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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, 1998
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) 690-1000
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:
6% Debentures Due October 15, 2010 New York Stock Exchange
6.8% Debentures Due December 15, 2027 New York Stock Exchange
6 5/8% Debentures Due December 1, 2008 New York Stock Exchange
6 7/8% Debentures Due October 15, 2026 New York Stock Exchange
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
8 3/4% Debentures Due June 1, 1999 New York Stock Exchange
8 3/4% Debentures Due October 1, 2019 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 $4,898,623,041 as of January 31, 1999. It was assumed
in this calculation that the registrant's affiliates are all of its directors
and/or officers, and they beneficially owned 278,755 shares of voting stock at
that date.
Shares of Common Stock, $2.75 Par Value, outstanding at January 31, 1999:
95,397,649.
The registrant's "Notice of Annual Meeting and Proxy Statement, 1999" and
Appendix I thereto are hereby incorporated by reference into Parts I, II, III
and IV of this Form 10-K.
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CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1998
TABLE OF CONTENTS
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Page
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PART I
ITEM 1. BUSINESS
Recent Developments......................................... 1
Forward-Looking Information................................. 1
The Company................................................. 1
Governmental Regulation..................................... 3
Capital Expenditures........................................ 4
Competitive Conditions...................................... 4
Gas Supply.................................................. 8
Gas Sales and Transportation................................ 11
Gas Sales, Supply, Transportation and Storage Statistics.... 12
Market Expansion............................................ 13
Rate Matters................................................ 14
Executive Officers of the Company........................... 15
ITEM 2. PROPERTIES
General Information on Facilities........................... 16
Map--Principal Facilities................................... 17
Map--Exploration and Production Areas....................... 18
Gas and Oil Producing Activities............................ 19
ITEM 3. LEGAL PROCEEDINGS........................................... 21
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 21
PART II
ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS.................................... 21
ITEM 6. SELECTED FINANCIAL DATA..................................... 21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.............................. 21
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK................................................... 21
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................. 21
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE............................... 22
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY............. 22
ITEM 11. EXECUTIVE COMPENSATION...................................... 22
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT............................................. 22
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 22
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM
8-K.................................................... 22
SIGNATURES .................................................................. 27
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CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1998
PART I
ITEM 1. BUSINESS
RECENT DEVELOPMENTS
On February 22, 1999, Consolidated Natural Gas Company (the Company) and
Dominion Resources, Inc. (DRI) announced that a definitive merger agreement
(merger agreement) was approved by the boards of directors of both companies.
Under the terms of the merger agreement, DRI will acquire all of the Company's
shares of common stock in a stock-for-stock transaction. Pursuant to the merger
agreement, each share of the Company's common stock will be converted into 1.52
shares of DRI common stock. The transaction is conditioned, among other things,
upon approvals of shareholders of both companies, opinions of independent
accountants that the transaction will be treated as a pooling of interests for
accounting purposes, approvals of various federal regulatory agencies and the
completion of regulatory processes in states where the combined company will
operate. DRI is a holding company with businesses in regulated and competitive
electric power, natural gas and oil development and selected financial services.
DRI's principal business subsidiary is Virginia Electric and Power Company, a
regulated public utility engaged in the generation, transmission, distribution
and sale of electric energy in Virginia and northeastern North Carolina.
Further information is hereby incorporated by reference to (i) the Notes to
Consolidated Financial Statements contained in Appendix I to the Company's
definitive proxy statement filed with the Securities and Exchange Commission
(SEC) pursuant to Regulation 14A and included as Exhibit 99 to this Annual
Report on Form 10-K (Form 10-K) (Reference is made thereto as follows: Note 19,
page 52) and (ii) the Company's Current Report on Form 8-K filed on March 1,
1999, including the merger agreement and press release filed as exhibits
thereto.
FORWARD-LOOKING INFORMATION
Certain matters discussed in this Form 10-K for the Company are "forward-looking
statements" intended to qualify for the safe harbors from liability established
by the Private Securities Litigation Reform Act of 1995. These forward-looking
statements can generally be identified as such because the context of the
statement will include words such as the Company "believes," "anticipates,"
"expects" or words of similar import. Similarly, statements that describe the
Company's future plans, objectives or goals are also forward-looking statements.
Such statements may address future events and conditions concerning the
Company's proposed merger with DRI, capital expenditures, earnings, risk
management, litigation, the year 2000 technology issues and costs, environmental
matters, rate and other regulatory matters, liquidity and capital resources, and
financial accounting and reporting matters. Actual results in each instance
could differ materially from those currently anticipated in such statements, due
to factors such as: natural gas and electric industry restructuring, including
ongoing state and federal activities; the weather; demographics; general
economic conditions and specific economic conditions in the Company's
distribution service areas; developments in the legislative, regulatory and
competitive environment in which the Company operates; and other circumstances
affecting anticipated revenues and costs.
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 nineteen directly
owned subsidiary companies.
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ITEM 1. BUSINESS (Continued)
The Parent Company and subsidiaries at December 31, 1998, 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 retail energy marketing
services. At December 31, 1998, the Company had 6,224 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
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
CNG Transmission Corporation (CNG Transmission)........... Delaware
CNG Producing Company (CNG Producing)..................... Delaware
CNG Main Pass Gas Gathering Corporation (CNG Main Pass)... Delaware
CNG Oil Gathering Corporation (CNG Oil Gathering)......... Delaware
CNG International Corporation (CNG International)......... Delaware
CNG Retail Services Corporation (CNG Retail).............. Delaware
CNG Products and Services, Inc. (CNG Products and
Services).............................................. Delaware
CNG Power Company (CNG Power)............................. Delaware
CNG Field Services Company (CNG Field Services)........... Delaware
CNG Power Services Corporation (CNG Power Services)....... 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
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The principal cities served at retail by the gas distribution subsidiaries (East
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, 1998, the
Company served at retail approximately 1,886,000 residential, commercial and
industrial gas sales and transportation 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 the Midwest,
the Mid-Atlantic states and the Northeast. Through its wholly owned subsidiary,
CNG Iroquois, Inc., CNG Transmission holds a 16% 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.
CNG Main Pass holds a 13.6% interest in Dauphin Island Gathering Partners, a
partnership which operates a gas gathering pipeline system in the Main Pass area
of the Gulf of Mexico.
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ITEM 1. BUSINESS (Continued)
CNG Oil Gathering holds a 33.3% general partnership interest in Main Pass Oil
Gathering Company which operates an oil gathering pipeline system in the Main
Pass and Viosca Knoll areas of the Gulf of Mexico.
CNG International engages in energy-related activities primarily through
utilities and pipeline companies outside of the United States (see
"International Activities," page 13).
CNG Retail was created in 1997 to market natural gas, electricity and related
products and services to residential, commercial and small industrial customers.
CNG Products and Services provides energy-related services to customers of the
Company's local distribution subsidiaries and others.
CNG Power, via CNG Market Center Services, Inc., holds a 50% general partnership
interest in the CNG/Sabine Center gas marketing hub.
CNG Field Services (formerly CNG Storage Service Company) provides natural gas
storage facilities and services and other activities of a full service gas
storage business. During 1998, CNG Field Services also engaged in activities
related to Appalachian area natural gas supply, including the administration of
supply contracts transferred from CNG Energy Services Corporation (CNG Energy
Services), a former subsidiary of the Company (see "Discontinued Operations,"
page 5).
Service Company is a subsidiary service company authorized by the 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 Power Services is a power marketing subsidiary which has FERC approval to
purchase and sell electricity at market-based prices. The Company exited the
power marketing business during 1998 (see "Discontinued Operations," page 5).
Consolidated LNG ended its involvement in liquefied natural gas operations in
1982 and, as of February 28, 1998, had recovered its undepreciated investment in
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 1996 through 1998 by all the
subsidiaries were not material.
CNG Coal formerly owned coal reserves and a related plant site, which were sold
in 1996.
CNG Financial was formed to engage in financing of gas-utilizing equipment, 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 1995 on the regulation of public utility holding companies.
This report contained recommendations for legislative action, including repeal
of the PUHCA with more oversight responsibility borne by the FERC and state
commissions. The report also proposed reform to remove a substantial portion of
the administrative burden inherent in the current PUHCA regulatory policies and
procedures. Legislation has been introduced which would completely repeal the
PUHCA, while another group has proposed a comprehensive energy reform program to
address market power issues, particularly regarding the electric industry (see
"Gas and Electric Industry Developments," page 5).
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. CNG Power Services and CNG Retail, public utilities as defined by section
201 of the Federal Power Act, are
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ITEM 1. BUSINESS (Continued)
also subject to limited FERC regulation. The distribution subsidiaries are
subject to regulation by the respective utility commissions in the states within
which they operate. Additionally, CNG Retail is classified as a public utility
in Pennsylvania for the limited purpose of its participation in the Pennsylvania
electric retail access programs.
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 (Clean Air
Act) and the Federal Clean Air Act Amendments of 1990 which added significantly
to the existing requirements established by the 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.
The electric utility company in Argentina, in which the Company has an interest,
is subject to regulation at the federal and provincial level. The Argentine gas
utility companies, in which the Company has an interest, are regulated at the
federal level. The pipelines in Australia, in which the Company has an interest,
are currently subject to state regulation, and will become subject to national
regulation being developed by the Commonwealth and state and territorial
governments.
CAPITAL EXPENDITURES
The current capital spending program for 1999 is estimated at $524.5 million, a
31% decrease compared with total capital spending in 1998. The estimated 1999
budget has been allocated as follows: exploration and production, $337.0
million; distribution, $128.4 million; transmission, $51.3 million; and
corporate and other, $7.8 million. The decreased level of capital expenditures
planned for 1999 anticipates lower spending for international projects, which
will be evaluated on a case-by-case basis. Exploration and production operations
reflect increased spending on deep-water projects and increased conventional
onshore and offshore drilling. Transmission and distribution operations
expenditures will primarily be limited to spending for enhancements and
improvements in the pipeline system and related facilities. The "corporate and
other" category includes expenditures to upgrade information systems technology.
The capital budget will be reviewed during the year and is subject to revision.
COMPETITIVE CONDITIONS
Various regulatory and market trends have combined to increase competition for
the Company in recent years, and for the energy industry in general. The factors
affecting the Company include: federal and state regulatory efforts, such as the
FERC's various initiatives to increase competition in both the gas and electric
industries; the overall availability of energy nationwide at relatively low
prices; competition from 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.
FERC Order No. 636 (Order 636) 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, bear all the
responsibilities and risks for arranging the procurement of their gas supplies
and contracting with pipelines to transport purchases. However, as the Company's
distribution subsidiaries had
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ITEM 1. BUSINESS (Continued)
been managing a part of their own gas supplies for a number of years, the
transition to a more competitive environment under Order 636 did not have a
significant impact on their operations. Storage facilities owned and operated as
part of the Company's distribution and transmission operations, as well as
acquired storage capacity, have become even more important factors in gas supply
management.
DISCONTINUED OPERATIONS
During April 1998, management approved a plan to discontinue the Company's
wholesale trading and marketing of natural gas and electricity, including
integrated energy management. On July 31, 1998, the sale of the capital stock of
CNG Energy Services to Sempra Energy Trading, a subsidiary of Sempra Energy, was
finalized. Included in the transaction were contracts for the purchase and sale
of natural gas as well as rights to natural gas pipeline and storage capacity,
mainly in the Northeast and Mid-Atlantic regions, and related working capital.
Proceeds of $37.4 million were received from the sale of the stock, as adjusted
for working capital items. The Company's transition out of the wholesale gas
business was substantially complete at December 31, 1998.
GAS AND ELECTRIC INDUSTRY DEVELOPMENTS
Gas industry competition at the retail level is receiving increased attention
from both regulators and legislators. Governments in three of the states in
which the Company operates distribution subsidiaries have enacted or considered
legislation regarding deregulation of natural gas at the retail level. In Ohio,
a 1996 law established customer choice as a state policy in the supply of
natural gas services. Implementation of the law, which allows retail customers
to obtain gas from an array of suppliers, is under way. In Pennsylvania, pending
legislation would unbundle gas utility merchant functions and permit the
Pennsylvania Public Utility Commission to certify marketers, in addition to gas
utilities, as suppliers of last resort, creating competition in a traditional
gas utility function. Most recently, Virginia has begun to consider gas
unbundling legislation.
In addition to restructuring of the gas industry, the emerging unbundling of
services provided by electric utilities is leading toward the convergence of the
two industries to create one overall, highly competitive marketplace for a
customer's total energy needs. Regulators and legislators at the federal level
and in many states are considering, or are already implementing, initiatives to
promote increased competition in the electric industry. A major development was
the issuance in 1996 of FERC Orders 888 and 889. By requiring open access to the
national electric transmission grid, Order 888 fosters increased competition in
both the generation of electricity and the supply of bulk power to major
wholesale customers. The companion order, Order 889, addresses the timing,
information access and other administrative details associated with the FERC
deregulation initiative. Congress also is considering legislation intended to
facilitate the move to competition in the electric industry.
Although progress status varies, pro-competition electric legislation is at
least under consideration in many states. In Ohio, leaders of the General
Assembly have predicted passage in 1999 of a bill to assure customer choice. In
Pennsylvania, the 1996 Electric Generation Customer Choice and Competition Act
required the transition to a competitive retail electric market to begin in
January 1999, with full competition by 2001. In Virginia, the General Assembly
has passed a restructuring bill which would, if approved by the Governor, phase
in retail competition starting on January 1, 2002. Regulators and legislators in
West Virginia are also debating issues related to electric industry
restructuring.
Reflecting the evolution to a more competitive energy environment, the pace and
size of business combinations among natural gas and electric utilities has
increased in recent years (see "Recent Developments," page 1, regarding the
Company's proposed merger with DRI). These business combinations have generally
been initiated to provide benefits from economies of scale, to reduce costs by
the elimination of duplicate facilities and processes, and to improve the
strategic and competitive position of the surviving entity.
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ITEM 1. BUSINESS (Continued)
Recent and pending regulatory actions may serve to further facilitate more
business combinations in the energy industry. The FERC has streamlined its
regulatory review process regarding pending mergers. In addition, Congress has
considered legislation to conditionally repeal the PUHCA, to which the Company
is subject (see "Governmental Regulation," page 3).
To focus the distribution and transmission operations on being more responsive
to customer needs and to enable them to more effectively seize growth
opportunities in the competitive marketplace, the Company announced a
significant reorganization of the management structure of its regulated
businesses in December 1998. The new structure brings all five regulated
subsidiaries--CNG Transmission, East Ohio Gas, Peoples Natural Gas, Virginia
Natural Gas and Hope Gas--under the leadership of a single management team. This
new team will manage by business process rather than by company. However, all
five companies will remain separate legal entities and will retain their names.
