transmission utilizes a large
portion of its turnable capacity to provide approximately 252 Bcf 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.
Two of the distribution subsidiaries, East Ohio Gas and Peoples Natural Gas, own
and operate the remaining 166 Bcf of storage capacity. In addition to owning
their own storage, these companies, as well as most of the other subsidiaries,
have ready access to a portion 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 is an important element in the effective management of both gas
supply and pipeline transport capacity.
The Company 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.
8
<PAGE> 11
ITEM 1. BUSINESS (Continued)
GAS AND OIL PRODUCING ACTIVITIES
Over the past several years, the exploration and production operations have been
affected by the generally adverse conditions in the industry. The effects of
continued warm weather, the lingering gas oversupply situation, and low gas and
oil wellhead prices have all contributed to a difficult operating environment.
However, the level of capital spending on exploration and production operations
has increased during the past three years, and is expected to increase again in
1996, reflecting the Company's longer-term commitment to these operations. Part
of the Company's strategy for its exploration and production operations is to
better balance offshore and onshore production, and to increase the oil portion
of total production. The Company will continue to develop its second deep-water
project in the Gulf of Mexico at Viosca Knoll 826, in addition to onshore and
other offshore projects.
The Company's gas wellhead prices in 1995 averaged $1.89 a thousand cubic feet
(Mcf), down from $2.16 in 1994. Consistent with prices nationwide, the Company's
gas wellhead prices in 1995 were below prior year levels for most of the period.
The Company'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-based pricing mechanisms under many of the
contracts, the Company's gas prices generally follow industry trends. The
average oil wellhead price in 1995 increased to $16.04 a barrel, compared with
$14.45 in 1994, consistent with the general increase in world oil prices.
The Company's total gas production in 1995 was 107.2 Bcf, down from 119.5 Bcf in
1994. Oil production was 3.1 million barrels, down 6 percent from 3.4 million
barrels in 1994. The low gas prices that prevailed nationwide during most of
1995 were the basis for the Company's decision to shut in a portion of its
offshore production at various times of the year which, in addition to normal
declines at certain properties, resulted in lower gas production for the year.
However, the lower oil production during 1995 was due largely to normal
production declines at older properties.
During 1995, CNG Producing participated in the drilling of 53 gross wells (26
net), compared with 81 gross wells (35 net) drilled in 1994. The following table
sets forth 1995 drilling activity by region:
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
Gross Wells Drilled
Exploratory Development
- - ----------------------------------------------------------------------------------------------
<S> <C> <C>
Onshore (Southwest and West).................................... 6 11
Gulf of Mexico.................................................. 15 6
Appalachian Region.............................................. -- 2
Canada.......................................................... -- 13
--- ---
Total...................................................... 21 32
=== ===
- - ----------------------------------------------------------------------------------------------
</TABLE>
Of the total 53 wells drilled in 1995, 38 were successful, a 72 percent success
rate. Of the 21 exploratory wells drilled, 7 were successful, including finds at
Main Pass 222/223 and West Cameron 580 off the Louisiana coast, and High Island
312, offshore Texas.
Total Company-owned proved gas reserves at year-end were 1,041 Bcf, up from 972
Bcf at the end of 1994. Proved oil reserves were 45.8 million barrels, compared
with 46.5 million barrels in 1994. East Ohio Gas sold all of its remaining gas
and oil reserves during 1995. CNG added 203 Bcf equivalent of gas and oil
reserves in 1995, equal to 167 percent of total production. (See "Company-Owned
Reserves," page 20.)
Natural gas production began in January 1996 at Popeye, a deep-water natural gas
discovery in the Green Canyon area of the Gulf of Mexico. The field is producing
over 120 million cubic feet of gas per day from two wells flowing through a
state of the art subsea facility developed to produce gas 2,000 feet below sea
level. CNG Producing's interest in this property is 37.5 percent. Other
participants in the joint venture are Mobil Oil Exploration and Producing
Southeast and BP Exploration Inc.
9
<PAGE> 12
ITEM 1. BUSINESS (Continued)
Development will continue in 1996 at Neptune, a deep water oil discovery at
Viosca Knoll 826. This project, in which the Company holds a 50 percent
interest, added proved reserves equivalent to 190 Bcf of gas in 1994,
representing the largest single addition to the Company's reserves in its
history. Facilities are being designed with Oryx Energy Company, the operating
partner, to produce up to 25,000 barrels of oil and 30 million cubic feet of
natural gas a day. Production is expected to begin in early 1997. Neptune will
make use of an innovative floating production facility called a Spar, a
700-foot-long cylindrical structure that will be towed to the site, turned on
end and anchored to the sea floor with cables. This is the first time a Spar
will be used in the Gulf of Mexico as a production platform. Participation in
the Popeye and Neptune projects is providing the Company access to new
technologies and the experience necessary to better evaluate future deep-water
opportunities.
The Company drilled 2 wells in the Appalachian Region during 1995. Gas from this
area normally commands a higher price because of its location in proximity to
major gas markets. However, due to deregulation and the increased availability
of pipeline capacity over the past few years, this location differential has
lessened somewhat. The Company plans to continue production from these
properties and to maintain its strong acreage position in the Appalachian
Region, and may seek to acquire additional properties in this area that meet the
Company's longer-term strategy. Selected Appalachian properties were sold during
1995, but the acreage and reserves were not material.
In the second quarter of 1995, CNG Energy Services and Centana Energy
Corporation (Centana) announced plans to build a gas and oil gathering pipeline
system to serve two production areas in the Gulf of Mexico--Main Pass and Viosca
Knoll. Later in 1995, a third partner, Amoco Pipeline, was added to the oil
gathering project. The system will have the capacity to carry 300 million cubic
feet per day of natural gas, 5,000 barrels per day of condensate and 130,000
barrels per day of crude oil. Construction of the pipeline system began in 1995
and is scheduled to be completed in 1996. Centana will operate the natural gas
and condensate lines and Amoco Pipeline will operate the oil pipeline. The
estimated cost of the projects is $89 million, with CNG Energy Services' share
amounting to approximately $37 million.
CNG Producing was the successful bidder on 8 leases offered in the federal
government's Gulf of Mexico lease sales in 1995, acquiring 8 blocks off the
coast of Louisiana. At year-end 1995, the Company held 2.0 million net acres of
exploration and production properties, down from 2.4 million at year-end 1994.
The Company's lease holdings include about 1.4 million net acres in the
Appalachian area, 308,800 in the offshore Gulf of Mexico, and 374,200 in the
inland areas of the Southwest, Gulf Coast and West. The Company holds a 21
percent interest in heavy oil properties in Alberta, Canada. Proved reserves
associated with the Canadian properties approximated 1 Bcf of gas and 5.8
million barrels of oil at December 31, 1995. On an energy-equivalent basis,
these reserves represent about 3 percent of Consolidated's total proved reserves
at that date.
The Company will continue to review its property inventory during 1996, and
sales of selected properties are possible depending on economic conditions.
GAS SALES AND TRANSPORTATION
Total gas sales in 1995 were 846 Bcf, up 37 percent from the 618 Bcf sold in
1994. Transportation volumes were 750 Bcf in 1995, a 3 percent increase from the
725 Bcf transported in 1994. (Five-year statistics are on page 12.)
GAS SALES CUSTOMERS
At December 31, 1995, the Company's distribution subsidiaries served almost 1.7
million residential customers, about 126,000 commercial customers and about
1,700 industrial customers in Ohio, Pennsylvania, Virginia and West Virginia.
10
<PAGE> 13
ITEM 1. BUSINESS (Continued)
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------------
Residential
Customers Total and Commercial Industrial Wholesale Nonregulated
- - ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
December 31,
1995 1,824,497 1,822,253 1,736 12 496
1994 1,799,649 1,797,433 1,697 14 505
1993 1,777,157 1,774,922 1,688 31 516
1992 1,759,284 1,757,139 1,694 32 419
1991 1,737,947 1,735,803 1,698 31 415
- - ----------------------------------------------------------------------------------------------------
</TABLE>
RESIDENTIAL AND COMMERCIAL SALES
Sales of gas to residential customers in 1995 were 212 Bcf, up 6 Bcf from 1994,
while sales to commercial customers were 70 Bcf in 1995, up 1 Bcf compared to
1994. Residential and commercial gas sales volumes increased during 1995
reflecting colder weather and the net addition of about 24,800 customers. The
weather in the Company's retail service areas in 1995 was 2 percent colder than
1994, but was 1 percent warmer than normal.
INDUSTRIAL SALES
Industrial sales in 1995 were 7 Bcf, down 2 Bcf compared to 1994. Due to both
availability and price, many industrial users buy gas directly from producers,
from marketers, or on the spot market, and contract with the subsidiary
companies for transportation service. Total gas deliveries (sales and
transportation) to industrial customers were 138 Bcf in 1995, compared with 130
Bcf in 1994.
WHOLESALE SALES
With CNG Transmission's abandonment of its traditional sales service pursuant to
FERC Order 636, wholesale sales volumes are no longer significant for the
Company. Total sales volumes were .3 Bcf in 1995, the same level as in 1994.
NONREGULATED SALES
Nonregulated gas sales in 1995 were 557 Bcf, up from 333 Bcf in 1994. Gas sales
by CNG Energy Services were 523 Bcf, compared to 190 Bcf in 1994. Volumes
related to gas brokering activity were 25 Bcf in 1995, down from 54 Bcf in 1994.
Sales of Company-produced gas, primarily by CNG Producing, to nonaffiliates were
9 Bcf, compared with 89 Bcf in 1994. Effective January 1, 1995, CNG Energy
Services became the primary marketing agent for all of the Company's
nonregulated gas production.
GAS TRANSPORTATION
Total transportation volumes in 1995 were 750 Bcf, up from 725 Bcf in 1994.
First quarter 1995 transport volumes were lower than the prior year due to
warmer weather in that period, while transport volumes were up for the balance
of 1995 compared to 1994. Total volumes transported by the distribution
subsidiaries for commercial, industrial and off-system customers were up 14 Bcf
over 1994, as transportation volumes for industrial customers were up 10 Bcf
compared to the prior year.
11
<PAGE> 14
ITEM 1. BUSINESS (Continued)
GAS SALES, SUPPLY AND TRANSPORTATION STATISTICS
(Excludes affiliated transactions)
<TABLE>
<CAPTION>
- - ------------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993 1992 1991
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
GAS SALES REVENUES (MILLIONS)
Regulated
Residential and commercial.... $1,560.1 $1,628.3 $1,595.1 $1,428.7 $1,373.1
Industrial.................... 32.6 45.8 55.4 50.0 46.0
Wholesale..................... 4.7 5.2 422.7 190.8 426.8
Nonregulated.................... 997.7 723.6 541.8 282.0 237.0
-------- -------- -------- -------- --------
Total.................... $2,595.1 $2,402.9 $2,615.0 $1,951.5 $2,082.9
======== ======== ======== ======== ========
AVERAGE SALES RATES PER MCF
Regulated
Residential and commercial.... $ 5.53 $ 5.91 $ 5.60 $ 5.09 $ 5.25
Industrial.................... 4.49 4.89 4.43 4.00 4.09
Wholesale..................... * * 5.24 * 4.49
Nonregulated.................... 1.79 2.17 2.40 2.10 2.01
Weighted average......... $ 3.07 $ 3.89 $ 4.33 $ 4.35 $ 4.29
======== ======== ======== ======== ========
GAS REQUIREMENTS (BCF)
Regulated gas sales
Residential and commercial.... 282.3 275.3 285.0 280.7 261.7
Industrial.................... 7.3 9.4 12.5 12.5 11.2
Wholesale..................... .3 .3 80.7 21.2 95.0
Nonregulated gas sales.......... 556.6 332.8 226.0 134.4 118.1
-------- -------- -------- -------- --------
Total sales.............. 846.5 617.8 604.2 448.8 486.0
Used and unaccounted for........ 51.0 48.3 44.0 51.7 34.5
-------- -------- -------- -------- --------
Total requirements....... 897.5 666.1 648.2 500.5 520.5
======== ======== ======== ======== ========
GAS SUPPLY (BCF)
Purchased gas................... 771.1 559.6 485.2 370.6 377.2
Storage (input) withdrawal...... 19.2 (13.0) 33.5 1.9 10.5
Gas produced
Gulf region................... 68.3 76.4 81.6 78.9 84.2
Appalachian area.............. 27.2 27.8 29.4 33.1 35.3
Other areas................... 11.7 15.3 18.5 16.0 13.3
-------- -------- -------- -------- --------
Total produced........... 107.2 119.5 129.5 128.0 132.8
-------- -------- -------- -------- --------
Total supply............. 897.5 666.1 648.2 500.5 520.5
======== ======== ======== ======== ========
PURCHASED GAS COSTS
(MILLIONS)**.................. $1,611.9 $1,375.8 $1,349.5 $1,132.1 $1,093.6
======== ======== ======== ======== ========
AVERAGE PURCHASE RATES PER
MCF**......................... $ 2.09 $ 2.46 $ 2.78 $ 3.05 $ 2.90
======== ======== ======== ======== ========
GAS TRANSPORTATION
Revenues (Millions)............. $ 333.2 $ 293.7 $ 222.5 $ 201.0 $ 154.9
======== ======== ======== ======== ========
Gas Transported (Bcf)........... 749.8 724.9 587.5 613.1 446.7
======== ======== ======== ======== ========
<FN>
- - ------------------------------------------------------------------------------------------------
* Demand charges and low sales volumes produce an average rate which is not
meaningful.
** Includes transportation charges.
</TABLE>
12
<PAGE> 15
ITEM 1. BUSINESS (Continued)
MARKET EXPANSION
In recent years the Company has pursued a broad program designed to expand its
interstate pipeline system and extend its marketing territory. The Company'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. The Company 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, the Company 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.
PIPELINE EXPANSION
CNG Transmission and Texas Eastern have joint plans to provide additional
services to certain customers in the Northeast, Mid-Atlantic and Southeast
markets. CNG and Texas Eastern will file companion applications with the FERC to
obtain the required federal certification. The project, known as the Seasonal
Service Expansion Project (formerly the "WinterNet" project), would provide 150
million cubic feet per day of natural gas service to meet the winter season and
peak needs of these customers. Project facilities would include additional
pipeline capacity along CNG Transmission's and Texas Eastern's pipeline systems,
access to salt-cavern storage, and additional compression on CNG Transmission's
system. If approved by the FERC, the project would be phased in over a four-year
period beginning in 1997. Facility construction on CNG Transmission's system is
projected to cost about $55 million.
ELECTRIC POWER MARKETING
During 1995, CNG Power Services commenced wholesale sales of electricity at
market-based rates and joined the Western Systems Power Pool (the Pool), a
trading organization of 120 companies that buy and sell electric power at tariff
rates set by the FERC. Currently, the Pool is able to trade wholesale
electricity from eastern Tennessee to the Pacific Ocean and is expected to
expand into the southern United States. CNG Power Services is also a member of
four of the nine districts of the North American Electric Reliability Council,
which serves to coordinate planning and power transmission operations. In
February 1996, the Company announced the opening of offices in Atlanta, Georgia
and Portland, Oregon to serve the wholesale and emerging retail electricity
markets in the Southeast and West Coast regions of the United States.
INTERNATIONAL ACTIVITIES
In November 1994, CNG Energy Services formed a marketing alliance with two
Canadian firms, Hydro-Quebec and Noverco. The alliance offers energy services to
customers throughout the northeastern and midwestern United States and eastern
Canada. In June 1995, the companies signed an agreement to create a
partnership--the Energy Alliance Partnership--to conduct alliance business. This
agreement is subject to SEC and other regulatory approvals.
In November 1995, the Company announced the formation of a strategic alliance
with EnergyAustralia (formerly MetNorth Energy), Australia's largest electric
utility, to assist EnergyAustralia in developing its natural gas marketing
capabilities and to jointly identify and develop energy infrastructure projects
in Australia and Asia.
13
<PAGE> 16
ITEM 1. BUSINESS (Continued)
In January 1996, the Company formed a new subsidiary, CNG International
Corporation (CNG International). The purpose of CNG International is to engage
in energy-related activities outside the United States, including activities
under the EnergyAustralia alliance. The financing of CNG International is
subject to SEC approval.
ADDITIONAL USES FOR NATURAL GAS
During 1995, the Company continued its involvement with a number of gas burning
technologies that provide opportunities to improve customer efficiency while
promoting the use of natural gas in markets that are not sensitive to the
weather or economic downturn. The advancement of such technologies appears
beneficial as business entities strive to comply with provisions of the Federal
Clean Air Act, legislation which applies strict anti-pollution standards to
factories, fleet and mass transit vehicles, and 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 which 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.
The Company 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 using NGVs for both fuel cost efficiencies and 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 vehicles. However,
beginning in 1997, the Federal Clean Air Act could require 22 of the country's
most polluted regions to convert a portion of their fleet vehicles to natural
gas. The Company 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.
RATE MATTERS (See Note 2 to the consolidated financial statements, page 49.)
The regulated 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 1995 and to date.
CNG TRANSMISSION
CNG Transmission received FERC approval to implement Order 636 effective October
1, 1993, in accordance with the terms of a comprehensive stipulation and
agreement reached with customers and others. With FERC approval, CNG
Transmission direct billed and began collecting transition costs amounting to
$177.9 million and $9.8 million in December 1993 and August 1994, respectively.
During 1995, CNG Transmission made refunds to its customers and affiliates of
$9.1 million in connection with the prior direct billings.
On November 29, 1995, the FERC approved a settlement agreement filed by CNG
Transmission in connection with its December 30, 1993 general rate filing. The
settlement resolves the outstanding issues in the case and results in an annual
revenue increase of $40 million, retroactive to July 1, 1994, the date new rates
went into effect subject to refund. The settlement reflects an imputed return on
equity of 11.30 percent. Customer refunds resulting from the settlement totaling
$81.5 million were made in
14
<PAGE> 17
ITEM 1. BUSINESS (Continued)
December 1995 with an additional $4.8 million expected to be refunded in the
first quarter of 1996. In its filing, CNG Transmission had requested a $106.6
million increase in annual revenues and a return on equity of 14.00 percent.
DISTRIBUTION SUBSIDIARIES
On August 3, 1995, the Pennsylvania Public Utility Commission approved a
settlement agreement filed by Peoples Natural Gas covering its February 1, 1995
general rate filing. The approved settlement includes an $8.0 million annual
revenue increase with new rates effective August 4, 1995. In its filing, Peoples
Natural Gas had originally requested a $32.8 million increase in annual
revenues.
On September 1, 1995, Virginia Natural Gas submitted an expedited rate filing
with the Virginia State Corporation Commission (VSCC) requesting an annual
revenue increase of $7.2 million. The new rates went into effect, subject to
refund, on October 1, 1995. On February 23, 1996, Virginia Natural Gas requested
approval from the VSCC to withdraw this rate filing. Pending VSCC approval,
customer refunds related to the filing will be made later in 1996.
On October 26, 1995, the Public Service Commission of West Virginia approved a
settlement agreement filed by Hope Gas in connection with its January 4, 1995
general rate filing. The new rates became effective November 1, 1995. The
approved settlement agreement increased base rates but eliminated the purchased
gas cost adjustment mechanism for the three-year period covered by the
settlement. Therefore, any increase or decrease in gas costs over the base
amount included in rates will not be passed on to customers during the
settlement period.
On November 8, 1995, a $6.2 million annual revenue increase became effective at
East Ohio Gas in connection with the November 3, 1994 settlement of its general
rate case, as approved by the Public Utilities Commission of Ohio. This increase
is in addition to the $62.4 million annual revenue increase that became
effective November 8, 1994.
On January 30, 1996, the VSCC issued a final order in connection with Virginia
Natural Gas' September 1, 1994 general rate filing. The order results in an
annual revenue increase of $6.1 million, retroactive to October 1, 1994, the
date new rates went into effect subject to refund. Customer refunds resulting
from the order will be made in the first half of 1996. The order reflects an
imputed return on equity of 11.3 percent. In its filing, Virginia Natural Gas
had requested a $9.9 million increase in annual revenues and a return on equity
of 11.75 percent.
15
<PAGE> 18
ITEM 1. BUSINESS (Concluded)
EXECUTIVE OFFICERS OF THE COMPANY (Note 1)
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------
Name, Age and Business Experience
Position (Note 2) During Past Five Years
- - ---------------------------------------------------------------------------------------------
<S> <C>
George A. Davidson, Jr. (57) Mr. Davidson was elected to his present position on May 19,
Chairman of the Board and 1987, and has been a Director since October 1985.
Chief Executive Officer,
and Director
Robert W. Best (49) Mr. Best joined the Company and was elected to his present
Senior Vice President position on January 1, 1996. Prior to joining the Company,
Mr. Best was Senior Vice President, Natural Gas of Transco
Energy from February 1992 to May 1995 and President and
Chief Operating Officer of Texas Gas (a wholly owned
subsidiary of Transco Energy) from April 1989 to May 1995.
William F. Fritsche, Jr. (64) Mr. Fritsche was elected to his present position on May 1,
Senior Vice President, 1995. He served as President of East Ohio Gas from
Distribution September 1994 to April 1995. From June 1987 to September
1994, he served as President of Virginia Natural Gas.
David M. Westfall (48) Mr. Westfall was elected to his present position on
Senior Vice President and December 1, 1995. He served as Senior Vice President,
Chief Financial Officer Financial from January 1995 to November 1995. From January
1988 to January 1995, he served as Senior Vice President at
CNG Transmission.
Stephen E. Williams (47) Mr. Williams was elected to his present position on January
Senior Vice President and 1, 1993. He served as Associate General Counsel from
General Counsel September 1992 to January 1993. From April 1987 to
September 1992, he served as General Counsel and Secretary
of CNG Transmission.
Stephen R. McGreevy (45) Mr. McGreevy was elected to his present position on March
Vice President, Accounting 1, 1993. He served as Controller from January 1986 to March
and Financial Control 1993.
Laura J. McKeown (37) Ms. McKeown was elected to her present position on May 16,
Secretary 1989.
Robert M. Sable, Jr. (44) Mr. Sable was elected to his present position on May 1,
Treasurer 1995. He served as Senior Assistant Treasurer from January
1993 to April 1995 and Assistant Treasurer from May 1987 to
January 1993.
Thomas F. Garbe (43) Mr. Garbe was elected to his present position on March 1,
Controller 1993. He served as Senior Assistant Controller from May
1991 to March 1993 and as Assistant Controller from January
1986 to May 1991.
- - ---------------------------------------------------------------------------------------------
<FN>
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.
</TABLE>
16
<PAGE> 19
ITEM 2. PROPERTIES
GENERAL INFORMATION ON FACILITIES (Maps are on pages 18 and 19.)
The Company's total gross investment in property, plant and equipment was $7.9
billion at December 31, 1995. The largest portion of this investment (61%) is in
facilities located in the Appalachian area. Another significant portion (24%) is
located in the Gulf of Mexico.
Of the $7.9 billion investment, $3.5 billion is in production and gathering
systems, of which 59 percent is invested in the Gulf of Mexico and the Gulf
coast and 26 percent in the Appalachian area. The Company's production
subsidiary, CNG Producing, accounts for $2.9 billion of the $3.5 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 7,010 miles of gathering lines
which are located almost entirely within the Appalachian area.
The Company's investment in its gas distribution network includes 29,043 miles
of pipe, exclusive of service pipe, the cost of which represents 61% of the $1.7
billion invested in the total function.
The Company's storage operation, the largest in the industry, consists of 26
storage fields, 332,288 acres of operated leaseholds, 2,060 storage wells and
821 miles of pipe. The investment in storage properties is $685 million,
including $115 million of cushion gas stored.
Of the $1.5 billion invested in transmission facilities, 68% represents the cost
of 7,317 miles of pipe required to move large volumes of gas throughout the
Company's operating area.
The Company has 105 compressor stations with 485,018 installed compressor
horsepower. Some of the stations are used interchangeably for several functions.
The Company's investment in its 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 11.4 Bcf on February 6, 1995.
17
<PAGE> 20
Map of Principal Facilities at December 31, 1995
(GRAPHIC MATERIAL OMITTED)
18
<PAGE> 21
Map of Exploration and Production Areas at December 31, 1995
(GRAPHIC MATERIAL OMITTED)
19
<PAGE> 22
ITEM 2. PROPERTIES (Continued)
GAS AND OIL PRODUCING ACTIVITIES (See Note 19(A) to the consolidated financial
statements, page 68.)
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, 1993
through 1995, follow:
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------------------------
December 31, 1995 1994 1993
- - --------------------------------------------------------------------------------------------------
Proved Total Proved Total Proved Total
Developed Proved Developed Proved Developed Proved
- - --------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Gas Reserves (Bcf)
Non-cost-of-service...... 717 985 730 901 761 885
Cost-of-service.......... 56 56 71 71 75 75
------ ------ ------ ------ ------ ------
Total............... 773 1,041 801 972 836 960
====== ====== ====== ====== ====== ======
Oil Reserves (000 Bbls)
Non-cost-of-service...... 19,838 45,791 20,379 46,255 21,936 27,596
Cost-of-service.......... -- -- 256 256 287 287
------ ------ ------ ------ ------ ------
Total............... 19,838 45,791 20,635 46,511 22,223 27,883
====== ====== ====== ====== ====== ======
- - --------------------------------------------------------------------------------------------------
</TABLE>
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, 1994, as well as those which will be reported at December 31, 1995,
are not reconcilable with Company-owned reserves because they are calculated on
an operated basis and include working interest reserves of all parties. East
Ohio Gas sold all of its remaining gas and oil reserves (which are classified as
cost-of-service in the table above) during 1995.
QUANTITIES OF GAS AND OIL PRODUCED
Net quantities (net before royalty) of gas and oil produced during each of the
last three years follow:
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Gas Production (Bcf)
Non-cost-of-service......................................... 103 114 124
Cost-of-service............................................. 4 6 6
----- ----- -----
Total.................................................. 107 120 130
===== ===== =====
Oil Production (000 Bbls)
Non-cost-of-service......................................... 3,132 3,333 3,907
Cost-of-service............................................. 17 24 29
----- ----- -----
Total.................................................. 3,149 3,357 3,936
===== ===== =====
- - ----------------------------------------------------------------------------------------------
</TABLE>
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 1993 through 1995 was $2.24, $2.16 and
$1.89, respectively. The respective average sales prices for oil were $15.66,
$14.45 and $16.04 per barrel. The average production (lifting) cost per Mcf
20
<PAGE> 23
ITEM 2. PROPERTIES (Continued)
equivalent of non-cost-of-service gas and oil produced during the years 1993
through 1995 was $.33, $.32 and $.34, respectively.
PRODUCTIVE WELLS
The number of productive gas and oil wells in which the subsidiary companies
have an interest at December 31, 1995, follow:
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------
Gas Wells Oil Wells
--------------- -------------
Gross Net Gross Net
- - ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Non-cost-of-service*.................................... 5,145 4,408 859 380
Cost-of-service......................................... 1,635 1,320 -- --
----- ----- --- ---
Total.............................................. 6,780 5,728 859 380
===== ===== === ===
- - ---------------------------------------------------------------------------------------------
<FN>
* Includes 81 gross (28 net) multiple completion gas wells and 6 gross (3 net)
multiple completion oil wells.
</TABLE>
ACREAGE
The following table sets forth the gross and net developed and undeveloped
acreage of the subsidiary companies at December 31, 1995:
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
Developed Acreage Undeveloped Acreage
----------------------- ---------------------
Gross Net Gross Net
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Non-cost-of-service.................... 1,631,188 1,239,603 894,837 582,830
Cost-of-service........................ 215,422 212,966 13,391 9,882
--------- --------- ------- -------
Total.................................. 1,846,610 1,452,569 908,228 592,712
========= ========= ======= =======
- - ----------------------------------------------------------------------------------------------
</TABLE>
Approximately 30% 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):
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------------
Exploratory Development Total
------------------ ------------------- ------------------
Productive Dry Productive* Dry Productive Dry
- - ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Years Ended December 31,
1995...................... 4 9 12 1 16 10
1994...................... 2 10 22 1 24 11
1993...................... 2 6 13 1 15 7
- - ---------------------------------------------------------------------------------------------------
<FN>
* Includes Canadian completions: 1995 - 3 wells, 1994 - 1 well and 1993 - 1
well.
</TABLE>
As of December 31, 1995, 13 gross (6 net) non-cost-of-service wells were in
process of drilling, including wells temporarily suspended. As of December 31,
1995, the Company was engaged in waterflood projects in Oklahoma and Texas, a
gas injection program in the Gulf of Mexico, and an enhanced oil recovery
program in Alberta, Canada.
21
<PAGE> 24
ITEM 2. PROPERTIES (Concluded)
GAS PURCHASE CONTRACT RESERVES (AT DECEMBER 31, 1995) AND AVAILABILITY OF
SUPPLY (CALENDAR YEAR 1996)
Gas purchase reserves under contract with independent producers in the
Appalachian area total 573 Bcf at December 31, 1995. In addition, at December
31, 1995, the Company had gas supply contracts with various other producers and
marketers with contract lengths ranging from a few months to nine years. The
volume of gas available to the Company under these supply contracts totals 289
Bcf if all volumes are requested. These gas purchase contract reserve and gas
supply contract volume amounts are as contained in the February 12, 1996 report
of Ralph E. Davis Associates, Inc. Of the total 573 Bcf under contract from
Appalachian producers, the volume of gas expected to be purchased in 1996 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 289 Bcf available under contract from other producers and marketers,
approximately 178 Bcf of gas will be available to the Company in 1996, assuming
all volumes are requested.
The Company anticipates that substantial volumes of gas will be available for
purchase during 1996 on the spot market. Due to the nature of spot market
transactions, the volumes of such gas available to the Company in 1996 cannot be
reasonably estimated. However, for the calendar year 1996, the Company expects
its distribution subsidiaries to have approximately 361 Bcf of firm transport
capacity available on upstream pipelines and 122 Bcf of storage capacity
available to meet their customer requirements.
The volumes expected to be available from Company-owned wells in 1996 amount to
129 Bcf of gas and 3,647 thousand barrels of oil. Included in these amounts are
125 Bcf of gas and 3,647 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. LEGAL PROCEEDINGS
Reference is made to Note 16 to the consolidated financial statements, page 63,
for environmental-related information.
Reference is made to "Rate Matters," page 14, for descriptions of certain
regulatory proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable
PART II
-------
ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS
This information is included in Note 19(C) to the consolidated financial
statements, page 73, and reference is made thereto.
22
<PAGE> 25
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
- - ------------------------------------------------------------------------------------------------------------
SUMMARY OF FINANCIAL DATA (Thousand $) 1995* 1994 1993 1992 1991
- - ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
EARNINGS
Gas sales............................ $2,595,103 $ 2,402,861 $ 2,615,036 $ 1,951,545 $ 2,082,927
Gas transportation, storage and
other.............................. 712,222 633,167 569,049 569,305 524,079
Total operating revenues......... 3,307,325 3,036,028 3,184,085 2,520,850 2,607,006
Purchased gas........................ 1,590,137 1,424,020 1,594,373 990,604 1,157,096
Transport capacity and other
purchased products................. 153,577 107,094 79,001 73,001 80,131
Operation and maintenance............ 739,612** 689,575 677,666 657,825 639,530
Depreciation and amortization........ 256,636 279,317 294,648 287,840 284,712
Impairment of gas and oil producing
properties......................... 226,209 -- -- -- --
Taxes, other than income taxes....... 191,698 192,617 181,053 169,315 160,632
Operating income before income
taxes.......................... 149,456 343,405 357,344 342,265 284,905
Income taxes......................... 2,943 82,427 99,906 68,623 54,844
Other income-net..................... 10,760 9,694 10,531 4,749 26,381
Write-down of coal properties........ 31,266 -- -- -- --
Interest charges..................... 104,663 87,501 79,475 83,433 87,829
Income before change in
accounting principle............... 21,344 183,171 188,494 194,958 168,613
Cumulative effect of applying SFAS
No. 109............................ -- -- 17,422 -- --
Net income....................... 21,344 183,171 205,916 194,958 168,613
Per share of common stock
Income before change in
accounting principle........... $.23 $1.97 $2.03 $2.19 $1.94
Cumulative effect of applying
SFAS No. 109................... -- -- .19 -- --
Net income....................... $.23 $1.97 $2.22 $2.19 $1.94
Average common shares outstanding.... 93,246,114 92,999,693 92,808,156 89,127,805 86,836,920
Return on average stockholders'
equity............................. 1.0% 8.4% 9.6% 9.7% 9.0%
Times fixed charges earned........... 1.21 3.53 3.95 3.41 2.86
- - ------------------------------------------------------------------------------------------------------------
DIVIDENDS--CASH
Paid per common share................ $1.94 $1.94 $1.92 $1.90 $1.88
Payout ratio..................... 843.5% 98.5% 86.5% 86.8% 96.9%
Declared per common share............ $1.94 $1.94 $1.925 $1.905 $1.885
- - ------------------------------------------------------------------------------------------------------------
ASSETS
Total assets......................... $5,418,293 $ 5,518,673 $ 5,437,188 $ 5,158,871 $ 5,026,775
Property, plant and equipment
Total investment................. 7,929,350 7,676,956 7,346,028 7,087,102 6,749,165
Accumulated depreciation......... 4,016,945 3,650,310 3,429,760 3,212,202 3,010,776
Capital expenditures and
acquisitions....................... 439,393 437,785 342,569 441,518 493,033
- - ------------------------------------------------------------------------------------------------------------
CAPITAL STRUCTURE
Total common stockholders' equity.... $2,045,818 $ 2,184,334 $ 2,176,432 $ 2,132,838 $ 1,889,783
Long-term debt....................... 1,291,811 1,151,973 1,158,648 1,111,956 1,159,123
---------- ----------- ----------- ----------- -----------
Total capitalization............. $3,337,629 $ 3,336,307 $ 3,335,080 $ 3,244,794 $ 3,048,906
========== =========== =========== =========== ===========
Long-term debt ratio................. 38.7% 34.5% 34.7% 34.3% 38.0%
Shares of common stock outstanding
at year-end........................ 93,591,623 93,027,847 92,933,828 92,557,017 87,321,917
Common stockholders' equity
per share.......................... $21.86 $23.48 $23.42 $23.04 $21.64
- - ------------------------------------------------------------------------------------------------------------
<FN>
* Certain amounts and ratios are not comparable with prior years due to special
charges.