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 recent years, 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. Opportunities for growth in the distribution operations, however, 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 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 Clean Air Act and the 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, 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 (see "Retail Unbundling," page 13). Currently, 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. In the latter market, 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 a variety of firm and interruptible
services, including gas transportation, storage, supply pooling and balancing,
and brokering, to industrial and commercial customers. Also, residential
customers in certain of the Company's service territories can choose an
alternative source of gas supply, including CNG Retail, with the distribution
subsidiaries continuing to provide the transportation service to the 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. CNG Transmission offers gas
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ITEM 1. BUSINESS (Continued)
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 environment has provided CNG Transmission and other
pipeline companies with a number of opportunities for expansion. CNG
Transmission has taken advantage of selected market expansion opportunities,
concentrating its efforts primarily in the Northeast and along the East Coast
(see "Market Expansion," page 13). 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. The Company's pipelines are
part of an interconnected gas transmission system which will continue to enable
retail end users to take advantage of the accessibility of supplies nationwide
as gas utilities unbundle services at the retail level (see "Gas and Electric
Industry Developments," page 5 and "Retail Unbundling," page 13).
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 array 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.
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. Gas producers
throughout the industry, including CNG Producing, face a 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
growth of gas and energy marketing firms has added to the competition for CNG
Producing. 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. However, these
arrangements represent only a portion of the Company's gas production. Further,
the deliverability of gas produced is influenced by competition for downstream
pipeline transportation capacity. The Company continues to develop marketing
strategies, contracts and arrangements to address customer needs for
intermediate and long-term gas supplies as well as swing, peaking and other
energy services. In addition, in the ordinary course of business, CNG Producing
participates in price risk management activities to manage exposure to price
risk in connection with the production and sale of natural gas and oil.
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.
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ITEM 1. BUSINESS (Continued)
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, Midwest and offshore; and withdrawals from
the Company's underground storage fields.
Regulatory actions, economic factors, and changes in customers and their
preferences continue to reshape the Company's gas sales markets. A significant
number of industrial and commercial customers and a growing number of
residential customers currently purchase a large portion of their gas supplies
from producers, marketers, or on the spot market, and contract with the
transmission and/or 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. This trend is likely to
continue as the state regulators continue unbundling services at the retail
level. The distribution subsidiaries continue to purchase gas supplies for their
remaining merchant customers and recover the costs through their approved rates.
CNG Retail has the responsibility and assumes the price risk for obtaining its
own gas supplies to meet customer needs.
The Company's available gas supply in 1998 was again in a surplus
position--where available supplies exceeded 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.
GAS PURCHASED
Purchased gas volumes were 294.8 Bcf in 1998, representing 65% of the Company's
1998 gas supply of 451.9 Bcf. Spot market and short-term purchases were 256.0
Bcf, or about 57% of the total 1998 supply. Volumes purchased under contracts
with Appalachian area producers totaled 38.8 Bcf or 8% of the 1998 supply.
Purchased gas volumes are impacted by the effects of weather, withdrawals from
stored gas inventory and the activities of CNG Retail.
The Company has continued to purchase volumes from the array of accessible
producing basins using its firm capacity resources. These purchased supplies
include Appalachian resources in Ohio, Pennsylvania and West Virginia, and
production from the Gulf Coast, Mid-Continent and offshore areas. Gas purchase
contract terms have continued to undergo transformation initiated with the
removal of CNG Transmission and other gas pipelines from the merchant function.
Much of the supply is purchased under seasonal or spot purchase agreements.
While the average term of the Company's gas purchase agreements has declined,
the reliability of supply has been adequate. The availability of supplies and
heightened competition have forged a viable market which has proven capable of
satisfying the firm delivery requirement for supplies to the Company's markets
in a highly reliable manner.
At December 31, 1998, the subsidiaries had 351.0 Bcf of firm annual transport
capacity on various pipelines to move supplies from purchase locations to
market, yielding deliveries of up to 1.0 Bcf of gas a day. These pipelines
include CNG Transmission, Tennessee Gas Pipeline Company, Panhandle Eastern Pipe
Line Company, Texas Eastern Transmission Corporation, ANR Pipeline Company,
Texas Gas Transmission Corporation, Transcontinental Gas Pipe Line Corporation,
Columbia Gas Transmission Corporation, Columbia Gulf Transmission and Trunkline
Gas Company.
GAS STORAGE
The Company's underground storage facilities play an important part in balancing
gas supply with sales demand and are essential to servicing the Company's large
volume of space-heating business. In addition,
8
<PAGE> 11
ITEM 1. BUSINESS (Continued)
storage capacity is an important element in the effective management of both gas
supply and pipeline transport capacity. 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 265 Bcf of gas storage
service for others. This service is provided principally to affiliates, end
users and many of CNG Transmission's former wholesale gas sales customers who
primarily serve consumers in the Northeast.
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 several of the other
subsidiaries, have access to a portion of the storage capacity operated by CNG
Transmission. The distribution subsidiaries also have capacity available in
storage fields owned by others.
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.
GAS AND OIL PRODUCING ACTIVITIES
The Company's total gas production in 1998 was 157.5 Bcf, down from 158.1 Bcf in
1997. Oil production was 7.9 million barrels, up 8% from 7.3 million barrels in
1997.
The Company's gas wellhead prices in 1998 averaged $2.26 a thousand cubic feet
(Mcf), down from $2.43 in 1997. 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 and the impact of price risk
management activities. 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 1998 decreased to $11.54 a barrel,
compared with $16.07 in 1997, consistent with the general decline in world oil
prices.
The following table sets forth 1998 drilling activity by region:
<TABLE>
- --------------------------------------------------------------------------------------------
Wells Drilled
Exploratory Development
- --------------------------------------------------------------------------------------------
Gross Net Gross Net
-- -- -- --
<S> <C> <C> <C> <C>
Onshore (Southwest and West)................................ 14 7 29 19
Gulf of Mexico.............................................. 14 7 17 7
Appalachian Region.......................................... 4 2 31 29
-- -- -- --
Total.................................................. 32 16 77 55
== == == ==
- --------------------------------------------------------------------------------------------
</TABLE>
Of the total 109 wells drilled in 1998, 93 were successful, an 85% success rate.
Of the 32 exploratory wells drilled, 18 were successful.
Total Company-owned proved gas reserves at year-end were 1,313 Bcf, up from
1,183 Bcf at the end of 1997. Proved oil reserves were 57.1 million barrels,
compared with 50.6 million barrels in 1997. The exploration and production
segment added 374 Bcf of gas equivalent from additions, revisions, and purchases
of gas and oil reserves in 1998 and also purchased 39 Bcf of gas reserves from
an affiliate, Peoples Natural Gas (See "Company-Owned Reserves," page 19).
9
<PAGE> 12
ITEM 1. BUSINESS (Continued)
During 1997, major discoveries were made in the Main Pass area of the Gulf of
Mexico. Production at Nautilus and Atlantis, two projects in the Main Pass area,
is expected to begin in the first quarter of 1999. Gas production began in
December 1998 at a third field, Nemo. Three platforms have been installed for
these fields along with facilities capable of processing 240 million cubic feet
of gas and 20,000 barrels of oil a day. The Company is the operator of the
Nautilus/Atlantis/Nemo complex and has 68.5%, 75% and 100% interests,
respectively, in the three fields.
The Company's production at Popeye, a deep-water natural gas discovery in the
Green Canyon area of the Gulf of Mexico, was the equivalent of 22 Bcf of gas
during 1998, including .6 million barrels of condensate. CNG Producing's
interest in this property is 37.5%. Shell Offshore, Inc. is the operator in the
joint venture and Mobil Oil Exploration and Producing Southeast and BP
Exploration Inc. are the other participants.
At Neptune, a deep-water oil discovery at Viosca Knoll 826, 1998 represented the
first full year of production. This project, in which the Company holds a 50%
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. Since 1994, proved reserves have been added at Neptune equivalent to 71
Bcf of gas. The Company's portion of production from this field was the
equivalent of 26 Bcf of gas during 1998. This production was comprised of 3.9
million barrels of oil and 3.1 Bcf of gas. Facilities designed with Oryx Energy
Company, the operating partner, were reworked during 1998 to produce up to
35,000 barrels of oil and 30 million cubic feet of natural gas a day.
During 1998, two deepwater discoveries were made in the Viosca Knoll area of the
Gulf of Mexico, North Marlin and Einset. North Marlin is a natural gas discovery
in over 2,500 feet of water three miles east of the Neptune project. CNG
Producing and its partners plan to install subsea production facilities at North
Marlin similar to those at Popeye. Shell Deepwater Development, Inc. (Shell
Deepwater) has a 35% interest in North Marlin and is the operator, while CNG
Producing holds a 35% interest and Murphy Exploration and Production Company
holds a 30% interest. The Einset discovery is southeast of North Marlin and was
made in about 3,600 feet of water. CNG Producing's interest in this property is
50% and Shell Deepwater holds a 50% interest and is the operator of this
project.
CNG Producing was the successful bidder on nine leases offered in the federal
government's Gulf of Mexico lease sales in 1998, including five blocks in deep
water areas of the Gulf of Mexico. At year-end 1998, the Company held 2.0
million net acres of exploration and production properties, approximately the
same as year-end 1997. The Company's lease holdings include about 1.4 million
net acres in the Appalachian area, 385,200 in the offshore Gulf of Mexico, and
230,600 in the inland areas of the Southwest, Gulf Coast and West. The Company
holds a 21% interest in heavy oil producing properties in Alberta, Canada.
Proved reserves associated with the Canadian properties approximated 1.0 Bcf of
gas and 5.8 million barrels of oil at December 31, 1998. On an energy-equivalent
basis, these reserves represent 2% of the Company's total proved reserves at
that date.
The Company drilled 35 wells in the Appalachian Region during 1998. 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.
The Company will continue to review its property inventory during 1999, and
sales of selected properties are possible depending on economic conditions.
10
<PAGE> 13
ITEM 1. BUSINESS (Continued)
GAS SALES AND TRANSPORTATION (Five-year statistics are on page 12. Certain prior
year amounts have been restated to reflect continuing operations only.)
GAS SALES CUSTOMERS
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
Customers Total* Residential Commercial Industrial Wholesale Nonregulated
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
December 31,
1998 1,878,008 1,605,426** 121,395 919 11 150,257
1997 1,864,853 1,655,587** 124,141 1,813 39 83,273
1996 1,841,227 1,713,504 125,842 1,764 37 80
1995 1,824,115 1,695,949 126,304 1,736 12 114
1994 1,799,435 1,672,630 124,803 1,697 14 291
- -----------------------------------------------------------------------------------------
</TABLE>
* Includes residential and commercial space-heating customers as follows:
1998-1,695,943; 1997-1,750,136; 1996-1,808,062; 1995-1,788,778; and
1994-1,762,207.
** Reflects the shift of former residential sales customers to other suppliers,
including CNG Retail (see "Retail Unbundling," page 13).
REGULATED GAS SALES
Sales of gas to residential customers in 1998 were 160 Bcf, down 48 Bcf from
1997, while sales to commercial customers were 44 Bcf in 1998, down 16 Bcf
compared to 1997. Warmer weather and the effect of the displacement of sales
volumes to other suppliers, including CNG Retail, were the reasons for the
decrease in gas sales volumes in 1998 compared to 1997. The weather in the
Company's retail service areas in 1998 was 18% warmer than normal and 19% warmer
than 1997.
Industrial sales in 1998 were 3 Bcf, down 1 Bcf from 1997. 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 subsidiaries for
transportation service. Total gas deliveries (sales and transportation) to
industrial customers were 136 Bcf in 1998, compared with 138 Bcf in 1997.
NONREGULATED SALES
Nonregulated gas sales in 1998 were 207 Bcf, up 36 Bcf from 1997. The increased
sales volumes in 1998 were due to gas sales by CNG Retail in its first full year
of operation.
GAS TRANSPORTATION
Total transportation volumes in 1998 were 641 Bcf, down from 736 Bcf in 1997.
CNG Transmission transported 442 Bcf of gas in 1998, down from 546 Bcf in 1997
due in large part to the impact of warmer weather during 1998. Total
transportation volumes also include volumes transported by the distribution
subsidiaries for residential, commercial, industrial and off-system customers
amounting to 199 Bcf in 1998, up 10 Bcf over 1997. This increase reflects
transportation provided to former residential sales customers of 15 Bcf in 1998,
compared to 3 Bcf in 1997, in connection with the retail unbundling initiative.
This increase was partially offset by declines in volumes transported to
commercial, industrial and off-system customers.
11
<PAGE> 14
ITEM 1. BUSINESS (Continued)
GAS SALES, SUPPLY, TRANSPORTATION AND STORAGE STATISTICS* (Excludes affiliated
transactions)
<TABLE>
- -----------------------------------------------------------------------------------------------
Years Ended December 31, 1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C>
- -----------------------------------------------------------------------------------------------
GAS SALES REVENUES (MILLIONS)
Regulated
Residential............................ $1,089.9 $1,449.1 $1,346.1 $1,214.2 $1,254.9
Commercial............................. 267.6 369.7 361.6 345.9 373.4
Industrial............................. 13.4 22.8 30.6 32.6 45.8
Wholesale.............................. 2.8 9.4 15.4 4.7 5.2
Nonregulated............................. 494.4 433.4 396.1 239.8 723.6
-------- -------- -------- -------- --------
Total............................... $1,868.1 $2,284.4 $2,149.8 $1,837.2 $2,402.9
======== ======== ======== ======== ========
AVERAGE SALES RATES PER MCF
Regulated
Residential............................ $ 6.82 $ 6.97 $ 6.15 $ 5.71 $ 6.09
Commercial............................. 6.04 6.19 5.41 4.95 5.38
Industrial............................. 5.32 5.33 4.47 4.49 4.89
Wholesale.............................. ** ** ** ** **
Nonregulated............................. 2.39 2.53 2.48 1.94 2.17
Weighted average.................... $ 4.51 $ 5.16 $ 4.74 $ 4.44 $ 3.89
======== ======== ======== ======== ========
GAS REQUIREMENTS (BCF)
Regulated gas sales
Residential............................ 159.9 207.8 218.7 212.5 205.9
Commercial............................. 44.3 59.7 66.8 69.8 69.4
Industrial............................. 2.5 4.3 6.9 7.3 9.4
Wholesale.............................. .4 .2 1.8 .3 .3
Nonregulated gas sales................... 207.1 171.0 159.7 123.5 332.8
-------- -------- -------- -------- --------
Total sales......................... 414.2 443.0 453.9 413.4 617.8
Used and unaccounted for................. 37.7 29.0 23.3 37.8 48.3
-------- -------- -------- -------- --------
Total requirements.................. 451.9 472.0 477.2 451.2 666.1
======== ======== ======== ======== ========
GAS SUPPLY (BCF)
Purchased gas............................ 294.8 295.9 353.2 323.5 559.6
Storage (input) withdrawal............... (.4) 18.0 (23.5) 20.5 (13.0)
Gas produced
Gulf region............................ 111.4 116.5 108.1 68.3 76.4
Appalachian area....................... 26.6 25.8 26.0 27.2 27.8
Other areas............................ 19.5 15.8 13.4 11.7 15.3
-------- -------- -------- -------- --------
Total produced...................... 157.5 158.1 147.5 107.2 119.5
-------- -------- -------- -------- --------
Total supply........................ 451.9 472.0 477.2 451.2 666.1
======== ======== ======== ======== ========
PURCHASED GAS COSTS (MILLIONS)***........ $ 900.4 $1,114.1 $ 963.2 $ 864.6 $1,375.8
======== ======== ======== ======== ========
AVERAGE PURCHASE RATES PER MCF***........ $ 2.95 $ 3.39 $ 3.37 $ 2.73 $ 2.46
======== ======== ======== ======== ========
GAS TRANSPORTATION
Revenues (Millions)...................... $ 416.7 $ 369.1 $ 297.9 $ 345.2 $ 293.7
======== ======== ======== ======== ========
Gas Transported (Bcf).................... 641.2 736.0 754.0 743.3 724.9
======== ======== ======== ======== ========
GAS STORED AT DECEMBER 31 (BCF).......... 397.2 407.2 426.2 406.4 427.4
======== ======== ======== ======== ========
- -----------------------------------------------------------------------------------------------
</TABLE>
* Continuing operations.