** Includes special charges for workforce reduction costs of $42,555,000.
</TABLE>
23
<PAGE> 26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
NET INCOME
Net income in 1995 was $21.3 million, or $.23 a share, compared with net income
of $183.2 million, or $1.97 a share, in 1994. Net income in 1993 was $205.9
million, or $2.22 a share.
Earnings for 1995 included the effects of three special charges. During the
first quarter, the Company recorded a non-cash charge to write down the cost of
gas and oil producing properties, amounting to $145.0 million after taxes, or
$1.56 a share. In the second quarter, the Company recognized a non-cash charge
of $20.3 million after taxes, or $.22 a share, in connection with a write-down
of coal properties. In addition, during the year the Company recorded charges
totaling $25.6 million after taxes, or $.27 a share, for costs related to
workforce reduction programs. Excluding these special items, net income for 1995
would have been $212.3 million, or $2.28 a share. Reference is made to Notes 3
and 4 to the consolidated financial statements, pages 49 and 50, for details of
the special charges recognized in 1995.
The favorable effects of new rates in place for most of the Company's gas
distribution and transmission customers, colder weather than in 1994 and lower
aggregate wage and benefit costs in the latter part of the year resulting from
the workforce reduction programs more than offset the impact of continued low
wellhead prices for natural gas and lower gas and oil production in 1995.
Weather in the Company's retail service territories was 2.2 percent colder than
in 1994 but 1.1 percent warmer than normal. Weather in 1995 was warmer than
normal for the sixth consecutive year. Normal weather represents a measure of
temperature experienced over a 30-year period.
Warmer weather, higher operating costs, lower average wellhead gas prices,
reduced gas production and higher interest expense contributed to the earnings
decline in 1994 compared with 1993. Normal weather would have added about $.12 a
share to the $1.97 a share reported for 1994.
In 1993, higher prices for natural gas production and increased gas deliveries
resulting from pipeline expansion projects, which more than offset warmer than
normal weather, were major factors in the year's results. Normal weather in the
Company's retail service areas in 1993 would have added about $.06 a share to
the $2.22 a share reported. Also, the recognition of 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 and reported as a
separate component of net income as the cumulative effect of the accounting
change, favorably impacted 1993 earnings. The effect, however, was partially
offset 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.
OPERATING REVENUES
Operating revenues include revenues from gas and oil sales, transportation of
gas, storage service, brokering activities, by-product operations and, beginning
in 1995, wholesale electric sales.
Total operating revenues in 1995 were $3,307.3 million, an increase of $271.3
million compared to 1994 operating revenues of $3,036.0 million. Regulated gas
sales revenues in 1995 decreased $81.9 million from 1994, to $1,597.4 million,
with sales volumes increasing 4.9 billion cubic feet (Bcf) to 289.9 Bcf. Colder
weather compared with 1994 led to the increase in sales volumes while lower unit
purchased gas costs reflected in revenues was responsible for the decline in
sales revenue. Nonregulated gas sales revenues increased $274.1 million in 1995,
with sales volumes increasing 223.8 Bcf over the 1994 period to 556.6 Bcf. These
increases were attributable to the growth of the Company's energy marketing
24
<PAGE> 27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
services component. The increased volumes sold more than offset the effects of
lower wellhead prices and production at the exploration and production
operations. Gas transportation and storage revenues were $456.4 million in 1995,
up $46.8 million over 1994. The increase was due principally to higher
transportation revenues, which increased $39.5 million due to both increased
volumes and rates. Other operating revenues increased $32.3 million in 1995 to
$255.8 million. The increase reflects wholesale sales of electricity of $21.8
million in 1995 by the energy marketing services component.
Total operating revenues in 1994 declined $148.1 million compared to 1993
operating revenues of $3,184.1 million. Regulated gas sales revenues were down
$393.9 million in 1994 primarily due to the abandonment by CNG Transmission
Corporation (CNG Transmission) of its traditional sales service with the
implementation of Federal Energy Regulatory Commission (FERC) Order 636 in
October 1993. Retail sales revenues were higher in 1994 as higher average sales
prices received from all customer classes more than offset a decline in gas
volumes sold resulting from the warmer weather in 1994. Nonregulated gas sales
revenues increased $181.8 million, representing a significant increase in
volumes sold due to a full year of operation at CNG Energy Services Corporation
(CNG Energy Services) partially offset by a decline in the average sales price.
Revenues from gas transportation and storage services rose $76.3 million
reflecting CNG Transmission's first full year of operations under FERC Order
636. Other operating revenues declined $12.3 million, primarily due to lower oil
sales volumes and prices.
OPERATING EXPENSES
Operating expenses, including taxes, increased 14 percent in 1995 to $3,160.8
million. Excluding the impact of the impairment of gas and oil producing
properties and the workforce reduction charges, operating expenses for 1995
would have been $2,990.2 million, up $215.1 million. Operating expenses in 1994
were $2,775.1 million, down 5 percent from $2,926.6 million in 1993.
Purchased gas consistently represents the largest operating expense item for the
Company. Purchased gas costs were $1,590.1 million in 1995, $1,424.0 million in
1994 and $1,594.4 million in 1993. This expense is 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. Total purchased gas
expense was higher in 1995 due primarily to increased volume requirements
associated with nonregulated gas sales. This factor more than offset lower unit
purchased gas costs, which reflected the nationwide decline in gas prices. Lower
spot market gas prices and lower recoveries of previously deferred gas costs by
the distribution subsidiaries, partially offset by increased volume
requirements, were the primary factors for the decline in 1994.
Transport capacity and other purchased products expense includes the cost of
pipeline capacity not associated with gas purchased and the cost of liquids,
by-products and, beginning in 1995, electricity purchased for resale. This
expense increased $46.5 million and $28.1 million in 1995 and 1994,
respectively, primarily due to increased transport capacity purchased from other
pipeline companies in both years, and electricity purchased for resale in 1995
totaling $19.6 million.
Excluding the $42.6 million of workforce reduction charges, combined operation
and maintenance expense increased $7.5 million in 1995. Higher customer-related
expenses, slightly higher overhead costs and the regulator-mandated adjustment
for certain previously deferred costs in connection with the settlement of CNG
Transmission's rate case were factors contributing to the $10.8 million increase
in operation expense. Lower royalties paid as a result of both lower gas
wellhead prices and production and the benefits of the workforce reduction
programs in the latter part of 1995 helped to minimize the increase. Maintenance
expense declined $3.3 million, to $85.9 million, in 1995.
Combined operation and maintenance expense increased $11.9 million in 1994, to
$689.6 million. The increase in operation expense of $9.9 million, to $600.4
million, was due principally to higher payroll
25
<PAGE> 28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
costs, including weather-related overtime during the unusually cold weather
early in 1994, and overhead costs. Maintenance expense was up $2.0 million, or 2
percent, to $89.2 million.
Total depreciation and amortization charges were down $22.7 million in 1995 and
$15.3 million in 1994 due to lower amortization charges for the Company's
exploration and production operations. Amortization of gas and oil producing
properties declined in 1995 primarily as the result of the lower investment
following the impairment of these properties in the first quarter. Reserve
additions and lower production also contributed to the lower charges in 1995,
and were the primary reasons for lower amortization charges in 1994.
Depreciation expense for the regulated subsidiaries was higher in both 1995 and
1994 due principally to the increased level of plant investment.
Taxes, other than income taxes, decreased $.9 million in 1995 due chiefly to
lower revenue-based taxes and increased $11.5 million in 1994 due in large part
to higher property taxes.
Income taxes decreased $79.4 million in 1995 compared to 1994 due mainly to
lower pretax earnings. Income taxes declined $17.5 million in 1994 compared to
the prior year primarily as a result of lower pretax earnings and an $11.4
million adjustment recorded in 1993 to deferred income tax expense due to the
increase in the federal corporate income tax rate. Reference is made to Note 7
to the consolidated financial statements for information on the effects of the
1993 increase in the federal corporate income tax rate.
OTHER INCOME
Excluding the write-down of coal properties of $31.3 million, 1995 other income
would have been $10.8 million, compared to $9.7 million in 1994 and $10.5
million in 1993. Interest revenues increased $4.1 million in 1995 due primarily
to the higher level of temporary cash investments during the year. Interest
revenues were $1.7 million higher in 1994, reflecting CNG Transmission's billing
of Order 636 transition costs in December 1993 and August 1994. Interest
revenues were up $1.5 million in 1993 due primarily to the recognition of
interest in connection with certain regulatory programs. The changes in
"Other-net" in the Consolidated Statement of Income reflect primarily the
differing levels of income recognized from the Company's external investments
and, in 1995, losses related to minor property dispositions at certain regulated
subsidiaries.
INTEREST CHARGES
Interest on long-term debt was up $7.0 million in 1995 due chiefly to interest
expense related to the $150 million of debentures issued in April 1995. Interest
on long-term debt increased $3.5 million in 1994, reflecting both a full year of
interest expense on debentures issued in 1993 and lower interest charges due to
redemptions and repayments of debenture borrowings in 1993. During 1993, the
Company called $266.2 million of its higher-cost borrowings, while issuing
$300.0 million of lower rate debentures. Other interest expense increased in
1995 as a result of higher interest rates on commercial paper borrowings. Other
interest expense increased in 1994 primarily due to higher interest on refund
obligations to customers. The amount of interest expense capitalized in 1995
declined from the level of the past two years due to the lower investment in
unproved properties held by the exploration and production operations.
FOURTH QUARTER RESULTS
The Company's net income for the fourth quarter of 1995 was $87.4 million
compared with $73.8 million earned in the 1994 fourth quarter, an increase of
$13.6 million. On a per share basis, the 1995 quarter was $.94 compared with
$.79 in 1994. The weather in the Company's retail service areas was 35 percent
colder than in the 1994 fourth quarter, while the Company's average gas wellhead
prices were up $.29
26
<PAGE> 29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
per thousand cubic feet (Mcf) compared with the 1994 fourth quarter. Proceeds
from the settlement of a major pipeline bankruptcy case and the effects of the
workforce reduction programs also contributed favorably to fourth quarter
results. These positive factors were partially offset by low gas margins, the
recognition of mark-to-market losses for storage-related futures contracts at
the energy marketing services component and the timing of certain discretionary
overhead expenses.
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------
QUARTERS ENDED DECEMBER 31, 1995 1994
- - ---------------------------------------------------------------------------------------------
(In Millions)
<S> <C> <C>
Operating revenues.................................................. $ 935.5 $ 788.6
Operating expenses.................................................. (775.0) (666.8)
Operating income before income taxes................................ 160.5 121.8
Income taxes........................................................ (44.6) (27.3)
Other income/expenses-net........................................... (28.5) (20.7)
------- -------
Net income.......................................................... $ 87.4 $ 73.8
======= =======
Per common share (in dollars)....................................... $.94 $.79
Average shares outstanding (thousands).............................. 93,442 93,026
- - ---------------------------------------------------------------------------------------------
</TABLE>
NEW ACCOUNTING STANDARDS
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." This standard is effective for fiscal years beginning
after December 15, 1995, and the Company will adopt the standard effective
January 1, 1996. The adoption is not expected to have a material effect on the
Company's financial position, results of operations or cash flows. Reference is
made to Note 1 to the consolidated financial statements, page 47, regarding this
new standard.
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation." Although the Company does not anticipate changing its accounting
method for stock-based compensation as a result of this new standard, the
disclosure requirements of SFAS No. 123 are effective for financial statements
for fiscal years beginning after December 15, 1995. Reference is made to Note 1
to the consolidated financial statements, page 48, regarding SFAS No. 123.
COMPONENTS OF THE BUSINESS
Due to the regulated nature of the distribution and transmission components of
the Company'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 operations. 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.
The following presents the operating results for each of the Company's business
components. Reference is made to Note 18 to the consolidated financial
statements, page 65, for additional disaggregated information pertaining to the
Company's operations.
27
<PAGE> 30
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OPERATING INCOME BEFORE INCOME TAXES
Operating income before income taxes for the Company's business components for
the last three years is shown in the table below.
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
OPERATING INCOME BEFORE INCOME TAXES 1995* 1994 1993
- - ----------------------------------------------------------------------------------------------
(In Millions)
<S> <C> <C> <C>
Distribution.............................................. $ 207.5 $159.0 $166.9
Transmission.............................................. 150.4 146.3 143.4
Exploration and production................................ (200.5) 34.0 47.3
Energy marketing services................................. (5.7) -- --
Other**................................................... 2.9 7.6 5.7
Corporate and eliminations................................ (5.1) (3.5) (6.0)
------- ------ ------
Total................................................ $ 149.5 $343.4 $357.3
======= ====== ======
- - ----------------------------------------------------------------------------------------------
<FN>
* Amount for the exploration and production operations includes the impact of
the write-down of gas and oil producing properties amounting to $226.2
million. Amounts for the distribution, transmission, exploration and
production, energy marketing services and corporate components include the
effect of workforce reduction charges totaling $22.3 million, $6.0 million,
$7.7 million, $.5 million and $4.6 million, respectively.
** Includes Consolidated LNG, CNG Research and CNG Coal. CNG Energy Services and
CNG Power (formerly CNG Energy) are included in the 1993 and 1994 amounts.
CNG Power Services is also included in the 1994 amount.
</TABLE>
DISTRIBUTION
"Distribution" represents the results of the five retail gas distribution
subsidiaries, including their minor gas and oil production activities.
Sales growth in the Company'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. (Virginia
Natural Gas), due to customer conversions from other energy sources and the past
and potential future expansion of its service territory. Since the Company'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 the other
distribution subsidiaries.
OPERATING INCOME BEFORE INCOME TAXES
Operating income before income taxes for the gas distribution operations was
$207.5 million in 1995, up $48.5 million from 1994. Excluding workforce
reduction charges amounting to $22.3 million, operating income for 1995 would
have been $229.8 million. In addition to the general rate increases placed into
effect in late 1994 and in 1995 at four of the distribution subsidiaries (see
"State Regulatory Issues"), colder weather, the addition of new customers,
higher transport volumes and lower wage and benefit costs in the latter part of
the year due to the workforce reduction programs contributed favorably to 1995
results. Overall, weather in the Company's retail service territories was 2
percent colder than 1994, but was 1 percent warmer than normal.
Operating income before income taxes for the gas distribution operations
declined $7.9 million in 1994, to $159.0 million. Warmer weather and higher
costs of operations were the principal reasons for the decline. Overall, weather
in the Company's retail service area was 3 percent warmer than 1993 and 4
percent warmer than normal. The higher operating costs were addressed in rate
filings made by the subsidiaries during the year. Two subsidiaries were granted
rate increases and another began collecting higher rates,
28
<PAGE> 31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
subject to refund. However, the increases were placed into effect in the latter
part of the year and did not have a significant impact on 1994 results.
The net addition of about 17,800 residential and commercial gas sales customers,
a minor increase in throughput, 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 operating results, but were offset by higher costs
of operations.
OPERATING REVENUES
Operating revenues of the gas distribution operations in 1995 declined $60.4
million from the prior year. Gas sales revenues declined $81.0 million as lower
average sales prices more than offset the impact of higher sales volumes. The
lower average sales prices were the result of lower unit purchased gas costs
reflected in the rates charged to customers. Rate increases in late 1994 and in
1995 (see "State Regulatory Issues"), however, helped hold down the decline in
sales revenues. Gas transportation and storage revenues increased $20.4 million
in 1995 due to both increased volumes and rates.
Revenues of the gas distribution operations rose $31.7 million in 1994, a 2
percent increase compared with 1993. Gas sales revenues rose $23.6 million due
to increases in the average sales price received from residential and commercial
customers, partially offset by reduced sales volumes due to warmer than normal
weather. Gas sales were impacted by general rate increases placed into effect in
the latter part of the year at three of the distribution subsidiaries and the
full year impact of a general rate increase that went into effect in late 1993
at Hope Gas, Inc. (Hope Gas). Gas transportation and storage revenues were up
$6.5 million, reflecting increased transportation volumes, while other operating
revenues increased $1.6 million.
DISTRIBUTION THROUGHPUT
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. In addition to sales service, the distribution operations provide
gas transportation services to a wide range of customers, primarily commercial
and industrial end users. Therefore, the volume of gas transported can be
affected by changes in both economic and market conditions.
<TABLE>
<CAPTION>
- - -----------------------------------------------------------------------------------------------
DISTRIBUTION THROUGHPUT 1995 1994 1993
- - -----------------------------------------------------------------------------------------------
(In Billion Cubic Feet)
<S> <C> <C> <C>
Sales......................................................... 289.9 285.0 297.8
Transportation................................................ 164.8 151.1 145.4
----- ----- -----
Throughput............................................... 454.7 436.1 443.2
===== ===== =====
- - -----------------------------------------------------------------------------------------------
</TABLE>
Gas sales volumes were up 2 percent in 1995, reflecting colder weather and the
net addition of about 24,800 residential and commercial customers. Residential
and commercial gas sales increased 6.6 Bcf and .4 Bcf, respectively, compared to
1994. While industrial sales volumes declined 2.1 Bcf, transportation volumes to
those customers increased 9.8 Bcf. Gas transported for commercial customers was
29.8 Bcf in 1995, up 5.4 Bcf compared to 1994. Transportation to off-system
customers declined 1.5 Bcf in 1995.
Warmer weather was the primary factor in the decline in gas sales during 1994,
while transportation volumes were up 4 percent. Although the impact was
partially offset by the net addition of about 22,500 customers, the weather was
3 percent warmer than in 1993, resulting in lower space-heating sales.
Residential and commercial gas sales volumes declined by 6.4 Bcf and 3.3 Bcf,
respectively, compared
29
<PAGE> 32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
to 1993. Industrial sales volumes were down 3.1 Bcf to 9.4 Bcf, while
transportation volumes were up 5.2 Bcf to 121.1 Bcf. Gas transported for
commercial customers was 24.4 Bcf in 1994, up 3.3 Bcf, while transportation to
off-system customers declined 2.8 Bcf to 5.6 Bcf in 1994.
TRANSMISSION
"Transmission" includes the results of the gas transmission, storage, by-product
and certain other activities of CNG Transmission and, prior to April 1, 1995,
the activities of CNG Storage Service Company (CNG Storage). CNG Storage was
formed primarily to engage in the sale, lease or brokerage of gas storage
capacity obtained from third parties including the sale or lease of base gas.
The results of CNG Storage for 1995 and prior periods were not a significant
portion of the transmission operations. Gas and oil production activities of CNG
Transmission are included in exploration and production operations.
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 CNG Transmission 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.
With its implementation of Order 636 effective October 1, 1993, 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. 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.
OPERATING INCOME BEFORE INCOME TAXES
Operating income before income taxes of the gas transmission operations
increased $4.1 million in 1995 to $150.4 million. Excluding workforce reduction
charges totaling $6.0 million, operating income before income taxes for 1995
would have been $156.4 million. Higher rates resulting from CNG Transmission's
latest general rate filing and cost controls were the major factors for the
improved results in 1995.
Operating income before income taxes increased $2.9 million, or 2 percent, in
1994 to $146.3 million. Operating results for 1994 reflect the first full year
of applying the straight fixed variable rate design under which operating income
is less influenced by changes in throughput than in the past. Significant
factors affecting 1994 operating results included increased transportation and
storage service revenues, competition from other pipelines, and higher operating
costs not yet reflected in rates.
Operating results for 1993 include the impact of 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 and, to a lesser extent,
sales of gas from storage inventory and certain other steps taken to facilitate
the transition to Order 636 also contributed to the 1993 results.
OPERATING REVENUES
Total operating revenues of the gas transmission operations increased $11.7
million in 1995 to $471.0 million. Gas transportation and storage revenues
increased $27.4 million in 1995 due primarily to higher transportation revenues,
which increased $24.3 million as higher rates more than offset slightly lower
transport volumes. Revenues from the sale of by-products declined $10.2 million,
due to the overall decline in volumes of products sold.
30
<PAGE> 33
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Total operating revenues declined by $524.5 million in 1994 to $459.3 million.
CNG Transmission abandoned its traditional sales service pursuant to the October
1, 1993 implementation of Order 636. Gas sales revenues in 1993 were $631.1
million. Increases during 1994 in transportation and storage service revenues of
$92.9 million and $22.9 million, respectively, reflected the impact of the first
full year of services provided under Order 636. Revenues from the sale of
by-products declined by $1.4 million in 1994 as a result of lower prices.
TRANSMISSION THROUGHPUT
The changing regulatory environment has 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 the Company'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.
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. Also, transmission operations provide 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.
<TABLE>
<CAPTION>
- - -----------------------------------------------------------------------------------------------
TRANSMISSION THROUGHPUT 1995 1994 1993
- - -----------------------------------------------------------------------------------------------
(In Billion Cubic Feet)
<S> <C> <C> <C>
Sales......................................................... -- -- 100.1
Transportation................................................ 744.0 748.4 610.9
----- ----- -----
Throughput*.............................................. 744.0 748.4 711.0
===== ===== =====
- - -----------------------------------------------------------------------------------------------
<FN>
* Includes intercompany activity.
</TABLE>
Total throughput for the gas transmission operations, consisting entirely of
transportation volumes, was 744.0 Bcf in 1995, down slightly compared with 1994.
First quarter 1995 throughput was lower than the prior year due to warmer
weather in that period, while throughput was up for the balance of 1995 compared
to 1994.
The Company's transmission operations total throughput of 748.4 Bcf in 1994
exceeded 1993's record throughput level by 5 percent. The 1994 throughput
consisted solely of transportation volumes as CNG Transmission abandoned its
traditional sales service with the October 1, 1993 implementation of Order 636.
The increase of 137.5 Bcf of transportation volumes compared to 1993 occurred
mainly in the first quarter of 1994 consistent with the cold weather experienced
early in the year.
EXPLORATION AND PRODUCTION
"Exploration and production" includes the results of CNG Producing Company (CNG
Producing) and the gas and oil production activities of CNG Transmission.
OPERATING INCOME BEFORE INCOME TAXES
The exploration and production operations reported an operating loss before
income taxes of $200.5 million in 1995, compared with operating income before
income taxes of $34.0 million in 1994.
31
<PAGE> 34
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
The loss for 1995 reflects the first quarter non-cash charge of $226.2 million
for the impairment of gas and oil producing properties and workforce reduction
charges during 1995 totaling $7.7 million. Excluding these special items,
operating income before income taxes would have been $33.4 million in 1995. The
impact of continued low gas wellhead prices and lower gas and oil production
slightly offset the favorable impact of higher oil wellhead prices, a $7.5
million reduction in production-related expenses, and reductions in overhead
costs in 1995. In addition, depreciation and amortization expense was $32.1
million lower in 1995 resulting from the impairment of gas and oil producing
properties, the effect of gas and oil reserve additions, and lower production.
Reserves equivalent to 203 Bcf of gas were added in 1995.
Exploration and production operating income before income taxes in 1994
decreased $13.3 million compared to 1993. The effect of the decline in total
operating revenues due to lower prices and production was partially offset by
decreases in royalty expense and depreciation and amortization of $9.4 million
and $21.2 million, respectively. The lower level of royalty expense is
attributable primarily to reduced gas and oil production during 1994. Lower
production, together with the recognition of additional proved gas and oil
reserves in the Gulf of Mexico, resulted in lower depreciation and amortization
expense for 1994. Reserves equivalent to 190 Bcf of gas at Viosca Knoll 826, a
deep-water project in the Gulf of Mexico in which the Company holds a 50 percent
interest, were added in 1994 and represent the largest single addition of
reserves in the Company's history.
In 1993, operating income was $47.3 million, up $8.5 million, as higher wellhead
prices for natural gas and slightly higher gas production more than offset lower
oil prices and production and lower margins on the brokering of gas.
GAS AND OIL PRODUCTION AND PRICES
The following table sets forth the Company's gas and oil production and average
wellhead prices for the exploration and production operations for the last three
years:
<TABLE>
<CAPTION>
- - ------------------------------------------------------------------------------------------------
PRODUCTION 1995 1994 1993
- - ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
GAS (BCF)
Nonregulated............................................. 102.6 113.7 123.5
Regulated*............................................... 4.6 5.8 6.0
------- ------- -------
Total.................................................. 107.2 119.5 129.5
======= ======= =======
OIL (000 BBLS)
Nonregulated............................................. 3,131.7 3,333.0 3,906.8
Regulated*............................................... 17.2 23.8 29.1
------- ------- -------
Total.................................................. 3,148.9 3,356.8 3,935.9
======= ======= =======
AVERAGE WELLHEAD PRICES
(NONREGULATED ONLY)
Gas (per Mcf)............................................ $ 1.89 $ 2.16 $ 2.24
Oil (per Bbl)............................................ $16.04 $14.45 $15.66
- - ------------------------------------------------------------------------------------------------
<FN>
* Cost-of-service.
</TABLE>
Consistent with prices nationwide, the Company's gas wellhead prices in 1995
were below prior year levels for most of the period as the average gas price of
$1.89 per Mcf was $.27 less than the 1994 price. As a result of continued weak
gas prices, the Company voluntarily shut in a portion of its production at
various times during 1995 which, in addition to normal declines at certain
properties, resulted in a decline in production compared to 1994. While average
oil wellhead prices rose $1.59 per barrel in 1995, oil production was lower than
1994 due primarily to normal production declines at older properties.
32
<PAGE> 35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Gas wellhead prices were strong in the first quarter of 1994 but declined and
remained considerably below 1993 levels for most of the balance of 1994. The
Company's average gas price was $2.16 per Mcf in 1994, down $.08 from 1993. The
low prices for natural gas that prevailed nationwide during most of 1994 were
the basis for the Company's decision to shut in a portion of its offshore
production during the latter part of the year, resulting in lower gas production
for the year. The Company's average oil price declined 8 percent in 1994,
consistent with the continued overall decline in world oil prices. The lower oil
production during 1994 was due largely to normal production declines at older
properties, in addition to the partial shut-in of production.
OPERATING REVENUES
Total operating revenues for the exploration and production operations decreased
$127.9 million in 1995, to $361.5 million. Gas sales revenues declined $134.0
million, reflecting the continued low level of gas wellhead prices and lower
production compared to 1994. Revenues from oil and condensate production and
brokering increased $10.5 million in 1995. Revenues from oil brokering were up
$8.8 million due to both higher volumes sold and higher rates, while revenues
from oil and condensate production were up $1.7 million as higher rates more
than offset the effect of lower volumes.
Total operating revenues declined $47.0 million in 1994. Gas sales revenues
decreased $23.0 million primarily due to lower prices received during 1994. Gas
sales volumes were flat compared with 1993 as lower sales of produced gas were
offset by an increase in brokered gas volumes. Oil and condensate revenues were
down $20.3 million which reflected lower volumes and prices for both oil
production and brokering activities. Revenues from oil and condensate production
decreased $13.2 million, while revenues from oil brokering were down $7.1
million. Other revenues declined $3.7 million due principally to business
interruption insurance reimbursements related to Hurricane Andrew received in
1993.
ENERGY MARKETING SERVICES
"Energy marketing services" represents the results of CNG Energy Services, CNG
Power Company (CNG Power), CNG Power Services Corporation (CNG Power Services),
and CNG Storage. These subsidiaries, which are under a single management team,
were reported as one business component in 1995. The results for these
subsidiaries, except CNG Storage, were included in the "Other" component prior
to 1995. CNG Storage was included in the "Transmission" component prior to April
1,1995.
CNG Energy Services markets Company-owned gas production and arranges gas
supplies, transportation, storage and related services for customers. CNG Power
holds the Company's ownership interests in seven independent power plants. CNG
Power Services purchases and resells electricity at market-based rates.
Energy marketing services reported an operating loss before income taxes of $5.7
million in 1995, which includes workforce reduction charges of $.5 million. In
addition to depressed gas margins throughout the year, CNG Energy Services
recognized a $5.3 million pretax charge in December 1995 in connection with a
mark-to-market valuation of exchange-traded futures contracts used to manage
price risk exposure related to its stored gas inventories. However, income from
the physical sale of gas from storage in 1996 is expected to generally offset
the effect of this charge. Total throughput for this component was 570.8 Bcf in
1995. Income recognized in connection with CNG Power's investments in 1995
totaled $3.9 million. This amount is not included in the operating loss before
income taxes but is reflected in "Other income" for the component.
33
<PAGE> 36
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).
Due primarily to the decline in wellhead gas prices, the Company was required
under the SEC full cost rules to recognize an impairment of its gas and oil
producing properties at March 31, 1995. The non-cash charge amounted to $226.2
million and reduced 1995 net income by $145.0 million. No additional impairment
of these properties was required during the remainder of 1995.
There are a number of factors, including prices, that determine whether or not
an impairment is required. Gas wellhead prices were strong during the fourth
quarter of 1995, and continued to be firm in the early part of 1996 due
primarily to higher demand caused by the colder weather and reduced storage
inventory levels. 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.
INTERNATIONAL ACTIVITIES
In November 1994, CNG Energy Services formed a marketing alliance with two
Canadian firms, Hydro-Quebec and Noverco. The alliance offers energy services to
customers throughout the northeastern and midwestern United States and eastern
Canada. In June 1995, the companies signed an agreement to create a
partnership--the Energy Alliance Partnership--to conduct alliance business. This
agreement is subject to SEC and other regulatory approvals.
In November 1995, the Company announced the formation of a strategic alliance
with EnergyAustralia (formerly known as MetNorth Energy), Australia's largest
electric utility, to assist EnergyAustralia in developing its natural gas
marketing capabilities and to jointly identify and develop energy infrastructure
projects in Australia and Asia.
In January 1996, the Company formed a new subsidiary, CNG International
Corporation (CNG International). The purpose of CNG International is to engage
in energy-related activities outside the United States, including activities
under the EnergyAustralia alliance. The financing of CNG International is
subject to SEC approval.
FEDERAL AND STATE REGULATORY MATTERS
FERC ORDER 636
FERC Order 636, issued in 1992, 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 costs 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. With FERC approval,
CNG Transmission direct billed and began collecting transition costs amounting
to $177.9 million and $9.8 million in December 1993 and August 1994,
34
<PAGE> 37
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
respectively. During 1995, CNG Transmission made refunds to its customers and
affiliates of $9.1 million in connection with the prior direct billings.
As part of the Settlement, CNG Transmission agreed to absorb up to $3.5 million
of GSR costs. GSR costs, however, have been minimized since certain of the
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 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. In its December 30,
1993, general rate filing with the FERC, CNG Transmission requested recovery of
$9.2 million of stranded facilities costs, but subsequently reduced that amount
to $4.3 million to reflect actual amounts incurred. In a December 30, 1994
filing, CNG Transmission requested recovery of an additional $.7 million of
stranded upstream transportation service costs. The recovery of these stranded
costs was included in the settlement agreement approved by the FERC on November
29, 1995 regarding its December 30, 1993 general rate filing.
Although a final overall estimate of new facilities costs to be incurred by CNG
Transmission has not yet been determined, such costs may approach $30 million.
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. Reference is made to Note 2 to the consolidated
financial statements for additional information regarding Order 636 transition
costs.
CNG TRANSMISSION
On November 29, 1995, the FERC approved a settlement agreement filed by CNG
Transmission in connection with its December 30, 1993 general rate filing. The
settlement resolves the outstanding issues in the case and results in an annual
revenue increase of $40 million, retroactive to July 1, 1994, the date new rates
went into effect subject to refund. The settlement reflects an imputed return on
equity of 11.30 percent. Customer refunds resulting from the settlement totaling
$81.5 million were made in December 1995 with an additional $4.8 million
expected to be refunded in the first quarter of 1996. In its filing, CNG
Transmission had requested a $106.6 million increase in annual revenues and a
return on equity of 14.00 percent.
STATE REGULATORY ISSUES
On August 3, 1995, the Pennsylvania Public Utility Commission approved a
settlement agreement filed by Peoples Natural Gas covering its February 1, 1995
general rate filing. The approved settlement includes an $8.0 million annual
revenue increase with new rates effective August 4, 1995. In its filing, Peoples
Natural Gas had originally requested a $32.8 million increase in annual
revenues.
On September 1, 1995, Virginia Natural Gas submitted an expedited rate filing
with the Virginia State Corporation Commission (VSCC) requesting an annual
revenue increase of $7.2 million. The new rates went into effect, subject to
refund, on October 1, 1995. On February 23, 1996, Virginia Natural Gas requested
approval from the VSCC to withdraw this rate filing. Pending VSCC approval,
customer refunds related to the filing will be made later in 1996.
On October 26, 1995, the Public Service Commission of West Virginia approved a
settlement agreement filed by Hope Gas in connection with its January 4, 1995
general rate filing. The new rates became effective November 1, 1995. The
approved settlement agreement increased base rates but eliminated
35
<PAGE> 38
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
the purchased gas cost adjustment mechanism for the three-year period covered by
the settlement. Therefore, any increase or decrease in gas costs over the base
amount included in rates will not be passed on to customers during the
settlement period.