** Demand charges and low sales volumes produce an average rate which is not
meaningful.
*** Includes transportation charges.
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. A pipeline
expansion project in conjunction with East Ohio Gas and others is expected to
provide additional capacity at minimal cost. 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
taken advantage of selected market expansion opportunities, concentrating its
efforts 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.
RETAIL UNBUNDLING
Similar to the unbundling of the services provided by gas pipeline companies,
gas distribution companies are adapting to the deregulation and unbundling of
the retail energy market. Under open access programs, natural gas suppliers
other than the local gas utility can use the utility's existing lines to deliver
gas to customers.
CNG Retail markets natural gas, electricity, and consumer products and services
to residential, commercial and small industrial customers, including those
within the Company's traditional service territories. CNG Retail will enable the
Company to take advantage of emerging deregulated energy markets for both gas
and electricity.
During the spring of 1997, Peoples Natural Gas opened its system in Pennsylvania
to customer choice. In addition, on July 2, 1997, the Public Utilities
Commission of Ohio approved the East Ohio Gas "Energy Choice" pilot program.
Under this program, approximately 15% of East Ohio Gas's residential and small
business customers are being given the opportunity to purchase their natural gas
from competing suppliers, if they so choose.
INTERNATIONAL ACTIVITIES
During December 1997, CNG International acquired ownership interests in two gas
utility holding companies, Sodigas Pampeana S.A. and Sodigas Sur S.A., and in an
electric utility holding company, Buenos Aires Energy Company (BAECO), from CEI
Citicorp Holdings S.A. in Argentina. The gas utility holding companies have
ownership interests in two gas distribution companies, Camuzzi Gas Pampeana and
Camuzzi Gas del Sur, and BAECO has an ownership interest in an electric
distribution company, EDEA. The service territories of these companies span from
Buenos Aires province to the southernmost tip of Argentina. In March 1998 CNG
International purchased additional interests in Sodigas Pampeana S.A., Sodigas
Sur S.A. and BAECO from Loma Negra, bringing the Company's ownership interests
in these entities to 21.55%, 21.55% and 25%, respectively. Camuzzi Argentina
S.A. maintains majority ownership interests in the holding companies. At
December 31, 1998, CNG International's investments in the Argentine holding
companies totaled $122.8 million.
In March 1998 CNG International purchased a 33.3% ownership interest in the
Dampier-to-Bunbury Natural Gas Pipeline (DBNGP) in Western Australia from the
Western Australia Government. One of CNG International's partners in the
purchase was El Paso Energy Corporation (El Paso), which also holds a 33.3%
ownership interest. In connection with their investments in DBNGP, CNG
International and El Paso formed DBNGP Finance Company LLC (DBNGP Finance).
DBNGP Finance is owned 50% by CNG International and 50% by EPED Holding Company,
a wholly-owned subsidiary of El Paso. Subsequent to the formation of DBNGP
Finance, the equity ownership interests of CNG International and El Paso in
DBNGP were transferred to this entity.
13
<PAGE> 16
ITEM 1. BUSINESS (Continued)
In October 1998 DBNGP Finance borrowed $250 million under a Senior Term Loan
Facility (Term Loan). The Term Loan matures October 2, 2001, can be extended in
one-year increments to October 2, 2003, and bears interest at a variable rate.
Of the gross proceeds received by DBNGP Finance under the Term Loan, $100
million was distributed to CNG International and was accounted for as a
reduction to the Company's investment in DBNGP Finance. In connection with the
Term Loan, CNG International entered into an Equity Contribution Agreement with
DBNGP Finance. CNG International is contractually obligated to make equity
contributions to DBNGP Finance equal to the Term Loan proceeds distributed to
CNG International, plus interest on such proceeds, in the event that DBNGP
Finance is unable to service this debt. The Company is contractually obligated
to cause CNG International to make such contributions.
CNG International's investments in Australia at December 31, 1998, including
DBNGP Finance, totaled $77.6 million.
RATE MATTERS
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, certain distribution companies make separate filings with their
respective regulatory commissions to reflect changes in the costs of purchased
gas.
On April 29, 1998, the Virginia State Corporation Commission issued a final
order in connection with the September 25, 1996 expedited rate application of
Virginia Natural Gas. The order resulted in an annual revenue increase of $7.2
million, retroactive to October 25, 1996, the date new rates went into effect
subject to refund. Customer refunds resulting from the order were made in 1998.
The order reflects an imputed return on equity of 10.9%. In its filing, Virginia
Natural Gas had requested a $13.9 million increase in annual revenues and a
return on equity of 11.3%.
On July 28, 1998, the Public Service Commission of West Virginia approved a
settlement agreement filed by Hope Gas in connection with its January 5, 1998
general rate filing. The new rates became effective November 1, 1998. Under the
settlement, Hope Gas is not permitted to request an increase in rates prior to
January 1, 2002, nor is it obligated to file for new rates after that date. The
approved settlement agreement grants Hope Gas a combined $6.5 million annual
revenue increase for both base rates and gas costs. Hope Gas had originally
proposed a $14.5 million annual increase in revenues.
On November 24, 1998, the FERC approved a settlement filed by CNG Transmission
in connection with its July 1, 1997 general rate filing. The settlement resolves
the outstanding issues in the case and maintains the preexisting level of annual
revenues. The settlement reflects an imputed return on equity of 10.7%. CNG
Transmission made interim customer refunds amounting to $39.2 million in
December 1998, and expects to make a final settlement refund of approximately
$19 million by the end of the first quarter of 1999. In its filing, CNG
Transmission had requested a $71 million increase in annual revenues and a
return on equity of 14.5%.
14
<PAGE> 17
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. (60) 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
David M. Westfall (51) Mr. Westfall was elected to his present position on May 1,
Senior Vice President, 1998. He served as Senior Vice President and Chief Financial
Nonregulated Business and Officer from December 1995 to April 1998, and as Senior Vice
Chief Financial Officer President, Financial from January 1995 to November 1995.
From January 1988 to January 1995, he served as Senior Vice
President at CNG Transmission.
Ronald L. Adams (39) Mr. Adams was elected to his present position on May 1,
Senior Vice President, 1998. He joined the Company as President of CNG Transmission
Regulated Business in July 1996. Prior to joining the Company, Mr. Adams held
numerous positions at Transcontinental Gas Pipe Line
Corporation (Transco) from December 1981 until June 1996.
His final position at Transco was Vice President, Operations
and Engineering.
Stephen E. Williams (50) Mr. Williams was elected to his present position on January
Senior Vice President and 1, 1993.
General Counsel
Stephen R. McGreevy (48) Mr. McGreevy was elected to his present position on March 1,
Vice President, Accounting 1993.
and Financial Control
Robert M. Sable, Jr. (47) Mr. Sable was elected to his present position on July 31,
Vice President and 1998. He served as Senior Vice President and Chief Financial
Treasurer Officer of CNG Energy Services from May 1997 through July
1998. Mr. Sable served as Treasurer of the Company from May
1995 until May 1997 and served as Senior Assistant Treasurer
from January 1993 to April 1995.
E. J. Marks, III (35) Mr. Marks was elected to his present position on January 1,
Secretary 1999. He served as Assistant Secretary and Assistant to the
Chairman from January 1998 to December 1998. From November
1993 to December 1997, he served as Manager, Corporate
Secretary's Department.
Thomas F. Garbe (46) Mr. Garbe was elected to his present position on March 1,
Controller 1993.
- ------------------------------------------------------------------------------------------------
</TABLE>
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.
15
<PAGE> 18
ITEM 2. PROPERTIES
GENERAL INFORMATION ON FACILITIES (Maps are on pages 17 and 18.)
The Company's total gross investment in property, plant and equipment was $9.2
billion at December 31, 1998. The largest portion of this investment (57%) is in
facilities located in the Appalachian area. Another significant portion (27%) is
located in the Gulf of Mexico.
Of the $9.2 billion investment, $4.3 billion is in production and gathering
systems, of which 64% is invested in the Gulf of Mexico and the Gulf coast and
22% in the Appalachian area. The Company's production subsidiary, CNG Producing,
accounts for $3.8 billion of the $4.3 billion investment, and CNG Transmission
and the distribution subsidiaries account for the remaining $.5 billion. In
addition to the wells and acreage listed elsewhere in ITEM 2, this investment
includes 6,488 miles of gathering lines which are located almost entirely within
the Appalachian area.
The Company's investment in its gas distribution network includes 30,251 miles
of pipe, exclusive of service pipe, the cost of which represents 60% of the $2.0
billion invested in the total function.
The Company's storage operation, the largest in the industry, consists of 26
storage fields, 334,086 acres of operated leaseholds, 2,067 storage wells and
802 miles of pipe. The investment in storage properties is $716 million,
including $91 million of cushion gas stored.
Of the $1.6 billion invested in transmission facilities, 67% represents the cost
of 6,653 miles of pipe required to move large volumes of gas throughout the
Company's operating area.
The Company has 92 compressor stations with 481,604 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. The system peak day
sendout in 1998 was 7.0 Bcf on March 12.
16
<PAGE> 19
CNG FACILITIES MAP
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, 1998
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 the Company'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.
17
<PAGE> 20
CNG EXPLORATION AND PRODUCTION MAP
The following graphic material which appeared in the paper format version of
the document is omitted from this electronic format document:
Map of Exploration and Production Areas at December 31, 1998
This United States map shows the general areas in which the Company 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 the Company's Canadian exploration and
production properties in Alberta, Canada.
18
<PAGE> 21
ITEM 2. PROPERTIES (Continued)
GAS AND OIL PRODUCING ACTIVITIES
Properties and activities subject to cost-of-service rate regulation are
indicated as applicable and are shown together with non-cost-of-service
properties and activities in the statistical presentations which follow.
COMPANY-OWNED RESERVES
Estimated net quantities (net before royalty) of proved gas and oil reserves at
December 31, 1996 through 1998, follow:
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
- ---------------------------------------------------------------------------------------------
<CAPTION>
December 31, 1998 1997 1996
- ---------------------------------------------------------------------------------------------
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.......... 1,052 1,313 925 1,141 900 1,040
Cost-of-service*............. -- -- 42 42 43 43
------ ------ ------ ------ ------ ------
Total..................... 1,052 1,313 967 1,183 943 1,083
====== ====== ====== ====== ====== ======
Oil Reserves (000 Bbls)........ 42,750 57,074 37,568 50,627 24,989 50,457
====== ====== ====== ====== ====== ======
</TABLE>
* In December 1998, Peoples Natural Gas transferred by sale all of its remaining
gas production properties to CNG Producing.
- --------------------------------------------------------------------------------
CNG Producing and CNG Transmission file Form EIA-23 with the Department of
Energy. The reserves reported on Form EIA-23 at December 31, 1997, as well as
those which will be reported at December 31, 1998, are not reconcilable with
Company-owned reserves because they are calculated on an operated basis and
include working interest reserves of all parties.
QUANTITIES OF GAS AND OIL PRODUCED
Quantities (net before royalty) of gas and oil produced during each of the last
three years follow:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------
Years Ended December 31, 1998 1997 1996
- -------------------------------------------------------------------------------------
<S> <C> <C> <C>
Gas Production (Bcf)*....................................... 157 158 148
===== ===== =====
Oil Production (000 Bbls)................................... 7,895 7,312 4,766
===== ===== =====
</TABLE>
* Includes cost-of-service production of 2, 3, and 3 Bcf for 1998, 1997 and
1996, respectively.
- --------------------------------------------------------------------------------
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 years 1998, 1997 and 1996 was $2.26, $2.43 and $2.46,
respectively. The respective average sales prices for oil were $11.54, $16.07
and $17.60 per barrel. The average production (lifting) cost per Mcf equivalent
of non-cost-of-service gas and oil produced during the years 1998, 1997 and 1996
was $.31, $.33 and $.32, respectively.
PRODUCTIVE WELLS
The number of productive gas and oil wells in which the Company's subsidiaries
have an interest at December 31, 1998, follow:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
Gas Wells Oil Wells
------------- -----------
Gross Net Gross Net
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Non-cost-of-service*........................................ 6,520 5,613 1,028 411
</TABLE>
* Includes 82 gross (23 net) multiple completion gas wells and 21 gross (8 net)
multiple completion oil wells.
- --------------------------------------------------------------------------------
19
<PAGE> 22
ITEM 2. PROPERTIES (Continued)
ACREAGE
The following table sets forth the gross and net developed and undeveloped
acreage of the Company's subsidiaries at December 31, 1998:
<TABLE>
- ----------------------------------------------------------------------------------------------
Developed Acreage Undeveloped Acreage
-------------------------- ----------------------
Gross Net Gross Net*
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Non-cost-of-service.............. 1,748,451 1,339,853 840,665 482,904
Cost-of-service.................. 212,055 212,055 -- --
--------- --------- ------- -------
Total....................... 1,960,506 1,551,908 840,665 482,904
========= ========= ======= =======
</TABLE>
* Approximately 29% of this 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,
1998................................. 9 7 54 1 63 8
1997................................. 4 5 69 2 73 7
1996................................. 4 5 33 1 37 6
</TABLE>
* Includes Canadian completions: 1998 --zero wells, 1997--12 wells and 1996--23
wells.
- --------------------------------------------------------------------------------
As of December 31, 1998, 6 gross (5.5 net) non-cost-of-service wells were in
process of drilling, including wells temporarily suspended. During 1998, the
Company was engaged in two waterflood projects in Oklahoma.