On November 8, 1995, a $6.2 million annual revenue increase became effective at
The East Ohio Gas Company in connection with the November 3, 1994 settlement of
its general rate case, as approved by the Public Utilities Commission of Ohio.
This increase is in addition to the $62.4 million annual revenue increase that
became effective November 8, 1994.
On January 30, 1996, the VSCC issued a final order in connection with Virginia
Natural Gas' September 1, 1994 general rate filing. The order results in an
annual revenue increase of $6.1 million, retroactive to October 1, 1994, the
date new rates went into effect subject to refund. Customer refunds resulting
from the order will be made in the first half of 1996. The order reflects an
imputed return on equity of 11.3 percent. In its filing, Virginia Natural Gas
had requested a $9.9 million increase in annual revenues and a return on equity
of 11.75 percent.
ENVIRONMENTAL MATTERS
The Company is 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 subsidiaries, or their predecessors.
Reference is made to Note 16 to the consolidated financial statements, page 63,
for a detailed description of environmental matters.
Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature of
environmental issues which 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. However, the amount of any such liabilities
could be material.
EFFECTS OF INFLATION
Although inflation rates have been moderate in recent years, any change in price
levels has an effect on operating results due to the capital intensive and
regulated nature of the Company's major business components. The Company
attempts to minimize the effects of inflation through cost control, productivity
improvements and regulatory actions where appropriate.
FINANCIAL CONDITION
DIVIDEND AND COMMON STOCK MATTERS
In December 1995, the Board of Directors continued the quarterly dividend on the
common stock at 48.5 cents a share. Total dividends paid to common shareholders
in 1995 were $180.8 million compared with $180.4 million in 1994 and $178.1
million in 1993.
During 1995, a total of 567,818 original issue shares were issued through
various Company-sponsored plans, including 216,766 shares acquired by employees
through the exercise of outstanding stock options.
Under the Company's stock repurchase plan, up to 4 million shares of the
outstanding common stock can be repurchased. The shares may be purchased in the
open market from time-to-time, depending on
36
<PAGE> 39
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
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, 1994. During 1995, no open market purchases were made by the
Company. The Company acquired 17,351 shares in 1995 through the provisions of
its employee incentive plans at a cost of $634,000, or an average price of
$36.54 a share. All of these shares were sold before year-end to the Company's
Thrift Plans.
CAPITAL SPENDING
The current capital budget for 1996 is estimated at $455.2 million, a 4 percent
increase compared with total capital spending in 1995. The estimated 1996 budget
has been allocated as follows: distribution, $147.6 million; transmission, $89.3
million; exploration and production, $180.6 million; energy marketing services,
$33.2 million; and corporate and other, $4.5 million. The increased level of
capital expenditures anticipated for 1996 reflects slightly higher spending for
exploration and production operations, including funds for development of Viosca
Knoll 826, the Company's second deep-water project in the Gulf of Mexico.
Transmission and distribution operations expenditures will primarily be limited
to spending for enhancements and improvements in the pipeline system and related
facilities. Expenditures for the energy marketing services component include
funds for the development, through partnerships with other energy companies, of
offshore gas and oil gathering systems for two production areas in the Gulf of
Mexico. The "corporate and other" category includes expenditures to upgrade
information systems technology.
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. Although the Company does not expect to require long-term financing
in 1996 to support capital spending, it may turn to the market to take advantage
of other opportunities and to increase its financial flexibility.
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 realized in the first
half of the year. However, cash requirements for capital expenditures,
dividends, debt retirements and other working capital needs 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 Consolidated Statement of Cash Flows, net cash
provided by operating activities was $552.7 million, $631.3 million and $470.9
million for the years 1995, 1994 and 1993, respectively. Lower gas wellhead
prices and rate-related refunds made to customers were the principal reasons for
the lower cash flows from operations in 1995. Higher rates put into effect at
CNG Transmission during the year and the recovery of Order 636 transition costs
contributed to the increase in operating cash flows in 1994.
During April 1995, the Company sold $150 million of 7 3/8% Debentures Due April
1, 2005. The net proceeds from the sale were used to finance, in part, 1995
capital expenditures and to reduce short-term debt.
The Company has shelf registrations with the SEC for the sale of up to $350
million of debt securities. The amount and timing of any future sale of these
debt securities will depend primarily on the ability of the Company to issue
senior debt under the financing restrictions contained in the Company's
indentures (see Note 13 to the consolidated financial statements, page 61,
regarding these restrictions). Any future sale will also depend on capital
requirements, including financing necessary to enable the Company to pursue
asset acquisition opportunities, and financial market conditions.
37
<PAGE> 40
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Concluded)
The Company's embedded long-term debt cost, excluding current maturities, at
year-end 1995 was 7.69 percent, compared with 7.74 percent for 1994 and 7.75
percent for 1993. The long-term debt to capitalization ratio was 38.7 percent at
the end of 1995, and 34.5 percent and 34.7 percent at year-end 1994 and 1993,
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.
At December 31, 1995, the Company had two short-term credit agreements with
groups of banks, for $475 million and $300 million, which replaced prior credit
agreements effective June 30, 1995. The Company made no borrowings under these
agreements during 1995 and there were no amounts outstanding under any credit
agreements at December 31, 1995 or 1994.
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 1995, of which $336 million was outstanding at
year-end. The Company may utilize unused portions of its credit agreements to
provide support for commercial paper notes.
In the normal course of business, the nonregulated subsidiaries utilize
exchange-traded commodity futures and options contracts and derivative financial
instruments to manage exposure to price risk in connection with the production,
purchase and sale of natural gas and oil, and for stored gas inventories. The
use of futures and options contracts and derivative financial instruments
exposes the Company to market risk and credit risk. Market risk represents the
potential loss that can be caused by a change in the market value of a
particular commitment. Although the use of exchange-traded and over-the-counter
instruments generally reduces market risk exposure due to unfavorable price
fluctuations, risk management activities, while not significant, can result in
the assumption of a limited degree of price risk in certain isolated
transactions. Credit risk relates to the risk of loss that the Company would
incur as a result of nonperformance by counterparties pursuant to the terms of
their contractual obligations. The Company does not have a significant exposure
to any individual counterparty to its energy price risk management activities.
Management has operating procedures in place to evaluate market and credit risks
and believes that the Company's exposure to risks associated with
exchange-traded futures and options contracts and derivative financial
instruments is not material in relation to the Company's financial position,
results of operations or cash flows. Reference is made to Notes 1 and 15 to the
consolidated financial statements, pages 45 and 62, regarding energy price risk
management activities.
SUMMARY OF FINANCIAL DATA
The Company's Summary of Financial Data is on page 23.
38
<PAGE> 41
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
19(A), page 68; Quarterly Financial Data-- Note 19(B), page 72.
FINANCIAL STATEMENTS
INDEX
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------------------
Page
- - --------------------------------------------------------------------------------------------
<S> <C>
Report of Independent Accountants............................................... 40
Consolidated Statement of Income for the Years 1993 through 1995................ 41
Consolidated Balance Sheet at December 31, 1994 and 1995........................ 42
Consolidated Statement of Cash Flows for the Years 1993 through 1995............ 44
Notes to Consolidated Financial Statements...................................... 45
Schedule II--Valuation and Qualifying Accounts.................................. Note 2
<FN>
Notes:
(1) Schedules I, III, IV, and V have been excluded because they are not
applicable.
(2) Omitted inasmuch as amounts involved are not significant.
- - --------------------------------------------------------------------------------------------
</TABLE>
39
<PAGE> 42
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 39 present fairly, in all material respects, the financial
position of Consolidated Natural Gas Company and subsidiaries (the Company) at
December 31, 1995 and 1994, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1995, 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. 109, "Accounting for
Income Taxes," in 1993.
PRICE WATERHOUSE LLP
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
February 20, 1996
40
<PAGE> 43
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1995 1994 1993
- - ---------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
OPERATING REVENUES
Regulated gas sales.......................................... $1,597,379 $1,679,235 $2,073,187
Nonregulated gas sales....................................... 997,724 723,626 541,849
---------- ---------- ----------
Total gas sales.......................................... 2,595,103 2,402,861 2,615,036
Gas transportation and storage............................... 456,370 409,632 333,332
Other........................................................ 255,852 223,535 235,717
---------- ---------- ----------
Total operating revenues (Note 2)........................ 3,307,325 3,036,028 3,184,085
---------- ---------- ----------
OPERATING EXPENSES
Purchased gas................................................ 1,590,137 1,424,020 1,594,373
Transport capacity and other purchased products.............. 153,577 107,094 79,001
Operation expense (Note 4)................................... 653,731 600,421 590,459
Maintenance.................................................. 85,881 89,154 87,207
Depreciation and amortization (Note 3)....................... 256,636 279,317 294,648
Impairment of gas and oil producing properties (Note 3)...... 226,209 -- --
Taxes, other than income taxes............................... 191,698 192,617 181,053
---------- ---------- ----------
Subtotal................................................. 3,157,869 2,692,623 2,826,741
---------- ---------- ----------
Operating income before income taxes..................... 149,456 343,405 357,344
Income taxes (Note 7)........................................ 2,943 82,427 99,906
---------- ---------- ----------
Operating income......................................... 146,513 260,978 257,438
---------- ---------- ----------
OTHER INCOME (DEDUCTIONS)
Interest revenues............................................ 9,095 5,006 3,317
Write-down of coal properties (Note 3)....................... (31,266) -- --
Other-net.................................................... 1,665 4,688 7,214
---------- ---------- ----------
Total other income (deductions).......................... (20,506) 9,694 10,531
---------- ---------- ----------
Income before interest charges........................... 126,007 270,672 267,969
---------- ---------- ----------
INTEREST CHARGES
Interest on long-term debt................................... 95,823 88,788 85,265
Other interest expense....................................... 14,732 7,992 4,995
Allowance for funds used during construction................. (5,892) (9,279) (10,785)
---------- ---------- ----------
Total interest charges................................... 104,663 87,501 79,475
---------- ---------- ----------
Income before cumulative effect of change
in accounting principle.................................... 21,344 183,171 188,494
Cumulative effect of applying SFAS No. 109 (Note 7).......... -- -- 17,422
---------- ---------- ----------
NET INCOME................................................... $ 21,344 $ 183,171 $ 205,916
========= ========= =========
Earnings per share of common stock
Income before cumulative effect of change
in accounting principle.............................. $.23 $1.97 $2.03
Cumulative effect of applying SFAS No. 109 (Note 7).... -- -- .19
---------- ---------- ----------
Net Income............................................. $.23 $1.97 $2.22
========= ========= =========
Average common shares outstanding (thousands)............ 93,246 93,000 92,808
<FN>
- - ---------------------------------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
41
<PAGE> 44
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
At December 31, 1995 1994
- - ----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Note 3)
Gas utility and other plant.................................... $ 4,710,086 $ 4,546,753
Accumulated depreciation and amortization...................... (1,785,965) (1,686,788)
----------- -----------
Net gas utility and other plant......................... 2,924,121 2,859,965
----------- -----------
Exploration and production properties.......................... 3,219,264 3,130,203
Accumulated depreciation and amortization...................... (2,230,980) (1,963,522)
----------- -----------
Net exploration and production properties............... 988,284 1,166,681
----------- -----------
Net property, plant and equipment....................... 3,912,405 4,026,646
----------- -----------
CURRENT ASSETS
Cash and temporary cash investments............................ 36,277 31,923
Accounts receivable
Customers.................................................... 522,391 407,145
Unbilled revenues and other.................................. 144,253 146,653
Allowance for doubtful accounts.............................. (10,306) (7,507)
Inventories, at cost
Gas stored--current portion (Note 8)......................... 112,429 190,196
Materials and supplies (average cost method)................. 35,815 35,072
Unrecovered gas costs (Note 2)................................. 25,123 13,135
Deferred income taxes--current (Note 7)........................ 20,993 60,103
Prepayments and other current assets........................... 181,686 188,019
----------- -----------
Total current assets.................................... 1,068,661 1,064,739
----------- -----------
REGULATORY AND OTHER ASSETS
Unamortized abandoned facilities (Note 9)...................... 28,672 40,955
Other investments.............................................. 60,939 54,682
Deferred charges and other assets (Notes 2, 4, 6, 7 and 16).... 347,616 331,651
----------- -----------
Total regulatory and other assets....................... 437,227 427,288
----------- -----------
Total assets............................................ $ 5,418,293 $ 5,518,673
=========== ===========
<FN>
- - ----------------------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
42
<PAGE> 45
ITEM 8.
(Cont.)
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
At December 31, 1995 1994
- - ----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
STOCKHOLDERS' EQUITY AND LIABILITIES
CAPITALIZATION
Common stockholders' equity (Note 10)
Common stock, par value $2.75 per share,
200,000,000 authorized shares
Issued, 1995--93,591,623 shares, 1994--93,027,847
shares.................................................... $ 257,377 $ 255,827
Capital in excess of par value............................... 478,535 458,628
Retained earnings (Note 12).................................. 1,309,906 1,469,879
----------- -----------
Total common stockholders' equity....................... 2,045,818 2,184,334
Long-term debt (Note 13)....................................... 1,291,811 1,151,973
----------- -----------
Total capitalization.................................... 3,337,629 3,336,307
----------- -----------
CURRENT LIABILITIES
Current maturities on long-term debt........................... 10,250 4,000
Commercial paper (Note 14)..................................... 336,000 440,000
Accounts payable............................................... 410,296 357,611
Estimated rate contingencies and refunds (Note 2).............. 59,363 83,404
Amounts payable to customers................................... 40,315 96,140
Taxes accrued.................................................. 114,335 94,413
Dividends declared............................................. 45,392 45,119
Other current liabilities...................................... 95,339 90,061
----------- -----------
Total current liabilities............................... 1,111,290 1,210,748
----------- -----------
DEFERRED CREDITS
Deferred income taxes (Note 7)................................. 672,266 758,633
Accumulated deferred investment tax credits.................... 31,031 33,229
Deferred credits and other liabilities (Note 7)................ 266,077 179,756
----------- -----------
Total deferred credits.................................. 969,374 971,618
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 17)
----------- -----------
Total stockholders' equity and liabilities.............. $ 5,418,293 $ 5,518,673
=========== ===========
- - ----------------------------------------------------------------------------------------------
</TABLE>
43
<PAGE> 46
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1995 1994 1993
- - ---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income................................................ $ 21,344 $ 183,171 $ 205,916
Adjustments to reconcile net income to net cash
provided by operating activities
Cumulative effect of applying SFAS No. 109............ -- -- (17,422)
Depreciation and amortization......................... 256,636 279,317 294,648
Impairment of gas and oil producing properties........ 226,209 -- --
Write-down of coal properties......................... 31,266 -- --
Deferred income taxes-net............................. (48,767) (60,744) (19,782)
Investment tax credit................................. (2,198) (2,567) (2,620)
Changes in current assets and current liabilities
Accounts receivable-net............................ (116,529) 81,896 (107,292)
Inventories........................................ 77,024 (48,566) (22,212)
Unrecovered gas costs.............................. (11,988) 5,467 249,549
Accounts payable................................... 69,761 11,198 13,831
Estimated rate contingencies and refunds........... (24,041) 25,948 (21,930)
Amounts payable to customers....................... (55,825) 68,538 24,393
Taxes accrued...................................... 19,922 (17,685) 16,909
Other-net.......................................... 13,643 (2,901) (5,022)
Changes in other assets and other liabilities......... 92,553 108,219 (137,571)
Other-net............................................. 3,714 37 (446)
--------- --------- ---------
Net cash provided by operating activities.......... 552,724 631,328 470,949
--------- --------- ---------
CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions........... (434,739) (416,051) (333,056)
Proceeds from dispositions of property,
plant and equipment-net................................. 14,066 164 4,716
Cost of other investments-net............................. (7,464) (14,902) (567)
--------- --------- ---------
Net cash used in investing activities.............. (428,137) (430,789) (328,907)
--------- --------- ---------
CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Issuance of common stock.................................. 19,058 279 13,066
Issuance of debentures.................................... 148,899 -- 295,098
Purchase of debentures.................................... -- -- (283,208)
Unsecured loan repayment.................................. (4,000) -- --
Commercial paper repayments-net........................... (103,399) (15,601) (5,015)
Dividends paid............................................ (180,782) (180,415) (178,125)
Other-net................................................. (9) (1) (91)
--------- --------- ---------
Net cash used in financing activities.............. (120,233) (195,738) (158,275)
--------- --------- ---------
Net increase (or decrease) in cash and
temporary cash investments....................... 4,354 4,801 (16,233)
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1.......... 31,923 27,122 43,355
--------- --------- ---------
CASH AND TEMPORARY CASH INVESTMENTS AT DECEMBER 31........ $ 36,277 $ 31,923 $ 27,122
========= ========= =========
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for
Interest (net of amounts capitalized)................... $ 102,663 $ 91,011 $ 92,880
Income taxes (net of refunds)........................... $ 58,949 $ 154,860 $ 109,998
Non-cash financing activities
Conversion of 7 1/4% Convertible Subordinated
Debentures............................................ $ -- $ 3,795 $ --
- - ---------------------------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
44
<PAGE> 47
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 Parent Company) and subsidiaries (the Company) within
this framework are summarized in this Note.
USE OF ESTIMATES
The consolidated financial statements reflect certain estimates and assumptions
made by management that affect the reported amounts of assets and liabilities,
the disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses for the periods
presented.
PRINCIPLES OF CONSOLIDATION
The Parent Company owns all of the capital stock of its subsidiaries. The
consolidated financial statements represent the accounts of the Company 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 all other
investments, 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 the cost of gas (including certain related costs) and the amount of such
costs included in current rates. The differences are accounted for as either
unrecovered gas costs or amounts payable to customers. Unrecovered amounts are
recognized as purchased gas costs in future periods when the costs are recovered
through adjusted rates.
ENERGY PRICE RISK MANAGEMENT ACTIVITIES
Statement of Financial Accounting Standards (SFAS) No. 119, "Disclosure about
Derivative Financial Instruments and Fair Value of Financial Instruments,"
requires certain disclosures about derivative financial instruments but does not
affect the accounting for derivatives.
In the normal course of business, the nonregulated subsidiaries utilize
exchange-traded commodity futures and option contracts and derivative financial
instruments to manage exposure to price risk in connection with the production,
purchase and sale of natural gas and oil, and for stored gas inventories.
Derivative financial instruments may also be used from time to time to manage
foreign currency risk in connection with certain contractual commitments.
Exchange-traded instruments permit settlement by physical delivery of the
commodity under contract and are not considered derivative financial instruments
under SFAS No. 119. The derivative financial instruments utilized by the
subsidiaries include over-the-counter (OTC) commodity price swap agreements, OTC
foreign currency swap agreements and OTC options and require settlement in cash.
Under the price swap agreements, the subsidiaries make
45
<PAGE> 48
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
payments to, or receive payments from, counterparties generally based on the
difference between fixed and variable gas prices or on prices at different
receipt points as specified in the contracts. Under foreign currency swap
agreements, payments are made to, or received from, counterparties generally
based on the difference in the current foreign exchange rate. Settlement takes
place under the swap agreements on a monthly basis, and amounts received or paid
are recognized as an adjustment to gas sales revenues, purchased gas expense or
transport capacity costs in that month to correspond with the recognition of the
related physical transaction.
For derivative financial instruments or exchange-traded contracts that qualify
(based on correlation to price movements of gas and oil) and are designated as
hedges, related gains or losses are deferred and subsequently recognized in
income, as gas sales revenues or purchased gas expense, in the same period the
hedged transaction occurs. Due to the nature of its operations, CNG Energy
Services marks-to-market the value of futures contracts related to stored gas
inventories each period, with gains and losses recognized in the operating
income of that period.
Margin accounts for open futures contracts are recorded in the Consolidated
Balance Sheet under "Prepayments and other current assets." Deferred losses or
gains are reflected in the Consolidated Balance Sheet under "Deferred charges
and other assets" and "Deferred credits and other liabilities," respectively.
Cash flows from price risk management activities are reported in the
Consolidated Statement of Cash Flows as an operating activity--consistent with
the category of the cash flows from the underlying physical transaction.
PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
GAS UTILITY AND OTHER PLANT
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.
EXPLORATION AND PRODUCTION PROPERTIES
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. If net capitalized costs exceed the estimated value at the end
of any quarterly period, then a permanent write-down of the assets must be
recognized in that period.
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,
and on 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.
46
<PAGE> 49
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ACCOUNTING FOR IMPAIRMENTS
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." This standard requires that long-lived assets and
certain intangibles be reviewed for impairment when events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. If the aggregate estimated future cash flows to be derived from an
asset are less than its carrying amount, an impairment must be recognized. SFAS
No. 121 also requires the write-off of a regulatory asset if and when it is no
longer probable that future revenues will provide for the recovery of the
carrying value of the asset. SFAS No. 121 is effective for fiscal years
beginning after December 15, 1995, and the Company will adopt the standard
effective January 1, 1996. The adoption is not expected to have a material
effect on the Company's financial position, results of operations or cash flows.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The subsidiaries subject to cost-of-service rate regulation capitalize the
estimated costs of 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 recognized.
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: 1993 - 3 1/4% to 8 7/8%; 1994 - 3 3/8% to 8 1/4% and
1995 - 5 3/4% to 8 3/8%. 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 required to be deferred by regulatory
authorities are being amortized as credits to income over the estimated service
lives of the related properties.
Effective January 1, 1993, the Company adopted the provisions of 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. The cumulative effect of this accounting change
increased 1993 net income by $17,422,000, or $.19 per share, resulting primarily
from the reduction in deferred income tax balances associated with nonregulated
activities.
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, and the payment of benefits to
certain retired executives under company-sponsored nonqualified employee benefit
plans.
Effective July 1, 1995, the Company applied SFAS No. 87 to certain of its
nonqualified employee benefit plans. Benefit costs under these plans had
previously been expensed as paid and were not material. The application of SFAS
No. 87 to these plans did not have a material effect on the Company's financial
position, results of operations or cash flows.
47
<PAGE> 50
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 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.
ACCOUNTING FOR STOCK-BASED COMPENSATION
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation." This standard encourages a fair value based method of accounting
for employee stock options and similar equity instruments. Although adoption of
this new method of accounting is optional, the standard requires companies
electing to follow existing accounting rules to disclose in a note the pro forma
effects as if the fair value based method of accounting had been applied. The
Company does not anticipate changing its accounting method for stock-based
compensation. As required, the new disclosures under SFAS No. 123 will be
reflected in the 1996 consolidated financial statements.
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 future rate-making
proceedings. 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 recognized in the period of the transaction.
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.
48
<PAGE> 51
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
For purposes of the Consolidated Statement of Cash Flows, temporary cash
investments are considered to be cash equivalents.
2. 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 $52,210,000 and $24,239,000 at
December 31, 1994 and 1995, including interest. These amounts are reported in
the Consolidated Balance Sheet under "Estimated rate contingencies and refunds"
together with $31,194,000 and $35,124,000, respectively, which are primarily
refunds received from suppliers and refundable to customers under regulatory
procedures.
As approved by the Federal Energy Regulatory Commission (FERC), CNG Transmission
has billed its customers, including certain affiliates, a total of $178.6
million, representing unrecovered purchased gas costs and unrecovered
sales-related transportation costs, resulting from its transition to
restructured services under FERC Order 636. Of the total amount billed by CNG
Transmission to the distribution subsidiaries, $21,070,000 is included in the
Consolidated Balance Sheet at December 31, 1995, under "Deferred charges and
other assets," representing remaining amounts to be recovered from their
customers.
The distribution subsidiaries have incurred or are expected to incur obligations
to upstream pipeline companies, including CNG Transmission, for transition costs
under FERC Order 636. The total estimated liability for such costs was
$69,451,000 and $37,021,000 at December 31, 1994 and 1995, respectively.
Additional amounts are likely to be accrued in the future once the pipeline
companies receive final FERC approval to recover these costs. Based on
management's current estimates, the distribution subsidiaries' portion of such
costs could be in the range of $25 million.
Based on regulatory actions in two jurisdictions and the past rate-making
treatment of similar costs in the other jurisdictions, management believes that
the distribution subsidiaries should generally be able to pass through all Order
636 transition costs to their customers.
3. PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
IMPAIRMENT OF GAS AND OIL PRODUCING PROPERTIES
As described in Note 1, certain of the subsidiaries follow the full cost method
of accounting for gas and oil producing activities as prescribed by the SEC.
Under these rules, the Company recognized an impairment of its gas and oil
producing properties at March 31, 1995, due primarily to the decline in gas
wellhead prices. The non-cash charge amounted to $226,209,000 and reduced 1995
first quarter net income by $145,000,000, or $1.56 per share.
DEPRECIATION AND AMORTIZATION
Amortization of capitalized costs under the full cost method of accounting for
the Company's exploration and production operations amounted to $1.18 per
thousand cubic feet (Mcf) equivalent of gas and oil produced in 1993, $1.15 in
1994, and $.98 in 1995. The 1995 amount includes the effect of the write-down of
the gas and oil producing properties noted above.
49
<PAGE> 52
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 1995, and the
years in which such excluded costs were incurred, follow:
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
Incurred in Years Ended December 31,
DECEMBER 31, ---------------------------------------
1995 1995 1994 1993 Prior
- - ----------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C>
Property acquisition costs........... $15,237 $ 5,521 $ 4,855 $3,143 $ 1,718
Exploration costs.................... 27,625 10,459 4,949 1,986 10,231
Capitalized interest................. 5,396 753 1,401 1,054 2,188
------- ------- ------- ------ -------
Total........................... $48,258 $16,733 $11,205 $6,183 $14,137
======= ======= ======= ====== =======
- - ----------------------------------------------------------------------------------------------
</TABLE>
There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 1995. 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.
WRITE-DOWN OF COAL PROPERTIES
In connection with a review of non-strategic assets, the Company initiated an
evaluation during 1995 of the possible disposition of the coal reserves and
related properties owned by CNG Coal. These reserves had been acquired in the
late 1960s and 1970s to meet expected long-term gas supply needs through coal
gasification. However, due to gas industry deregulation, excess gas supplies
nationwide, and both low demand and prices for coal, the Company concluded that
it was not economically feasible to develop such reserves at this time, nor were
these assets currently aligned with the Company's longer-term strategy.
An appraisal of the properties was completed during the second quarter of 1995
by an independent geological firm, which indicated that a write-down was
warranted. Accordingly, at June 30, 1995, the cost of these properties was
written down resulting in a pretax charge amounting to $31,266,000. This charge
reduced 1995 second quarter net income by $20,323,000, or 22 cents per share,
but had no effect on the Company's cash flow. In the fourth quarter of 1995, the
Company entered into a non-binding letter of intent for the proposed sale of
these properties to a third party. Negotiations are in progress with the third
party to finalize the sale. Any gain or loss resulting from the disposition of
these properties is not expected to be material.
4. WORKFORCE REDUCTION COSTS
In March 1995, the Board of Directors approved a workforce reduction program as
part of the Company's efforts to permanently reduce costs in response to
competitive conditions. The workforce reduction program consisted of a voluntary
early retirement program, with eligibility based upon the employee's age and
years of service as of December 31, 1995, and an involuntary separation program.
The early retirement incentives included five additional years of age and
pension service for determining pension benefits. The early retirement program
was offered at six of the subsidiaries from April 1 through May 31, 1995, with
eligible employees retiring before December 31, 1995. The involuntary separation
program involved severance benefit payments to affected employees. In June 1995,
the Board of Directors approved a separate workforce reduction program at a
seventh subsidiary that included voluntary early retirement incentives and
severance benefits similar to those offered at the other six subsidiaries. The
early retirement program was offered at the seventh subsidiary from July 1
through August 31, 1995. Eligible employees under this program also retired
before December 31, 1995.
50
<PAGE> 53
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
A total of 571 eligible employees elected to accept the early retirement offer
and an additional 217 employees were separated from the Company in conjunction
with these programs. Accordingly, the Company recorded charges to "Operation
expense" in the 1995 Consolidated Statement of Income amounting to $42,555,000.
These charges reduced 1995 net income by $25,618,000, or 27 cents per share. In
addition, certain of the regulated subsidiaries have deferred, as a regulatory
asset, a portion of their workforce reduction costs pending recovery in future
rates. The balance of these deferrals was $16,379,000 at December 31, 1995. The
total workforce reduction costs include the impact of curtailment accounting for
the pension and postretirement benefit plans. Details of the costs are shown in
the following table.
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------------------
Amounts Amounts
Expensed Deferred at Total
in 1995 December 31, 1995 Costs
- - --------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Pension and nonqualified benefit plans:
Special termination benefit cost............. $30,284 $ 6,893 $37,177
Curtailment gain-net......................... (5,891) (277) (6,168)
Postretirement benefit plans:
Special termination benefit cost............. 1,086 62 1,148
Curtailment loss-net......................... 6,008 9,656 15,664
Severance and other............................ 11,068 45 11,113
------- ------- -------
Total........................................ $42,555 $16,379 $58,934
======= ======= =======
- - --------------------------------------------------------------------------------------------
</TABLE>
In January 1996, unions at two subsidiaries approved the adoption of an early
retirement program with voluntary early retirement incentives similar to those
described above. The early retirement program will be offered to eligible union
employees from February 1 through March 31, 1996, with most retirement dates
effective April 1, 1996. Costs resulting from the program will be recognized in
1996, but are not expected to be material.
5. PENSION COSTS
Net pension cost, as determined by an independent actuary, included the
following components:
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - ---------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Service cost - benefits earned during the period....... $ 23,741 $ 28,509 $ 27,266
Interest cost on projected benefit obligation.......... 62,125 59,006 56,834
Return on plan assets.................................. (265,460) (33,363) (89,441)
Net amortization and deferral.......................... 162,002 (60,228) (303)
Curtailment and special termination benefits........... 24,393 -- --
Special voluntary retirement programs.................. 800 800 800
--------- -------- --------
Net pension cost (or credit)......................... $ 7,601 $ (5,276) $ (4,844)
========= ======== ========
- - ---------------------------------------------------------------------------------------------
</TABLE>
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
51
<PAGE> 54
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
began October 1, 1990, in accordance with the rate-making treatment approved by
the Pennsylvania Public Utility Commission.
The following table sets forth the funded status of the plans, as determined by
an independent actuary, at December 31, 1994 and 1995:
<TABLE>
<CAPTION>
- - ------------------------------------------------------------------------------------------------
Plans Where Assets Plans Where
Exceed Accumulated Accumulated Benefits
Benefits Exceed Assets
------------------------ --------------------
December 31, 1995 1994 1995 1994
- - ------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
Actuarial present value of:
Vested benefit obligation.................. $ 711,644 $ 600,111 $ 25,203 $ 13,717
========== ========== ======== ========
Accumulated benefit obligation............. $ 740,890 $ 625,900 $ 28,858 $ 13,717
========== ========== ======== ========
Projected benefit obligation............... $ 952,260 $ 832,431 $ 36,044 $ 13,717
Plan assets at fair value.................... 1,395,778 1,178,505 -- --
---------- ---------- -------- --------
Plan assets in excess of (or less than)
projected benefit obligation............ 443,518 346,074 (36,044) (13,717)
Unrecognized net loss (or gain).............. (354,370) (242,721) 1,358 1,901
Unrecognized net obligation (or asset)....... (77,300) (86,620) 21,396 1,970
Unrecognized prior service cost.............. 5,634 7,053 2,341 3,067
Recognition of minimum liability............. -- -- (17,909) (6,938)
---------- ---------- -------- --------
Prepaid pension cost (or pension
liability).............................. $ 17,482 $ 23,786 $(28,858) $(13,717)
========== ========== ======== ========
- - ------------------------------------------------------------------------------------------------
</TABLE>
The projected benefit obligation at December 31, 1994 and 1995, was determined
using an annual discount rate of 7.5% and 7.0%, respectively, 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 and related intangible asset recognized relating to the
Company's supplemental pension benefit plans at December 31, 1994, was
$6,938,000 and $5,037,000, respectively. As described in Note 1, the Company
applied the provisions of SFAS No. 87 to certain nonqualified employee benefit
plans effective July 1, 1995. The minimum liability and related intangible asset
recognized relating to both the supplemental pension and nonqualified employee
benefit plans at December 31, 1995, was $17,909,000 and $15,605,000,
respectively. These amounts are included in the Consolidated Balance Sheet under
"Deferred credits and other liabilities" and "Deferred charges and other
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 $386,000 at December 31, 1994, and a charge to retained
earnings of $262,000 at December 31, 1995.