GAS PURCHASE CONTRACT RESERVES (AT DECEMBER 31, 1998) AND AVAILABILITY OF
SUPPLY
(CALENDAR YEAR 1999)
Gas purchase reserves under contract with independent producers in the
Appalachian area total 233 Bcf at December 31, 1998. In addition, at December
31, 1998, the Company had gas supply contracts with various other producers and
marketers with contract lengths ranging from a few months to seven years. The
volume of gas available to the Company under these supply contracts totals 151
Bcf if all volumes are requested, and has declined from the prior year due
chiefly to the sale of CNG Energy Services (see "Discontinued Operations," page
5). These gas purchase contract reserve and gas supply contract volume amounts
are as contained in the February 3, 1999 report of Ralph E. Davis Associates,
Inc. Of the total 233 Bcf under contract from Appalachian producers, the volume
of gas expected to be purchased in 1999 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 151 Bcf
available under contract from other producers and marketers, approximately 99
Bcf of gas will be available to the Company in 1999, assuming all volumes are
requested.
The Company anticipates that substantial volumes of gas will be available for
purchase during 1999 on the spot market. Due to the nature of spot market
transactions, the volumes of such gas available to the Company in 1999 cannot be
reasonably estimated. However, for the calendar year 1999, the Company expects
its distribution subsidiaries to have approximately 1 Bcf per day of firm
transport capacity available on upstream pipelines and 124 Bcf of storage
capacity available to meet their customer requirements.
20
<PAGE> 23
ITEM 2. PROPERTIES (Concluded)
The volumes expected to be available from Company-owned wells in 1999 amount to
194 Bcf of gas and 9,535 thousand barrels of oil, all from 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 discovery, acquisition and/or sale of reserves.
ITEM 3. LEGAL PROCEEDINGS
Environmental-related information is hereby incorporated by reference to the
Notes to Consolidated Financial Statements contained in Appendix I to the
Company's definitive proxy statement filed with the SEC pursuant to Regulation
14A and included as Exhibit 99 to this Form 10-K. Reference is made thereto as
follows: Note 16, page 46.
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 hereby incorporated by reference to the Notes to
Consolidated Financial Statements contained in Appendix I to the Company's
definitive proxy statement filed with the SEC pursuant to Regulation 14A and
included as Exhibit 99 to this Form 10-K. Reference is made thereto as follows:
Note 20(C), page 58.
ITEM 6. SELECTED FINANCIAL DATA
This information is hereby incorporated by reference to page 21 of Appendix I to
the Company's definitive proxy statement filed with the SEC pursuant to
Regulation 14A and included as Exhibit 99 to this Form 10-K.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
This information is hereby incorporated by reference to pages 1 through 20 of
Appendix I to the Company's definitive proxy statement filed with the SEC
pursuant to Regulation 14A and included as Exhibit 99 to this Form 10-K.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
This information is hereby incorporated by reference to Management's Discussion
and Analysis of Financial Condition and Results of Operations contained in
Appendix I to the Company's definitive proxy statement filed with the SEC
pursuant to Regulation 14A and included as Exhibit 99 to this Form 10-K.
Reference is made thereto as follows: Price Risk Management Activities, page 18.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
SUPPLEMENTARY DATA
This information is hereby incorporated by reference to the Notes to
Consolidated Financial Statements contained in Appendix I to the Company's
definitive proxy statement filed with the SEC pursuant to
21
<PAGE> 24
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Concluded)
Regulation 14A and included as Exhibit 99 to this Form 10-K. Reference is made
thereto as follows: Gas and Oil Producing Activities--Note 20(A), page 52;
Quarterly Financial Data--Note 20(B), page 57.
FINANCIAL STATEMENTS
This information is hereby incorporated by reference to pages 22 through 58 of
Appendix I to the Company's definitive proxy statement filed with the SEC
pursuant to Regulation 14A and included as Exhibit 99 to this Form 10-K.
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 SEC
pursuant to Regulation 14A. Information concerning the executive officers of the
Company is on page 15 of this Report.
ITEM 11. EXECUTIVE COMPENSATION
This information is hereby incorporated by reference to the Company's definitive
proxy statement filed with the SEC pursuant to Regulation 14A.
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 SEC pursuant to Regulation 14A.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
This information is hereby incorporated by reference to the Company's definitive
proxy statement filed with the SEC pursuant to Regulation 14A.
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
1998, the year for which this Form 10-K is being filed.
On March 1, 1999, the Company filed a Current Report on Form 8-K regarding its
proposed merger with DRI (see "Recent Developments," page 1, and Exhibit (2A),
page 24).
22
<PAGE> 25
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM
8-K (Continued)
DOCUMENTS FILED AS A PART OF THIS REPORT
Financial Statements
All of the financial statements filed as a part of this Report are hereby
incorporated by reference to Appendix I to the Company's definitive proxy
statement filed with the SEC pursuant to Regulation 14A and included as Exhibit
99 to this Form 10-K. Reference is made thereto as follows:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Page in
Appendix I
- ------------------------------------------------------------------------
<S> <C>
Report of Independent Accountants........................... 22
Consolidated Statement of Income for the Years 1996 through
1998...................................................... 23
Consolidated Balance Sheet at December 31, 1997 and 1998.... 24
Consolidated Statement of Cash Flows for the Years 1996
through 1998.............................................. 26
Consolidated Statement of Comprehensive Income for the Years
1996 through 1998......................................... 27
Notes to Consolidated Financial Statements.................. 28
Schedule II--Valuation and Qualifying Accounts.............. Note 2
</TABLE>
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.
- --------------------------------------------------------------------------------
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. 33-63931,
333-10869 and 333-25347) and Form S-8 (Nos. 2-77204, 2-97948, 33-40478,
33-44892, 333-18783 and 333-33505) of Consolidated Natural Gas Company of our
report dated February 9, 1999, except as to the subsequent event described in
Note 19 which is as of February 22, 1999, appearing on page 22 of Appendix I to
the Consolidated Natural Gas Company proxy statement for the 1999 annual meeting
of stockholders which is incorporated in this Annual Report on Form 10-K. We
also consent to the references to us under the heading "Experts" in certain of
these Prospectuses.
PRICEWATERHOUSECOOPERS LLP
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
March 15, 1999
23
<PAGE> 26
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
EXHIBITS
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- ----------------------------------------------------------------------
<C> <S>
(2) Plan of acquisition, reorganization, arrangement,
liquidation or successor:
(2A) Agreement and Plan of Merger, dated as of February 19,
1999, by and between Dominion Resources, Inc. and
Consolidated Natural Gas Company, is hereby
incorporated by reference to Exhibit 2 to the Current
Report on Form 8-K filed on March 1, 1999
(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), as amended May
31, 1996 (such amendment incorporated by reference to
Exhibit 4(B) to the Form S-3 Registration Statement
under the Securities Act of 1933, Consolidated Natural
Gas Company, Registration No. 333-10869)
(3B) By-Laws of Consolidated Natural Gas Company, last
amended May 19, 1998, are filed herewith
(4) Instruments Defining the Rights of Security Holders,
Including Indentures:
(4A) 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
(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)(i) Description of Consolidated Natural Gas Company
Rights Agreement (Rights Agreement), is hereby incorporated
by reference to Exhibit 1 to the Current Report on
Form 8-K filed on January 23, 1996
(ii) First Amendment to the Rights Agreement, dated as of
January 19, 1999, is hereby incorporated by reference to
Exhibit 2 to the Registration Statement on Form 8-A/A
filed on March 4, 1999
(iii) Amendment No. 2 to the Rights Agreement, dated as of
February 19, 1999, is hereby incorporated by reference to
Exhibit 3 to the Registration Statement on Form 8-A/A
filed on March 4, 1999
</TABLE>
24
<PAGE> 27
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
EXHIBITS (Continued)
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- ----------------------------------------------------------------------
<C> <S>
(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
(10I) 1989
(10J), (10L) 1994
(10D), (10K), (10N) 1995
(10M), (10O), (10P), (10Q) 1996
(10F), (10J)(i) 1997
(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
(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 February 18, 1997
(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, dated January 19, 1999, is filed herewith
(10I) Form of Change of Control Salary Continuation
Agreement between Consolidated Natural Gas Company and
certain employees
(10J) Consolidated Natural Gas Company Annual Executive
Incentive Program, as amended December 13, 1994
(10J)(i) Attachment C, as amended February 18, 1997, to the
Consolidated Natural Gas Company Annual Executive Incentive
Program
(10K) Unfunded Supplemental Benefit Plan for Employees of
Consolidated Natural Gas Company and Its Participating
Subsidiaries Who Are Not Represented by a Recognized
Union, as amended December 12, 1995
(10L) Consolidated Natural Gas Company Non-Employee
Directors' Restricted Stock Plan
(10M) Consolidated Natural Gas Company 1995 Employee Stock
Incentive Plan, as amended September 10, 1996
</TABLE>
25
<PAGE> 28
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Concluded)
EXHIBITS (Concluded)
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
SEC
Exhibit
Number Description of Exhibit
--------------------------------------------------------------------
<C> <S>
(10N) Form of Change of Control Employment Agreement
between Consolidated Natural Gas Company and certain
employees dated December 12, 1995
(10O) Consolidated Natural Gas Company 1991 Stock Incentive
Plan, as amended September 10, 1996
(10P) Trust Agreement between Consolidated Natural Gas
Company and Mellon Bank (Trustee) relating to funding of
certain beneficial plans for certain employees,
dated June 1, 1995
(10Q) Consolidated Natural Gas Company 1997 Stock Incentive
Plan, is incorporated by reference to Exhibit A in the
Company's 1997 definitive proxy statement filed with
the SEC
(10R) Employment Agreement between Consolidated Natural
Gas Company and George A. Davidson, Jr. dated December 22,
1998, and related letter dated January 8, 1999, are
filed herewith
(11) Statement re Computation of Per Share Earnings:
Computations of Earnings Per Common Share--Basic, and
Earnings Per Common Share--Diluted of Consolidated Natural
Gas Company and Subsidiaries for the years ended December
31, 1996 through 1998, 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
1994-1998, 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 3, 1999, 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, 1998, are filed
herewith
(23B) Consent of PricewaterhouseCoopers LLP--included as
part of this ITEM 14
(27) Financial Data Schedule has been filed electronically
(99) Appendix I to the Consolidated Natural Gas Company "Notice
of Annual Meeting and Proxy Statement, 1999," is filed
herewith
- ----------------------------------------------------------------------
</TABLE>
26
<PAGE> 29
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)
By: /S/ GEORGE A. DAVIDSON, JR.
------------------------------------
(George A. Davidson, Jr.)
Chairman of the Board
and Chief Executive Officer
March 15, 1999
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 15, 1999.
/S/ GEORGE A. DAVIDSON, JR.
- ---------------------------
(George A. Davidson, Jr.)
Chairman of the Board
and Chief Executive Officer,
and Director
/S/ D. M. WESTFALL
- ---------------------------
(D. M. Westfall)
Senior Vice President,
Nonregulated Business
and Chief Financial Officer
/S/ S. R. MCGREEVY
- ---------------------------
(S. R. McGreevy)
Vice President, Accounting
and Financial Control
/S/ WILLIAM S. BARRACK, JR.
- ---------------------------
(William S. Barrack, Jr.)
Director
/S/ J. W. CONNOLLY
- ---------------------------
(J. W. Connolly)
Director
/S/ RAYMOND E. GALVIN
- ---------------------------
(Raymond E. Galvin)
Director
/S/ RAY J. GROVES
- ---------------------------
(Ray J. Groves)
Director
/S/ PAUL E. LEGO
- ---------------------------
(Paul E. Lego)
Director
/S/ MARGARET A. MCKENNA
- ---------------------------
(Margaret A. McKenna)
Director
/S/ STEVEN A. MINTER
- ---------------------------
(Steven A. Minter)
Director
/S/ RICHARD P. SIMMONS
- ---------------------------
(Richard P. Simmons)
Director
27
<PAGE> 30
EXHIBIT INDEX
- --------------------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- --------------------------------------------------------------------------------
(2) Plan of acquisition, reorganization, arrangement, liquidation or
successor:
(2A) Agreement and Plan of Merger, dated as of February 19, 1999, by
and between Dominion Resources, Inc. and Consolidated Natural
Gas Company, is hereby incorporated by reference to Exhibit 2
to the Current Report on Form 8-K filed on March 1, 1999
(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), as amended
May 31, 1996 (such amendment incorporated by reference to
Exhibit 4(B) to the Form S-3 Registration Statement under the
Securities Act of 1933, Consolidated Natural Gas Company,
Registration No. 333-10869)
(3B) By-Laws of Consolidated Natural Gas Company, last amended May
19, 1998, are filed herewith
(4) Instruments Defining the Rights of Security Holders, Including
Indentures:
(4A) 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
(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)(i) 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
(ii) First Amendment to the Rights Agreement, dated as of January
19, 1999, is hereby incorporated by reference to Exhibit 2 to
the Registration Statement on Form 8-A/A filed on March 4,
1999
(iii) Amendment No. 2 to the Rights Agreement, dated as of February
19, 1999, is hereby incorporated by reference to Exhibit 3 to
the Registration Statement on Form 8-A/A filed on March 4, 1999
(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
(10I) 1989
(10J), (10L) 1994
(10D), (10K), (10N) 1995
(10M), (10O), (10P), (10Q) 1996
(10F), (10J)(i) 1997
<PAGE> 31
- --------------------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- --------------------------------------------------------------------------------
(10) Material Contracts (Continued):
(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
(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 February 18, 1997
(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, dated
January 19, 1999, is filed herewith
(10I) Form of Change of Control Salary Continuation Agreement between
Consolidated Natural Gas Company and certain employees
(10J) Consolidated Natural Gas Company Annual Executive Incentive
Program, as amended December 13, 1994
(10J)(i)Attachment C, as amended February 18, 1997, to the Consolidated
Natural Gas Company Annual Executive Incentive Program
(10K) Unfunded Supplemental Benefit Plan for Employees of
Consolidated Natural Gas Company and Its Participating
Subsidiaries Who Are Not Represented by a Recognized Union, as
amended December 12, 1995
(10L) Consolidated Natural Gas Company Non-Employee Directors'
Restricted Stock Plan
(10M) Consolidated Natural Gas Company 1995 Employee Stock Incentive
Plan, as amended September 10, 1996
(10N) Form of Change of Control Employment Agreement between
Consolidated Natural Gas Company and certain employees dated
December 12, 1995
(10O) Consolidated Natural Gas Company 1991 Stock Incentive Plan, as
amended September 10, 1996
(10P) Trust Agreement between Consolidated Natural Gas Company and
Mellon Bank (Trustee) relating to funding of certain beneficial
plans for certain employees, dated June 1, 1995
(10Q) Consolidated Natural Gas Company 1997 Stock Incentive Plan, is
incorporated by reference to Exhibit A in the Company's 1997
definitive proxy statement filed with the SEC
<PAGE> 32
- --------------------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- --------------------------------------------------------------------------------
(10) Material Contracts (Continued):
(10R) Employment Agreement between Consolidated Natural Gas Company
and George A. Davidson, Jr. dated December 22, 1998, and
related letter dated January 8, 1999, are filed herewith
(11) Statement re Computation of Per Share Earnings:
Computations of Earnings Per Common Share -- Basic, and Earnings
Per Common Share -- Diluted of Consolidated Natural Gas Company and
Subsidiaries for the years ended December 31, 1996 through 1998, 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 1994-1998, 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 3, 1999, 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, 1998, are filed herewith
(23B) Consent of PricewaterhouseCoopers LLP - included as part of
ITEM 14
(27) Financial Data Schedule, is filed herewith
(99) Appendix I to the Consolidated Natural Gas Company "Notice of Annual
Meeting and Proxy Statement, 1999," is filed herewith
- --------------------------------------------------------------------------------
<PAGE> 1
EXHIBIT 3B
CONSOLIDATED NATURAL GAS COMPANY
BYLAWS
AS LAST AMENDED
MAY 19, 1998
<PAGE> 2
CONSOLIDATED NATURAL GAS COMPANY
--ooOoo--
BYLAWS
OFFICES
-------
1. The principal office shall be in the City of Wilmington, County of
New Castle, State of Delaware, and the name of the resident agent in charge
thereof is The Corporation Trust Company.