52
<PAGE> 55
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
6. OTHER POSTRETIREMENT BENEFITS
Net periodic postretirement benefit cost, as determined by an independent
actuary, included the following components:
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - ---------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Service cost - benefits attributed to service during the
period..................................................... $11,549 $12,708 $10,549
Interest cost on accumulated postretirement benefit
obligation................................................. 28,017 24,380 23,208
Return on plan assets........................................ (145) (28) --
Amortization of transition obligation........................ 14,420 14,420 14,420
Curtailment and special termination benefits................. 7,094 -- --
Net amortization and deferral................................ 380 4 --
------- ------- -------
Net periodic postretirement benefit cost................... $61,315 $51,484 $48,177
======= ======= =======
- - ---------------------------------------------------------------------------------------------
</TABLE>
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, 1994 and 1995:
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------------------
December 31, 1995 1994
- - --------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees........................................................ $ 271,209 $ 208,685
Fully eligible active plan participants......................... 25,475 41,433
Other active plan participants.................................. 88,235 85,757
--------- ---------
Total accumulated postretirement benefit obligation.......... 384,919 335,875
Plan assets at fair value......................................... 12,127 2,717
--------- ---------
Accumulated postretirement benefit obligation in
excess of plan assets...................................... (372,792) (333,158)
Unrecognized prior service cost................................... (20,887) (6,930)
Unrecognized net loss............................................. 64,166 21,113
Unrecognized transition obligation................................ 230,853 259,553
--------- ---------
Accrued postretirement benefit liability..................... $ (98,660) $ (59,422)
========= =========
- - --------------------------------------------------------------------------------------------
</TABLE>
As permitted, the Company elected to amortize the accumulated postretirement
benefit obligation existing at January 1, 1993 (transition obligation) of
$288,393,000 over a 20-year period. The weighted average discount rate used in
determining the accumulated postretirement benefit obligation at December 31,
1994 and 1995, was 8.25% and 7.00%, respectively. The average assumed annual
rate of salary increase for the applicable life insurance plans was 5.5% in 1994
and 5.0% in 1995.
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation for the medical plans is 8.5% for 1996,
declining gradually to 5.0% 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, 1995, would
be increased by $42.1 million. A 1% change would also increase the aggregate of
the service and interest cost components of net periodic postretirement benefit
cost for 1995 by $5.2 million.
The majority of the estimated postretirement benefit costs and the transition
obligation is attributable to the rate-regulated subsidiaries. Pending the
expected recovery of SFAS No. 106 costs and related
53
<PAGE> 56
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
deferrals in regulatory proceedings, these subsidiaries have generally deferred
the differences between SFAS No. 106 costs and amounts included in rates. In
general, the rate-regulated subsidiaries have obtained approval for recovery in
rates from their respective regulatory commissions for the increased level of
expense resulting from the adoption of SFAS No. 106. The amount of SFAS No. 106
costs deferred at December 31, 1994 and 1995, was $55,185,000 and $68,026,000,
respectively, which is included in the Consolidated Balance Sheet under
"Deferred charges and other assets."
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. Accordingly, two subsidiaries began funding postretirement benefit
costs via voluntary employees' beneficiary associations (VEBAs) during 1994 and
one subsidiary began funding in 1995. A fourth subsidiary is expected to begin
funding in 1996. The remaining subsidiaries do not prefund postretirement
benefit costs, but rather pay claims as presented. Assets held by the VEBAs
consist primarily of short-term fixed income securities.
7. INCOME TAXES
As described in Note 1, the Company adopted the provisions of SFAS No. 109
effective January 1, 1993. The cumulative effect of this accounting change
increased 1993 net income by $17,422,000, or $.19 per share, due primarily to
the reduction in deferred tax balances associated with nonregulated activities.
"Income taxes" in the Consolidated Statement of Income include the following:
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - ---------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Current provision
Federal............................................... $ 44,705 $126,362 $ 99,029
State................................................. 9,203 19,376 23,279
Deferred income taxes-net
Federal............................................... (47,146) (50,443) (6,688)
State................................................. (1,621) (10,301) (13,094)
Investment tax credit................................... (2,198) (2,567) (2,620)
-------- -------- --------
Total................................................. $ 2,943 $ 82,427 $ 99,906
======== ======== ========
- - ---------------------------------------------------------------------------------------------
</TABLE>
In August 1993, the federal corporate income tax rate was increased from 34% to
35%, retroactive to January 1, 1993. As required by Statement No. 109, existing
deferred tax assets and liabilities were adjusted to reflect this enacted tax
rate change. As a result, deferred income tax expense in 1993 was increased by
$11,429,000, or $.12 per share.
Income taxes differed from the amounts shown in the next table that were
computed by applying the statutory federal income tax rate of 35% to reported
income before taxes. The reasons for the differences follow:
54
<PAGE> 57
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - ---------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Income before taxes...................................... $24,287 $265,598 $288,400
======= ======== ========
Computed "expected" tax expense.......................... $ 8,500 $ 92,959 $100,940
Increases (or reductions) in tax resulting from:
Production tax credit.................................. (8,472) (7,987) (8,435)
Investment tax credit.................................. (2,198) (2,567) (2,620)
State income taxes..................................... 4,928 5,899 6,620
Effect of increase in federal corporate income tax rate
on deferred income taxes............................ -- -- 11,429
Miscellaneous.......................................... 185 (5,877) (8,028)
------- -------- --------
Total income taxes................................ $ 2,943 $ 82,427 $ 99,906
======= ======== ========
Effective tax rate..................................... 12.1% 31.0% 34.6%
- - ---------------------------------------------------------------------------------------------
</TABLE>
The current and noncurrent deferred income taxes reported in the Consolidated
Balance Sheet at December 31, 1995, represent the net expected future tax
consequences attributable to temporary differences between the carrying amounts
of nontax assets and liabilities and their tax bases. These temporary
differences and the related tax effect were as follows:
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
1995
-------------------------------------
Deferred income Deferred income
December 31, taxes taxes - current
- - ----------------------------------------------------------------------------------------------
<S> <C> <C>
(In Thousands)
Deferred tax liabilities:
Excess of tax over book depreciation................ $497,415 $ --
Exploration and intangible well drilling costs...... 217,352 --
FERC Order 636 transition costs..................... 7,838 --
Unrecovered gas costs............................... -- 9,232
Other............................................... 68,751 --
------ --------
Total liabilities................................ 791,356 9,232
------ --------
Deferred tax assets:
Tax basis step-up in connection with acquisition of
subsidiary....................................... 19,923 --
Deferred investment tax credits..................... 18,817 --
Overheads capitalized for tax purposes.............. 11,092 --
Write-down of coal properties....................... 10,943 --
Amounts payable to customers........................ -- 14,710
Supplier and other refunds.......................... -- 5,338
Other............................................... 58,315 10,177
Valuation allowance................................. -- --
------ --------
Total assets..................................... 119,090 30,225
------ --------
Total deferred income taxes...................... $672,266 $(20,993)
======== ========
- - ----------------------------------------------------------------------------------------------
</TABLE>
55
<PAGE> 58
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
A regulatory liability amounting to $61,678,000 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
$105,159,000 has been recorded at December 31, 1995. These amounts are included
in the Consolidated Balance Sheet under "Deferred credits and other liabilities"
and "Deferred charges and other assets," respectively.
8. GAS STORED
The distribution subsidiaries, except Virginia Natural Gas, value their stored
gas inventory under the LIFO method. Virginia Natural Gas and CNG Energy
Services value their stored gas inventory under the weighted average cost
method. Based upon the average price of gas purchased during 1995, the current
cost of replacing the inventory of "Gas stored--current portion" exceeded the
amount stated on a LIFO basis by approximately $152,938,000 at December 31,
1995.
A portion of gas in underground storage used as a pressure base and for
operational balancing is included in "Property, Plant and Equipment" in the
amounts of $126,496,000 and $126,393,000 at December 31, 1994 and 1995,
respectively.
9. 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 SFAS 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.
56
<PAGE> 59
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
10. COMMON STOCKHOLDERS' EQUITY
A summary of the changes in stockholders' equity follows:
<TABLE>
<CAPTION>
- - -------------------------------------------------------------------------------------------------------------------------
Common Stock
Issued Capital in Excess Treasury Stock
--------------------- of Par Value --------------------
Number of Value ------------------------------- Retained Number of
Shares at Par Paid-In Other Total Earnings Shares Cost
- - -------------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1992.................. 92,557 $254,532 $398,749 $40,280 $439,029 $1,439,277 -- $ --
Net income.............. -- -- -- -- -- 205,916 -- --
Cash dividends declared
Common stock ($1.925
per share).......... -- -- -- -- -- (178,771) -- --
Common stock issued
Stock options......... 238 654 8,834 -- 8,834 -- -- --
Stock awards-net...... 66 180 2,925 -- 2,925 -- -- --
DRP*.................. 58 159 2,697 -- 2,697 -- -- --
System Thrift Plans... 15 43 679 -- 679 -- -- --
Purchase of treasury
stock................. -- -- -- -- -- -- (29) (1,417)
Sale of treasury
stock................. -- -- (83) -- (83) -- 29 1,417
Pension liability
adjustment............ -- -- -- -- -- 361 -- --
------ -------- -------- ------- -------- ---------- --- -------
Balance at December 31,
1993.................. 92,934 255,568 413,801 40,280 454,081 1,466,783 -- --
Net income.............. -- -- -- -- -- 183,171 -- --
Cash dividends declared
Common stock ($1.94
per share).......... -- -- -- -- -- (180,461) -- --
Common stock issued
Conversion of
debentures.......... 70 193 3,669 -- 3,669 -- -- --
Stock awards-net...... 16 45 621 -- 621 -- -- --
Stock options......... 8 21 258 -- 258 -- -- --
Purchase of treasury
stock................. -- -- -- -- -- -- (6) (257)
Sale of treasury
stock................. -- -- (1) -- (1) -- 6 257
Pension liability
adjustment (Note 5)... -- -- -- -- -- 386 -- --
------ -------- -------- ------- -------- ---------- --- -------
Balance at December 31,
1994.................. 93,028 255,827 418,348 40,280 458,628 1,469,879 -- --
Net income.............. -- -- -- -- -- 21,344 -- --
Cash dividends declared
Common stock ($1.94
per share).......... -- -- -- -- -- (181,055) -- --
Common stock issued
Stock options......... 217 596 7,453 -- 7,453 -- -- --
System Thrift Plans... 213 586 7,586 -- 7,586 -- -- --
DRP*.................. 104 287 3,837 -- 3,837 -- -- --
Stock awards-net...... 30 81 1,040 -- 1,040 -- -- --
Purchase of treasury
stock................. -- -- -- -- -- -- (17) (634)
Sale of treasury
stock................. -- -- (9) -- (9) -- 17 634
Pension liability
adjustment (Note 5)... -- -- -- -- -- (262) -- --
------ -------- -------- ------- -------- ---------- --- -------
Balance at December 31,
1995.................. 93,592 $257,377 $438,255 $40,280 $478,535 $1,309,906 -- $ --
====== ======== ======== ======= ======== ========== === =======
- - -------------------------------------------------------------------------------------------------------------------------
<FN>
* Dividend Reinvestment Plan.
</TABLE>
57
<PAGE> 60
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
SHAREHOLDER RIGHTS PLAN
On November 13, 1995, the Board of Directors adopted a shareholder rights plan
and on January 23, 1996, declared a dividend of one right (Right) for each share
of common stock outstanding at the close of business on February 28, 1996. Each
Right would entitle the holder to purchase from the Company one-half of one
share of common stock at a price of $175 per share ($87.50 per half-share),
subject to adjustment (Purchase Price), if certain conditions are met in
connection with a possible acquisition of the common stock of the Company by a
third party. If the Rights become exercisable, each holder may exercise a Right
and receive common stock (or, in certain cases, cash, property or other
securities) of the Company or common stock of the acquiring company having a
value equal to twice the Right's then current Purchase Price.
Also, under certain conditions, the Board of Directors may exchange the Rights,
in whole or in part, at an exchange ratio of one share of common stock (and/or
other securities, cash or other assets having the same value as a share of
common stock) per Right, subject to adjustment, or may redeem the Rights in
whole at a price of $0.01 per Right. Until a Right is exercised or exchanged for
common stock, the holder, as such, is not a stockholder of the Company. Unless
earlier exercised or redeemed, the Rights will expire on February 28, 2006.
UNISSUED SHARES
At December 31, 1995, 106,408,377 shares of common stock were unissued. Of
these, a total of 16,326,310 shares have been registered with the SEC for
possible issuance under various benefit plans. Shares acquired by these plans
can consist of original issue shares, treasury shares or shares purchased in the
open market. In addition, 2,098,824 shares have been registered with the SEC for
possible issuance to shareholders under the Dividend Reinvestment Plan and
4,559,353 shares are 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. 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. No
treasury shares were held at December 31, 1994 or 1995.
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. The maximum
number of shares available for issuance in each calendar year is determined in
accordance with a formula contained in the plan. During 1995, 3,741,422 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.
58
<PAGE> 61
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
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, 1995, no stock appreciation rights have
been granted under the plan.
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.
1995 EMPLOYEE STOCK INCENTIVE PLAN
The 1995 Employee Stock Incentive Plan was established in conjunction with the
Long-Term Strategic Incentive Program described below. This plan provides for
the granting of stock-based awards to certain key employees similar to those
granted under the 1991 Stock Incentive Plan. There were no grants made under
this plan during 1995.
LONG-TERM INCENTIVE PLAN
The 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. The terms and conditions of the options granted under this
plan are similar to those under the 1991 Stock Incentive Plan.
A summary of stock option activity under both the 1991 Stock Incentive Plan and
the Long-Term Incentive Plan for the years ended December 31, 1993 through 1995,
follows:
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------------------
Number Option Price
of Shares Per Share
- - --------------------------------------------------------------------------------------------
<S> <C> <C>
(In Thousands)
Shares under option:
At January 1, 1993...................................... 1,713 $32.50--$50.75
Granted................................................. 552 $44.88--$55.00
Exercised............................................... (238) $33.25--$50.75
Cancelled............................................... (65) $34.75--$50.75
-------
At December 31, 1993.................................... 1,962 $32.50--$55.00
Granted................................................. 651 $34.75--$45.13
Exercised............................................... (8) $34.38--$43.88
Cancelled............................................... (48) $34.75--$50.75
-------
At December 31, 1994.................................... 2,557 $32.50--$55.00
Granted................................................. 1,078 $37.25--$45.38
Exercised............................................... (217) $34.38--$43.88
Cancelled............................................... (470) $34.38--$55.00
-------
At December 31, 1995.................................... 2,948 $32.50--$55.00
=======
- - --------------------------------------------------------------------------------------------
</TABLE>
59
<PAGE> 62
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Effective January 2, 1996, additional options for the purchase of 482,500 shares
were granted to eligible employees. At December 31, 1995, options were
exercisable for the purchase of 1,048,064 shares. Stock options become
exercisable for the purchase of 401,776 shares in 1996, 534,731 in 1997, 424,323
in 1998, and 539,076 shares thereafter.
LONG-TERM STRATEGIC INCENTIVE PROGRAM
On December 12, 1995, the Board of Directors approved the Long-Term Strategic
Incentive Program. Grants under this program, consisting of performance
restricted stock awards (performance shares) and nonqualified stock options, are
expected to be made every three years. Performance shares will vest contingent
upon attainment of certain strategic business results over a three-year period.
Stock options granted under this program vest after three years and will be
exercisable for one day. The exercise period can be extended from the vesting
date up to 10 years for all or a portion of the options if certain strategic
business results are attained over the vesting period. Awards under this program
will utilize shares available under both the 1991 Stock Incentive Plan and the
1995 Employee Stock Incentive Plan. No awards were made under this program in
1995. Effective January 2, 1996, grants were made under the program consisting
of 331,700 performance shares and 2,624,000 stock options.
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, 1994 or 1995.
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), $506,988,000 of consolidated retained earnings was free from such
restrictions at December 31, 1995. The indenture also imposes dividend
limitations on the subsidiaries, but at December 31, 1995, these limitations did
not restrict their ability to pay dividends to the Company.
60
<PAGE> 63
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. LONG-TERM DEBT
Long-term debt, excluding current maturities, follows:
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------
December 31, 1995 1994
- - ---------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Debentures
7 3/8%, Due April 1, 2005................................... $ 150,000 $ --
6 5/8%, Due December 1, 2013................................ 150,000 150,000
5 3/4%, Due August 1, 2003.................................. 150,000 150,000
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................................ 93,750 100,000
Unamortized debt discount................................... (8,304) (8,262)
Convertible Subordinated Debentures
7 1/4%, Due December 15, 2015............................... 246,205 246,205
Unamortized debt discount................................... (1,840) (1,970)
9.94% Unsecured loan due January 1, 1999...................... 12,000 16,000
---------- ----------
Total.................................................... $1,291,811 $1,151,973
========== ==========
- - ---------------------------------------------------------------------------------------------
</TABLE>
The aggregate principal amounts of the Company's debentures maturing in the
years 1996 through 2000 are: $6,250,000; $106,250,000; $156,250,000;
$113,375,000 and $22,080,000.
Discounts and the expenses incurred in connection with the issuance of
debentures are being amortized on a basis which will equitably distribute the
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 being repaid in five annual
installments of $4,000,000 each beginning January 1, 1995, has been guaranteed
by the Company.
RESTRICTIONS UNDER CERTAIN DEBT AGREEMENTS
At December 31, 1995, the Company had senior debentures outstanding under a 1971
indenture between the Company and Chemical Bank, as trustee (the 1971
Indenture). The 1971 Indenture contains covenants which limit, among other
things, the incurrence of funded debt. Funded debt is indebtedness maturing (or,
at the Company's option, renewable or extendable for) more than one year after
the date of issuance. One of the covenants contained in the 1971 Indenture
provides that the Company may not issue funded debt unless (a) consolidated
income available for interest and subsidiary preferred stock dividends (computed
before income and excess or other profits taxes) of the Company for any twelve
consecutive months within the preceding fifteen months shall have been not less
than 2 1/2 times the sum of the total annual interest charges upon the funded
debt of the Company and the total annual dividend requirements on subsidiary
preferred stock, in each case to be outstanding immediately thereafter and (b)
after giving effect to such issuance the sum of the principal amount of
61
<PAGE> 64
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
funded debt of the Company outstanding and the amount of subsidiary preferred
stock outstanding shall not be more than 60 percent of the consolidated net
tangible assets of the Company. The Company has a shelf registration with the
SEC for the sale of up to $350 million of debt securities. Debt securities to be
issued under this shelf registration would be classified as funded debt and,
therefore, the 1971 Indenture limits the Company's ability to issue such
securities if the provisions of the covenant summarized above are not met.
As a result of the charges in 1995 for workforce reduction costs and write-downs
of gas and oil producing properties and coal properties, the Company's ability
to issue funded debt is expected to be restricted through May 1996.
14. SHORT-TERM BORROWINGS
The weighted average interest rate on the Company's commercial paper notes
outstanding at December 31, 1994 and 1995, was 5.86% and 5.79%, respectively.
The Company entered into a $475,000,000 credit agreement and a $300,000,000
credit agreement effective June 30, 1995. These agreements replaced existing
credit agreements that were terminated on that same date. Borrowings under these
agreements 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 repaid 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. These agreements may be used for general corporate purposes, including
the support of commercial paper notes. The agreements are currently scheduled to
expire on June 29, 1996; however, the Company expects that the agreements will
be renewed or replaced by comparable agreements. A facility fee is charged under
the agreements but is not considered significant. There were no borrowings under
these agreements at December 31, 1995.
15. FINANCIAL INSTRUMENTS
FAIR VALUES
The estimated fair value of the Company's long-term debt, including current
maturities, was as follows at December 31, 1994 and 1995:
<TABLE>
<CAPTION>
- - -------------------------------------------------------------------------------------------------
1995 1994
--------------------------- ---------------------------
Carrying Fair Carrying Fair
December 31, Amount Value Amount Value
- - -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
(In Thousands)
Long-term debt..................... $1,312,205 $1,368,002 $1,166,205 $1,095,492
- - -------------------------------------------------------------------------------------------------
</TABLE>
The fair values were estimated based upon closing transactions and/or quotations
for the Company's debentures as of those dates. Temporary cash investments and
commercial paper notes are stated at amounts which approximate fair value due to
the short maturities of those financial instruments.
DERIVATIVE FINANCIAL INSTRUMENTS AND ENERGY PRICE RISK MANAGEMENT ACTIVITIES
The majority of the Company's energy price risk management activities involve
exchange-traded futures and options contracts which can be settled through the
purchase or delivery of commodities. The Company's nonregulated subsidiaries use
futures and options to manage commodity price risk in connection with the
production, purchase and sale of natural gas and oil, and for stored gas
inventories. At December 31, 1995, the Company's price risk management
activities included futures contracts under hedging activities maturing through
May 1997 covering 11.2 billion cubic feet (Bcf) of natural gas and
62
<PAGE> 65
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
107,000 barrels of oil. Since these contracts qualify and have been designated
as hedges, any gains or losses resulting from market price changes are expected
to be generally offset by the related physical transaction. The net unrealized
gain related to these futures contracts was approximately $1,500,000 at December
31, 1995.
In addition to exchange-traded futures and options contracts, the nonregulated
subsidiaries periodically enter into OTC price swap agreements to manage their
exposure to commodity price risk under existing sales commitments. At December
31, 1995, the Company's nonregulated subsidiaries had swap agreements of varying
duration outstanding with several counterparties to exchange monthly payments on
net notional quantities of 30.3 Bcf of gas over the ensuing 3 years. Net
notional quantities or amounts do not represent the quantities or amounts
exchanged by the parties and, thus, are not a measure of the exposure of the
Company through its use of derivatives. The amounts exchanged are calculated on
the basis of monthly notional quantities and other terms of the agreements. The
net unrealized loss related to these swap agreements was approximately
$2,600,000 at December 31, 1995. Profits expected on anticipated sales related
to the hedged transactions should generally offset the estimated unrealized
losses on the swap agreements. CNG Energy Services has also entered into a
10-year foreign currency swap agreement to manage foreign exchange rate risk in
connection with the payment of demand charges for pipeline capacity in Canada.
The aggregate notional amount underlying this swap agreement was approximately
$72,500,000 at December 31, 1995. The unrealized gain related to the foreign
currency swap agreement was approximately $2,100,000 at December 31, 1995.
The use of futures and options contracts and derivative financial instruments
exposes the Company to market risk and credit risk. Market risk represents the
potential loss that can be caused by a change in the market value of a
particular commitment. Although the use of exchange-traded and OTC instruments
generally reduces market risk exposure due to unfavorable price fluctuations,
such risk management activities, while not significant, can also result in the
assumption of a limited degree of price risk in certain isolated transactions.
Credit risk relates to the risk of loss that the Company would incur as a result
of nonperformance by counterparties pursuant to the terms of their contractual
obligations. The Company does not have a significant exposure to any individual
counterparty to its energy price risk management activities. Management has
operating procedures in place to evaluate market and credit risks and believes
that the Company's exposure to risks associated with exchange-traded futures and
options contracts and derivative financial instruments is not material in
relation to the Company's financial position, results of operations or cash
flows.
16. ENVIRONMENTAL MATTERS
The Company is 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 subsidiaries, or their predecessors.
The Company has taken a proactive position with respect to environmental
concerns. As part of normal business operations, subsidiaries periodically
monitor their properties and facilities to identify and resolve potential
environmental matters, and the Company conducts general environmental surveys on
a continuing basis at its operating facilities to monitor compliance with
environmental laws and regulations. As part of this process, voluntary surveys
at subsidiary sites have been conducted to determine the extent of any possible
soil contamination due to hazardous substances, such as mercury, and when
contamination has been discovered remediation efforts are undertaken. Further,
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. No civil penalties have been assessed as of this date. Pursuant to
the Order and Agreement, CNG Transmission
63
<PAGE> 66
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
is performing sampling, testing and analysis, and conducting a program of
remediation at some of its Pennsylvania facilities. Total remediation costs in
connection with these sites and the Order and Agreement are not expected to be
material with respect to the Company's financial position, results of operations
or cash flows. Based on current information, the Company has recognized a gross
estimated liability amounting to $22,004,000 at December 31, 1995, for future
costs expected to be incurred to remediate or mitigate hazardous substances at
these sites and at facilities covered by the Order and Agreement.
Inasmuch as certain environmental-related expenditures are expected to be
recoverable in future regulatory proceedings, a regulatory asset amounting to
$13,932,000 at December 31, 1995, is included in the Consolidated Balance Sheet
under the caption "Deferred charges and other assets." Also, uncontested claims
amounting to $3,669,000 at December 31, 1995, were recognized for environmental-
related costs probable for recovery through joint-interest operating agreements.
The total amounts included in operating expenses for remediation and other
environmental-related costs, and the components of such costs, are as follows:
<TABLE>
<CAPTION>
- - -----------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - -----------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Recurring costs for ongoing operations..................... $3,094 $3,479 $3,381
Mandated remediation and other compliance costs............ 2,307 214 3,963
Voluntary remediation costs................................ 1,630 507 1,185
Other...................................................... 79 28 520
------- ------- -------
Total.................................................... $7,110 $4,228 $9,049
====== ====== ======
- - -----------------------------------------------------------------------------------------------
</TABLE>
CNG Transmission and certain of the distribution subsidiaries are subject to the
Federal Clean Air Act (Clean Air Act) and the Federal Clean Air Act Amendments
of 1990 (1990 amendments) which added significantly to the existing Clean Air
Act requirements. As a result of the 1990 amendments, these subsidiaries were
required to install Reasonably Available Control Technology (RACT) at some
compressor stations by May 31, 1995, to reduce nitrogen oxide emissions.
Compliance requires capital expenditures to similarly retrofit some of the
compressor engines along the Company's pipeline system. In this regard,
approximately $23.3 million was expended in 1994 to install emission control
equipment. During 1995, the Company expended $11.3 million to retrofit existing
engines with emission control equipment to meet the RACT requirements and to
comply with certification standards under the 1990 amendments. All required
permit applications have been filed with the appropriate federal and state
agencies and have been approved or are pending approval. The Company anticipates
spending an additional $2.4 million during 1996. The total capital expenditures
required to comply with the 1990 amendments are expected to be recoverable
through future regulatory proceedings.
The Company has determined that it is associated with 16 former manufactured gas
plant sites, five of which are currently owned by subsidiaries. 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 Company discovered in the course of conducting a routine environmental
survey at East Ohio Gas that some of its practices for collecting and handling
pipeline fluids that may have been contaminated with polychlorinated biphenyls
(PCBs) may not have complied with environmental regulations. The
64
<PAGE> 67
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
appropriate agencies have been notified as part of the federal self-disclosure
process and discussions are continuing with the agencies to gain approval of
revised collection and handling procedures. A thorough investigation of all
collection and handling practices at East Ohio Gas is ongoing and the results of
this investigation will be provided to the appropriate agencies. The
discrepancies in the procedures were primarily in connection with recordkeeping
and did not involve spills, leaks, or other mishandling of PCB contaminated
fluids and did not damage the environment. The Company anticipates that
penalties, if any, incurred in connection with this matter may be mitigated as a
result of the Company's self disclosure. The amount of any liabilities in
connection with this matter is not expected to be material with respect to the
Company's financial position, results of operations or cash flows.
Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature of
environmental issues which 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. However, the amount of any such liabilities
could be material.
17. 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 1993 through 1995 was not material, and future rental
payments required under leases in effect at December 31, 1995, are not material.
It is estimated that the Company's 1996 capital budget will amount to
$455,200,000, and that approximately $180,600,000 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 the Company's financial position, results of operations or cash flows.
18. DISAGGREGATED INFORMATION
In addition to operating in all phases of the natural gas business, the Company
explores for and produces oil and provides a variety of energy marketing
services.
Distribution represents the retail gas distribution subsidiaries. These
subsidiaries sell gas and/or provide transportation services to residential,
commercial and industrial customers in Ohio, Pennsylvania, Virginia and West
Virginia, and are subject to price regulation by their respective state utility
commissions.
Transmission operations include the activities of CNG Transmission, an
interstate pipeline company regulated by the FERC which 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.
Transmission operations also include, prior to April 1, 1995, the activities of
CNG Storage. CNG Storage is engaged 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.
Exploration and production includes the results of CNG Producing and the gas and
oil production activities of CNG Transmission. These operations are located
throughout the United States and in the Gulf of Mexico. CNG Producing also owns
a working interest in a heavy oil program in Alberta, Canada.
65
<PAGE> 68
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Energy marketing services is comprised of CNG Energy Services, CNG Power, CNG
Power Services and, for the period April 1, 1995 through December 31, 1995, CNG
Storage. CNG Energy Services markets Company-owned gas production and arranges
gas supplies, transportation, storage and related services throughout North
America. CNG Power develops new business opportunities for the Company in
energy-related markets. It invests in and develops independent power producer
projects and conducts a gas liquids business. CNG Power Services, created in
1994, is the power marketing subsidiary of the Company and has received FERC
approval to purchase and resell electricity at market-based rates. Except for
CNG Storage, the operations of these subsidiaries, if applicable, were included
in the "Other" category for 1993 and 1994.
The activities of Consolidated LNG, CNG Research and CNG Coal are included in
the "Other" category.
Transactions between affiliates are recognized at prices which approximate
market value. Significant transactions between the operating components are
eliminated to reconcile the disaggregated information to consolidated amounts.
Identifiable assets of each component are those assets that are used in its
operations.
66
<PAGE> 69
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents disaggregated information pertaining to the
Company's operations:
<TABLE>
<CAPTION>
- - -------------------------------------------------------------------------------------------------------------------------------
Exploration Energy
and Marketing Corporate and
Distribution Transmission Production Services Other Eliminations Total
- - -------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
(In Thousands)
1995
Operating revenues
Nonaffiliated......... $ 1,738,947 $ 365,888 $ 174,442 $1,020,789 $ 7,259 $ -- $3,307,325
Affiliated............ 6,280 105,138 187,012 87,611 10,168 (396,209) --
----------- ---------- ----------- ---------- -------- ---------- ----------
Total............. 1,745,227 471,026 361,454 1,108,400 17,427 (396,209) 3,307,325
Other operating
expenses.............. 1,466,776 261,091 438,477 1,113,014 14,543 (392,668) 2,901,233
Depreciation and
amortization.......... 70,972 59,552 123,492 1,072 -- 1,548 256,636
----------- ---------- ----------- ---------- -------- ---------- ----------
Operating income before
income taxes.......... $ 207,479 $ 150,383 $ (200,515) $ (5,686) $ 2,884 $ (5,089) $ 149,456
=========== ========== =========== ========== ======== ========== ==========
Capital expenditures.... $ 160,480 $ 81,557 $ 176,789 $ 19,567 $ -- $ 1,000 $ 439,393
Identifiable assets..... $ 2,645,004 $1,483,631 $ 1,155,092 $ 317,490 $ 54,425 $ (237,349) $5,418,293
- - -------------------------------------------------------------------------------------------------------------------------------
1994
Operating revenues
Nonaffiliated......... $ 1,804,317 $ 348,141 $ 411,876 $ -- $471,694 $ -- $3,036,028
Affiliated............ 1,296 111,147 77,564 -- 44,966 (234,973) --
----------- ---------- ----------- ---------- -------- ---------- ----------
Total............. 1,805,613 459,288 489,440 -- 516,660 (234,973) 3,036,028
Other operating
expenses.............. 1,579,259 259,078 299,872 -- 508,303 (233,206) 2,413,306
Depreciation and
amortization.......... 67,401 53,944 155,558 -- 736 1,678 279,317
----------- ---------- ----------- ---------- -------- ---------- ----------
Operating income before
income taxes.......... $ 158,953 $ 146,266 $ 34,010 $ -- $ 7,621 $ (3,445) $ 343,405
=========== ========== =========== ========== ======== ========== ==========
Capital expenditures.... $ 146,882 $ 108,647 $ 166,022 $ -- $ 15,198 $ 1,036 $ 437,785
Identifiable assets..... $ 2,595,615 $1,543,790 $ 1,372,747 $ -- $283,799 $ (277,278) $5,518,673
- - -------------------------------------------------------------------------------------------------------------------------------
1993
Operating revenues
Nonaffiliated......... $ 1,772,816 $ 689,772 $ 437,125 $ -- $284,372 $ -- $3,184,085
Affiliated............ 1,112 293,984 99,301 -- 73,401 (467,798) --
----------- ---------- ----------- ---------- -------- ---------- ----------
Total............. 1,773,928 983,756 536,426 -- 357,773 (467,798) 3,184,085
Other operating
expenses.............. 1,541,741 789,894 312,393 -- 351,800 (463,735) 2,532,093
Depreciation and
amortization.......... 65,295 50,418 176,738 -- 292 1,905 294,648
----------- ---------- ----------- ---------- -------- ---------- ----------
Operating income before
income taxes.......... $ 166,892 $ 143,444 $ 47,295 $ -- $ 5,681 $ (5,968) $ 357,344
=========== ========== =========== ========== ======== ========== ==========
Capital expenditures.... $ 115,376 $ 113,385 $ 110,746 $ -- $ 1,757 $ 1,305 $ 342,569
Identifiable assets..... $ 2,519,247 $1,574,047 $ 1,363,065 $ -- $267,033 $ (286,204) $5,437,188
- - -------------------------------------------------------------------------------------------------------------------------------
</TABLE>
67
<PAGE> 70
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
19. 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 SFAS 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:
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
December 31, 1995 1994
- - ----------------------------------------------------------------------------------------------
<S> <C> <C>
(In Thousands)
Capitalized costs of
Proved properties........................................... $ 2,871,560 $ 2,796,911
Unproved properties......................................... 270,315 255,490
----------- -----------
Subtotal................................................. 3,141,875 3,052,401
----------- -----------
Accumulated depreciation of
Proved properties........................................... 2,090,498 1,855,398
Unproved properties......................................... 116,256 86,887
----------- -----------
Subtotal................................................. 2,206,754 1,942,285
----------- -----------
Net capitalized costs.................................... $ 935,121 $ 1,110,116
=========== ===========
- - ----------------------------------------------------------------------------------------------
</TABLE>
As described in Note 3, the Company was required to recognize an impairment of
its gas and oil producing properties at March 31, 1995. The non-cash charge
amounted to $226,209,000 and is reflected in the 1995 amounts included above.