2. The corporation may also have offices at such other places as the
board of directors may from time to time determine or the business of the
corporation may require
STOCKHOLDERS' MEETING
---------------------
3. The annual meetings of the stockholders for the election of
directors shall be held at the office of the corporation in the City of
Wilmington, County of New Castle, State of Delaware, or at such other place,
within or without the State of Delaware, as may from time to time be designated
by the board of directors. The board of directors shall authorize the Secretary
of the corporation to select the location within said place for the holding of
such meeting. Meetings of stockholders for any other purpose may be held either
within or without the State of Delaware at such place and time as shall be
designated in the notice of the meetings.
4. The annual meeting of stockholders shall be held on the second
Tuesday in the month of April in each year if not a legal holiday, and if a
legal holiday then on the next secular day following, at such time as shall be
designated by the Secretary and set forth in the notice of the meeting. The
stockholders shall elect directors by a plurality vote, by ballot, and transact
such other business as may properly be brought before the meeting.
5. Written notice of annual meeting shall be served upon or mailed to
each stockholder entitled to vote thereat at such address as appears on the
books of the corporation, at least thirty days prior to the meeting.
6. At least ten days before every election of directors, a complete
list of the stockholders entitled to vote at said election, arranged in
alphabetical order, with the residence
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<PAGE> 3
of each and the number of voting shares held by each, shall be prepared by the
Secretary. Such list shall be open at the place where the election is to be held
for said ten days, to the examination of any stockholder, and shall be produced
and kept at the time and place of election during the whole time thereof, and
subject to the inspection of any stockholder who may be present.
7. Except as otherwise provided by applicable law, the Certificate of
Incorporation or these Bylaws, a special meeting of the stockholders of the
corporation may be called at any time by the chairman of the board and shall be
called by the chairman of the board or secretary at the request in writing of a
majority of the board of directors, or at the request in writing of the holders
of seventy-five percent or more of the issued and outstanding shares of stock of
the corporation entitled to vote thereon. Such request shall state the purpose
or purposes of the proposed meeting.
8. Written notice of a special meeting of stockholders stating the time
and place and object thereof, shall be served upon or mailed to each stockholder
entitled to vote thereat at such address as appears on the books of the
corporation, at least twenty days before such meeting.
9. Business transacted at all special meetings shall be confined to the
objects stated in the call.
9-A. The Company shall appoint inspectors of election for meetings of
stockholders in accordance with the provisions of applicable law. Such
inspectors of election shall have the powers, duties, and responsibilities as
provided by applicable law.
10. The holders of a majority of the stock issued and outstanding and
entitled to vote thereat, present in person or represented by proxy, shall be
requisite and shall constitute a quorum at all meetings of the stockholders for
the transaction of business except as otherwise provided by statute, by the
certificate of incorporation or by these Bylaws. If, however, such quorum shall
not be present or represented at any meeting of the stockholders, the
stockholders entitled to vote thereat, present in person or represented by
proxy, shall have power to adjourn the meeting from time to time, without notice
other than announcement at the meeting, until a quorum shall be present or
represented. At such adjourned meeting at which a quorum shall be present or
represented any business may be transacted which might have been transacted at
the meeting as originally notified.
11. When a quorum is present at any meeting, the vote of the holders of
a majority of the stock having voting power present in person or represented by
proxy shall decide any
2
<PAGE> 4
question brought before such meeting, unless the question is one upon which by
express provision of the statutes or of the certificate of incorporation or of
these Bylaws, a different vote is required in which case such express provision
shall govern and control the decision of such question.
12. At any meeting of the stockholders every stockholder having the
right to vote shall be entitled to (i) vote in person, (ii) by proxy appointed
by an instrument in writing subscribed by such stockholder and bearing a date
not more than three years prior to said meeting, unless said instrument provides
for a longer period, (iii) or by transmitting or authorizing the transmission of
a telegram, cablegram, or other means of electronic transmission (including, but
not limited to, telephonic transmission) set forth or submitted with information
from which it can be determined that the transmission was authorized by the
stockholder. Each stockholder shall have one vote for each share of stock having
voting power, registered in his name on the books of the corporation, and except
where the transfer books of the corporation shall have been closed or a date
shall have been fixed as a record date for the determination of its stockholders
entitled to vote, no share of stock shall be voted on at any election of
directors which shall have been transferred on the books of the corporation
within twenty days next preceding such elections of directors.
12-A. The stockholders of the corporation may act by written consent in
lieu of a meeting in the manner set forth in Section 4 of Article FOURTH of the
Certificate of Incorporation.
DIRECTORS
---------
13. The number of directors which shall constitute the whole Board
shall be fixed by resolution of a majority of the whole Board. The directors
shall be elected at annual meetings of stockholders and shall be divided into
three classes as nearly equal in number as possible. The term of office of the
first class shall expire on the date of the 1985 annual meeting of stockholders;
the term of office of the second class shall expire one year thereafter; and
that of the third class, two years thereafter. At each annual meeting after such
classification, the successors to the class of directors whose terms shall
expire in that year, shall be elected directors for a term of three years
except, however, the Board may, by resolution adopted by a majority of the whole
Board, elect directors to serve for interim periods. Each director shall be
elected to serve until his successor shall be elected and shall qualify,
provided that the term of office of a director who is an employee of the Company
or any of its subsidiary companies shall
3
<PAGE> 5
expire contemporaneously with his or her retirement from active service with the
Company, except in such case where the majority of the Board requests that an
employee director continue to serve, and provided further that the term of
office of a director shall expire on the date of the annual meeting immediately
subsequent to the date of his or her 70th birthday. Directors need not be
stockholders.
13-A. Unless recommended by the board of directors for election, no
person shall be elected a director, unless notice in writing of a nomination by
a stockholder of the corporation shall be received by the secretary of the
corporation not more than sixty and not less than thirty calendar days before
the date of the meeting at which the election is to take place. Such notice must
set forth (i) the name, age, business address and (if known) residence address
of each nominee proposed in such notice; (ii) the principal occupation or
employment of each such nominee; (iii) a description of the business experience
during the last five years of each such nominee; and (iv) the number of shares
of capital stock of the corporation beneficially owned by each such nominee. In
addition, such notice must be signed by a stockholder duly qualified to attend
and vote at the meeting (other than the person or persons nominated) and must
contain a notice in writing signed by each nominee of his willingness to be
elected and to serve as a director.
If a nomination by a stockholder is not made in accordance with the
foregoing procedures, the chairman of the meeting shall have the power to
declare such nomination to be null, void and of no force or effect and to
disregard such nomination in conducting the election of directors at such
meeting.
14. The directors may hold their meetings and keep the books of the
corporation outside of Delaware, at such offices of the corporation or at such
other places as they may from time to time determine.
15. If the office of any director or directors becomes vacant by reason
of death, resignation, retirement, disqualification, removal from office, or
otherwise a majority of the remaining directors, though less than a quorum,
shall choose a successor or successors, who shall hold office for the unexpired
term in respect to which such vacancy occurred.
16. The property and business of the corporation shall be managed by
its board of directors which may exercise all such powers of the corporation and
do all such lawful acts and things as are not by statute or by the certificate
of incorporation or by these by laws directed or required to be exercised or
done by the stockholders.
4
<PAGE> 6
COMMITTEES OF DIRECTORS
-----------------------
17. The board of directors may, by resolution or resolutions passed by
a majority of the whole board, designate one or more committees, each committee
to consist of two or more of the directors of the corporation, which to the
extent provided in said resolution or resolutions, shall have and may exercise
the powers of the board of directors in the management of the business and
affairs of the corporation, and may have power to authorize the seal of the
corporation to be affixed to all papers which may require it. Such committee or
committees shall have such name or names as may be determined from time to time
by resolution adopted by the board of directors.
18. The committee shall keep regular minutes of their proceedings and
report the same to the board when required.
COMPENSATION OF DIRECTORS
-------------------------
19. Directors who are not employees of the Company or any of its
subsidiary companies shall be paid an annual fee as compensation for serving as
a director and, in addition, shall receive fees and expenses for attendance at
meetings of the board of directors or meetings of standing committees of the
board of directors, all as may be allowed by resolution of the board.
INDEMNIFICATIONS
----------------
20-A. Each person who at any time is, or shall have been a director,
officer, or employee of the Corporation, or serves or has served as a director,
officer, employee, fiduciary or other representative of another company,
partnership, joint venture, trust, association or other enterprise (including
any employee benefit plan), where such service was specifically requested by the
Corporation in accordance with clause (e) below, or the established guidelines
for participation in outside positions (such service hereinafter being referred
to as "Outside Service"), and is threatened to be or is made a party to any
threatened, pending, or completed claim, action, suit or Proceeding, whether
civil, criminal, administrative or investigative ("Proceeding"), by reason of
the fact that he is, or was, a director, officer or employee of the Corporation
or a director, officer, employee, fiduciary or other representative of such
other enterprise, shall be indemnified against expenses (including attorney's
fees), judgments, fines and amounts paid in settlement ("Loss") actually and
reasonably incurred by him in connection with any such Proceeding to the full
extent permitted under the General Corporation Law of the
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<PAGE> 7
State of Delaware, as the same exists or may hereafter be amended, (but, in the
case of any such amendment, only to the extent that such amendment permits the
Corporation to provide broader indemnification rights than said Law permitted
the Corporation to provide prior to such amendment). The Corporation shall
indemnify any person seeking indemnity in connection with any Proceeding (or
part thereof) initiated by such person only if such Proceeding (or part thereof)
initiated by such person was authorized by the Board of Directors of the
Corporation. With respect to any Loss arising from Outside Service, the
Corporation shall provide such indemnification only if and to the extent that
(i) such other company, partnership, joint venture, trust, association or
enterprise is not legally permitted or financially able to provide such
indemnification, and (ii) such Loss is not paid pursuant to any insurance policy
other than any insurance policy maintained by the Corporation.
20-B. The right to be indemnified pursuant hereto shall include the
right to be paid by the Corporation for expenses, including attorney's fees,
incurred in defending any such Proceeding in advance of its final disposition;
provided, however, that the payment of such expenses in advance of the final
disposition of such Proceeding shall be made only upon delivery to the
Corporation of an undertaking, by or on behalf of such director, officer, or
employee, in which such director, officer or employee agrees to repay all
amounts so advanced if it should be determined ultimately that such director,
officer or employee is not entitled to be indemnified under applicable law.
20-C. The right of any director or officer (but not employee) to be
indemnified or to the reimbursement or advancement of expenses pursuant hereto
(i) is a contract right based upon good and valuable consideration, pursuant to
which the person entitled thereto may bring suit as if the provisions hereof
were set forth in a separate written contract between the Corporation and the
director or officer, and (ii) shall continue to exist after the rescission or
restrictive modification hereof with respect to events occurring prior thereto.
20-D. The right to be indemnified or to the reimbursement or
advancement of expenses pursuant hereto shall in no way be exclusive of any
other rights of indemnification or advancement to which any such director,
officer or employee may be entitled, under any bylaw, agreement, vote of
stockholders or disinterested directors or otherwise both as to action in his
official capacity and as to action in another capacity while holding such
office, and shall continue as to a person who has ceased to be a director,
officer or employee and shall inure to the benefit of the heirs, executors and
administrators of such person.
6
<PAGE> 8
20-E. Any person who is serving or has served as a director, officer,
employee or fiduciary of (i) another corporation of which a majority of the
shares entitled to vote in the election of its directors is held by the
Corporation at the time of such service, or (ii) any employee benefit plan of
the Corporation or of any corporation referred to in clause E(i), shall be
deemed to be doing or have done so at the request of the Corporation.
MEETINGS OF THE BOARD
---------------------
21. The first meeting of the board following an annual meeting of
stockholders shall be held at such time and place either within or without the
State of Delaware as shall be fixed by a majority of the directors and no notice
of such meeting shall be necessary to the newly elected directors in order
legally to constitute the meeting provided a quorum shall be present, or they
may meet at such place and time as shall be fixed by the consent in writing of
all the directors.
22. Regular meetings of the board may be held without notice at such
time and place either within or without the State of Delaware as shall from time
to time be determined by the board.
23. Special meetings of the board may be called by the chairman of the
board on two days' notice to each director, either personally or by mail or by
telegram; special meetings shall be called by the chairman of the board or
secretary in like manner and on like notice on written request of two directors.
24. At all meetings of the board a majority of the number of directors
then constituting the whole board shall be necessary and sufficient to
constitute a quorum for the transaction of business and the act of a majority of
the directors present at any meeting at which there is a quorum shall be the act
of the board of directors, except as may be otherwise specifically provided by
statute or by these Bylaws. If a quorum shall not be present at any meeting of
directors the directors present thereat may adjourn the meeting from time to
time, without notice other than announcement at the meeting, until a quorum
shall be present.
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<PAGE> 9
NOTICES
-------
25. Whenever under the provisions of the statutes or of the certificate
of incorporation or of these Bylaws, notice is required to be given to any
director or stockholder, it shall not be construed to mean personal notice, but
such notice may be given in writing, by mail, by depositing the same in the post
office or letter box, in a post-paid sealed wrapper, addressed to such director
or stockholder at such address as appears on the books of the corporation, or,
in default of other address, to such director or stockholder at the General Post
Office in the City of Wilmington, Delaware, and such notice shall be deemed to
be given at the time when the same shall be thus mailed.
26. Whenever any notice is required to be given under the provisions of
the statutes or of the certificate of incorporation, or of these Bylaws, a
waiver thereof in writing signed by the person or persons entitled to said
notice, whether before or after the time stated therein, shall be deemed
equivalent thereto. Whenever the vote of stockholders at a meeting thereof is
required or permitted to be taken in connection with any corporate action by any
provisions of the statutes or of the certificate of incorporation or of these
Bylaws, the meeting and vote of stockholders may be dispensed with, if all the
stockholders who would have been entitled to vote upon the action if such
meeting were held, shall consent in writing to such corporate action being
taken.