TOTAL COSTS INCURRED
The following costs were incurred by subsidiaries in their gas and oil producing
activities during the years 1993 through 1995:
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
(In Thousands)
Property acquisition costs
Proved properties................................. $ 5,824 $ 4,000 $ 132
Unproved properties............................... 9,686 18,998 18,224
--------- --------- ---------
Subtotal....................................... 15,510 22,998 18,356
Exploration costs................................... 50,974 48,514 47,934
Development costs................................... 102,574 82,020 40,516
--------- --------- ---------
Total.......................................... $ 169,058 $ 153,532 $ 106,806
========= ========= =========
- - ----------------------------------------------------------------------------------------------
</TABLE>
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. The Company cautions that
these standardized disclosures do not represent
68
<PAGE> 71
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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.
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
(In Thousands)
Revenues (net of royalties) from:
Sales to nonaffiliated companies................. $ 60,139 $ 201,820 $ 204,614
Transfers to other operations.................... 150,930 55,007 88,241
--------- --------- ---------
Total......................................... 211,069 256,827 292,855
--------- --------- ---------
Less: Production (lifting) costs................... 40,812 42,723 49,177
Depreciation and amortization................ 117,163 150,936 173,171
Impairment of producing properties........... 226,209 -- --
Income tax expense........................... (68,615) 15,446 18,400
--------- --------- ---------
Results of operations.............................. $(104,500) $ 47,722 $ 52,107
========== ========= =========
- - ----------------------------------------------------------------------------------------------
</TABLE>
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, 1993 through 1995, and changes
in the reserves during those years, are shown in the two schedules which follow:
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - ---------------------------------------------------------------------------------------------
<S> <C> <C> <C>
(In Bcf)
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--GAS
At January 1.................................................. 901 885 918
Changes in reserves
Extensions, discoveries and other additions................ 167 111 55
Revisions of previous estimates............................ 17 16 46
Production................................................. (103) (114) (124)
Purchases of gas in place.................................. 7 8 --
Sales of gas in place...................................... (4) (5) (10)
---- ---- ----
At December 31................................................ 985 901 885
==== ==== ====
PROVED DEVELOPED RESERVES*--GAS
At January 1.................................................. 730 761 794
At December 31................................................ 717 730 761
* Net before royalty.
- - ---------------------------------------------------------------------------------------------
</TABLE>
Included in the caption "Extensions, discoveries and other additions" for 1994
and 1995 are 56 and 110 Bcf, respectively, 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, 1993 through 1995,
include United States reserves of 884, 900 and 984 Bcf which, together with the
Canadian
69
<PAGE> 72
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
reserves and the gas reserves reported under "Cost-of-Service Properties," are
as contained in reports of Ralph E. Davis Associates, Inc., independent
geologists.
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
(In Thousand Bbls)
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--OIL
At January 1............................................. 46,255 27,596 29,238
Changes in reserves
Extensions, discoveries and other additions........... 1,965 24,709 1,978
Revisions of previous estimates....................... 1,117 (2,791) 290
Production............................................ (3,132) (3,333) (3,907)
Purchases of oil in place............................. 163 77 --
Sales of oil in place................................. (577) (3) (3)
------ ------ ------
At December 31........................................... 45,791 46,255 27,596
====== ====== ======
PROVED DEVELOPED RESERVES*--OIL
At January 1............................................. 20,379 21,936 27,449
At December 31........................................... 19,838 20,379 21,936
* Net before royalty.
- - ----------------------------------------------------------------------------------------------
</TABLE>
Included in the caption "Extensions, discoveries and other additions" for 1994
are 22,305 thousand barrels of proved undeveloped reserves for which development
costs will be incurred in future years. The foregoing proved developed and
undeveloped oil reserves at December 31, 1993 through 1995, include United
States reserves of 21,917, 40,918 and 39,964 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.
<TABLE>
<CAPTION>
- - -----------------------------------------------------------------------------------------------
December 31, 1995 1994 1993
- - -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
(In Thousands)
Future cash inflows............................ $ 2,668,837 $ 2,303,024 $ 2,336,553
Less: Future development and production
costs........................................ 659,532 626,344 529,592
Future income tax expense................ 602,158 490,079 537,966
----------- ----------- -----------
Future net cash flows.......................... 1,407,147 1,186,601 1,268,995
Less annual discount (10% a year).............. 565,404 482,109 500,732
----------- ----------- -----------
Standardized measure of discounted future
net cash flows............................... $ 841,743 $ 704,492 $ 768,263
=========== =========== ===========
- - -----------------------------------------------------------------------------------------------
</TABLE>
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
70
<PAGE> 73
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
flows, less the tax basis of the properties involved, and giving effect to tax
deductions, or permanent differences and tax credits.
It is not intended that the FASB's standardized measure of discounted future net
cash flows represent the fair market value of the Company'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.
<TABLE>
<CAPTION>
- - ---------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - ---------------------------------------------------------------------------------------------
<S> <C> <C> <C>
(In Thousands)
Standardized measure of discounted future net
cash flows at January 1........................ $ 704,492 $ 768,263 $ 818,352
Changes in the year resulting from
Sales and transfers of gas and oil produced
during the year, less production costs...... (170,257) (214,104) (243,678)
Prices and production and development costs
related to future production................ 150,634 (153,962) 12,635
Extensions, discoveries and other additions,
less production and development costs....... 181,664 144,342 99,662
Previously estimated development costs
incurred during the year.................... 62,958 46,568 4,838
Revisions of previous quantity estimates....... 8,336 4,228 66,506
Accretion of discount.......................... 98,736 108,417 109,287
Income taxes................................... (70,927) 33,029 (41,395)
Purchases and sales of proved reserves in
place-net................................... 1,794 4,122 (5,439)
Other (principally timing of production)....... (125,687) (36,411) (52,505)
--------- --------- ---------
Standardized measure of discounted future net
cash flows at December 31...................... $ 841,743 $ 704,492 $ 768,263
========= ========= =========
- - ---------------------------------------------------------------------------------------------
</TABLE>
COST-OF-SERVICE PROPERTIES
As previously stated, activities subject to cost-of-service rate regulation are
excluded from the foregoing information. At December 31, 1994 and 1995, net
capitalized costs of cost-of-service properties amounted to $25,244,000 and
$14,809,000, respectively. Related proved reserves of gas and oil are located in
the United States, and amounted to 75, 71 and 56 Bcf of gas at December 31, 1993
through 1995, and 287 and 256 thousand barrels of oil at December 31, 1993 and
1994, respectively. There were no cost-of-service oil reserves at December 31,
1995. East Ohio Gas sold all of its remaining gas and oil reserves during 1995.
Production for the years 1993 through 1995 amounted to 6, 6 and 4 Bcf of gas and
29, 24 and 17 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.
71
<PAGE> 74
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 1994 and 1995
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 the Company.
Seasonal fluctuations are further influenced by the timing of price relief
granted under regulation to compensate for certain past cost increases.
<TABLE>
<CAPTION>
- - -----------------------------------------------------------------------------------------------
Quarter
-------------------------------------------------
First* Second** Third*** Fourth
- - -----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
(In Thousands)
1995
Total operating revenues................... $1,191,637 $664,972 $515,142 $935,574
Operating income before income taxes....... (15,918) 2,999 1,956 160,419
Net income (loss).......................... (21,396) (33,512) (11,215) 87,467
Earnings (loss) per share of common
stock.................................... (.23) (.36) (.12) .94
1994
Total operating revenues................... $1,213,596 $582,008 $451,829 $788,595
Operating income before income taxes....... 217,439 22,141 (17,990) 121,815
Net income (loss).......................... 130,918 3,069 (24,557) 73,741
Earnings (loss) per share of common
stock.................................... 1.41 .03 (.26) .79
<FN>
* The 1995 first quarter includes the effect of an impairment of gas and oil producing
properties that reduced operating income before income taxes by $226,209,000 and net income
by $145,000,000, or $1.56 per share (see Note 3 to the consolidated financial statements).
** The 1995 second quarter includes charges related to workforce reductions that reduced
operating income before income taxes by $36,412,000 and net income by $23,668,000, or $.25
per share. Net income was also reduced by the write-down of coal properties amounting to
$20,323,000, or $.22 per share (see Notes 3 and 4 to the consolidated financial
statements).
*** The 1995 third quarter includes charges related to workforce reductions that reduced
operating income before income taxes by $3,457,000 and net income by $2,343,000, or $.02
per share (see Note 4 to the consolidated financial statements).
- - -----------------------------------------------------------------------------------------------
</TABLE>
72
<PAGE> 75
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Concl.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
(C) COMMON STOCK MARKET PRICES AND RELATED MATTERS
At December 31, 1995, there were 38,516 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 1994 and
1995 follow. Restrictions on the payment of dividends are discussed in Note 12.
<TABLE>
<CAPTION>
- - ----------------------------------------------------------------------------------------------
Quarter
-------------------------------------
First Second Third Fourth
- - ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Market Price Range
1995 --High.......................................... $38 3/4 $40 $41 $46 1/4
--Low........................................... $33 5/8 $35 1/8 $35 3/4 $37 3/8
1994 --High.......................................... $47 $40 $41 1/8 $39
--Low........................................... $38 3/4 $36 3/4 $37 1/2 $33 3/8
Dividends Declared per Share
1995................................................. $ .485 $ .485 $ .485 $ .485
1994................................................. $ .485 $ .485 $ .485 $ .485
- - ----------------------------------------------------------------------------------------------
</TABLE>
73
<PAGE> 76
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
Not applicable
PART III
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 16 of this Report.
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. 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. 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. 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
1995, the year for which this Form 10-K is being filed.
On January 23, 1996, the Company filed a Current Report on Form 8-K with the SEC
regarding a Rights Agreement (see Note 10 to the consolidated financial
statements, page 58).
DOCUMENTS FILED AS A PART OF THIS REPORT
Financial Statements
All of the financial statements filed as a part of this Report are included in
ITEM 8 and reference is made to the index on page 39.
74
<PAGE> 77
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
constituting part of the Registration Statements on Form S-3 (Nos. 33-1040,
33-52585 and 33-63931) and Form S-8 (Nos. 2-77204, 2-97948, 33-40478 and
33-44892) of Consolidated Natural Gas Company of our report dated February 20,
1996, appearing on page 40 of this Form 10-K. We also consent to the references
to us under the heading "Experts" in such Prospectuses.
PRICE WATERHOUSE LLP
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
March 27, 1996
<TABLE>
<CAPTION>
EXHIBITS
- - ---------------------------------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- - ---------------------------------------------------------------------------------------------
<C> <S> <C>
(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
(4C) Description of Consolidated Natural Gas Company Rights Agreement, is hereby
incorporated by reference to Exhibit 1 to the Current Report on Form 8-K
filed on January 23, 1996
</TABLE>
75
<PAGE> 78
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
<TABLE>
<CAPTION>
EXHIBITS (Continued)
- - -----------------------------------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- - -----------------------------------------------------------------------------------------------
<C> <S> <C> <C>
(10) Material Contracts:
The following exhibits are filed with this Form 10-K by being incorporated by
reference to their filing in the Company's Forms 10-K for previous years. The
following table indicates for each of such exhibits the Form 10-K, File No. 1-3196,
where such exhibit was filed. Exhibits not included in this table are filed herewith
or incorporated by reference to another source as indicated below.
Form 10-K Exhibit Number Reporting Year of Form 10-K
(10A), (10B), (10C), (10E), (10G) 1987
(10H), (10 I) 1989
(10F), (10J), (10L) 1994
(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, as
amended December 12, 1995, is filed herewith
(10E) Form of agreement between Consolidated Natural Gas Company and non-employee
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, as amended December 13, 1994
(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, as amended December 13, 1994
(10K) Unfunded Supplemental Benefit Plan for Employees of Consolidated Natural Gas
Company and Its Participating Subsidiaries Who Are Not Represented by a
Recognized Union, as amended December 12, 1995, is filed herewith
(10L) Description of Consolidated Natural Gas Company Non-Employee Directors'
Restricted Stock Plan
</TABLE>
76
<PAGE> 79
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Concluded)
<TABLE>
<CAPTION>
EXHIBITS (Concluded)
- - -----------------------------------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- - -----------------------------------------------------------------------------------------------
<C> <S> <C>
(10M) Description of Consolidated Natural Gas Company 1995 Employee Stock Incentive
Plan, is filed herewith
(10N) Form of Change of Control Employment Agreement between Consolidated Natural
Gas Company and certain employees dated December 12, 1995, is filed herewith
(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, 1993 through 1995, 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 1991-1995, 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 12, 1996, 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, 1995, are filed herewith
(23B) Consent of Price Waterhouse LLP--included as part of this ITEM 14
(27) Financial Data Schedule, is filed herewith
- - -----------------------------------------------------------------------------------------------
</TABLE>
77
<PAGE> 80
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 27, 1996 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 27, 1996.
<TABLE>
<S> <C>
GEORGE A. DAVIDSON, JR. PAUL E. LEGO
- - ------------------------------------------------- -------------------------------------------------
(George A. Davidson, Jr.) (Paul E. Lego)
Chairman of the Board Director
and Chief Executive Officer,
and Director MARGARET A. MCKENNA
-------------------------------------------------
D. M. WESTFALL (Margaret A. McKenna)
- - ------------------------------------------------- Director
(D. M. Westfall)
Senior Vice President STEVEN A. MINTER
and Chief Financial Officer -------------------------------------------------
(Steven A. Minter)
S. R. MCGREEVY Director
- - -------------------------------------------------
(S. R. McGreevy) WALTER R. PEIRSON
Vice President, Accounting -------------------------------------------------
and Financial Control (Walter R. Peirson)
Director
WILLIAM S. BARRACK, JR.
- - ------------------------------------------------- RICHARD P. SIMMONS
(William S. Barrack, Jr.) -------------------------------------------------
Director (Richard P. Simmons)
Director
J. W. CONNOLLY
- - ------------------------------------------------- LOIS WYSE
(J. W. Connolly) -------------------------------------------------
Director (Lois Wyse)
Director
RAY J. GROVES
- - -------------------------------------------------
(Ray J. Groves)
Director
</TABLE>
78
<PAGE> 81
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, 1995 (Page 18)
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 delivery connections with customers and gas receipt or delivery
connections with other pipelines. Also shown on the map are the general
locations of certain compressor facilities and underground storage fields.
Map of Exploration and Production Areas at December 31, 1995 (Page 19)
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.
<PAGE> 82
<TABLE>
<CAPTION>
EXHIBIT INDEX
- - ---------------------------------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- - ---------------------------------------------------------------------------------------------
<C> <S> <C>
(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
(4C) Description of Consolidated Natural Gas Company Rights Agreement, is hereby
incorporated by reference to Exhibit 1 to the Current Report on Form 8-K
filed on January 23, 1996
</TABLE>
<PAGE> 83
<TABLE>
<CAPTION>
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SEC
Exhibit
Number Description of Exhibit
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<C> <S> <C>
(10) Material Contracts:
The following exhibits are filed with this Form 10-K by being incorporated by
reference to their filing in the Company's Forms 10-K for previous years. The
following table indicates for each of such exhibits the Form 10-K, File No. 1-3196,
where such exhibit was filed. Exhibits not included in this table are filed herewith
or incorporated by reference to another source as indicated below.
Form 10-K Exhibit Number Reporting Year of Form 10-K
(10A), (10B), (10C), (10E), (10G) 1987
(10H), (10 I) 1989
(10F), (10J), (10L) 1994
(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, as
amended December 12, 1995, is filed herewith
(10E) Form of agreement between Consolidated Natural Gas Company and non-employee
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, as amended December 13, 1994
(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, as amended December 13, 1994
(10K) Unfunded Supplemental Benefit Plan for Employees of Consolidated Natural Gas
Company and Its Participating Subsidiaries Who Are Not Represented by a
Recognized Union, as amended December 12, 1995, is filed herewith
(10L) Description of Consolidated Natural Gas Company Non-Employee Directors'
Restricted Stock Plan
</TABLE>
<PAGE> 84
<TABLE>
<CAPTION>
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SEC
Exhibit
Number Description of Exhibit
- - -----------------------------------------------------------------------------------------------
<C> <S> <C>
(10M) Description of Consolidated Natural Gas Company 1995 Employee Stock Incentive
Plan, is filed herewith
(10N) Form of Change of Control Employment Agreement between Consolidated Natural
Gas Company and certain employees dated December 12, 1995, is filed herewith
(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, 1993 through 1995, 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 1991-1995, 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 12, 1996, 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, 1995, are filed herewith
(23B) Consent of Price Waterhouse LLP--included as part of ITEM 14
(27) Financial Data Schedule, is filed herewith
- - -----------------------------------------------------------------------------------------------
</TABLE>
<PAGE> 1
EXHIBIT 4.A(1)
INDENTURES OF CONSOLIDATED NATURAL GAS COMPANY
The Indentures and Supplemental Indentures between Consolidated Natural Gas
Company and its debenture Trustees, as listed below, are incorporated by
reference to material previously filed with the Commission as indicated:
Manufacturers Hanover Trust Company (now Chemical Bank)
Indenture dated as of May 1, 1971 (Exhibit (5) to Certificate
of Notification at Commission File No. 70- 5012)
Eleventh Supplemental Indenture thereto dated as of December 1,
1986 (Exhibit (5) to Certificate of Notification at Commission
File No. 70-7079)
Thirteenth Supplemental Indenture thereto dated as of February 1,
1989 (Exhibit (5) to Certificate of Notification at Commission
File No. 70-7336)
Fourteenth Supplemental Indenture thereto dated as of June 1, 1989
(Exhibit (5) to Certificate of Notification at Commission File
No. 70-7336)
Fifteenth Supplemental Indenture thereto dated as of October 1,
1989 (Exhibit (5) to Certificate of Notification at Commission
File No. 70-7651)
Sixteenth Supplemental Indenture thereto dated as of October 1,
1992 (Exhibit (4) to Certificate of Notification at Commission
File No. 70-7651)
Seventeenth Supplemental Indenture thereto dated as of August 1,
1993 (Exhibit (4) to Certificate of Notification at Commission
File No. 70-8167)
Eighteenth Supplemental Indenture thereto dated as of December 1,
1993 (Exhibit (4) to Certificate of Notification at Commission
File No. 70-8167)
United States Trust Company of New York
Indenture dated as of April 1, 1995 (Exhibit (4) to Certificate of
Notification at Commission File No. 70-8107)
The Chase Manhattan Bank (National Association)
Indenture dated as of December 15, 1990 (Exhibit (4A)(1) to
Consolidated Natural Gas Company's Form 10-K for the year ended
December 31, 1990, File No. 1-3196)
<PAGE> 1
SYSTEM SHORT SERVICE SUPPLEMENTAL RETIREMENT PLAN
FOR CERTAIN MANAGEMENT EMPLOYEES OF
CONSOLIDATED NATURAL GAS COMPANY
AND ITS
PARTICIPATING SUBSIDIARIES (THE "PLAN")
Effective June 1, 1976 and
Amended November 15, 1977 and January 1, 1984
and December 12, 1995
SECTION 1. PURPOSE. The purpose of this Plan is to provide supplemental
retirement benefits on an unfunded, contractual basis for certain management
employees whose commencement of service in the Consolidated Natural Gas System
occurred after the employee had acquired experience and displayed talents of
considerable value to Consolidated, and who in joining Consolidated, gave up
valuable pension benefits. Such supplemental retirement benefits are expected
to reduce the high starting salaries ordinarily sought by employees recruited
from outside companies (to compensate for the loss of service credits and
pension benefits). This in turn will help us maintain our salary scales for the
jobs involved. Upon retirement from Consolidated, the supplemental benefit will
bring pensions closer to the amounts that would have been received had the
employee's entire career been with Consolidated.
SECTION 2. EMPLOYEES COVERED. Employees eligible for benefits under this
Plan ("Participant") shall be those employees who (a) are designated by the
Board of Directors as being eligible for this Plan and (b) were recruited for
the executive payroll or who in the future are recruited for the executive
payroll, of one or more companies in the System. This Plan is intended to cover
only a select group of management or highly compensated employees. It is
intended primarily to provide deferred compensation to such group.
SECTION 3. VESTING. A Participant's benefits under this Plan shall vest
on the earliest to occur of the following if the Participant continues in
employment with one or more companies in the System on the executive payroll
through such date:
(i) The Participant's retirement in accordance with the retirement
regulations of the System Pension Plan of Consolidated Natural Gas Company and
Its
<PAGE> 2
Participating Subsidiaries for Employees who are Not Represented by a Recognized
Union ("Consolidated Plan"); or
(ii) The Participant's achievement of a fifteen-year Period of
Employment. For purposes of this Plan, "Period of Employment" shall have the
meaning ascribed to such term in the Consolidated Plan. After the fifteen-year
period has been achieved, the rights of the employee shall be vested. Except as
set forth below in the case of a Change of Control of the Company, prior to such
time, an employee will have no enforceable rights under this Plan, and failure
to achieve the fifteen-year period will automatically result in the complete
forfeiture of all rights hereunder, unless the employee retires in accordance
with the retirement regulations in the Consolidated Plan.
Notwithstanding the foregoing, in the event of a Change of
Control of the Company, a Participant's accrued benefit under the Plan shall
vest in full upon the latter of 1) the date of the Change of Control or 2)
completion by the Participant of a 5-year Period of Employment. For purposes
of this section, "Change of Control" shall have the meaning ascribed to it
in the 1991 Stock Incentive Plan.
SECTION 4. BENEFIT FORMULA. Supplemental retirement benefits payable on a
single life form at retirement or other applicable date to a Participant under
this Plan shall be an annual amount equal to the lesser of (a) or (b) below,
reduced by (c) below:
(a) The Participant's annual benefit determined under the formulas
contained in the Consolidated Plan on the basis of commencement at retirement or
other applicable date on the single life form but substituting for the
percentage of "Final Average Annual Earnings" in Section 6A(1)(a)(i) of the
Consolidated Plan a percentage equal to 133-1/3% thereof.
(b) (1) In the case of retirement at or after age 65 - 55% of
the Participant's "Final Average Annual Earnings" (as defined in the
Consolidated Plan) less such
-2-
<PAGE> 3
portion of the Participant's annual Primary Social Security Benefit payable at
retirement. (Social Security Benefit);
(2) In the case of early retirement, the difference between 55% and
the percentage that would have been applicable for the calculation of the
employee's regular pension at age 65 shall remain fixed for any retirement
between age 60 and 65. This difference is added to the regular percentage
applicable at retirement and the resulting percentage is applied to the "Final
Average Annual Earnings." From the resulting total is subtracted the Social
Security Benefit. Provided, however, that such amount shall be reduced by
applying the reduction percentage, if any, applicable to such Participant
because of early commencement of his benefits under the Consolidated Plan.
(c) The aggregate annual pension benefit to which the Participant is
entitled under the Consolidated Plan and the Unfunded Supplemental Benefit Plan
For Employees of Consolidated Natural Gas Company and its Participating
Subsidiaries who are not Represented by a Recognized Union, (ERISA EXCESS PLAN).
(d) For purposes of this Plan, calculation of "Final Average Annual
Earnings" will be made by ignoring the limitations imposed by Sections
401(a)(17) and 415 of the Internal Revenue Code of 1986, as amended.
SECTION 5. FORM OF BENEFIT PAYMENTS. Benefits will be payable in monthly
installments beginning when benefits commence under the Consolidated Plan, and
will be payable commencing upon retirement in accordance with the method of
payment in effect for the Participant under the Consolidated Plan and adjusted
on the basis of the same actuarial factors applicable to such method under the
Consolidated Plan, in a single lump sum or by a combination of such methods, as
determined by the Committee in its discretion. Lump sum payments shall be
calculated using the Pension Benefit Guaranty Corporation interest rates for
valuing immediate annuities that are in effect at the Participant's retirement
date and the UP-1984 mortality table.
-3-
<PAGE> 4
SECTION 6. PAYMENT OF BENEFITS. Benefits under the Plan are unfunded and
unsecured, and shall be paid out of the general assets of the employers in the
System in the same proportion as such employers share in the Participant's Final
Average Annual Earnings, as defined in the Consolidated Plan. The rights of a
Participant or anyone claiming through said Participant shall be those of an
unsecured creditor. Should the employer choose to invest in specific assets
with a view toward providing a source of funds to pay benefits hereunder, any
such asset shall be held in the employer's name and shall be subject to the
claims of general creditors, and no Participant shall have any special claim or
lien on any such asset. No trust or security interests are created by this
Plan. Any investing as outlined above may be discontinued at any time without
regard to the sufficiency of any investments to pay benefits hereunder.
SECTION 7. ADMINISTRATION. (a) This Plan shall be administered by the
Annuities and Benefits Committee of the Consolidated Natural Gas Company (the
"Committee"). The Committee shall have power to interpret the Plan and
determine eligibility for benefits. The Committee may appoint agents to assist
in the administration of the Plan, and to do those things necessary to carry out
the Plan.
(b) Claims shall be handled as follows:
(1) All claims for benefits shall be in writing and shall be
filed with the Committee.
(2) If the Committee wholly or partially denies a claim for
benefits, the Committee shall within 90 days after the Plan's receipt of the
claim give the claimant written notice setting forth in understandable language:
(i) the specific reason(s) for the denial; (ii) specific reference to pertinent
Plan provisions on which the denial is based; (iii) a description of any
additional material or information which must be submitted to perfect the claim;
and (iv) an explanation of the Plan's review procedure, as set forth below.
(c) The claimant shall have 60 days after the day on which such
written notice of denial is handed or mailed to the claimant in which to apply
to the Committee in
-4-
<PAGE> 5
writing for a full and fair review of the denial of the claim. In connection
with such review, the claimant (or a representative) shall be afforded a
reasonable opportunity to review pertinent documents, and may submit issues and
comments in writing.
(d) The Committee shall issue its decision on review promptly and
within 60 days after the Plan's receipt of the request for review, unless
special circumstances require an extension to not later than 120 days after
receipt of the request for review. Written notice of such extension shall be
furnished to the claimant prior to the commencement of the extension. The
decision shall be in writing and shall, in understandable language, set forth
specific reasons for the decision and specific references to pertinent Plan
provisions on which the decision is based.
SECTION 8. NONASSIGNABILITY. Benefits under this Plan may not be assigned
or alienated.
SECTION 9. AMENDMENT OR TERMINATION. Consolidated Natural Gas Company and
Its Participating Subsidiaries reserve the right to amend or discontinue this
Plan at any time in whole or in part. No such action, when considered in
conjunction with corresponding changes in the retirement benefits provided under
other System programs, shall have the effect of reducing the aggregate
retirement benefit which has accrued under all System retirement programs to the
date of such action based on service with the System performed to such date.
SECTION 10. APPLICABLE LAW. This Plan shall be construed in accordance
with the laws of the Commonwealth of Pennsylvania except where preempted by
federal law.
SECTION 11. EFFECT ON EMPLOYMENT RIGHTS. Nothing contained in the Plan
shall be deemed to give any Participant or employee the right to be retained in
the
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<PAGE> 6
service of the Company or any subsidiary, or to interfere with the right of the
employer to discharge any employee at any time for any reason, regardless of
the effect such a discharge would have upon participation in this Plan or the
benefit which would be payable hereunder.
SECTION 12. NO SALARY REDUCTION. The Plan does not involve a reduction in
salary for the eligible employees, nor does it involve the foregoing of an
increase in future salary by the Participant.
SECTION 13. BINDING ON SUCCESSORS. This Plan shall be binding upon and
inure to the benefit of the Company, its subsidiaries and successors and
assigns, and each Participant and such Participant's heirs, executors,
administrators and legal representatives.
SECTION 14. CHANGE IN CONTROL. Upon a Change in Control, as defined in
the Trust Agreement between Consolidated Natural Gas Company and Mellon Bank
effective June 1, 1995 (the "Rabbi Trust") the Consolidated Natural Gas Company
shall, as soon as possible, but in no event longer than 30 days following the
Change or Control, do the following:
(a) Add this Plan to the Rabbi Trust by establishing a new account
under said Rabbi Trust.
(b) Make an irrevocable contribution to the Rabbi Trust in an amount
that is sufficient to pay each Plan participant or beneficiary the benefits to
which the Plan participants or their beneficiaries would be entitled pursuant to
the terms of the Plan as of the date on which the Change in Control occurred.
SECTION 15. EFFECTIVE DATE. This Plan is effective June 1, 1976, and
amended November 15, 1977 and January 1, 1984 and December 12, 1995.
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<PAGE> 1
UNFUNDED SUPPLEMENTAL BENEFIT PLAN
FOR EMPLOYEES OF
CONSOLIDATED NATURAL GAS COMPANY AND ITS
PARTICIPATING SUBSIDIARIES WHO ARE NOT
REPRESENTED BY A RECOGNIZED UNION
(ERISA EXCESS PLAN)
EFFECTIVE JANUARY 1, 1976
AS AMENDED EFFECTIVE APRIL 15, 1985
AND DECEMBER 12, 1995
<PAGE> 2
TABLE OF CONTENTS
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<TABLE>
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1. DEFINITIONS.............................................................4
1.1. Act...........................................................4
1.2. Board.........................................................4
1.3. Code..........................................................4
1.4. Committee.....................................................4
1.5. Company.......................................................4
1.6. Consolidated System...........................................2
1.7. Effective Date................................................2
1.8. Employee......................................................2
1.9. Limitations...................................................2
1.10. Pension Plan.................................................2
1.11. Plan.........................................................2
1.12. Thrift Plan..................................................2
2. PURPOSE OF THE PLAN.....................................................3
2.1. Purpose.......................................................3
3. ELIGIBILITY.............................................................3
3.1. Eligibility...................................................3
4. BENEFITS................................................................4
4.1. Amount of Benefits............................................4
4.2. Form of Benefit Payments......................................5
4.3. Time of Benefit Payments......................................5
4.4. Benefits Unfunded.............................................6
4.5. Accounts......................................................6
5. ADMINISTRATION..........................................................6
5.1. Duties of the Committee.......................................6
5.2. Claims Procedure..............................................7
6. AMENDMENT AND TERMINATION...............................................8
6.1. Amendment and Termination.....................................8
6.2. Contractual Obligation........................................8
</TABLE>
<PAGE> 3
<TABLE>
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Page
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7. MISCELLANEOUS...........................................................8
7.1. No Employment Rights..........................................8
7.2. Assignment....................................................8
7.3. Law Applicable................................................8
7.4. No Salary Reduction...........................................9
7.5. Binding on Successors.........................................9
7.6. Change in Control.............................................9
</TABLE>
<PAGE> 4
UNFUNDED SUPPLEMENTAL BENEFIT PLAN
FOR EMPLOYEES OF
CONSOLIDATED NATURAL GAS COMPANY AND ITS
PARTICIPATING SUBSIDIARIES WHO ARE NOT
REPRESENTED BY A RECOGNIZED UNION
CONSOLIDATED NATURAL GAS COMPANY hereby establishes the Unfunded
Supplemental Benefit Plan for Employees of Consolidated Natural Gas Company and
Its Participating Subsidiaries Who Are Not Represented by a Recognized Union,
upon the following terms and conditions:
1. DEFINITIONS
The words and phrases defined hereinafter shall have the following meaning:
.1. Act.
The Employee Retirement Income Security Act of 1974, as amended, or
as it may be amended from time to time.
.2. Board.
The Board of Directors of Consolidated Natural Gas Company.
.3. Code.
The Internal Revenue Code of 1986, as amended, or as it may be
amended from time to time.
.4. Committee.
The Annuities and Benefits Committee of Consolidated Natural Gas
Company.
.5. Company.
Consolidated Natural Gas Company.
<PAGE> 5
.6. Consolidated System.
The Company and all subsidiary and/or affiliated corporations which
are participating employers under the Pension Plan and the Thrift Plan.
.7. Effective Date.
January 1, 1976; provided that amendments will be effective only
after the date of adoption.
.8. Employee.
A participant in the Pension Plan or the Thrift Plan.
.9. Limitations.
The provisions of the Pension Plan and/or Thrift Plan which
implement the requirements of Code Section 401(a)(17) and Code Section 415.
.10. Pension Plan.
The System Pension Plan of Consolidated Natural Gas Company and Its
Participating Subsidiaries for Employees Who Are Not Represented by a Recognized
Union.
.11. Plan.
The Unfunded Supplemental Benefit Plan for Employees of
Consolidated Natural Gas Company and Its Participating Subsidiaries Who Are Not
Represented by a Recognized Union, as set forth herein.
.12. Thrift Plan.
The System Thrift Plan of Consolidated Natural Gas Company and Its
Participating Subsidiaries for Employees Who Are Not Represented by a Recognized
Union, providing for "Thrift Contributions" elected by the Employee and
"Matching Contributions" which terms when used herein shall have the meaning set
forth in the Thrift Plan.
2. PURPOSE OF THE PLAN
.1. Purpose.
The purpose of the Plan is to provide retirement benefits to
certain employees according to the benefit formulas of the Pension Plan and the
Thrift Plan without
2
<PAGE> 6
regard to certain artificial Code rules that limit the amount of earnings that
can be counted, or the total amount of benefit that can be paid, by a qualified
plan.
This Plan consists of two separate plans for purposes of Title I of
the Act (i) with respect to the benefits provided by reason of Section
401(a)(17) of the Code, an unfunded plan maintained for the purpose of providing
deferred compensation for a select group of management or highly compensated
employees, and (2) with respect to the benefits provided by reason of Section
415 of the Code, an unfunded excess benefit plan.
3. ELIGIBILITY
.1. Eligibility.