OFFICERS
--------
27. The officers of the corporation shall be elected or appointed by
the board of directors and shall be a chairman of the board, a president, one or
more vice chairmen, one or more vice-presidents, a secretary, a treasurer, and a
controller. The chairman of the board and the president shall be chosen from
among the directors.
28. The board of directors at its first meeting after each annual
meeting of stockholders shall choose the officers of the corporation. In its
discretion the board of directors, by a vote of the majority thereof, may leave
unfilled any office except those of the chairman of the board, treasurer and
secretary.
29. The board shall elect or appoint such other officers and agents as
it shall deem necessary, who shall hold their offices for such terms and shall
exercise such powers and perform such duties as shall be determined from time to
time by the board. Any two offices (but not more than two) may be held by the
same person.
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<PAGE> 10
30. The salaries of all officers and agents of the corporation shall be
fixed by the board of directors.
31. The officers of the corporation shall hold office until their
successors are chosen and qualify in their stead. Any officer elected or
appointed by the board of directors may be removed at any time by the
affirmative vote of a majority of the whole board of directors. If the office of
any officer becomes vacant for any reason, the vacancy shall be filled by the
board of directors.
THE CHAIRMAN OF THE BOARD, THE PRESIDENT AND VICE CHAIRMEN
----------------------------------------------------------
32. The chairman of the board shall be in general charge of the
business of the corporation and shall have the duty to see that all orders and
resolutions of the board are carried into effect. He shall preside at all
meetings of the stockholders and directors and shall perform such other duties
as the Bylaws or the board of directors shall prescribe.
32-A. The president shall have active direction of the affairs of the
corporation subject to the chairman of the board and the board of directors. In
the absence or disability of the chairman of the board, the president shall
preside at meetings of the stockholders and directors and exercise the powers
and duties of the chairman of the board.
32-B. A vice chairman shall perform such duties as the board of
directors shall designate. In the absence of the president, one or more vice
chairmen may perform those duties as prescribed to the president in paragraph
32-A.
33. The chairman of the board or the president or a vice chairman shall
execute bonds, mortgages, and other contracts requiring a seal, under the seal
of the corporation, except where required or permitted by law to be otherwise
signed and executed and except where the signing and execution thereof shall be
expressly delegated by the board of directors to some other officer or agent of
the corporation.
VICE-PRESIDENTS
---------------
34. The vice presidents of the corporation, in such order as may be
designated by the board of directors, shall, in the absence or disability of the
president, perform the duties and exercise the powers of the president. The
vice-president designated as chief financial officer of the corporation shall
have general responsibility for the financial operations of the corporation and
for all receipts and disbursements of funds of the corporation. Each vice
president shall perform such other duties as the board of directors shall
prescribe.
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THE SECRETARY AND ASSISTANT SECRETARIES
---------------------------------------
35. The secretary shall attend all sessions of the board and all
meetings of the stockholders and record all votes and the minutes of all
proceedings in a book to be kept for that purpose and shall perform like duties
for the standing committees when required. He shall give, or cause to be given,
notice of all meetings of the stockholders and special meetings of the board of
directors, and shall perform such other duties as may be prescribed by the board
of directors, chairman of the board or president. He shall keep in safe custody
the seal of the corporation and, when authorized by the board, affix the same to
any instrument requiring it and, when so affixed, it shall be attested by his
signature or by the signature of the treasurer or an assistant secretary.
36. The assistant secretaries in the order designated by the board
shall, in the absence or disability of the secretary, perform the duties and
exercise the powers of the secretary and shall perform such other duties as the
board of directors shall prescribe.
THE TREASURER AND ASSISTANT TREASURERS
--------------------------------------
37. The treasurer shall, under the supervision and direction of the
vice- president designated as chief financial officer of the corporation, have
the custody of the corporate funds and securities and shall keep full and
accurate accounts of receipts and disbursements in books belonging to the
corporation and shall deposit all moneys and other valuable effects in the name
and to the credit of the corporation in such depositories as may be designated
by the board of directors.
38. He shall disburse the funds of the corporation as may be ordered by
the board, taking proper vouchers for disbursements, and shall render to the
chairman of the board, the president and directors, at the regular meetings of
the board, or whenever they may require it, an account of all his transactions
as treasurer and of the financial condition of the corporation.
39. If required by the board of directors, he shall give the
corporation a bond (which shall be renewed every six years) in such sum and with
such surety or sureties as shall be satisfactory to the board for the faithful
performance of the duties of his office and for the restoration to the
corporation, in case of his death, resignation, retirement or removal from
office, of all books, papers, vouchers, money and other property of whatever
kind in his possession or under his control belonging to the corporation.
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<PAGE> 12
40. The assistant treasurers in the order designated by the board
shall, in the absence or disability of the treasurer, perform the duties and
exercise the powers of the treasurer and shall perform such other duties as the
board of directors shall prescribe.
THE CONTROLLER AND ASSISTANT CONTROLLERS
----------------------------------------
40-A. The controller shall, under the supervision and direction of the
vice-president, accounting and financial control, act as the principal
accounting officer of the corporation and shall be responsible for the keeping
of complete and accurate records of the business, assets, liabilities and
transactions of the corporation, for the preparation of such financial
statements of the corporation as may be required by law or requested by the
board of directors or the chairman of the board, for the coordination on behalf
of the corporation of the audits made by independent accountants of the
corporation's books, records and financial statements, and for all matters
relating to the accounting by the corporation for its operations and financial
position.
40-B. If required by the board of directors, the controller shall give
the corporation a bond (which shall be renewed every six years) in such sum and
with such surety or sureties as shall be satisfactory to the board for the
faithful performance of the duties of his office and for the restoration to the
corporation, in case of his death, resignation, retirement or removal from
office, of all books, papers, vouchers, money and other property of whatever
kind in his possession or under his control belonging to the corporation.
40-C. The assistant controllers in the order designated by the board
shall, in the absence or disability of the controller, perform the duties and
exercise the powers of the controller.
CERTIFICATES OF STOCK
---------------------
41. The certificates of stock of the corporation shall be numbered and
shall be entered in the books of the corporation as they are issued. They shall
exhibit the holder's name and number of shares and shall be signed by the
chairman or a vice-chairman of the board of directors, or the president or a
vice-president, and by the treasurer or an assistant treasurer, or the secretary
or an assistant secretary. The stock certificate shall be countersigned by a
transfer agent or an assistant transfer agent or a transfer clerk acting on
behalf of the corporation, or a registrar. Any or all the signatures on the
certificate may be a facsimile.
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<PAGE> 13
TRANSFERS OF STOCK
------------------
42. Upon surrender to the corporation or the transfer agent of the
corporation of a certificate for shares duly endorsed or accompanied by proper
evidence of succession, assignment or authority to transfer, it shall be the
duty of the corporation to issue a new certificate to the person entitled
thereto, cancel the old certificate and record the transaction upon its books.
CLOSING OF TRANSFER BOOKS
-------------------------
43. The board of directors shall have power to close the stock transfer
books of the corporation for a period not exceeding fifty days preceding the
date of any meeting of stockholders or the date for payment of any dividend or
the date for the allotment of rights or the date when any change or conversion
or exchange of capital stock shall go into effect or for a period of not
exceeding fifty days in connection with obtaining the consent of stockholders
for any purpose; provided, however, that in lieu of closing the stock transfer
books as aforesaid, the board of directors may fix in advance a date, not
exceeding fifty days preceding the date of any meeting of stockholders, or the
date for the payment of any dividend, or the date for the allotment of rights,
or the date when any change or conversion or exchange of capital stock shall go
into effect, or a date in connection with obtaining such consent, as a record
date for the determination of the stockholders entitled to notice of, and to
vote at, any such meeting, and any adjournment thereof, or entitled to receive
payment of any such dividend, or to any such allotment of rights, or to exercise
the rights in respect of any such change, conversion or exchange of capital
stock, or to give such consent, and in such case such stockholders and only such
stockholders as shall be stockholders of record on the date so fixed shall be
entitled to such notice of, and to vote at, such meeting and any adjournment
thereof, or to receive payment of such dividend, or to receive such allotment of
rights, or to exercise such rights, or to give such consent, as the case may be,
notwithstanding any transfer of any stock on the books of the corporation after
any such record date fixed as aforesaid.
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<PAGE> 14
REGISTERED STOCKHOLDERS
-----------------------
44. The corporation shall be entitled to treat the holder of record of
any share or shares of stock as the holder in fact thereof and, accordingly,
shall not be bound to recognize any equitable or other claim to or interest in
such share on the part of any other person, whether or not it shall have express
or other notice thereof, except as otherwise provided by the laws of Delaware.
LOST CERTIFICATE
----------------
45. The board of directors may direct a new certificate or certificates
to be issued in place of any certificate or certificates theretofore issued by
the corporation alleged to have been lost or destroyed, upon the making of an
affidavit of that fact by the person claiming the certificate of stock to be
lost or destroyed. When authorizing such issue of new certificate or
certificates, the board of directors, may in its discretion and as a condition
precedent to the issuance thereof, require the owner of such lost or destroyed
certificate or certificates, or his legal representative, to advertise the same
in such manner as it shall require and/or give the corporation a bond in such
sum as it may direct as indemnity against any claim that may be made against the
corporation with respect to the certificate alleged to have been lost or
destroyed.
DIVIDENDS
---------
46. Dividends upon the capital stock of the corporation, subject to the
provisions of the certificate of incorporation, if any, may be declared by the
board of directors at any regular or special meeting, pursuant to law. Dividends
may be paid in cash, in property, or in shares of the capital stock, subject to
the provisions of the certificate of incorporation.
47. Before payment of any dividend there may be set aside out of any
funds of the corporation available for dividends such sum or sums as the
directors from time to time, in their absolute discretion, think proper as a
reserve fund to meet contingencies, or for equalizing dividends, or for
repairing or maintaining any property of the corporation, or for such other
purpose as the directors shall think conducive to the interest of the
corporation, and the directors may modify or abolish any such reserve in the
manner in which it was created.
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<PAGE> 15
DIRECTORS' ANNUAL STATEMENT
---------------------------
48. The board of directors shall present at each annual meeting and
when called for by vote of the stockholders at any special meeting of the
stockholders, a full and clear statement of the business and condition of the
corporation.
CHECKS
------
49. All checks or demands for money and notes of the corporation shall
be signed by such officer or officers or such other person or persons as the
board of directors may from time to time designate.
FISCAL YEAR
-----------
50. The fiscal year shall be the calendar year.
SEAL
----
51. The corporate seal shall have inscribed thereon the name of the
corporation, the year of its organization and the words "Corporate Seal,
Delaware". Said seal may be used by causing it or a facsimile thereof to be
impressed or affixed or reproduced or otherwise.
AMENDMENTS
----------
52. Except as otherwise provided in the Certificate of Incorporation or
these Bylaws, these Bylaws may be altered or repealed: (i) at any regular
meeting of the stockholders or at any special meeting of the stockholders at
which a quorum is present or represented, provided notice of the proposed
alteration or repeal be contained in the notice of such special meeting, by the
affirmative vote of a majority of the stock entitled to vote at such meeting and
present or represented thereat, or (ii) by the affirmative vote of a majority of
the board of directors at any regular meeting of the board or at any special
meeting of the board if notice of the proposed alteration or repeal be contained
in the notice of such special meeting; provided, however, that no change of the
time or place of the meeting for the election of directors shall be made within
sixty days next before the day on which such meeting is to be held, and that in
case of any change of such time or place, notice thereof shall be given to each
stockholder in person or by letter mailed to his last known post office address
at least twenty days before the meeting is held.
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<PAGE> 1
EXHIBIT 4A(1)
INDENTURES OF CONSOLIDATED NATURAL GAS COMPANY
----------------------------------------------
The Indentures, Supplemental Indentures and Securities Resolutions 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 The Chase Manhattan 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)
Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2 to
Form 8-A filed April 21, 1995 under file No. 1-3196 and relating to
the 7-3/8% Debentures Due April 1, 2005)
Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2 to
Form 8-A filed October 18, 1996 under file No. 1-3196 and relating to
the 6-7/8% Debentures Due October 15, 2026)
Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2 to
Form 8-A filed December 12, 1996 under file No. 1-3196 and relating to
the 6-5/8% Debentures Due December 1, 2008)
Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2 to
Form 8-A filed December 12, 1997 under file No. 1-3196 and relating to
the 6.80% Debentures Due December 15, 2027)
Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2 to
Form 8-A filed October 22, 1998 under file No. 1-3196 and relating to
the 6% Debentures Due October 15, 2010)
<PAGE> 1
EXHIBIT 10H
EMPLOYMENT AGREEMENT
BETWEEN
CONSOLIDATED NATURAL GAS COMPANY
AND
NAME
DATED JANUARY 19, 1999
<PAGE> 2
<TABLE>
<CAPTION>
TABLE OF CONTENTS
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PAGE
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<S> <C> <C>
1. OPERATION AND TERM OF AGREEMENT; CERTAIN DEFINITIONS 2
2. CHANGE OF CONTROL 3
3. EMPLOYMENT PERIOD 4
4. TERMS OF EMPLOYMENT 5
(A) Position and Duties 5
(B) Compensation 6
(i) Base Salary 6
(ii) Annual Bonus 6
(iii) Incentive, Savings and Retirement Plans 6
(iv) Split Dollar Life Insurance and Supplemental Death
Benefit Plans 8
(v) Welfare Benefit Plans 8
(C) Additional Rights of the Executive and Obligations of the Company 8
(i) Expenses 8
(ii) Fringe Benefits 8
(iii) Office and Support Staff 9
(iv) Vacation 9
(v) Indemnification 9
5. TERMINATION 9
(A) Death or Disability 9
(B) Cause 10
(C) Good Reason 10
(D) Notice of Termination 12
(E) Date of Termination 12
6. OBLIGATIONS OF THE COMPANY AND CNG SYSTEM COMPANY
UPON TERMINATION 12
(A) Termination Because of Death 12
(B) Termination Because of Disability 13
(C) Termination For Cause by the Company or For Other Than
Good Reason by the Executive 14
(D) Termination For Good Reason by the Executive or For Other
Than Cause or Disability by the CNG System Company or
Other Than as a Result of Death 14
(E) Successor in Interest 17
</TABLE>
<PAGE> 3
<TABLE>
<S> <C> <C>
7. NON-EXCLUSIVITY OF RIGHTS 18
8. FULL SETTLEMENT 18
9. CERTAIN ADDITIONAL PAYMENTS BY THE COMPANY 19
10. CONFIDENTIAL INFORMATION 21
11. SUCCESSORS 22
12. MISCELLANEOUS 22
</TABLE>
<PAGE> 4
EMPLOYMENT AGREEMENT
AGREEMENT by and between Consolidated Natural Gas Company, a Delaware
corporation (the "Company"), and Name (the "Executive"), dated as of January 19,
1999.
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, which is intended to supercede and cancel all previous change of
control agreements, employment agreements or salary continuation agreements
entered into between any of the CNG System Companies and the Executive.
NOW THEREFORE, the parties, for good and valuable consideration and
intending to be legally bound, agree as follows:
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<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 any CNG System Company is terminated or if the
Executive would otherwise lose any rights under this Agreement due to
a demotion or salary reduction prior to the date on which a Change of
Control occurs, and it is reasonably demonstrated that such
termination or demotion or salary reduction (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 or demotion or salary reduction.
(C) "CNG System Company(ies)" shall be the Company and/or any and all of
its Subsidiaries.
(D) A reference herein to a section of the Internal Revenue Code of 1986,
as amended (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.
2
<PAGE> 6
(E) 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 Exchange Act or any rule or regulation enacted or
promulgated as a successor thereto.
(F) Subsidiary(ies) means a corporation or other entity 50% or more of the
equity interests of which are owned directly or indirectly by the
Company.
(G) Employee Benefit Plan means any written plan providing benefits for
employees of the Company or any Subsidiary.
(H) 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.
(I) Voting Securities or Security means any securities of the Company
which carry the right to vote generally in the election of directors.
2. Change of Control. For the purpose of this Agreement, a "Change of
Control" means and shall be deemed to have occurred upon the first to
occur of the following if:
(A) any Person (as defined in the Exchange Act), 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 (i) eligible to file a Schedule 13G pursuant
to Rule 13d-1(b)(1) under the Exchange Act with respect to Voting
Securities or (ii) 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
3
<PAGE> 7
(B) the individuals who, as of the date hereof, constitute the Board
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 date hereof
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
(C) the stockholders of the Company approve a merger, consolidation,
recapitalization or reorganization of the Company or a subsidiary of
the Company, reverse split of any class of Voting Securities, or an
acquisition of securities or assets by the Company or a subsidiary of
the Company, or consummation of any such transaction if stockholder
approval is not obtained, other than (i) any such transaction which
would result in at least 60 percent of the total voting power
represented by the voting securities of the Company (or the company
into which the Company has merged or the ultimate parent company of
the Company) outstanding immediately after such transaction being
beneficially owned by at least 60 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 (ii) 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;
for purposes of this subsection 2(C), the relevant measurements
concerning voting power and ownership will be examined on the date the
shareholders vote, as if the transaction closed that date, as opposed
to the date the transaction actually closes;
(D) 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.
3. Employment Period. The Company hereby agrees to continue or cause the
continuation of the Executive in the employ of a CNG System Company, and
the Executive hereby agrees to remain in the employ of a CNG System
Company, except as herein provided, for the period commencing on the
Effective Date and ending on the third anniversary of such date (the
"Employment Period").
4
<PAGE> 8
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 CNG
System Company to which Executive is assigned 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 CNG System
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 CNG
System Company to which Executive is assigned. 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 CNG System Company to
terminate the Executive's employment for Cause, as defined below.
5
<PAGE> 9
(B) Compensation.
(i) Base Salary. During the Employment Period, the Executive shall
receive an annual base salary ("Base Salary"), at a monthly rate
at least equal to the highest monthly base salary paid or payable
to the Executive by any CNG System Company during the 12-month
period immediately preceding the month in which the Effective
Date occurs. As used herein, "Base Salary" will include all wages
or salary paid to the Executive and will be calculated before any
salary reduction or deferrals, including but not limited to
reductions made pursuant to: Code Section 125; Code Section
401(k); and the Executive Incentive Deferral Plan. 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 CNG System Companies. 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 Annual Executive Incentive Program, any successor
to such program or otherwise) in cash at least equal to the
highest of: a) the average annual bonus payable to the Executive
from any CNG System Company in respect of the highest two of the
last three fiscal years immediately preceding the Effective Date
in which bonuses were paid or b) the Target Annual Bonus in the
then current year for persons in the Executive's Salary Grade. As
used herein, "Target Annual Bonus" will mean the anticipated
bonus level for a salary grade or position, which will not be
less than the same percentage of base salary as was in effect for
the applicable salary grade or position at any time during the
90-day period immediately preceding the Change of Control.
(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 CNG System Companies (including, without
6
<PAGE> 10
limitation, the Company's Executive Incentive Deferral Plan and
its System 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 CNG System Companies
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 CNG System Companies. Notwithstanding
the foregoing, the Company will not be required to institute new
long-term incentive plans or programs following the Effective
Date and before the date of closing or consummation of the
transaction contemplated by a Change of Control so long as
existing long-term incentive awards for the full calendar year
which includes the Effective Date have been paid in connection
with the Change of Control.
In the event of the termination of the Company's Thrift Plan, or
modification of such Plan, having the effect of reducing the
applicable CNG System Company's monthly and/or matching
contributions for the benefit of the Executive pursuant to such
Plan, the CNG System Company shall, for the duration of the
Employment Period, make monthly and/or matching contributions to
a deferred compensation account maintained on behalf of the
Executive in amounts which when added to any contributions made
by the CNG System Company for the benefit of the Executive under
the Thrift Plan shall at least equal the greater of (a) the CNG
System Company's average monthly or matching contributions to the
Executive's account under the Thrift Plan in respect to the
fiscal year immediately preceding the Effective Date or (b) the
CNG System 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 in the case of an account maintained under a
qualified plan, in accordance with the terms of the plan, or in
the case of any other such account, at the termination of the
Executive's employment with the CNG System Companies.
7
<PAGE> 11
(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 CNG System Companies.
(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 CNG System Companies (including, without
limitation, medical, prescription, dental, vision, short term
disability, income gap long term disability, salary continuance,
severance, 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 CNG System Companies.
(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 incurred by the Executive in accordance with the most
favorable policies, practices and procedures of the CNG System
Companies 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 CNG System Companies.
(ii) Fringe Benefits. During the Employment Period, the Executive
shall be entitled to the same fringe benefits for which the
Executive was eligible prior to the Effective Date, including but
8
<PAGE> 12
not limited to the use of an automobile and payment of related
expenses, or automobile allowances, where applicable, parking,
financial consulting services, reimbursement for club dues, where
applicable, home security, where applicable, in accordance with
the most favorable plans, practices, policies and programs of the
CNG System Companies 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 CNG System Companies.
(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 CNG System Company to
which the Executive was assigned 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 CNG System Companies.
(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 CNG System
Companies 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 CNG System Companies.
(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 or the CNG System Company to which Executive is assigned
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 CNG
System Company to which Executive is assigned determines in good
9
<PAGE> 13
faith that the Disability of the Executive has occurred (pursuant to
the definition of "Disability" set forth below), it may give to the
Executive written notice of its intention to terminate the Executive's
employment. In such event, the Executive's employment with the CNG
System 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 CNG System 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 CNG System 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 CNG System Company to which
Executive is assigned 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 any CNG System 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 CNG System Company or (iii) the conviction of
the Executive of a felony.
(C) Good Reason. Anything in this Agreement to the contrary
notwithstanding, 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 CNG System Company to which the Executive is assigned. 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 or the CNG System
Company to which the Executive is assigned which results in a
diminution in such position, authority, duties or
responsibilities, excluding for this purpose an isolated,
10
<PAGE> 14
insubstantial and inadvertent action not taken in bad faith and
which is remedied by the CNG System Company promptly after
receipt of notice thereof given by the Executive;
(ii) any failure by the CNG System Company to which Executive is
assigned 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 CNG System Company promptly after receipt of
notice thereof given by the Executive;
(iii) the Company or the CNG System Company's to which the Executive
is assigned 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 or the CNG System
Company to which Executive is assigned 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, sale or other disposition by the Company of the CNG
System Company 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 the Effective Date, shall be deemed
to be a termination for Good Reason for all purposes of this
Agreement. Any termination by the Executive for Good Reason (other
than a termination during the 30-day period described in the
immediately preceding sentence for a reason other than one set forth
in clauses (i) through (vi) of this Section 5(C)) will be treated as a
termination by the Company for purposes of any severance plan or
policy in which the Executive could have been a participant
immediately prior to the Effective Date, and the Executive shall be
entitled to severance benefits under any such plan or policy as in
effect immediately prior to the Effective Date. Notwithstanding the
foregoing, the Executive will
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<PAGE> 15
not be entitled to severance under any voluntary severance pay policy
or plan or voluntary job elimination program.
(D) Notice of Termination. Any termination of the Executive's employment
by the CNG System 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 CNG System Company other than for
Cause or Disability or by reason of death, the Date of Termination
shall be the date on which the CNG System 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 and CNG System 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 Executive's Target Bonus
under the applicable bonus plan for the calendar year in effect
including the Date of Termination and a fraction, the numerator of
which is the number of days in the current fiscal year through the
Date of
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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 CNG System Company
or other appropriate plan or entity, and any accrued vacation pay not
yet paid by the CNG System Company and (iv) all amounts payable to the
estate or designated beneficiaries of the Executive under the System
Thrift Plan, System Pension Plan, ESOP, the Split Dollar Life
Insurance and Supplemental Death Benefit Plans and any other plans,
practices, policies and programs of the CNG System 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 CNG System Company to surviving
families of executives of the CNG System Company 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 CNG System Company 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 CNG System Companies 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 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 CNG System Companies to disabled executives and/or
their families in accordance with such plans, practices, policies and
programs relating to disability, if any, of the CNG System Companies
in effect at any time during the 90-day period immediately preceding
the Effective Date or, if
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<PAGE> 17
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 CNG System Companies and their families.
(C) Termination For Cause by the CNG System 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 CNG System Company or Other Than As a Result of
Death. If, during the Employment Period, the Executive's employment
shall be terminated by the Company or the CNG System Company to which
Executive is assigned, 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 CNG System Companies
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 and provide the following benefits:
(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 an
amount equal to the product of the Executive's Target Annual
Bonus under the applicable bonus plan for the calendar year
including the Date of Termination and a fraction, the numerator
of which is the number of days in such calendar year through the
Date of Termination and the denominator of which is 365, 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
(ii) In the event any compensation has been previously deferred by the
Executive, all amounts previously deferred (together with any
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<PAGE> 18
accrued interest thereon) and not yet paid by the CNG System
Company; and
(iii) (a) In the event the Executive is at least 50 years old with 10
years of Service on the Date of Termination, the Executive shall
be entitled to elect, at the time of his termination of
employment, one of the following benefits under the Split Dollar
Life Insurance Program and the Consolidated Natural Gas Company
Supplemental Retirement Benefit Plan (the "Supplemental
Retirement Plan"): (x) retirement under the Supplemental
Retirement Plan with five (5) years added to age and Service for
all purposes, including retirement eligibility or (y) purchase
for and deliver to Executive by the Company of a completely paid
up whole life insurance policy to be owned by Executive, with the
beneficiary to be designated by the Executive, and with a death
benefit equal to two times Executive's Base Salary. The Company
will also pay to the Executive, at the time of termination of
employment, an amount that, after payment of all federal, state
and local income, employment and excise taxes thereon, is equal
to all applicable federal, state and local income and employment
and excise taxes payable on the benefit provided for in this
Section 6(D)(iii)(a).
(b) In the event the Executive is not 50 years old or has less
than 10 years of Service on the Date of Termination, the Company
will purchase for and deliver to the Executive a completely paid
up whole life insurance policy to be owned by the Executive, with
the beneficiary to be designated by the Executive, and with a
death benefit equal to two times the Executive's Base Salary. The
Company will also pay to the Executive, at the time of
termination of employment, an amount that, after payment of all
federal, state and local income, employment and excise taxes
thereon, is equal to all applicable federal, state and local
income and employment and excise taxes payable in respect of the
delivery of the whole life insurance policy pursuant to this
subsection (iii) (b).
(c) If the Executive elects to receive benefits under the
Supplemental Retirement Plan under subsection (iii) (a) above, he
will be entitled to no benefits and have no other rights under
the Split Dollar Life Insurance Program, and if the Executive
elects to receive a paid up whole life insurance policy under the
Split Dollar Life Insurance Program, he will be entitled to no
benefits and have no other rights under the Supplemental
Retirement Plan. Delivery of a paid up whole life insurance
15
<PAGE> 19
policy and the additional amount pursuant to this subsection
(iii) will constitute the full satisfaction of all the Company's
obligations to the Executive under the Split Dollar Life
Insurance Program. Benefits under the Supplemental Retirement
Plan may be provided in whole or in part under the COC Plan
(defined below); and
(iv) A lump sum severance payment in an amount equal to three (3)
times the Executive's Annual Compensation. For purposes of this
Agreement, "Annual Compensation" shall be an amount equal to the
sum of (a) the Executive's Base Salary from the CNG System
Companies, in effect immediately prior to the Date of
Termination, plus (b) the highest of the annual bonus payable to
the Executive (whether paid currently or deferred) for the
calendar year immediately preceding the Date of Termination or
the Executive's Target Annual Bonus, not prorated, for the
calendar year which includes the Date of Termination; and
(v) A lump sum payment equal to (a) the cost to the Company or CNG
System Company, at the Date of Termination, of coverage of the
Executive and his or her dependents under the Company or CNG
System Company's life, short term disability, long term
disability, health, medical, dental, vision, AD&D and other
employee welfare benefit plans or programs (as in effect on the
Date of Termination) for 36 months following the Date of
Termination, and (b) an amount that, after payment of all
federal, state and local income, employment and excise taxes
thereon, is equal to all applicable federal, state and local
income, employment and excise taxes payable on the amount set
forth in clause (a) of this Section 6(D)(v); and
(vi) (a) In the event the Executive is age 50 or older with 10 years
of service on the Date of Termination, (x) the Executive will be
eligible to receive retirement benefit payments under the
Retirement and Postretirement Benefit Plan for Certain Employees
of Consolidated Natural Gas Company and Its Participating
Subsidiaries (the "COC Plan"), which will contain terms requiring
the Company to fund the retirement benefits under the COC Plan
under the existing Rabbi Trust between the Company and Mellon
Bank in connection with a Change of Control) which will add five
(5) years to age and service and will allow payments beginning on
or about the Date of Termination all as more fully set forth in
the COC Plan, and (y) the Executive and his or her spouse will be
eligible to receive retiree medical insurance benefits beginning
on the Date of Termination and
16
<PAGE> 20
continuing for the remainder of their lives on terms
substantially identical to the terms of the Company's retiree
medical plan in effect on the Effective Date, any other
dependents of the Executive shall be entitled to such medical
benefits for so long as they are eligible, and the Executive
shall be eligible to receive retiree life insurance benefits
beginning on the Date of Termination and continuing for the
remainder of his or her life on terms substantially identical to
the terms of the Company's retiree life insurance plan as if
effect on the Effective Date. The COC Plan will contain
provisions for funding this benefit under the Rabbi Trust or
similar document to the maximum extent permitted by the Code.
(b) In the event the Executive is under age 50 or has less than
10 years of service on the Date of Termination, (x) the Executive
will be eligible for retirement benefits under the COC Plan,
which will treat Executive as having an additional five (5) years
of service for all purposes and add five (5) years to age for
purposes of retirement discounts, but not for the benefit
commencement date, and (y) retirement benefit payments under the
COC Plan will begin on the date the Executive reaches age 55, all
as more fully set forth in the COC Plan; and
(vii) At the CNG System Company's expense and without any limit on
such expenses, the Executive will be entitled to outplacement
services for up to one year following the Date of Termination,
including a private office, administrative support and
individualized consultation provided by an outplacement service
provider acceptable to the Executive and the CNG System Company.