Any Employee or the beneficiaries of any Employee eligible to
receive benefits from the Pension Plan and/or the Thrift Plan shall be eligible
to receive benefits under this Plan if the benefits otherwise prescribed cannot
fully be provided by the Pension Plan and/or the Thrift Plan because of the
Limitations. Notwithstanding the generality of the foregoing, it is recognized
and intended that the group of persons who will benefit under the Plan are and
will be a select group of management or highly compensated employees, and that
the Plan is intended to provide deferred compensation to such eligible
employees.
4. BENEFITS
.1. Amount of Benefits.
The amount of the benefit payable under this Plan shall be equal to
the sum of the following amounts:
(a) The single sum actuarial value of the benefit which, is the
difference between:
(1) the benefit payable under the Pension Plan when
calculated under the Pension Plan without taking into account the provisions of
the Pension Plan dealing with limits on the amount of Earnings which can be
counted for purposes of Section 401(a)(17) of the Code, and limits on benefits
imposed by Section 415 of the Code; and
3
<PAGE> 7
(2) the benefit actually payable under the Pension
Plan, taking into account said 401(a)(17) and 415 limitations;
(b) An amount equal to the sum of (1) and (2) below reduced by
(3) below:
(1) the Matching Contributions which would have been
made on behalf of the Employee under the Thrift Plan if the Limitations were
inapplicable, based on the level of Thrift Contributions in effect for the
Employee;
(2) the net investment gain, if any, which would have
been earned pursuant to the Employee's investment elections under the Thrift
Plan if the Matching Contributions described in (1) above plus the Employee's
contributions, had been made to the Thrift Plan;
(3) an amount equal to the net investment loss, if any,
which would have been incurred pursuant to the Employee's investment elections
under the Thrift Plan if the Matching Contributions and employee contributions
described in (2) above had been made to the Thrift Plan.
(c) For Employees who began accruing benefits under Section
4.1(b) of this Plan before April 15, 1985, an amount determined by the Committee
to be necessary to compensate the Employee for any excess of the income tax
liability incurred by the Employee because of the payments to the Employee
described in subsections (b) and (c) of this Section 4.1 over the tax which
would have been incurred with respect to such payments if they had been received
as part of a taxable lump sum distribution of the Employee's entire interest in
the Thrift Plan.
.2. Form of Benefit Payments.
Benefits payable to or on behalf of an Employee as determined under
Section 4.1 shall be paid in a single lump sum or installments in cash or common
stock of the Company, in the form of a single life annuity or joint and survivor
annuity, or by a combination of such methods, as determined by the Committee in
its discretion.
4
<PAGE> 8
.3. Time of Benefit Payments.
(a) Except as set forth in Section 4.3(b) hereof, benefits due
under this Plan shall be paid at such time or times following the Employee's
retirement as the Committee in its discretion determines.
(b) Following a Change of Control (as defined in the Company's
1991 Stock Incentive Plan), benefits will be paid in a lump sum within 10 days
after the earlier to occur of: the date the Participant reaches Normal
Retirement Age (as defined in the Pension Plan) or the date the Participant is
no longer employed by any member of the Consolidated System.
.4. Benefits Unfunded.
Benefits payable under this Plan are unfunded and unsecured, and
shall be paid by the Company out of its general assets. The rights of an
Employee and anyone claiming through said Employee shall be those of an
unsecured general creditor of the Company. Should the Company choose to invest
in specific assets with a view toward providing a source of funds to pay
benefits hereunder, any such asset shall be held in the Company's name and shall
be subject to the claims of its general creditors, and no Employee or former
Employee shall have any special claim or lien on any such asset. No trust or
security interests are created by this document. Any investing as outlined
above may be discontinued by the Company at any time, it being understood that
no such obligation exists.
.5. Accounts.
(a) The Committee shall cause an account to be kept for each
eligible Employee. The account shall reflect the amounts which would be payable
under Section 4.1(b).
(b) The account shall be considered a bookkeeping account only,
kept solely for the convenience of the Plan. The keeping of an account shall
not in any way be interpreted to mean that an Employee has any right to such
account or that there are assets set aside for such account.
5
<PAGE> 9
5. ADMINISTRATION
.1. Duties of the Committee.
This Plan shall be administered by the Committee in accordance with
its terms and purposes. The Committee shall have discretion to interpret this
Plan and to determine the amount and manner of payment of the benefits due to or
on behalf of each Employee from this Plan and shall cause them to be paid
accordingly.
.2. Claims Procedure.
(a) All claims for benefits shall be in writing and shall be
filed with the Committee.
(b) If the Committee wholly or partially denies an Employee's
claim for benefits, the Committee shall within 90 days after the Plan's receipt
of the claim give the claimant written notice setting forth in understandable
language: (i) the specific reason(s) for the denial; (ii) specific reference to
pertinent Plan provisions on which the denial is based; (iii) a description of
any additional material or information which must be submitted to perfect the
claim; and (iv) an explanation of the Plan's review procedure, as set forth
below.
(c) The claimant shall have 60 days after the day on which such
written notice of denial is handled or mailed to the claimant in which to apply
to the Committee in writing for a full and fair review of the denial of the
claim. In connection with such review, the claimant (or representative) shall
be afforded a reasonable opportunity to review pertinent documents, and may
submit issues and comments in writing with the application for review.
(d) The Committee shall issue its decision on review promptly
and within 60 days after the Plan's receipt of the request for review, unless
special circumstances require an extension to not later than 120 days after
receipt of the request for review. Written notice of such extension shall be
furnished to the claimant prior to the commencement of the extension. The
decision shall be in writing and shall in understandable language set forth
specific reasons for the decision and specific references to pertinent Plan
provisions on which the decision is based.
6
<PAGE> 10
6. AMENDMENT AND TERMINATION
.1. Amendment and Termination.
While the Company intends to maintain this Plan in conjunction with
the Pension Plan and the Thrift Plan for as long as necessary, the Company
reserves the right to amend and/or terminate it at any time for whatever reasons
it may deem appropriate.
.2. Contractual Obligation.
Notwithstanding Section 6.1, the Company hereby makes a contractual
commitment to pay the benefits under this Plan.
7. MISCELLANEOUS
.1. No Employment Rights.
Nothing contained in this Plan shall be construed as a contract of
employment between the Company or any corporation in the Consolidated System and
any Employee, or as a right of any Employee to be continued in the employment of
the Company, or as a limitation of the right of the Company to discharge any of
its Employees with or without cause.
.2. Assignment.
The benefits payable under this Plan may not be assigned or
alienated, nor shall they be subject to garnishment, attachment, execution or
levy of any kind.
.3. Law Applicable.
This Plan shall be governed by the laws of the Commonwealth of
Pennsylvania except where preempted by federal law.
.4. No Salary Reduction.
The Plan does not involve a reduction in salary for the Employee,
nor the forgoing of an increase in future salary by the Employee.
7
<PAGE> 11
.5. Binding on Successors.
The Plan shall be binding upon and inure to the benefit of the
Company, its successors and assigns, and each Employee and his or her heirs,
executors, administrators and legal representatives.
.6. Change in Control.
Upon a Change in Control, as defined in the Trust Agreement between
Consolidated Natural Gas Company and Mellon Bank effective June 1, 1995 (the
"Rabbi Trust") the Consolidated Natural Gas Company shall, as soon as possible,
but in no event longer than 30 days following the Change in Control, do the
following:
(1) Add this Plan to the Rabbi Trust by establishing a new
account under said Rabbi Trust.
(2) Make an irrevocable contribution to the Rabbi Trust in an
amount that is sufficient to pay each Plan participant or beneficiary the
benefits to which Plan participants or their beneficiaries would be entitled
pursuant to the terms of the Plan as of the date on which the Change in Control
occurred.
CONSOLIDATED NATURAL GAS
COMPANY
By
--------------------------
ATTEST:
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CONSOLIDATED NATURAL GAS COMPANY
1995 EMPLOYEE STOCK INCENTIVE PLAN
SECTION 1. PURPOSES.
1.01 The purposes of the CNG 1995 Employee Stock Incentive
Plan (the "Plan") are to enable Consolidated Natural Gas Company (together with
any successor thereto, the "Company"), and its Affiliates to attract and retain
key employees who are not officers or directors of the Company for purposes of
Section 16 of the Exchange Act and the best available personnel for positions
of substantial responsibility, to reward such employees for superior
performance and to strengthen the mutuality of interests between such employees
and the Company's shareholders. The Plan is designed to meet this intent by
providing such employees with a proprietary interest in pursuing the long-term
growth, profitability and financial success of the Company in order to provide
them with additional motivation to continue in the Company's employ and to
further its profitable growth.
SECTION 2. DEFINITIONS; CONSTRUCTION.
2.01 DEFINITIONS. In addition to the terms defined elsewhere
in the Plan, the following terms as used in the Plan shall have the following
meanings when used with initial capital letters:
2.01.1 "Affiliate" means any entity other than the
Company in which the Company owns, directly or indirectly, at
least 20 percent of the combined voting power of all classes of
stock of such entity or at least 20 percent of the ownership
interests in such entity.
2.01.2 "Award" means any Option, Stock Appreciation
Right, Restricted Stock, Deferred Stock, Performance Award, or
Dividend Equivalent, or any other right or interest relating to
Shares or cash granted under the Plan.
2.01.3 "Award Agreement" means any written agreement,
contract or other instrument or document evidencing an Award.
2.01.4 "Board" means the Company's Board of Directors.
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2.01.5 "Code" means the Internal Revenue Code of 1986,
as amended from time to time, together with rules, regulations
and interpretations promulgated thereunder.
2.01.6 "Committee" means the Compensation and Benefits
Committee or such other Committee of the Board as may be
designated by the Board to administer the Plan, as referred to
in Section 3.01 hereof.
2.01.7 "Common Stock" means the Common Stock, $2.75 par
value, and such other securities of the Company as may be
substituted for Shares pursuant to Section 8.01 hereof.
2.01.8 "Deferred Stock" means Shares, granted under
Section 6.05 hereof, receipt of which is deferred for a
specified deferral period.
2.01.9 "Disability" means disability as determined
under procedures established by the Committee for purposes of
the Plan.
2.01.10 "Dividend Equivalent" means a right, granted
under Section 6.07 hereof, to receive interest or dividends, or
interest or dividend equivalents.
2.01.11 "Exchange Act" means the Securities Exchange
Act of 1934, as amended.
2.01.12 "Fair Market Value" means, as of any date, with
respect to Shares at any time that Shares are listed on the New
York Stock Exchange, the closing sale price as of that date or
nearest preceding date on which a sale was reported; provided,
however, if in a given case the Fair Market Value of Shares is
not an even multiple of one dollar, such Fair Market Value may
be rounded up or down to a whole number if specified by the
Committee; and, with respect to Shares at any time that Shares
are not listed on the New York Stock Exchange, or property other
than Shares, the fair market value of such Shares or other
property determined by such methods or procedures as shall be
established from time to time by the Committee.
2.01.13 "Option" means a right, granted under Section
6.02 hereof, to purchase Shares or other Awards at a specified
price during specified time periods. All Options shall be
non-qualified stock options; i.e.,
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options that do not meet the requirements of Section 422 of the
Code.
2.01.14 "Participant" means a key employee of the
Company or any Affiliate who is not a director or officer of the
Company for purposes of Section 16 of the Exchange Act and who
is granted an Award under the Plan.
2.01.15 "Performance Award" means a right, granted
under Section 6.06 hereof, to receive Awards based upon
performance criteria specified by the Committee.
2.01.16 "Person" shall have the meaning assigned in the
Exchange Act.
2.01.17 "Restricted Stock" means Shares, granted under
Section 6.04 hereof, that are subject to certain restrictions.
2.01.18 "Rule 16b-3" means Rule 16b-3, as amended from
time to time, or any successor to such Rule promulgated by the
Securities and Exchange Commission under Section 16 of the
Exchange Act.
2.01.19 "Shares" means the Common Stock of the Company,
$2.75 par value, and such other securities of the Company as may
be substituted for Shares pursuant to Section 8.01 hereof.
2.01.20 "Stock Appreciation Right" means a right,
granted under Section 6.03 hereof, to be paid an amount measured
by the appreciation in the Fair Market Value of Shares from the
date of grant to the date of exercise.
Definitions of the terms "Change of Control," "Change of Control
Price," "Potential Change of Control," "Related Party" and "Voting Securities"
are set forth in Section 9.03 hereof.
2.02 CONSTRUCTION. For purposes of the Plan, the following
rules of construction shall apply:
2.02.1 The word "or" is disjunctive but not necessarily
exclusive.
2.02.2 Words in the singular include the plural; words
in the plural include the singular; and words in the neuter
gender include the masculine and feminine
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genders and words in the masculine or feminine gender include
the other and neuter genders.
SECTION 3. ADMINISTRATION.
3.01 The Plan shall be administered by the Committee. The
Committee shall have full and final authority to take the following actions, in
each case subject to and consistent with the provisions of the Plan:
(i) to designate Participants;
(ii) to determine the type or types of Awards to be
granted to each Participant;
(iii) to determine the number of Awards to be granted,
the number of Shares or amount of cash or other property to
which an Award will relate, the terms and conditions of any
Award (including, but not limited to, any exercise price, grant
price or purchase price, any limitation or restriction, any
schedule for lapse of limitations, forfeiture restrictions or
restrictions on exercisability or transferability, and
accelerations or waivers thereof, based in each case on such
considerations as the Committee shall determine), and all other
matters to be determined in connection with an Award;
(iv) to determine whether, to what extent and under
what circumstances an Award may be settled in, or the exercise
price of an Award may be paid in, cash, Shares, other Awards or
other property, or an Award may be accelerated, vested,
canceled, forfeited, exchanged or surrendered;
(v) to determine whether, to what extent and under
what circumstances cash, Shares, other Awards, other property
and other amounts payable with respect to an Award shall be
deferred either automatically or at the election of the
Committee or at the election of the Participant;
(vi) to interpret and administer the Plan and any
instrument or agreement relating to, or Award made under, the
Plan;
(vii) to prescribe the form of each Award Agreement,
which need not be identical for each Participant;
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(viii) to adopt, amend, suspend, waive and rescind such
rules and regulations as the Committee may deem necessary or
advisable to administer the Plan;
(ix) to correct any defect or supply any omission or
reconcile any inconsistency, and to construe and interpret the
Plan, the rules and regulations, any Award Agreement or other
instrument entered into or Award made under the Plan; and
(x) to make all other decisions and determinations
as may be required under the terms of the Plan or as the
Committee may deem necessary or advisable for the administration
of the Plan.
Any action of the Committee with respect to the Plan
shall be final, conclusive and binding on all Persons, including the Company,
Affiliates, Participants, any Person claiming any rights under the Plan from or
through any Participant, employees and stockholders. The express grant of any
specific power to the Committee, and the taking of any action by the Committee,
shall not be construed as limiting any power or authority of the Committee.
The Committee may delegate to officers or managers of the Company or of any
Affiliate the authority, subject to such terms as the Committee shall
determine, to perform administrative functions under the Plan and to take such
actions and perform such functions under the Plan as the Committee may specify.
Each member of the Committee shall be entitled to, in good faith, rely or act
upon any report or other information furnished to him by any officer, manager
or other employee of the Company or any Affiliate, the Company's independent
certified public accountants, or any executive compensation consultant or other
professional retained by the Company to assist in the administration of the
Plan. Any and all powers, authorizations and discretions granted by the Plan
to the Committee shall likewise be exercisable at any time by the Board.
SECTION 4. SHARES SUBJECT TO THE PLAN.
4.01 The maximum number of shares of Common Stock in respect
for which Awards may be granted under the Plan, subject to adjustment as
provided in Section 8.01 of the Plan, shall be 4,000,000.
For purposes of this Section 4.01, the number of Shares to which
an Award relates shall be counted against the number of Shares reserved and
available under the Plan at the time of grant of the Award, unless such number
of Shares cannot be determined at that time, in which case the number of Shares
actually distributed pursuant to the Award shall be counted against the number
of Shares reserved and available under the Plan at the
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time of distribution; provided, however, that Awards related to or retroactively
added to, or granted in tandem with, substituted for or converted into, other
Awards shall be counted or not counted against the number of Shares reserved and
available under the Plan in accordance with procedures adopted by the Committee
so as to ensure appropriate counting but avoid double counting; and, provided
further, that the number of Shares deemed to be issued under the Plan upon
exercise of an Option or another stock-based award in the nature of a stock
purchase right shall be reduced by the number of Shares surrendered by the
Participant in payment of the exercise or purchase price of the Award.
If any Shares to which an Award relates are forfeited, or
payment is made to the Participant in the form of cash, cash equivalents or
other property other than Shares, or the Award otherwise terminates without
payment being made to the Participant in the form of Shares, any Shares counted
against the number of Shares reserved and available under the Plan with respect
to such Award shall, to the extent of any such forfeiture, alternative payment
or termination, again be available for Awards under the Plan.
Any Shares distributed pursuant to an Award may consist, in
whole or in part, of authorized and unissued Shares or of treasury Shares,
including Shares repurchased by the Company for purposes of the Plan.
SECTION 5. ELIGIBILITY.
5.01 Awards may be granted only to individuals who are
employees of the Company or any Affiliate and who are not directors or officers
of the Company for purposes of Section 16 of the Exchange Act. In determining
the eligibility of an employee to receive an Award, the Committee shall consider
the position and responsibilities of the employee being considered, the nature
and value to the Company or a Subsidiary of his services and accomplishments,
his present and potential contribution to the success of the Company and its
Subsidiaries and such other factors as the Committee may deem relevant.
SECTION 6. SPECIFIC TERMS OF AWARDS.
6.01 GENERAL. Subject to the terms of the Plan and any
applicable Award Agreement, awards may be issued as set forth in this Section 6.
In addition, the Committee may impose on any Award or the exercise thereof, at
the date of grant or thereafter (subject to the terms of Section 10.01), such
additional terms and conditions, not inconsistent with the provisions of the
Plan, as the Committee shall determine, including terms requiring forfeiture of
Awards in the event of termination of employment by
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the Participant. Except as provided in Section 7.01, or as required by
applicable law, Awards shall be granted for no consideration other than prior
and future services.
6.02 OPTIONS. The Committee is authorized to grant Options to
Participants on the following terms and conditions:
(i) EXERCISE PRICE. The exercise price per Share of
an Option shall be determined by the Committee; provided,
however, that, except as provided in Section 7.01, such exercise
price shall not be less than the Fair Market Value of a Share on
the date of grant of such Option and in no event shall be less
than the par value of a Share.
(ii) OPTION TERM. The term of each Option shall be
determined by the Committee.
(iii) METHODS OF EXERCISE. The Committee shall
determine the time or times at which an Option may be exercised
in whole or in part, the methods by which such exercise price
may be paid or deemed to be paid, and the form of such payment,
including, without limitation, cash, Shares, other outstanding
Awards or other property (including notes or other contractual
obligations of Participants to make payment on a deferred basis,
to the extent permitted by law) or any combination thereof,
having a fair market value equal to the exercise price.
6.03 STOCK APPRECIATION RIGHTS. The Committee is authorized to
grant Stock Appreciation Rights to Participants on the following terms and
conditions:
(i) RIGHT TO PAYMENT. A Stock Appreciation Right
shall confer on the Participant to whom it is granted a right to
receive, upon exercise thereof, the excess of (i) the Fair
Market Value of a Share on the date of exercise or, if the
Committee shall so determine, at any time during a specified
period before or after the date of exercise, over (ii) the grant
price of the Stock Appreciation Right as determined by the
Committee as of the date of grant of the Stock Appreciation
Right, which, except as provided in Section 7.01, shall not be
less than the Fair Market Value of a Share on the date of grant.
(ii) OTHER TERMS. The term, methods of exercise,
methods of settlement and any other terms and
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conditions of any Stock Appreciation Right shall be determined
by the Committee.
6.04 RESTRICTED STOCK. The Committee is authorized to grant
Restricted Stock to Participants on the following terms and conditions:
(i) ISSUANCE AND RESTRICTIONS. Restricted Stock
shall be subject to such restrictions on transferability and
other restrictions as the Committee may impose (including,
without limitation, limitations on the right to vote Restricted
Stock or the right to receive dividends thereon), which
restrictions may lapse separately or in combination at such
times, under such circumstances, in such installments or
otherwise, as the Committee shall determine at the time of grant
or thereafter.
(ii) FORFEITURE. Except as otherwise determined by
the Committee at the time of grant or thereafter, upon
termination of employment (as determined under criteria
established by the Committee) during the applicable restriction
period, Restricted Stock that is at that time subject to
restrictions shall be forfeited and reacquired by the Company;
provided, however, that the Committee may provide, by rule or
regulation or in any Award Agreement, that restrictions on
Restricted Stock shall be waived in whole or in part in the
event of terminations resulting from specified causes, and the
Committee may in other cases waive in whole or in part
restrictions on Restricted Stock.
(iii) CERTIFICATES FOR SHARES. Restricted Stock
granted under the Plan may be evidenced in such manner as the
Committee shall determine, including, without limitation,
issuance of certificates representing Shares. Certificates
representing Shares of Restricted Stock shall be registered in
the name of the Participant and shall bear an appropriate legend
referring to the terms, conditions and restrictions applicable
to such Restricted Stock.
6.05 DEFERRED STOCK. The Committee is authorized to grant
Deferred Stock to Participants on the following terms and conditions:
(i) ISSUANCE AND LIMITATIONS. Delivery of Shares
shall occur upon expiration of the deferral period specified for
the Award of Deferred Stock by the Committee. In addition, an
Award of Deferred Stock
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shall be subject to such limitations as the Committee may
impose, which limitations may lapse at the expiration of the
deferral period or at other specified times, separately or in
combination, in installments or otherwise, as the Committee
shall determine at the time of grant or thereafter. A
Participant awarded Deferred Stock shall have no voting rights
and shall have no rights to receive dividends in respect of
Deferred Stock, unless and only to the extent that the Committee
shall award Dividend Equivalents in respect of such Deferred
Stock.
(ii) FORFEITURE. Except as otherwise determined by
the Committee upon termination of employment (as determined
under criteria established by the Committee) during the
applicable deferral period, Deferred Stock that is at that time
subject to deferral (other than a deferral at the election of
the Participant) shall be forfeited; provided, however, that the
Committee may provide, by rule or regulation or in any Award
Agreement, that forfeiture of Deferred Stock shall be waived in
whole or in part in the event of terminations resulting from
specified causes, and the Committee may in other cases waive in
whole or in part the forfeiture of Deferred Stock.
6.06 PERFORMANCE AWARDS. The Committee is authorized to grant
Performance Awards to Participants on the following terms and conditions:
(i) RIGHT TO PAYMENT. A Performance Award shall
confer upon the Participant rights, valued as determined by the
Committee, and payable to, or exercisable by, the Participant to
whom the Performance Award is granted, in whole or in part, as
the Committee shall establish. The performance criteria and all
other terms and conditions of the Performance Award shall be
determined by the Committee upon the grant of each Performance
Award or thereafter.
(ii) OTHER TERMS. A Performance Award may be
denominated or payable in cash, deferred cash, Shares, other
Awards or other property, and other terms and conditions of
Performance Awards shall be, as determined by the Committee.
6.07 DIVIDEND EQUIVALENTS. The Committee is authorized to
grant Dividend Equivalents to Participants. Dividend Equivalents shall confer
upon the Participant rights to receive, currently or on a deferred basis,
interest or dividends,
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or interest or dividend equivalents, with respect to a number of Shares, or
otherwise, as determined by the Committee. The Committee may provide that
Dividend Equivalents shall be paid or distributed when accrued or shall be
deemed to have been reinvested in additional Shares or additional Awards or
otherwise reinvested.
6.08 EXCHANGE PROVISIONS. The Committee may at any time offer
to exchange or buy out any previously granted Award for a payment in cash,
Shares, another Award or other property, based on such terms and conditions as
the Committee shall determine and communicate to the Participant at the time
that such offer is made.
SECTION 7. GENERAL TERMS OF AWARDS.
7.01 STAND-ALONE, TANDEM AND SUBSTITUTE AWARDS. Awards granted
under the Plan may, in the discretion of the Committee, be granted either alone
or in addition to, in tandem with or in substitution for, any other Award
granted under the Plan, or any other plan of the Company or any Affiliate
(subject to the terms of Section 10.01) including a business entity to be
acquired by the Company. If an Award is granted in substitution for another
Award or award, the Committee shall require the surrender of such other Award or
award in consideration for the grant of the new Award. Awards granted in
addition to or in tandem with other Awards or awards may be granted either at
the same time as or at a different time from the grant of such other Awards or
awards. The exercise price of any Option, the grant price of any Stock
Appreciation Right or the purchase price of any other Award conferring a right
to purchase Shares:
(i) granted in substitution for an outstanding Award
or award shall either be not less than the Fair Market Value of
Shares at the date such substitute Award is granted or not less
than such Fair Market Value at that date reduced to reflect the
Fair Market Value of the Award or award required to be
surrendered by the Participant as a condition to receipt of a
substitute Award; or
(ii) retroactively granted in tandem with an
outstanding Award or award shall be either not less than the
Fair Market Value of Shares at the date of grant of the later
Award or equal to the Fair Market Value of Shares at the date of
grant of the earlier Award or award.
7.02 TERM OF AWARDS. The term of each Award shall be for such
period as may be determined by the Committee.
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7.03 FORM OF PAYMENT OF AWARDS. Subject to the terms of the
Plan and any applicable Award Agreement, payments or substitutions to be made by
the Company or an Affiliate upon the grant or exercise of an Award may be made
in such forms as the Committee shall determine at the time of grant or
thereafter (subject to the terms of Section 10.01), including, without
limitation, cash, Shares, other Awards or other property or any combination
thereof, and may be made in a single payment or substitution, in installments or
on a deferred basis, in each case in accordance with rules and procedures
established by the Committee. Such rules and procedures may include, without
limitation, provisions for the payment or crediting of reasonable interest on
installment or deferred payments or the grant or crediting of Dividend
Equivalents in respect of installment or deferred payments.
7.04 LIMITS ON TRANSFER OF AWARDS; BENEFICIARIES. No right or
interest of a Participant in any Award shall be pledged, encumbered or
hypothecated to or in favor of any Person other than the Company or an
Affiliate, or shall be subject to any lien, obligation or liability of such
Participant to any Person other than the Company or an Affiliate. Unless
otherwise determined by the Committee, no Award and no rights or interests
therein shall be assignable or transferable by a Participant otherwise than by
will or the laws of descent and distribution except to the Company or any
Affiliate under the terms of the Plan; provided, however, that, if so determined
by the Committee, a Participant may, in the manner established by the Committee,
designate a beneficiary or beneficiaries to exercise the rights of the
Participant, and to receive any distribution with respect to any Award, upon the
death of the Participant. A beneficiary, guardian, legal representative or
other Person claiming any rights under the Plan from or through any Participant
shall be subject to all the terms and conditions of the Plan and any Award
Agreement applicable to such Participant as well as any additional restrictions
or limitations deemed necessary or appropriate by the Committee.
7.05 REGISTRATION AND LISTING COMPLIANCE. No Award shall be
paid and no Shares shall be distributed with respect to any Award in a
transaction subject to the registration requirements of the Securities Act of
1933, as amended, or any state securities law or subject to a listing
requirement under any listing agreement between the Company and any national
securities exchange, and no Award shall confer upon any Participant rights to
such delivery or distribution, until such laws and contractual obligations of
the Company have been complied with in all material respects.
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7.06 STOCK CERTIFICATES. All certificates for Shares delivered
under the terms of the Plan shall be subject to such stop-transfer orders and
other restrictions as the Committee may deem advisable under federal or state
securities laws, rules and regulations thereunder, and the rules of any national
securities exchange or automated quotation system on which Shares are listed or
quoted. The Committee may cause a legend or legends to be placed on any such
certificates to make appropriate reference to such restrictions or any other
restrictions or limitations that may be applicable to Shares. In addition,
during any period in which Awards or Shares are subject to restrictions or
limitations under the terms of the Plan or any Award Agreement, or during any
period during which delivery or receipt of an Award or Shares has been deferred
by the Committee or a Participant, the Committee may require any Participant to
enter into an agreement providing that certificates representing Shares issuable
or issued pursuant to an Award shall remain in the physical custody of the
Company or such other Person as the Committee may designate.
SECTION 8. ADJUSTMENT PROVISIONS.
8.01 In the event that the Committee shall determine that any
dividend or other distribution (whether in the form of cash, Shares, other
securities or other property), recapitalization, stock split, reverse stock
split, reorganization, merger, consolidation, split-up, spin-off, combination,
repurchase, exchange of Shares or other securities of the Company, or other
similar corporate transaction or event affects the Shares such that an
adjustment is determined by the Committee to be appropriate in order to prevent
dilution or enlargement of Participants' rights under the Plan, then the
Committee shall, in such manner as it may deem equitable, adjust any or all of
(i) the number and kind of Shares which may thereafter be issued in connection
with Awards; (ii) the number and kind of Shares issued or issuable in respect of
outstanding Awards; and (iii) the exercise price, grant price or purchase price
relating to any Award or, if deemed appropriate, make provision for a cash
payment with respect to any outstanding Award. In addition, the Committee is
authorized to make adjustments in the terms and conditions of, and the criteria
in, Awards in recognition of unusual or nonrecurring events (including, without
limitation, events described in the preceding sentence) affecting the Company or
any Affiliate or the financial statements of the Company or any Affiliate, or in
response to changes in applicable laws, regulations or accounting principles.
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SECTION 9. CHANGE OF CONTROL PROVISIONS.
9.01 ACCELERATION OF EXERCISABILITY AND LAPSE OF RESTRICTIONS;
CASH-OUT OF AWARDS. In the event of a Change of Control, the following
acceleration and cash-out provisions shall apply unless otherwise provided by
the Committee at the time of the Award grant.
(i) All outstanding Awards pursuant to which the
Participant may have rights the exercise of which is restricted
or limited shall become fully exercisable; unless the right to
lapse of restrictions or limitations is waived or deferred by a
Participant prior to such lapse, all restrictions or limitations
(including risks of forfeiture and deferrals) on outstanding
Awards subject to restrictions or limitations under the Plan
shall lapse; and all performance criteria and other conditions
to payment of Awards under which payments of cash, Shares or
other property are subject to conditions shall be deemed to be
achieved or fulfilled and shall be waived by the Company.
(ii) For a period of up to 60 days following a Change
in Control, the Participant may elect to surrender any
outstanding Award and to receive, in full satisfaction therefor,
a cash payment equal to the value of such Award calculated on
the basis of the Change of Control Price of any Shares or the
Fair Market Value of any property other than Shares relating to
such Award. In the event that an Award is granted in tandem
with another Award such that the Participant's right to payment
for such Award is an alternative to payment of another Award,
the Participant electing to surrender any such tandem Award
shall surrender all alternative Awards related thereto and
receive payment for the Award which produces the highest payment
to the Participant.
9.02 CREATION AND FUNDING OF TRUST. Upon the earlier of the
occurrence of a Potential Change of Control or a Change of Control, the Company
shall deposit with the trustee of a trust for the benefit of Participants monies
or other property having a Fair Market Value at least equal to the value of
cash, Shares and other property to be paid or distributed in connection with
Awards outstanding at that date. The trust shall be a grantor trust which shall
preserve the "unfunded" status of Awards under the Plan. Subsequent to a
Potential Change of Control which is no longer continuing and prior to any
Change of Control, upon the
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request of the Company, the trustee shall deliver the monies or other property
held in the trust to the Company.
9.03 DEFINITION OF CERTAIN TERMS. For purposes of this Section
9, the following definitions, in addition to those set forth in Section 2.01,
shall apply:
9.03.1 "Change of Control" means and shall be deemed to
have occurred if:
(i) any Person, other than the Company or a Related
Party, is or becomes the "beneficial owner" (as defined in Rule
13d-3 under the Exchange Act), directly or indirectly, of Voting
Securities representing 20 percent or more of the total voting
power of all the then-outstanding Voting Securities, except that
there shall be excluded from the number of Voting Securities
deemed to be beneficially owned by a Person a number of Voting
Securities representing not more than 10 percent of the
then-outstanding voting power if such Person is (a) eligible to
file a Schedule 13G pursuant to Rule 13d-1(b)(1) under the
Exchange Act with respect to Voting Securities or (b) an
underwriter who becomes the beneficial owner of more than 20
percent of the then-outstanding Voting Securities pursuant to a
firm commitment underwriting agreement with the Company; or
(ii) the individuals who, as of the effective date of
the Plan, constitute the Board of Directors of the Company
together with those who first become directors subsequent to
such date and whose recommendation, election or nomination for
election to the Board was approved by a vote of at least a
majority of the directors then still in office who either were
directors as of the effective date of the Plan or whose
recommendation, election or nomination for election was
previously so approved (the "Continuing Directors"), cease for
any reason to constitute a majority of the members of the Board;
or
(iii) the stockholders of the Company approve a
merger, consolidation, recapitalization or reorganization of the
Company, reverse split of any class of Voting Securities, or an
acquisition of securities or assets by the Company, or
consummation of any such transaction if stockholder approval is
not obtained, other than (a) any such transaction which would
result in at least 75 percent of the total voting power
represented by the voting securities of the surviving entity
outstanding immediately after such
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transaction being beneficially owned by at least 75 percent of
the holders of outstanding Voting Securities immediately prior
to the transaction, with the voting power of each such
continuing holder relative to other such continuing holders not
substantially altered in the transaction, or (b) any such
transaction which would result in a Related Party beneficially
owning more than 50 percent of the voting securities of the
surviving entity outstanding immediately after such transaction;
or
(iv) the stockholders of the Company approve a plan
of complete liquidation of the Company or an agreement for the
sale or disposition by the Company of all or substantially all
of the Company's assets other than any such transaction which
would result in a Related Party owning or acquiring more than 50
percent of the assets owned by the Company immediately prior to
the transaction.
9.03.2 "Change of Control Price" means, with respect to
a Share, the higher of (i) the highest reported sales price of
Shares on the New York Stock Exchange during the 30 calender
days preceding a Change of Control or (ii) the highest price
paid or offered in a transaction which either (a) results in a
Change of Control or (b) would be consummated but for another
transaction which results in a Change of Control and, if it were
consummated, would result in a Change of Control. With respect
to clause (ii) in the preceding sentence, the "price paid or
offered" will be equal to the sum of (i) the face amount of any
portion of the consideration consisting of cash or cash
equivalents and (ii) the fair market value of any portion of the
consideration consisting of real or personal property other than
cash or cash equivalents, as established by an independent
appraiser selected by the Committee.
9.03.3 "Potential Change of Control" means and shall be
deemed to have arisen if (i) the Company enters into an
agreement, the consummation of which would result in the
occurrence of a Change of Control; or (ii) any Person (including
the Company) publicly announces an intention to take or to
consider taking actions which if consummated would constitute a
Change of Control; or (iii) any Person, other than a Related
Party, files with the Securities and Exchange Commission a
Schedule 13D pursuant to Rule 13d-1 under the Exchange Act with
respect to more than 7.5 percent of any outstanding class of
Voting Securities; or
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<PAGE> 16
(iv) the Committee adopts a resolution to the effect that, for
purposes of the Plan, a Potential Change of Control has arisen.
A Potential Change of Control will be deemed to continue (i)
with respect to an agreement within the purview of clause (i) of
the preceding sentence, until the agreement is canceled or
terminated; or (ii) with respect to an announcement within the
purview of clause (ii) of the preceding sentence, until the
Person making the announcement publicly abandons the stated
intention or fails to act on such intention for a period of 12
calendar months; or (iii) with respect to the filing of a
Schedule 13D within the purview of clause (iii) of the preceding
sentence, until the Person involved publicly announces that its
ownership of the Voting Securities is for investment purposes
only and not for the purpose of seeking a Change of Control or
such Person disposes of the Voting Securities; or (iv) with
respect to any Potential Change of Control, until a Change of
Control has occurred or the majority of the Continuing Directors
and the Committee, acting jointly, on reasonable belief after
due investigation, adopt a resolution that the Potential Change
of Control has ceased to exist.
9.03.4 "Related Party" means (i) a majority-owned
subsidiary of the Company; or (ii) an employee or group of
employees of the Company or any majority-owned subsidiary of the
Company; or (iii) a trustee or other fiduciary holding
securities under an employee benefit plan of the Company or any
majority-owned subsidiary of the Company; or (iv) a corporation
owned directly or indirectly by the stockholders of the Company
in substantially the same proportion as their ownership of
Voting Securities.
9.03.5 "Voting Securities or Security" means any
securities of the Company which carry the right to vote
generally in the election of directors.
SECTION 10. AMENDMENTS TO AND TERMINATION OF THE PLAN.
10.01 The Board may amend, alter, suspend, discontinue or
terminate the Plan without the consent of stockholders or Participants;
provided, however, that, without the consent of the Participant, no amendment,
alteration, suspension, discontinuation or termination of the Plan may
materially and adversely affect the rights of such Participant under any Award
theretofore granted to him. The Committee may waive any conditions or rights
under, amend any terms of, or amend, alter,
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<PAGE> 17
suspend, discontinue or terminate, any Award theretofore granted, prospectively
or retrospectively; provided, however, that, without the consent of a
Participant, no amendment, alteration, suspension, discontinuation or
termination of any Award may materially and adversely affect the rights of such
Participant under any Award theretofore granted to him.
SECTION 11. GENERAL PROVISIONS.
11.01 NO RIGHTS TO AWARDS; NO STOCKHOLDER RIGHTS. Nothing in
this Plan shall give any Participant or employee any right or claim to be
granted any Award under the Plan, and there is no obligation for uniformity of
treatment of Participants and employees. No Award shall confer on any
Participant any of the rights of a stockholder of the Company unless and until
Shares are in fact issued to such Participant in connection with such Award.
11.02 WITHHOLDING. The Company or any Affiliate is authorized
to withhold from any Award granted or any payment due under the Plan, including
from a distribution of Shares, amounts of withholding taxes due with respect to
an Award, its exercise or any payment thereunder, and to take such other action
as the Committee may deem necessary or advisable to enable the Company and
Participants to satisfy obligations for the payment of withholding taxes and tax
liabilities in excess thereof. This authority shall include authority to
withhold or receive Shares, Awards or other property and to make cash payments
in respect thereof in satisfaction of such tax obligations.
11.03 NO RIGHT TO EMPLOYMENT. Nothing contained in the Plan or
any Award Agreement shall confer, and no grant of an Award shall be construed as
conferring, upon any Participant any right to continue in the employ of the
Company or any Affiliate or to interfere in any way with the right of the
Company or any Affiliate to terminate his employment at any time or increase or
decrease his compensation from the rate in existence at the time of granting of
an Award, except as may be expressly provided in any Award Agreement or other
compensation arrangement.
11.04 UNFUNDED STATUS OF AWARDS; CREATION OF TRUSTS. The Plan
is intended to constitute an "unfunded" plan for incentive and deferred
compensation. With respect to any payments not yet made to a Participant
pursuant to an Award, nothing contained in the Plan or any Award shall give any
such Participant any rights that are greater than those of a general unsecured
creditor of the Company; provided, however, that, in addition to the
requirements of Section 9.02, the Committee may authorize the creation of trusts
or make other arrangements to meet the Company's obligations under the Plan to
deliver cash,
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<PAGE> 18
Shares or other property pursuant to any Award, which trusts or other
arrangements shall be consistent with the "unfunded" status of the Plan unless
the Committee otherwise determines.
11.05 NO LIMIT ON OTHER COMPENSATORY ARRANGEMENTS. Nothing
contained in the Plan shall prevent the Company or any Affiliate from adopting
other or additional compensation arrangements (which may include, without
limitation, employment agreements with executives and arrangements which relate
to Awards under the Plan), and such arrangements may be either generally
applicable or applicable only in specific cases. Notwithstanding anything in
the Plan to the contrary, the terms of each Award shall be construed so as to
be consistent with such other arrangements in effect at the time of the Award.
11.06 NO FRACTIONAL SHARES. No fractional Shares shall be
issued or delivered pursuant to the Plan or any Award. The Committee shall
determine whether cash, other Awards or other property shall be issued or paid
in lieu of fractional Shares or whether such fractional Shares or any rights
thereto shall be forfeited or otherwise eliminated.
11.07 GOVERNING LAW. The validity, interpretation,
construction and effect of the Plan and any rules and regulations relating to
the Plan shall be governed by the laws of the State of Delaware (without regard
to provisions governing conflict of laws) and applicable federal law.
11.08 SEVERABILITY. If any provision of the Plan or any Award
is or becomes or is deemed invalid, illegal or unenforceable in any
jurisdiction, or would disqualify the Plan or any Award under any law deemed
applicable by the Committee, such provision shall be construed or deemed amended
to conform to applicable laws or if it cannot be construed or deemed amended
without, in the determination of the Committee, materially altering the intent
of the Plan, it shall be deleted and the remainder of the Plan shall remain in
full force and effect; provided, however, that, unless otherwise determined by
the Committee, the provision shall not be construed or deemed amended or deleted
with respect to any Participant whose rights and obligations under the Plan are
not subject to the law of such jurisdiction or the law deemed applicable by the
Committee.
SECTION 12. EFFECTIVE DATE AND TERMINATION.
12.01 The Plan shall become effective as of December 12, 1995.
No award may be granted under the Plan after December 12, 2005.
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<PAGE> 1
EMPLOYMENT AGREEMENT
BETWEEN
CONSOLIDATED NATURAL GAS COMPANY
AND
[NAME]
DATED [DATE]
<PAGE> 2
TABLE OF CONTENTS
-----------------
<TABLE>
<CAPTION>
Page
----
<S> <C>
1. Operation and Term of Agreement; Certain Definitions....................... 2
2. Change of Control.......................................................... 3
3. Employment Period.......................................................... 4
4. Terms of Employment........................................................ 4
(a) Position and Duties................................................ 4
(b) Compensation....................................................... 5
(i) Base Salary................................................ 5
(ii) Annual Bonus............................................... 5
(iii) Incentive, Savings and Retirement Plans.................... 5
(iv) Split Dollar Life Insurance and Supplemental Death
Benefit Plans.............................................. 6
(v) Welfare Benefit Plans...................................... 6
(c) Additional Rights of the Executive and Obligations
of the Company..................................................... 7
(i) Expenses................................................... 7
(ii) Fringe Benefits............................................ 7
(iii) Office and Support Staff................................... 7
(iv) Vacation................................................... 7
(v) Indemnification............................................ 7
5. Termination................................................................ 8
(a) Death or Disability................................................ 8
(b) Cause.............................................................. 8
(c) Good Reason........................................................ 8
(d) Notice of Termination.............................................. 9
(e) Date of Termination............................................... 10
6. Obligations of the Company upon Termination............................... 10
(a) Termination Because of Death...................................... 10
(b) Termination Because of Disability................................. 11
(c) Termination For Cause by the Company or For
Other than Good Reason by the Executive........................... 11
(d) Termination For Good Reason by the Executive
</TABLE>
<PAGE> 3
<TABLE>
<S> <C>
or For Other Than Cause or Disability by the Company
or Other Than As a Result of Death................................ 11
(e) Successor in Interest............................................. 12
7. Non-exclusivity of Rights................................................. 13
8. Full Settlement........................................................... 13
9. Certain Additional Payments by the Company................................ 13
10. Confidential Information.................................................. 16
11. Successors................................................................ 16
12. Miscellaneous............................................................. 16
</TABLE>
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<PAGE> 4
EMPLOYMENT AGREEMENT
--------------------
AGREEMENT by and between Consolidated Natural Gas Company, a Delaware
corporation (the "Company"), and [Name] (the "Executive"), dated as of [Date].
WHEREAS, the Company recognizes that the current business environment makes
it difficult to attract and retain highly qualified executives unless a certain
degree of security can be offered to such individuals against organizational and
personnel changes which frequently follow Changes of Control (as defined below)
of a corporation; and
WHEREAS, even rumors of acquisitions or mergers may cause executives to
consider major career changes in an effort to assure financial security for
themselves and their families; and
WHEREAS, the Company desires to assure fair treatment of its key executives
in the event of a Change of Control and to allow them to make critical career
decisions without undue time pressure and financial uncertainty, thereby
increasing their willingness to remain with the Company notwithstanding the
outcome of a possible Change of Control transaction; and
WHEREAS, the Company recognizes that its key executives will be involved in
evaluating or negotiating any offers, proposals or other transactions which
could result in Changes of Control of the Company and believes that it is in the
best interest of the Company and its stockholders for such key executives to be
in a position, free from personal financial and employment considerations, to be
able to assess objectively and pursue aggressively the interests of the
Company's stockholders in making these evaluations and carrying on such
negotiations; and
WHEREAS, the Board of Directors (the "Board") of the Company believes it is
essential to provide the Executive with compensation arrangements upon a Change
of Control which provide the Executive with individual financial security and
which are competitive with those of other corporations, and in order to
accomplish these objectives, the Board has caused the Company to enter into this
Agreement.
NOW THEREFORE, the parties, for good and valuable consideration and
intending to be legally bound, agree as follows:
<PAGE> 5
1. OPERATION AND TERM OF AGREEMENT; CERTAIN DEFINITIONS.
(a) This Agreement shall be effective immediately upon its
execution, but neither this Agreement nor any of its provisions shall be
operative unless and until there has been a Change of Control of the
Company, as such term is defined below. The term of this Agreement shall
end on the third anniversary of the date of execution of this Agreement;
provided, however, that commencing on the date one year after the date
hereof, and on each annual anniversary of such date (such date and each
annual anniversary thereof is hereinafter referred to as the "Renewal
Date"), the term of this Agreement shall be automatically extended so as to
terminate three years from such Renewal Date, unless at least 60 days prior
to the Renewal Date the Company shall give written notice that the term of
the Agreement shall not be so extended; and provided, further, that after a
Change of Control of the Company during the term of this Agreement, this
Agreement shall remain in effect until all of the obligations of the
parties hereunder are satisfied.
(b) The "Effective Date" shall be the first date during the
term of this Agreement on which a Change of Control occurs. Anything in
this Agreement to the contrary notwithstanding, if the Executive's
employment with the Company is terminated prior to the date on which a
Change of Control occurs, and it is reasonably demonstrated that such
termination (i) was at the request of a third party who has taken steps
reasonably calculated to effect a Change of Control or (ii) otherwise arose
in connection with or anticipation of a Change of Control, then for all
purposes of this Agreement the "Effective Date" shall mean the date
immediately prior to the date of such termination.
(c) "Formula Compensation" means the "base amount" as defined
in Section 280G(b)(3) of the Internal Revenue Code of 1986, as amended (the
"Code").
(d) A reference herein to a section of the Code or a
subdivision thereof shall be construed to incorporate reference to any
section or subdivision of the Code enacted as a successor thereto, any
applicable proposed, temporary or final regulations promulgated pursuant to
such sections and any applicable interpretation thereof by the Internal
Revenue Service.
(e) "Present value," for purposes of this Agreement, shall be
determined in accordance with Section 280G(d)(4) of the Code as of the date
specified for such determination, applying a discount rate, compounded no
less frequently than monthly, that is equivalent to the rate specified for
such determination.
(f) A reference herein to a section of the Securities Exchange
Act of 1934, as amended (the "Exchange Act"), or any rule or regulation
promulgated thereunder shall be construed to incorporate reference to any
section of the
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<PAGE> 6
Exchange Act or any rule or regulation enacted or promulgated as a
successor thereto.
(g) Subsidiary(ies) means a company 50% or more of the voting
securities of which are owned by the Company.
(h) Employee Benefit Plan means any written plan providing
benefits for employees of the Company or any Subsidiary.
2. CHANGE OF CONTROL. For the purpose of this Agreement, a "Change of
Control" shall be deemed to have occurred upon the happening of any of the
following:
(a) The acquisition (other than from the Company) by any
person, entity or "group," within the meaning of Section 13(d)(3) or
14(d)(2) of the Exchange Act (excluding, for this purpose, the Company or
its Subsidiaries, or any Employee Benefit Plan which acquires beneficial
ownership of voting securities of the Company), of beneficial ownership
(within the meaning of Rule 13d-3 promulgated under the Exchange Act) of
20% or more of either the then outstanding shares of common stock or the
combined voting power of the Company's then outstanding voting securities
entitled to vote generally in the election of directors; or
(b) Individuals who, as of the date hereof, constitute the
Board (the "Incumbent Board") cease for any reason to constitute at least a
majority of the Board, provided that any person who first becomes a
director subsequent to the date hereof whose recommendation, election or
nomination for election by the Company's stockholders was approved by a
vote of at least a majority of the directors then comprising the Incumbent
Board (other than an election or nomination of an individual whose initial
assumption of office is in connection with an actual or threatened election
contest relating to the election of the directors of the Company, as such
terms are used in Rule 14a-11 of Regulation 14A promulgated under the
Exchange Act) shall be, for purposes of this Agreement, considered as
though such person were a member of the Incumbent Board; or
(c) Approval by the stockholders of the Company of a
reorganization, merger or consolidation, in each case, with respect to
which all or substantially all of the individuals and entities who were the
beneficial owners, respectively, of the outstanding Company voting
securities immediately prior to such reorganization, merger or
consolidation, do not, following such reorganization, merger or
consolidation, beneficially own, directly or indirectly, more than 50% of
the combined voting power of the then outstanding voting securities
entitled to vote generally in the election of directors of the company
resulting from such reorganization, merger or consolidation in
substantially the same proportions as their ownership, immediately prior to
such reorganization, merger or consolidation, of the outstanding Company
voting securities; or
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<PAGE> 7
(d) Approval by stockholders of the Company of a complete
liquidation or dissolution of the Company or a sale of all or substantially
all the assets of the Company.
3. EMPLOYMENT PERIOD. The Company hereby agrees to continue the
Executive in the Company's employ, and the Executive hereby agrees to remain in
the employ of the Company, for the period commencing on the Effective Date and
ending on the third anniversary of such date (the "Employment Period").
4. TERMS OF EMPLOYMENT.
(a) POSITION AND DUTIES.
(i) During the Employment Period, (A) the Executive's
position (including status, offices, titles and reporting
requirements), authority, duties and responsibilities shall be at
least commensurate in all material respects with the most
significant of those held, exercised and assigned at any time
during the 90-day period immediately preceding the Effective Date
and (B) the Executive's services shall be performed at the location
where the Executive was employed immediately preceding the
Effective Date or any office or location less than 25 miles from
such location.
(ii) During the Employment Period, and excluding any
periods of vacation and sick leave to which the Executive is
entitled, the Executive agrees to devote reasonable attention and
time during normal business hours to the business and affairs of
the Company and, to the extent necessary to discharge the
responsibilities assigned to the Executive hereunder, to use the
Executive's reasonable best efforts to perform faithfully and
efficiently such responsibilities. During the employment period it
shall not be a violation of this Agreement for the Executive to (A)
serve on corporate, civic or charitable boards or committees, (B)
deliver lectures, fulfill speaking engagements or teach at
educational institutions and (C) manage personal investments, so
long as such activities do not significantly interfere with the
performance of the Executive's responsibilities as an employee of
the Company in accordance with this Agreement. It is expressly
understood and agreed that to the extent that any such activities
have been conducted by the Executive prior to the Effective Date,
the continued conduct of such activities (or the conduct of
activities similar in nature and scope thereto) subsequent to the
Effective Date shall not thereafter be deemed to interfere with the
performance of the Executive's responsibilities to the Company.
The preceding sentence shall in no way be construed as a limitation
on the non-business activities listed previously in this paragraph
of Section 4(a)(ii). Activities of the Executive consistent with
this paragraph shall not permit the Company to terminate the
Executive's employment for Cause, as defined below.
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<PAGE> 8
(b) COMPENSATION.
(i) BASE SALARY. During the Employment Period, the
Executive shall receive a base salary ("Base Salary") at a monthly
rate at least equal to the highest monthly base salary paid or
payable to the Executive by the Company during the 12-month period
immediately preceding the month in which the Effective Date occurs.
During the Employment Period, the Base Salary shall be reviewed at
least annually and shall be increased at any time and from time to
time as shall be substantially consistent with increases in base
salary awarded in the ordinary course of business to other key
executives of the Company and its Subsidiaries. Any increase in
Base Salary shall not serve to limit or reduce any other obligation
to the Executive under this Agreement. Base Salary shall not be
reduced after any such increase.
(ii) ANNUAL BONUS. In addition to Base Salary, the
Executive shall be awarded, for each fiscal year ending during the
Employment Period, an annual bonus (an "Annual Bonus") (either
pursuant to the Company's Cash Incentive Bonus Plan, any successor
to such plan or otherwise) in cash at least equal to the average
annual bonus payable to the Executive from the Company and its
Subsidiaries in respect of the two of the last three fiscal years
immediately preceding the Effective Date in which the bonuses paid
were higher.
(iii) INCENTIVE, SAVINGS AND RETIREMENT PLANS. In
addition to Base Salary and Annual Bonus payable as hereinabove
provided, the Executive shall be entitled to participate during the
Employment Period in all incentive, savings and retirement plans,
practices, policies and programs in which the Executive was
participating prior to the Effective Date and which are applicable
to other key executives of the Company and its Subsidiaries
(including, without limitation, the Company's Cash Incentive Bonus
Deferral Plan and its Thrift Plan), in each case providing benefits
which are the economic equivalent to those currently in effect or
as subsequently amended prior to the Effective Date. The
compensation, benefits and reward opportunities provided to the
Executive pursuant to such plans, practices, policies and programs,
in the aggregate, shall be at least as favorable as the most
favorable of such compensation, benefits and reward opportunities,
in the aggregate, provided by the Company for the Executive under
such plans, practices, policies and programs as in effect at any
time during the 90-day period immediately preceding the Effective
Date or, if more favorable to the Executive, as provided at any
time thereafter with respect to other key executives of the Company
and its Subsidiaries.
In the event of the termination of the Company's Thrift Plan, or
modification of such Plan, having the effect of reducing the
Company's
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<PAGE> 9
monthly contributions for the benefit of the Executive pursuant to
such Plan, the Company shall, for the duration of the Employment
Period, make monthly contributions to a deferred compensation
account maintained on behalf of the Executive in amounts which when
added to any contributions made by the Company for the benefit of
the Executive under the Thrift Plan shall at least equal the
greater of (A) the Company's average monthly contributions to the
Executive's account under the Thrift Plan in respect to the fiscal
year immediately preceding the Effective Date or (B) the Company's
average monthly contribution to the Executive's account under the
Thrift Plan during the term of the Agreement. Amounts contributed
to an account pursuant to the preceding sentence and the income
thereon shall be payable to the Executive either (Y) in the case
of an account maintained under a qualified plan, in accordance with
the terms of the plan, or (Z) in the case of any other such
account, at the termination of the Executive's employment by the
Company.
(iv) SPLIT DOLLAR LIFE INSURANCE AND SUPPLEMENTAL DEATH
BENEFIT PLANS. During the Employment Period, and thereafter in
accordance with the terms of the Split Dollar Life Insurance and
Supplemental Death Benefit Plans applicable to the Executive, the
Executive, his beneficiaries and his estate shall be entitled to
the benefit of such plans as in effect on the Effective Date or, if
more favorable to the Executive, as in effect at any time
thereafter with respect to key executives of the Company and its
Subsidiaries.
(v) WELFARE BENEFIT PLANS. During the Employment
Period, the Executive and/or the Executive's family, as the case
may be, shall be eligible for participation in and shall receive
all benefits under welfare benefit plans, practices, policies and
programs provided by the Company and its Subsidiaries (including,
without limitation, medical, prescription, dental, disability,
salary continuance, employee life, group life, accidental death and
travel accident insurance plans and programs), in each case
providing benefits which are the economic equivalent to those
currently in effect or as subsequently amended prior to the
Effective Date. The benefits provided to the Executive and/or the
Executive's family pursuant to such plans, practices, policies and
programs in accordance with this Section 4(b)(v) shall at all times
be at least as favorable as the most favorable of such plans,
practices, policies and programs in effect at any time during the
90-day period immediately preceding the Effective Date or, if more
favorable to the Executive and/or the Executive's family, as in
effect at any time thereafter with respect to other key executives
of the Company and its Subsidiaries.
(c) ADDITIONAL RIGHTS OF THE EXECUTIVE AND OBLIGATIONS OF THE
COMPANY.
(i) EXPENSES. During the Employment Period, the
Executive shall be entitled to receive prompt reimbursement for all
reasonable expenses
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<PAGE> 10
incurred by the Executive in accordance with the most favorable
policies, practices and procedures of the Company and its
Subsidiaries in effect at any time during the 90-day period
immediately preceding the Effective Date or, if more favorable to
the Executive, as in effect at any time thereafter with respect to
other key executives of the Company and its Subsidiaries.
(ii) FRINGE BENEFITS. During the Employment Period, the
Executive shall be entitled to fringe benefits, including but not
limited to the use of an automobile and payment of related
expenses, in accordance with the most favorable plans, practices,
policies and programs of the Company and its Subsidiaries in effect
at any time during the 90-day period immediately preceding the
Effective Date or, if more favorable to the Executive, as in effect
at any time thereafter with respect to other key executives of the
Company and its Subsidiaries.
(iii) OFFICE AND SUPPORT STAFF. During the Employment
Period, the Executive shall be entitled to an office or offices of
a size and with furnishings and other appointments, and to
secretarial and other assistance, at least equal to the most
favorable of the foregoing provided to the Executive by the Company
and its Subsidiaries at any time during the 90-day period
immediately preceding the Effective Date or, if more favorable to
the Executive, as provided at any time thereafter with respect to
other key executives of the Company and its Subsidiaries.
(iv) VACATION. During the Employment Period, the
Executive shall be entitled to paid vacation in accordance with the
most favorable plans, practices, policies and programs of the
Company and its Subsidiaries as in effect at any time during the
90-day period immediately preceding the Effective Date or, if more
favorable to the Executive, as in effect at any time thereafter
with respect to other key executives of the Company and its
Subsidiaries.
(v) INDEMNIFICATION. The Executive shall be entitled
during the Employment Period, and thereafter with respect to
occurrences during the Employment Period, to the benefit of the
indemnification provisions contained in the By-Laws of the Company
as in effect on the Effective Date or, if more favorable to the
Executive, as in effect at any time thereafter, to the extent
permitted by applicable law at the time of the assertion of any
liability against the Executive.
5. TERMINATION.
(a) DEATH OR DISABILITY. The Executive's employment under this
Agreement shall terminate automatically upon the Executive's death. If the
Company determines in good faith that the Disability of the Executive has
occurred (pursuant to the definition of "Disability" set forth below), it
may give to
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<PAGE> 11
the Executive written notice of its intention to terminate the Executive's
employment. In such event, the Executive's employment with the Company
shall terminate effective on the 30th day after receipt of such notice by
the Executive (the "Disability Effective Date"), provided that, within the
30 days after such receipt, the Executive shall not have returned to
full-time performance of the Executive's duties. For purposes of this
Agreement, "Disability" means any physical or mental condition which wholly
prevents the Executive from performing the duties of his occupation with
the Company for at least 26 weeks after the commencement of such condition
and which is determined to be of a permanent duration by a physician
selected by the Company or its insurers and acceptable to the Executive or
the Executive's legal representative (such agreement as to acceptability
not to be withheld unreasonably).
(b) CAUSE. During the Employment Period, the Company may only
terminate the Executive's employment under Section 5(a) or for "Cause." For
purposes of this Agreement, "Cause" means (i) an act or acts of personal
dishonesty engaged in by the Executive and intended to result in
substantial personal enrichment of the Executive at the expense of the
Company, (ii) repeated violations by the Executive of the Executive's
obligations under Section 4(a)(ii) of this Agreement which are demonstrably
willful and deliberate on the Executive's part and which are not remedied
in a reasonable period of time after receipt of written notice from the
Company or (iii) the conviction of the Executive of a felony.
(c) GOOD REASON. Notwithstanding anything to the contrary
contained herein, during the Employment Period, the Executive's employment
may be terminated by the Executive for Good Reason and such termination
shall be deemed a constructive discharge of the Executive by the Company.
For purposes of this Agreement, "Good Reason" means:
(i) the assignment to the Executive of any duties
inconsistent in any respect with the Executive's position (included
status, offices, titles and reporting requirements), authority,
duties or responsibilities as contemplated by Section 4(a)(i) of
this Agreement, or any other action by the Company which results in
a diminution in such position, authority, duties or
responsibilities, excluding for this purpose an isolated,
insubstantial and inadvertent action not taken in bad faith and
which is remedied by the Company promptly after receipt of notice
thereof given by the Executive;
(ii) any failure by the Company to comply with any of
the provisions of Section 4 of this Agreement, other than an
isolated, insubstantial and inadvertent failure not occurring in
bad faith and which is remedied by the Company promptly after
receipt of notice thereof given by the Executive;
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<PAGE> 12
(iii) the Company's requiring the Executive to be based
at any office or location other than that described in Section
4(a)(i)(B) hereof, except for travel reasonably required in the
performance of the Executive's responsibilities;
(iv) any purported termination by the Company of the
Executive's employment otherwise than as expressly permitted by
this Agreement;
(v) any failure by the Company to comply with and
satisfy Section 11(c) of this Agreement; or
(vi) any spin-off by the Company of the corporate unit
employing the Executive at any time during the Employment Period.
For purposes of this Section 5(c), any good faith determination of
"Good Reason" made by the Executive shall be conclusive. Anything in this
Agreement to the contrary notwithstanding, a termination by the Executive
for any reason during the 30-day period immediately following the first
anniversary of a Change of Control (other than a Change of Control
resulting from stockholder approval of, or consummation of, a
reorganization, merger or consolidation involving the Company with respect
to which stockholders of the Company receive (or retain) solely voting
common stock of the company resulting from the reorganization, merger or
consolidation in exchange for their Company common stock) shall be deemed
to be a termination for Good Reason for all purposes of this Agreement.
(d) NOTICE OF TERMINATION. Any termination of the Executive's
employment by the Company for Cause or by the Executive for Good Reason
shall be communicated by Notice of Termination to the other party hereto
given in accordance with Section 12(b) of this Agreement. For purposes of
this Agreement, a "Notice of Termination" means a written notice which (i)
indicates the specific termination provision in this Agreement relied upon,
(ii) sets forth in reasonable detail the facts and circumstances claimed to
provide a basis for termination of the Executive's employment under the
provision so indicated and (iii) if the Date of Termination (as defined
below) is other than the date of receipt of such notice, specifies the
termination date (which date shall be not more than 15 days after the
giving of such notice). The failure by the Executive to set forth in the
Notice of Termination any fact or circumstance which contributes to a
showing of Good Reason shall not waive any right of the Executive hereunder
or preclude the Executive from asserting such fact or circumstance in
enforcing his rights hereunder.
(e) DATE OF TERMINATION. "Date of Termination" means the date
of receipt of the Notice of Termination or any later date specified
therein, as the case may be; provided, however, that (i) if the Executive's
employment is terminated by the Company other than for Cause or Disability
or by reason of
-9-
<PAGE> 13
death, the Date of Termination shall be the date on which the Company
notifies the Executive of such termination and (ii) if the Executive's
employment is terminated by reason of death or Disability, the Date of
Termination shall be the date of death of the Executive or the Disability
Effective Date, as the case may be.
6. OBLIGATIONS OF THE COMPANY UPON TERMINATION.
(a) TERMINATION BECAUSE OF DEATH. If the Executive's
employment is terminated by reason of the Executive's death, such
employment shall terminate without further obligations under this Agreement
to the Executive's representatives, other than those obligations accrued or
earned and vested (if applicable) by the Executive as of the Date of
Termination, including, for this purpose (i) the Executive's full Base
Salary through the Date of Termination at the rate in effect on the Date of
Termination, (ii) the product of the Annual Bonus paid to the Executive for
the last full fiscal year and a fraction, the numerator of which is the
number of days in the current fiscal year through the Date of Termination,
and the denominator of which is 365, (iii) any compensation previously
deferred by the Executive (together with any accrued interest thereon) and
not yet paid by the Company and any accrued vacation pay not yet paid by
the Company and (iv) all amounts payable to the estate or designated
beneficiaries of the Executive under the Thrift Plan, the Split Dollar Life
Insurance and Supplemental Death Benefit Plans and any other plans,
practices, policies and programs of the Company, and/or all other amounts
payable pursuant to Section 4(b)(iii) hereof (such amounts specified in
clauses (i), (ii), (iii) and (iv) are hereinafter referred to as "Accrued
Obligations"). All such Accrued Obligations shall be paid to the
Executive's estate or beneficiary, as applicable, in a lump sum in cash
within 30 days of the Date of Termination or otherwise in accordance with
the Executive's specific elections pursuant to any such plan, practice,
policy or program. Anything in this Agreement to the contrary
notwithstanding, the Executive's family shall be entitled to receive
benefits at least equal to the most favorable benefits provided by the
Company and any of its Subsidiaries to surviving families of executives of
the Company and such Subsidiaries under such plans, practices, policies or
programs relating to family death benefits, if any, in accordance with the
most favorable plans, practices, policies and programs of the Company and
its Subsidiaries in effect at any time during the 90-day period immediately
preceding the Effective Date or, if more favorable to the Executive and/or
the Executive's family, as in effect on the date of the Executive's death,
with respect to other key executives of the Company and its Subsidiaries
and their families.
(b) TERMINATION BECAUSE OF DISABILITY. If the Executive's
employment is terminated by reason of the Executive's Disability, such
employment shall terminate without further obligations to the Executive,
other than those obligations accrued or earned and vested (if applicable)
by the Executive as of the Date of Termination, including for this purpose,
all Accrued Obligations. All such Accrued Obligations shall be paid to the
Executive in a lump sum in cash
-10-
<PAGE> 14
within 30 days of the Date of Termination or otherwise in accordance with
the Executive's specific elections pursuant to any plan, practice, policy
or program providing benefits forming a part of the Accrued Obligations.
Anything in this Agreement to the contrary notwithstanding, the Executive
shall be entitled after the Disability Effective Date to receive disability
and other benefits at least equal to the most favorable of those provided
by the Company and any of its Subsidiaries to disabled executives and/or
their families in accordance with such plans, practices, policies and
programs relating to disability, if any, of the Company and its
Subsidiaries in effect at any time during the 90-day period immediately
preceding the Effective Date or, if more favorable to the Executive and/or
the Executive's family, as in effect at any time thereafter with respect to
other key executives of the Company and its Subsidiaries and their
families.
(c) TERMINATION FOR CAUSE BY THE COMPANY OR FOR OTHER THAN GOOD
REASON BY THE EXECUTIVE. If the Executive's employment shall be terminated
for Cause, or if the Executive terminates his employment other than for
Good Reason, the Executive's employment under this Agreement shall
terminate without further obligations to the Executive, other than those
obligations accrued or earned and vested (if applicable) by the Executive
through the Date of Termination, including for this purpose, all Accrued
Obligations. All such Accrued Obligations shall be paid to the Executive
in a lump sum in cash within 30 days of the Date of Termination or
otherwise in accordance with the Executive's specific elections pursuant to
any plan, practice, policy or program providing benefits forming a part of
the Accrued Obligations.
(d) TERMINATION FOR GOOD REASON BY THE EXECUTIVE OR FOR OTHER
THAN CAUSE OR DISABILITY BY THE COMPANY OR OTHER THAN AS A RESULT OF DEATH.
If, during the Employment Period, the Executive's employment shall be
terminated by the Company other than for Cause or Disability or other than
as a result of the Executive's death or if the Executive shall terminate
his employment for Good Reason, the Company shall pay to the Executive in a
lump sum in cash within 30 days after the Date of Termination (or otherwise
in accordance with the Executive's specific elections pursuant to any plan,
practice, policy or program providing benefits forming a part of the
Accrued Obligations) the aggregate of the following amounts and shall make
the following transfers:
(i) The Executive's full Base Salary and vacation pay
accrued (for vacation not taken) through the Date of Termination at
the rate in effect at the time of the Notice of Termination plus
accrued incentive compensation under the Company's Cash Incentive
Bonus Plan through the Date of Termination at the same percentage
rate (i.e., percentage of the Executive's previous year-end salary)
applicable to the calendar year immediately prior to the Date of
Termination, plus all other amounts to which the Executive is
entitled under any compensation plan, practice, policy or program
of the Company in effect at the time such payments are due; and
-11-
<PAGE> 15
(ii) In the event any compensation has been previously
deferred by the Executive, all amounts previously deferred
(together with any accrued interest thereon) and not yet paid by
the Company; and
(iii) Transfer the Company's entire right, title and
interest in and to split dollar life insurance and supplemental
death benefit policies pertaining to the Executive maintained under
the Company's Split Dollar Life Insurance and Supplemental Death
Benefit Plans for employees on the executive payroll of the
Company; and
(iv) A lump sum severance payment in an amount the
present value of which is equal to [Amount] times the Executive's
Formula Compensation, as defined in Section 1(c) above.
(e) SUCCESSOR IN INTEREST. The Executive may designate a
Successor (or Successors) in Interest to receive any and all amounts due
the Executive in accordance with this Agreement should the Executive be
deceased at any time of payment. Such designation of Successor(s) in
Interest shall be made in writing and signed by the Executive, and
delivered to the Company pursuant to Section 12(b) hereof. Any such
designation may be made to any legal person, persons, trust or the
Executive's estate as he shall determine in his sole discretion. In the
event any designation shall be incomplete, or in the event the Executive
shall fail to designate a Successor in Interest, his estate shall be deemed
to be his Successor in Interest to receive such portion of all of the
payments due hereunder. The Executive may amend, change or revoke any such
designation at any time and from time to time, in the same manner. This
Section 6(e) shall not supersede any designation of beneficiary or
Successor in Interest made by the Executive, or separately covered, under
any other plan, practice, policy or program of the Company.
7. NON-EXCLUSIVITY OF RIGHTS. Nothing in this Agreement shall prevent
or limit the Executive's continuing or future participation in any benefit,
bonus, incentive or other plans, practices, policies or programs provided by the
Company or any of its Subsidiaries and for which the Executive may qualify, nor
shall anything herein limit or otherwise affect such rights as the Executive may
have under any stock option or other agreements with the Company or any of its
Subsidiaries. Amounts which are vested benefits or which the Executive is
otherwise entitled to receive under any plan, practice, policy or program of the
Company or any of its Subsidiaries at or subsequent to the Date of Termination
shall be payable in accordance with such plan, practice, policy or program.
8. FULL SETTLEMENT. The Company's obligation to make the payments
provided for in this Agreement and otherwise to perform its obligations
hereunder shall not be affected by any set-off, counterclaim, recoupment,
defense or other claim, right or action which the Company may have against the
Executive or others. In no event
-12-
<PAGE> 16
shall the Executive be obligated to seek other employment or take any other
action by way of mitigation of the amounts payable to the Executive under any of
the provisions of this Agreement. The Company agrees to pay, to the fullest
extent permitted by law, all legal fees and expenses which the Executive may
reasonably incur as a result of any contest (regardless of the outcome thereof)
by the Company or others of the validity or enforceability of, or liability
under, any provision of this Agreement (including as a result of any contest by
the Executive about the amount of any payment pursuant to Sections 6 or 9 of
this Agreement), plus in each case interest at the applicable Federal rate
provided for in Section 7872(f)(2) of the Code. In any such action brought by
the Executive for damages or to enforce any provisions of this Agreement, he
shall be entitled to seek both legal and equitable relief and remedies,
including, without limitation, specific performance of the Company's obligations
hereunder, in his sole discretion.
9. CERTAIN ADDITIONAL PAYMENTS BY THE COMPANY.
(a) Anything in this Agreement to the contrary notwithstanding,
in the event it shall be determined that any payment or distribution made,
or benefit provided, by the Company to or for the benefit of the Executive
(whether paid or payable or distributed or distributable pursuant to the
terms of this Agreement or otherwise, but determined without regard to any
additional payments required under this Section 9) (a "Payment") would be
subject to the excise tax imposed by Section 4999 of the Code (or any
similar excise tax) or any interest or penalties are incurred by the
Executive with respect to such excise tax (such excise tax, together with
any such interest and penalties, are hereinafter collectively referred to
as the "Excise Tax"), then the Executive shall be entitled to receive an
additional payment (a "Gross-Up Payment") in an amount such that after
payment by the Executive of all taxes (including any Excise Tax) imposed
upon the Gross-Up Payment and any interest or penalties imposed with
respect to such taxes, the Executive retains from the Gross-Up Payment an
amount equal to the Excise Tax imposed upon the Payments.
(b) Subject to the provisions of Section 9(c), all
determinations required to be made under this Section 9, including
determination of whether a Gross-Up Payment is required and of the amount
of any such Gross-Up Payment, shall be made by Price Waterhouse (the
"Accounting Firm") which shall provide detailed supporting calculations
both to the Company and the Executive within 15 business days of the Date
of Termination, if applicable, or such earlier time as is requested by the
Company, provided that any determination that an Excise Tax is payable by
the Executive shall be made on the basis of substantial authority. The
initial Gross-Up Payment, if any, as determined pursuant to this Section
9(b), shall be paid to the Executive within five business days of the
receipt of the Accounting Firm's determination. If the Accounting Firm
determines that no Excise Tax is payable by the Executive, it shall furnish
the Executive with a written opinion that he has substantial authority not
to report any Excise Tax on his Federal income tax return. Any
determination by the Accounting Firm meeting the requirements of this
-13-
<PAGE> 17
Section 9(b) shall be binding upon the Company and the Executive; subject
only to payments pursuant to the following sentence based on a
determination that additional Gross-Up Payments should have been made,
consistent with the calculations required to be made hereunder (the amount
of such additional payments are referred to herein as the "Gross-Up
Underpayment"). In the event that the Company exhausts its remedies
pursuant to Section 9(c) and the Executive thereafter is required to make a
payment of any Excise Tax, the Accounting Firm shall determine the amount
of the Gross-Up Underpayment that has occurred and any such Gross-Up
Underpayment shall be promptly paid by the Company to or for the benefit of
the Executive. The fees and disbursements of the Accounting Firm shall be
paid by the Company.
(c) The Executive shall notify the Company in writing of any
claim by the Internal Revenue Service that, if successful, would require
the payment by the Company of a Gross-Up Payment. Such notification shall
be given as soon as practicable but not later than ten business days after
the Executive receives written notice of such claim and shall apprise the
Company of the nature of such claim and the date on which such claim is
requested to be paid. The Executive shall not pay such claim prior to the
expiration of the 30-day period following the date on which it gives such
notice to the Company (or such shorter period ending on the date that any
payment of taxes with respect to such claim is due). If the Company
notifies the Executive in writing prior to the expiration of such period
that it desires to contest such claim and that it will bear the costs and
provide the indemnification as required by this sentence, the Employee
shall:
(i) give the Company any information reasonably
requested by the Company relating to such claim,
(ii) take such action in connection with contesting such
claim as the Company shall reasonably request in writing from time
to time, including, without limitation, accepting legal
representation with respect to such claim by an attorney reasonably
selected by the Company,
(iii) cooperate with the Company in good faith in order
effectively to contest such claim, and
(iv) permit the Company to participate in any
proceedings relating to such claim;
provided, however, that the Company shall bear and pay directly all costs
and expenses (including additional interest and penalties) incurred in
connection with such contest and shall indemnify and hold the Executive
harmless, on an after-tax basis, for any Excise Tax or income tax,
including interest and penalties with respect thereto, imposed as a result
of such representation and payment of costs and expenses. Without
limitation on the foregoing provisions of this Section 9(c), the Company
shall control all proceedings taken in connection with
-14-
<PAGE> 18
such contest and, at its sole option, may pursue or forgo any and all
administrative appeals, proceedings, hearings and conferences with the
taxing authority in respect of such claim and may, at its sole option,
either direct the Executive to pay the tax claimed and sue for a refund or
contest the claim in any permissible manner, and the Executive agrees to
prosecute such contest to a determination before any administrative
tribunal, in a court of initial jurisdiction and in one or more appellate
courts, as the Company shall determine; provided, however, that if the
Company directs the Executive to pay such claim and sue for a refund, the
Company shall advance the amount of such payment to the Executive, on an
interest-free basis and shall indemnify and hold the Executive harmless, on
an after-tax basis, from any Excise Tax or income tax, including interest
or penalties with respect thereto, imposed with respect to such advance or
with respect to any imputed income with respect to such advance; and
further provided that any extension of the statute of limitations relating
to the payment of taxes for the taxable year of the Executive with respect
to which such contested amount is claimed to be due is limited solely to
such contested amount. Furthermore, the Company's control of the contest
shall be limited to issues with respect to which a Gross-Up Payment would
be payable hereunder and the Executive shall be entitled to settle or
contest, as the case may be, any other issue raised by the Internal Revenue
Service or any other taxing authority.
(d) If, after the receipt by the Executive of an amount
advanced by the Company pursuant to Section 9(c), the Executive becomes
entitled to receive any refund with respect to such claim, the Executive
shall (subject to the Company's complying with the requirements of Section
9(c)) promptly pay to the Company the amount of such refund (together with
any interest paid or credited thereon after taxes applicable thereto). If,
after the receipt by the Executive of an amount advanced by the Company
pursuant to Section 9(c), a determination is made that the Executive shall
not be entitled to any refund with respect to such claim and the Company
does not notify the Executive in writing of its intent to contest such
denial of refund prior to the expiration of 30 days after such
determination, then any obligation of the Executive to repay such advance
shall be forgiven and the amount of such advance shall offset, to the
extent thereof, the amount of Gross-Up Payment required to be paid.
10. CONFIDENTIAL INFORMATION. The Executive shall hold in a fiduciary
capacity for the benefit of the Company all secret or confidential information,
knowledge or data relating to the Company or any of its Subsidiaries, and their
respective businesses, which shall have been obtained by the Executive during
the Executive's employment by the Company or any of its Subsidiaries and which
shall not be or become public knowledge (other than by acts of the Executive or
his representatives in violation of this Agreement). After the Date of
Termination of the Executive's employment with the Company, the Executive shall
not, without the prior written consent of the Company, communicate or divulge
any such information, knowledge or data to anyone other than the Company and
those designated by it. In no event shall an asserted violation of the
-15-
<PAGE> 19
provisions of this Section 10 constitute a basis for deferring or withholding
any amounts otherwise payable to the Executive under this Agreement.
11. SUCCESSORS.
(a) This Agreement is personal to the Executive and without the
prior written consent of the Company shall not be assignable by the
Executive otherwise than by will or the laws of descent and distribution.
This Agreement shall inure to the benefit of and be enforceable by the
Executive's legal representatives or Successor(s) in Interest.
(b) This Agreement shall inure to the benefit of and be binding
upon the Company and its successors and assigns.
(c) The Company will require any successor (whether direct or
indirect, by purchase, merger, consolidation or otherwise) to all or
substantially all of the business and/or assets of the Company to assume
expressly and agree to perform this Agreement in the same manner and to the
same extent that the Company would be required to perform it if no such
succession had taken place. As used in this Agreement, "Company" shall
mean the Company as hereinbefore defined and any successor to its business
and/or assets as aforesaid which assumes and agrees to perform this
Agreement by operation of law or otherwise.
12. MISCELLANEOUS.
(a) This Agreement shall be governed by and construed in
accordance with the laws of the State of Delaware, without reference to
principles of conflict of laws. The captions of this Agreement are not
part of the provisions hereof and shall have no force or effect. This
Agreement may not be amended or modified otherwise than by a written
agreement executed by the parties hereto or their respective successors and
legal representatives.
(b) All notices and other communications hereunder shall be in
writing and shall be given by hand delivery to the other party or by
registered or certified mail, return receipt requested, postage prepaid,
addressed as follows:
If to the Executive:
-------------------
To the address on record
at the employing company
If to the Company:
-----------------
Consolidated Natural Gas Company
CNG Tower
Pittsburgh, PA 15222-3199
Attention: Senior Vice President and General Counsel
-16-
<PAGE> 20
or to such other address as either party shall have furnished to the other
in writing in accordance herewith. Notice and communications shall be
effective when actually received by the addressee.
(c) Whenever reference is made herein to any specific plan or
program of the Company, to the extent that the Executive is not a
participant therein or has no benefit accrued thereunder, whether vested or
contingent, as of the Effective Date, then such reference herein shall be
null and void and of no effect, and the Executive shall acquire no
additional benefit as a result of such reference.
(d) The invalidity or unenforceability of any provision of this
Agreement shall not affect the validity or enforceability of any other
provision of this Agreement.
(e) The Company may withhold from any amounts payable under
this Agreement such Federal, state or local taxes as shall be required to
be withheld pursuant to any applicable law or regulation.
(f) The Executive's failure to insist upon strict compliance
with any provision hereof shall not be deemed to be a waiver of such
provision or any other provision thereof.
(g) This Agreement contains the entire understanding of the
Company and the Executive with respect to the subject matter hereof but
does not supersede or override the provisions of any stock option, employee
benefit or other plan, program, policy or practice in which Executive is a
participant or under which Executive is a beneficiary.
(h) The Executive and the Company acknowledge that the
employment of the Executive by the Company prior to the Effective Date is
"at will," and, prior to the Effective Date, may be terminated by either
the Executive or the Company at any time. Upon a termination of the
Executive's employment or upon the Executive's ceasing to be an officer of
the Company, in each case, prior to the Effective Date, there shall be no
further rights under this Agreement.
IN WITNESS WHEREOF, the Executive has hereunto set his hand and, pursuant
to the authorization from its Board of Directors, the Company has caused these
presents to be executed as of the day and year first above written.
--------------------------------------
[Name]
-17-
<PAGE> 21
Executive
CONSOLIDATED NATURAL GAS COMPANY
By:
----------------------------------
G. A. Davidson, Jr.
Chairman and CEO
Attest:
- - ------------------------------
L. J. McKeown
Secretary
-18-
<PAGE> 1
EXHIBIT 11
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
COMPUTATION OF PER SHARE EARNINGS (Note 1)
(In Thousands, Except Per Share Data)
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - --------------------------------------------------------------------------------------------
<S> <C> <C> <C>
EARNINGS PER SHARE OF COMMON STOCK,
as Shown on the Consolidated Statement of Income
Income before cumulative effect of change
in accounting principle......................... $21,344 $183,171 $188,494
Cumulative effect of applying Statement of
Financial Accounting Standards No. 109
(SFAS No. 109)...................................... - - 17,422
------- -------- --------
Net income.............................................. $21,344 $183,171 $205,916
======= ======== ========
Average common shares outstanding....................... 93,246 93,000 92,808
------- -------- --------
Earnings per share of common stock
Income before cumulative effect of change
in accounting principle............................. $ .23 $ 1.97 $ 2.03
Cumulative effect of applying SFAS No. 109............ - - .19
------- -------- --------
Net income............................................ $ .23 $ 1.97 $ 2.22
======= ======== ========
PRIMARY EARNINGS PER SHARE
Income before cumulative effect of change
in accounting principle............................... $21,344 $183,171 $188,494
Cumulative effect of applying SFAS No. 109.............. - - 17,422
------- -------- --------
Net income.............................................. $21,344 $183,171 $205,916
======= ======== ========
Average common shares outstanding....................... 93,246 93,000 92,808
Incremental shares resulting from
assumed exercise of stock options..................... 99 78 316
------- -------- --------
Average common shares, as adjusted...................... 93,345 93,078 93,124
------- -------- --------
Primary earnings per share
Income before cumulative effect of change
in accounting principle............................. $ .23 $ 1.97 $ 2.02
Cumulative effect of applying SFAS No. 109............ - - .19
------- -------- --------
Net income............................................ $ .23 $ 1.97 $ 2.21
======= ======== ========
- - --------------------------------------------------------------------------------------------
</TABLE>
<PAGE> 2
EXHIBIT 11
(Cont.)
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
COMPUTATION OF PER SHARE EARNINGS (Note 1)(Continued)
(In Thousands, Except Per Share Data)
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993
- - --------------------------------------------------------------------------------------------
<S> <C> <C> <C>
FULLY DILUTED EARNINGS PER SHARE (Note 2)
Income before cumulative effect of change
in accounting principle............................... $21,344 $183,171 $188,494
Interest on 7 1/4% Convertible Subordinated
Debentures, net of tax effect......................... 11,913 12,465 12,663
------- -------- --------
Income before cumulative effect of change
in accounting principle, as adjusted.................. 33,257 195,636 201,157
Cumulative effect of applying SFAS No. 109.............. - - 17,422
------- -------- --------
Net income, as adjusted................................. $33,257 $195,636 $218,579
======= ======== ========
Average common shares outstanding....................... 93,246 93,000 92,808
Incremental shares resulting from assumed
exercise of stock options............................. 154 96 349
Shares issuable from assumed conversion of 7 1/4%
Convertible Subordinated Debentures................... 4,559 4,577 4,630
------- -------- --------
Average common shares, as adjusted...................... 97,959 97,673 97,787
------- -------- --------
Fully diluted earnings per share
Income before cumulative effect of change
in accounting principle, as adjusted................ $ .34 $ 2.00 $ 2.06
Cumulative effect of applying SFAS No. 109............ - - .18
------- -------- --------
Net income, as adjusted............................... $ .34 $ 2.00 $ 2.24
======= ======== ========
- - --------------------------------------------------------------------------------------------
<FN>
Notes:
(1) This calculation is submitted in accordance with Regulation S-K Item
601(b)(11) although not required by footnote 2 to paragraph 14 of APB
Opinion No. 15 because it results in dilution of less than 3%.
(2) This calculation is submitted in accordance with Regulation S-K Item
601(b)(11) although it is contrary to paragraph 40 of APB Opinion No. 15
because the assumed conversion of the 7 1/4% Convertible Subordinated
Debentures produces an antidilutive result.
</TABLE>
<PAGE> 1
EXHIBIT 12
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
RATIO OF EARNINGS TO FIXED CHARGES
(Thousands of Dollars)
<TABLE>
<CAPTION>
- - --------------------------------------------------------------------------------------------------------------------
Years Ended December 31, 1995 1994 1993 1992 1991
- - --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Income before cumulative effect of change
in accounting principle.............................. $ 21,344 $183,171 $188,494 $194,958 $168,613
Add income taxes (excluding cumulative effect
of change in accounting principle)................... 2,943 82,427 99,906 68,623 54,844
-------- -------- -------- -------- --------
Income before income taxes........................ 24,287 265,598 288,400 263,581 223,457
Distributed income from unconsolidated investees,
less equity in earnings thereof...................... 1,501 560 2,960 (1,707) (2,131)
-------- -------- -------- -------- --------
Subtotal.......................................... 25,788 266,158 291,360 261,874 221,326
-------- -------- -------- -------- --------
Add fixed charges:
Interest on long-term debt, including amortization
of debt discount and expense less premium.......... 95,823 88,788 85,265 93,594 96,528
Other interest expense............................... 14,732 7,992 4,995 7,170 14,727
Portion of rentals deemed to be representative
of the interest factor............................. 9,565 8,486 8,378 7,822 7,460
Fixed charges associated with 50% projects
with debt.......................................... 1,388 - - - -
-------- -------- -------- -------- --------
TOTAL FIXED CHARGES...................................... 121,508 105,266 98,638 108,586 118,715
-------- -------- -------- -------- --------
TOTAL EARNINGS........................................... $147,296 $371,424 $389,998 $370,460 $340,041
======== ======== ======== ======== ========
RATIO OF EARNINGS TO FIXED CHARGES....................... 1.21 3.53 3.95 3.41 2.86
======== ======== ======== ======== ========
- - --------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE> 1
EXHIBIT 21
<TABLE>
<CAPTION>
SUBSIDIARIES OF CONSOLIDATED NATURAL GAS COMPANY
------------------------------------------------
Percent Voting
Securities
Owned by
State of Immediate
Name of Company Incorporation Parent Company
- - --------------------------------------------------------------- ------------- --------------
<S> <C> <C>
CONSOLIDATED NATURAL GAS COMPANY............................... Delaware
Subsidiary companies:
Consolidated Natural Gas Service Company, Inc................ Delaware 100%
CNG Transmission Corporation................................. Delaware 100%
CNG Iroquois, Inc.......................................... Delaware 100%
The East Ohio Gas Company.................................... Ohio 100%
The Peoples Natural Gas Company.............................. Pennsylvania 100%
Virginia Natural Gas, Inc.................................... Virginia 100%
Hope Gas, Inc................................................ West Virginia 100%
West Ohio Gas Company........................................ Ohio 100%
CNG Producing Company........................................ Delaware 100%
CNG Pipeline Company....................................... Texas 100%
CNG Energy Services Corporation.............................. Delaware 100%
CNG Main Pass Gas Gathering Corporation.................... Delaware 100%
CNG Oil Gathering Corporation.............................. Delaware 100%
CNG Products and Services, Inc............................. Delaware 100%
CNG International, Inc.*..................................... Delaware 100%
CNG Power Company............................................ Delaware 100%
CNG Bear Mountain, Inc..................................... Delaware 100%
CNG Market Center Services, Inc............................ Delaware 100%
CNG Technologies, Inc...................................... Delaware 100%
Granite Road CoGen, Inc.................................... Texas 100%
CNG Power Services Corporation............................... Delaware 100%
CNG Lakewood, Inc.......................................... Delaware 100%
CNG Storage Service Company.................................. Delaware 100%
Consolidated System LNG Company.............................. Delaware 100%
CNG Research Company......................................... Delaware 100%
CNG Coal Company............................................. Delaware 100%
CNG Financial Services, Inc.................................. Delaware 100%
*CNG International, Inc. was incorporated on January 19, 1996.
</TABLE>
<PAGE> 1
RALPH E. DAVIS ASSOCIATES, INC.
[LOGO]
February 12, 1996
CONSOLIDATED NATURAL GAS COMPANY
CNG Tower
625 Liberty Avenue
Pittsburgh, Pennsylvania 15222-3199
Report Covering Natural Gas Supply
And Owned Oil Reserves
December 31, 1995
----------------------------------
Gentlemen:
Consolidated Natural Gas Company, through its subsidiaries (collectively
Consolidated or the Company) is engaged in exploring for, developing, producing,
purchasing, gathering, transporting, storing and distributing natural gas,
together with by-product operations. The principal market area of the
Company's retail operations is in Ohio, Pennsylvania, Virginia and West
Virginia. Consolidated operates a regional interstate pipeline system that
supplies natural gas to affiliates, and to utilities and end-users in the
Midwest, Mid-Atlantic states and the Northeast. Exploration and production
activities are carried on primarily in the Appalachian area, the Gulf Coast area
(including offshore), the Mid-Continent area, the Permian Basin area, the Rocky
Mountain area and in Canada.
The history of the operations in the Appalachian area covers a period of
over 100 years. Prior to 1943, Consolidated's gas supply was obtained from
company-owned production and by purchase from fields located within the
Appalachian area. From 1943 to 1993 Consolidated purchased gas from pipeline
companies which obtained their gas supply from fields in the Gulf Coast and
Southwest. Because of regulatory changes, Consolidated had been reducing the
volumes of gas purchased from pipeline companies since the mid-1980's. In 1993,
all remaining long-term gas purchase contracts with pipelines were converted to
firm transport contracts as the result of Federal Energy Regulatory Commission
(FERC) Order 636.
<PAGE> 2
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 12, 1996
Page 2
Consolidated now purchases gas under contracts with producers and marketers,
and also purchases gas on the spot market. A substantial part of these gas
supplies are also obtained from fields in the Gulf Coast and Southwest. Since
1957 Consolidated has also been engaged in exploration and production of gas in
Louisiana and the Texas Gulf Coast, including offshore. During the twelve
months ended December 31, 1995 most of the gas produced and purchased by the
Company was obtained from the Southwest. All gas volumes herein are stated at
a measuring base of 14.73 pounds per square inch absolute.
Gas requirements for Consolidated (including Canadian sales) increased from
666 billion cubic feet in 1994 to 897 billion cubic feet in 1995.
APPALACHIAN AREA RESERVES
Studies of the natural gas available from Appalachian gas fields lead us to
conclude that the Company may expect to obtain for a number of years a supply
from this area. The development which has occurred in this natural gas province
has resulted in extensive drilling of shallow formations in much of the area.
The entire sedimentary section has not been adequately tested in the Appalachian
area and there is the possibility that natural gas is present in commercial
quantities below the known producing formations. Consolidated has participated
in programs to test deeper formations. Consolidated has also found that reentry
into old wells has been beneficial in finding commercial quantities behind pipe.
We estimate Consolidated's proved reserves in the Appalachian fields, as of
December 31, 1995, to be 306 billion cubic feet (including CNG Producing
Company's Appalachian reserves) from company-owned wells and 573 billion cubic
feet from gas purchase wells, for a total of 879 billion cubic feet, exclusive
of gas in storage reservoirs. Total additions to the reserves controlled by the
Company in the Appalachian fields have in the past been substantial. It is
possible that future exploration and development will locate appreciable new
reserves. In addition, subsidiary companies had remaining working interest oil
reserves estimated at 449,598 barrels (including CNG Producing Company's
Appalachian oil reserves) in the Appalachian area.
<PAGE> 3
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 12, 1996
Page 3
CNG PRODUCING COMPANY
CNG Producing Company is Consolidated's primary exploration and production
subsidiary. As of December 31, 1995, the estimated proved working interest
reserves of CNG Producing Company are 830 billion cubic feet of gas and
45,653,418 barrels of crude oil and condensate. The foregoing totals include
approximately 1 billion cubic feet of gas and 5,827,290 barrels of heavy oil
reserves in Canada.
In the United States, CNG Producing Company has proved reserves in 10
states and the offshore area of the Gulf Coast. The majority of CNG Producing
Company's United States reserves are in the Gulf Coast and Mid-Continent areas.
The estimated proved reserves in the United States are 829 billion cubic feet of
gas and 39,826,128 barrels of crude oil and condensate.
The estimated Appalachian proved reserves as of December 31, 1995 for CNG
Producing Company, which are included in the total Appalachian reserves
disclosed earlier in this report, are 96 billion cubic feet of gas and 96,841
barrels of oil. In addition to the Appalachian area, CNG Producing Company
conducts exploration and development programs in other areas, including the San
Juan Basin in New Mexico. The San Juan Basin has a history of oil and gas
production from conventional sources, but recent interest in the area stems from
an unconventional source of gas supply. This interest is the Fruitland Coal
formation, where CNG Producing Company and others are producing gas from the
coal beds. The estimated San Juan Basin proved reserves of CNG Producing
Company as of December 31, 1995 are 6 billion cubic feet.
SOUTHWEST GAS
Pursuant to FERC Order 636, all long term gas supply contracts between
Consolidated and its previous pipeline suppliers have now been converted to firm
transportation agreements. Consolidated's subsidiaries have replaced a portion
of these pipeline supplies with volumes obtained under gas supply contracts with
various gas producing companies and marketing groups. These gas supply contracts
have remaining terms ranging from a few months
<PAGE> 4
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 12, 1996
Page 4
to as long as nine (9) years. Purchase entitlements under these contracts
total approximately 289 billion cubic feet, if all volumes are requested. This
estimate gives no consideration to the estimated volumes of spot market gas
which may be purchased in the future.
GAS STORAGE
The Company owns and operates 26 gas storage fields, five of which are
owned and operated jointly with other companies. One storage field is owned and
operated jointly with Texas Eastern, one with Tennessee, one with North Penn
Gas, one with both Tennessee and National Fuel Gas Supply Corporation, and
another with both Texas Eastern and Transcontinental. Consolidated's net
injected gas stored at December 31, 1995, was 460 billion cubic feet (including
53 billion cubic feet of remaining non-recoverable native gas, and 60 billion
cubic feet of non-recoverable base gas.)
The proximity of these storage fields to principal markets and their high
deliverability are important factors in enabling the Company to meet peak loads
and daily requirements during the heating season, and permit the gas purchased
to be taken relatively uniformly in summer and winter.
There are additional depleted, or nearly depleted, gas fields in the
Appalachian area which can be converted to storage fields if needed.
POTENTIAL SUPPLY SOURCES
In order to meet the demands for gas in its market area over the long-term
future, Consolidated may need additional supplies over those available from the
sources discussed above.
Canadian authorities have increased the volumes of gas which may be
imported into the United States. Gas presently being imported from Canada is
principally obtained from provinces in Western Canada. In the future, the
availability of additional gas will probably be dependent on gas from frontier
areas such as the MacKenzie Basin - Beaufort Sea area and/or the Arctic Islands.
Such additional gas from Canada may be available in part to Consolidated
directly or through other suppliers.
<PAGE> 5
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 12, 1996
Page 5
Other potential sources of gas include Alaska, Mexico, liquefied natural
gas from abroad, synthetic gas from coal or other feed stock and additional
coalbed methane.
SUMMARY AND CONCLUSIONS
We have estimated proved working interest crude oil and condensate reserves
owned by Consolidated from sources in the United States and Canada at 46,006,176
barrels as of December 31, 1995 as follows:
<TABLE>
<CAPTION>
Stock Tank Barrels
------------------
<S> <C>
Appalachian Field Reserves 352,758
- - --------------------------
CNG Producing Company
- - ---------------------
Southwest 45,556,577
Appalachian 96,841
----------
Sub Total 45,653,418
TOTAL - OWNED OIL AND CONDENSATE RESERVES 46,006,176
</TABLE>
We have estimated the gas reserves available to Consolidated from sources
in the United States and Canada at 2,362 billion cubic feet as of December 31,
1995 as follows:
<TABLE>
<CAPTION>
Billion
Cubic Feet
at 14.73 psia
-------------
<S> <C>
Appalachian Field Reserves
- - --------------------------
Company-Owned Wells 210
Gas Purchase Contract Wells 573
Gas in Storage Reservoirs 460
-----
Sub-Total 1,243
CNG Producing Company Reserves
- - ------------------------------
Company-Owned Wells
Southwest 734
Appalachian 96
---
Sub-Total 830
Gas Supply Contracts 289
- - --------------------
TOTAL - CONTROLLED GAS RESERVES 2,362
</TABLE>
<PAGE> 6
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 12, 1996
Page 6
Consolidated's requirements for the twelve months ended December 31, 1995,
including sales of gas produced in Canada, were approximately 897 billion cubic
feet.
Additional supplies are expected to become available from the Appalachian
area, the Gulf Coast and other areas and from company-owned reserves.
Potential sources of supply include additional gas from Canada, Mexico and
Alaska, liquefied natural gas from abroad, gas from the reforming of liquid
hydrocarbons such as naphtha and oil, gas from coal gasification and coalbed
methane.
The time at which these additional supplies will become available cannot be
definitely predicted. However, Consolidated is in a favorable position to
secure gas supplies from many directions, including its proven reserves, the
volume of gas in underground storage, the prospects for additional supplies from
its traditional supply areas, the several potential supply sources and the
Company's own program to augment its supply.
Yours very truly,
RALPH E. DAVIS ASSOCIATES, INC.
/s/ THOMAS N. SUDDERTH
-------------------------------
Thomas N. Sudderth
President
TNS:sw
<PAGE> 7
RALPH E. DAVIS ASSOCIATES, INC.
[LOGO]
March 22, 1996
CONSENT OF INDEPENDENT GEOLOGISTS
We hereby consent to the use of our report dated February 12, 1996,
relating to the total gas supply and Company-owned oil and gas reserves of
Consolidated Natural Gas Company, to be filed as an Exhibit to Consolidated
Natural Gas Company's Annual Report on Form 10-K for the year ended December 31,
1995. We further consent to the filing hereof as an Exhibit to said Annual
Report on Form 10-K.
We also consent to the incorporation by reference into (i) the Registration
Statements on Form S-3 (Nos. 33-1040, 33-52585 and 33-63931) and Form S-8 (Nos.
2-77204, 2-97948, 33-40478 and 33-44892) of Consolidated Natural Gas Company,
and (ii) the prospectuses made a part thereof, of our estimates of Company-owned
oil and gas reserves in the United States and Canada included in Consolidated
Natural Gas Company's Annual Report on Form 10-K for the year ended December 31,
1995. We also consent to the references to us under the heading "Experts" in
such Prospectuses.
/s/ THOMAS N. SUDDERTH
--------------------------
Thomas N. Sudderth
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED FINANCIAL STATEMENTS INCLUDED IN ITEM 8 OF CONSOLIDATED NATURAL GAS
COMPANY'S ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1995, AND
IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
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