The Executive may also elect to forego this benefit in exchange
for a payment of $25,000. The CNG System Company will pay to the
Executive an additional amount that, after payment of all
federal, state and local income, employment and excise taxes
thereon, is equal to all applicable federal, state and local
income, employment and excise taxes payable on the benefit or
cash set forth in this Section 6(D)(vii).
(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
17
<PAGE> 21
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 or the CNG System 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, severance or other plans, practices, policies or programs
provided by the Company and/or any CNG System Company 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 and/or any CNG System Company. Amounts which
are vested benefits or which the Executive is otherwise entitled to receive
under any plan, practice, policy or program of the Company and/or any CNG
System Company 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 or cause to be made 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 or
any CNG System Company may have against the Executive or others. In no
event 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, any CNG System 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, the Executive
shall be entitled to seek both legal and equitable relief and remedies,
including, without limitation, specific performance of the Company's
obligations hereunder, in the Executive's sole discretion.
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<PAGE> 22
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 or any CNG System 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 PricewaterhouseCoopers, LLP (the "Accounting
Firm") which shall provide detailed supporting calculations both to
the Company and the Executive within 30 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 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
19
<PAGE> 23
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 such contest and, at its sole option, may pursue
or forgo any and all administrative appeals, proceedings,
hearings and
20
<PAGE> 24
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 CNG System 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 CNG System Companies all secret or confidential
information, knowledge or data relating to the CNG System Companies, and
their respective businesses, which shall have been obtained by the
Executive
21
<PAGE> 25
during the Executive's employment by the CNG System Companies 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 CNG System
Companies, 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 CNG System Companies and those designated by it.
In no event shall an asserted violation of the 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
22
<PAGE> 26
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 or (CNG System):
Consolidated Natural Gas Company
CNG Tower
Pittsburgh, PA 15222-3199
Attention: Senior Vice President and General Counsel
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 or CNG System 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. This section does not include any severance plans or any
other exit incentives.
(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 and the CNG System 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
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<PAGE> 27
benefit or other plan, program, policy or practice in which Executive
is a participant or under which Executive is a beneficiary. This
Agreement supersedes and cancels all previous Change of Control
agreements, employment agreements and salary continuation agreements
entered into between the Company, or any of its subsidiaries, and the
Executive.
(H) The Executive and the Company acknowledge that the employment of the
Executive by any CNG System Company prior to the Effective Date is "at
will," and, prior to the Effective Date, may be terminated by either
the Executive or the applicable CNG System Company at any time, unless
subsection 1(B) applies. Upon a termination of the Executive's
employment or upon the Executive's ceasing to be an officer of any CNG
System Company, in each case, prior to the Effective Date, there shall
be no further rights under this Agreement, unless section 1(B)
applies.
(I) The Company agrees that it will cause the appropriate CNG System
Companies to perform any and all obligations hereunder which said CNG
System Companies need to perform to comply herewith. The Company will
assure compliance herewith and assume full responsibility and
liability for any failure on the part of any CNG System Company to do
so.
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
Executive
CONSOLIDATED NATURAL GAS COMPANY
By:
-----------------------------------------
Stephen E. Williams
Senior Vice President and General Counsel
Attest:
- ------------------------------
E. J. Marks
Secretary
<PAGE> 1
EXHIBIT 10R
CONSOLIDATED
NATURAL GAS CNG
COMPANY
CNG Tower
625 Liberty Avenue
Pittsburgh, PA 15222-3199
GEORGE A. DAVIDSON, JR.
Chairman and CEO
December 22, 1998
Mr. Steven A. Minter
Executive Director and President
The Cleveland Foundation
1422 Euclid Avenue
Suite 1400
Cleveland, OH 44115
Dear Steve:
As you know, I have informed you and the other members of the Board of
Directors of Consolidated Natural Gas Company ("CNG" or the "Company") of my
intention to retire from CNG on August 1, 2000 ("Retirement Date").
Consequently, the Board has initiated a search for a new CEO for CNG.
Of course, the Board and I share a desire to make the leadership transition
process as smooth and successful as possible. To that end, you (as chair of the
Board's Human Resources Committee) and I have discussed a number of matters
regarding my responsibilities at CNG during this period, and my compensation and
benefits during the period of transition and thereafter. As I have advised you,
the terms of my continued employment by CNG through my Retirement Date are
important to me and my family for many reasons, including the vesting of my
pension and stock options. Likewise, it is important to CNG for me to remain
employed with CNG through my Retirement Date, and CNG wants to provide
inducements to me for my continued employment.
The purpose of this letter is to set forth our mutual understanding as to
our agreement on all these matters.
(1) I will retain my title and position of Chairman of the Board and CEO of
the Company until (a) my Retirement Date, (b) the Board selects my successor, or
(c) the Board eliminates my position, whichever first occurs. As Chairman of the
Board and CEO, I will continue to have responsibilities equivalent to those of
chairmen of boards and CEOs of other Fortune 500 companies, including oversight
of the Company's business, participation in top level
<PAGE> 2
Mr. Steven A. Minter
December 22, 1998
Page 2
strategy decisions and chairing meetings of the Company's Board. I will continue
to serve my current term as a member of the Board, and I will resign from the
Board as of my Retirement Date. If the Board selects my successor, relieves me
of my duties as Chairman, or eliminates my position prior to my Retirement Date,
until my Retirement Date, I will continue to be treated as a senior executive
officer, occupy the same or equivalent office space and be provided with the
current level of secretarial and administrative assistance, including but not
limited to support and assistance in my position as Chairman of the Convergence
Study of the Consumer Energy Council of America.
(2) Until my Retirement Date, I will continue to be compensated at a base
compensation of no less than Seven Hundred Thousand Dollars ($700,000) per year,
and commencing in 1999, I will receive a minimum annual increase of five (5%)
per cent of my base compensation or the same average percentage increase in base
compensation as received by the other senior executive officers, whichever is
greater. Also, I will continue to be provided with the company car,
reimbursement for dues and membership fees at Allegheny Country Club and the
Duquesne Club, and I will receive all the benefits and incentive programs
provided and/or offered to the other senior executive officers by the Company
including, vacation, group health and disability insurance programs,
reimbursement for financial counseling services, executive physical
examinations, any early retirement incentive programs, etc. In addition, I will
continue to receive incentive compensation under CNG's short-term incentive plan
at a minimum of "target" (sixty(60%)per cent of base compensation). My vested
options under the current long term incentive plan will be exercisable for ten
years from the date of the grant. The holding period requirement for restricted
stock under the current long term incentive plan will be removed for my stock on
my Retirement Date. Until my Retirement Date, I will participate in any new
incentive plans on a pro rata basis based upon the number of quarters between
the effective date of the plan and my Retirement Date and the total number of
quarters during the term of the plan(s). I will receive vesting of performance
shares and stock options provided under any new incentive plans on a pro rata
basis based upon the number of quarters between the effective date of the plan
and my Retirement Date and the total number of quarters during the term of the
plans. For purposes of calculating the number of quarters, any portion of a
quarter included within such period will be deemed to be a full quarter.
(3) In the event of my death prior to my Retirement Date, the Company shall
be obligated to pay my estate or designated beneficiary the compensation and
benefits to which I am entitled until my Retirement Date, including, but not
limited to, the compensation and benefits provided in this agreement, and to
provide any applicable family health insurance and all other benefits normally
provided to survivors of senior executives of the Company until my Retirement
Date, and to provide all other applicable benefits under any life insurance
policies provided by the Company and all benefits payable pursuant to any
retirement plans.
<PAGE> 3
Mr. Steven A. Minter
December 22, 1998
Page 3
(4) In the event that I become permanently disabled, mentally or
physically, as determined by a physician selected by the Company, my employment
with the Company will continue until my Retirement Date, and the Company shall
be obligated to provide the compensation and benefits to which I am entitled, to
provide any applicable family health insurance and all other benefits normally
provided to families of senior executives until my Retirement Date, including,
but not limited to, the compensation and benefits provided in this agreement.
(5) After my Retirement Date or upon my resignation pursuant to paragraph
(8) of this agreement, CNG will provide me an executive office in its
headquarters office building, or comparable office space at or near 625 Liberty
Avenue, Pittsburgh, Pennsylvania, together with routine clerical assistance,
telephone and fax service, and financial counseling equivalent to the current
financial counseling provided, free of cost for my lifetime. CNG will also
provide me a parking space at CNG Tower or a similar location near CNG Tower,
free of cost for my lifetime. CNG will also reimburse me for all reasonable and
necessary expenses incurred on behalf of CNG, and all reasonable and necessary
expenses incurred in furtherance of my duties and participation with the
Consumer Energy Council of America and the American Gas Association.
(6) After my Retirement Date or upon my resignation pursuant to paragraph
(8) of this agreement, at my option, CNG will sell to me the Buick Park Avenue
which the Company has leased for me. In the event that I elect to purchase this
car, the purchase price will be the fair market value of the car at the time of
the transfer as determined by the wholesale value of the car as listed in the
Blue Book.
(7) Except as permitted by the Board or as required by law, after
retirement I will not disclose any confidential knowledge or information of the
Company or any of its subsidiaries, unless such knowledge or information becomes
generally known in the industry through no fault of my own.
(8) If prior to my Retirement Date, I am relieved of my duties as Chairman
or if my position as Chairman is eliminated or if my responsibilities and/or
treatment as a senior executive officer as described in paragraph (1) of this
agreement are reduced for any reason other than my death or disability, I may
elect to resign prior to August 1, 2000, and after my resignation the Company
will pay me all of the compensation and benefits to which I am entitled as if my
employment had continued until August 1, 2000, including, but not limited to,
the compensation and benefits provided in this agreement, including all
post-retirement benefits, and commencing on the first day of the month following
the date of such termination, the Company will pay to me the difference between
what my monthly benefit would have been under the System Pension Plan of
Consolidated Natural Gas Company and Its Participating Subsidiaries For
Employees Who Are Not Represented By A Recognized Union ("System Pension Plan")
and the Unfunded Supplemental Benefit Plan For Employees of Consolidated Natural
Gas Company
<PAGE> 4
Mr. Steven A. Minter
December 22, 1998
Page 4
and Its Participating Subsidiaries For Employees Who Are Not Represented By A
Recognized Union (collectively the "Plans") had my employment continued through
July 31, 2000 and my actual benefit under said Plans at the time of the
termination of my employment with the Company (the "Early Termination
Differential"). For purpose of calculating the Early Termination Differential,
in determining my benefit under said Plans as if my employment had continued
through July 31, 2000, my base annual salary will be the greater amount between
my actual base annual salary on the day of the termination of my employment or
my current base annual salary plus five (5%) per cent increases on March 1, 1999
and March 1, 2000 ($771,750). The form of Early Termination Differential payable
by the Company to me will be identical to the form of benefit elected by me
under the System Pension Plan as of my actual termination date. The Early
Termination Differential will be paid to me during my lifetime and, if I elected
a joint and survivor annuity under the System Pension Plan, the Early
Termination Differential, appropriately reduced if necessary under the System
Pension Plan based upon said election, will continue to be paid to my surviving
spouse for her lifetime.
(9) This agreement is intended to expand upon my compensation and benefits,
and nothing in this agreement is intended to, or shall be interpreted to, reduce
any compensation or benefit to which I or my family members, legal
representatives or heirs are or will become entitled, or affect the terms and
conditions of any benefit, pension or incentive plan, including, but not limited
to, the Agreement dated December 12, 1995 between me and CNG, which will remain
in full force and effect until it expires by its own terms, or unless with my
consent said agreement is amended or superseded by another agreement. Moreover,
if, prior to my Retirement Date, the Company offers or provides enhancements to
such agreements and/or plans, and/or additional agreements or benefits plans,
then I will be entitled to and/or may elect to include such enhancements in
those agreements and/or plans and/or elect to participate in and receive the
benefits of any new agreements or benefit plans.
(10) CNG agrees to reimburse all legal fees, accounting fees and tax
advisor fees and expenses which I incur in connection with the negotiation and
preparation of this agreement, up to a maximum of $10,000. Also, the Company
will reimburse me for any excise taxes on severance benefits that are considered
excess parachute payments under the Internal Revenue Code of 1986, as amended.
(11) This agreement shall be binding on CNG and its successors and assigns
and shall inure to the benefit of me, my heirs, personal representatives,
successors and assigns.
(12) This agreement is made and entered into in the Commonwealth of
Pennsylvania, and shall in all respects be interpreted, enforced and governed
under the laws of said Commonwealth.
<PAGE> 5
Mr. Steven A. Minter
December 22, 1998
Page 5
If the foregoing correctly states our understanding and agreement, please
so indicate by signing both copies of this letter in the space indicated,
thereby evidencing CNG's intent to be legally bound by this agreement, and
return one copy to me.
Very truly yours,
/s/ George A. Davidson, Jr.
-------------------------------------
George A. Davidson, Jr.
Accepted and agreed to,
this 23rd day of December, 1998.
Consolidated Natural Gas Company
By: /s/ Steven A. Minter
---------------------------
Steven A. Minter
<PAGE> 6
CONSOLIDATED
NATURAL GAS CNG
COMPANY
CNG Tower
625 Liberty Avenue
Pittsburgh, PA 15222-3199
GEORGE A. DAVIDSON, JR.
Chairman and CEO
January 8, 1999
Mr. Steven A. Minter
Executive Director and President
The Cleveland Foundation
1422 Euclid Avenue
Suite 1400
Cleveland, OH 44115
Dear Steve:
Re: Letter Agreement dated December 22, 1998
----------------------------------------
You have requested that I confirm our understanding with respect to three
aspects of the December 22, 1998, letter agreement between us.
First, the third sentence of numbered paragraph (2) of that agreement
provides that until my Retirement Date, I will continue to receive short-term
incentive compensation at a minimum of the target rate of sixty percent of base
compensation. This will confirm our intention that such incentive compensation
would be payable only if the payment of short-term incentive compensation to CNG
executives generally is triggered under, and pursuant to, the company's
short-term incentive plan.
Secondly, we agree that the office space, parking space, clerical support
and financial counseling referred to in numbered paragraph (5) of that agreement
is to be provided to me at my request only. Likewise, it is our intention that
to the extent that I request any of these benefits, they will be provided at no
cost to me, including any income taxes which may be payable by me as a result of
my receipt of the benefits. Accordingly, CNG will reimburse me for all income
taxes, if any, which I may be required to pay as a result of receiving these
benefits, including the reimbursement for payment of any income taxes on the
benefits pursuant to this provision.
Thirdly, with respect to the provisions of numbered paragraph (10) of that
agreement, it is our intent that I will cooperate with CNG to avoid causing any
<PAGE> 7
January 8, 1999
Page 2
severance benefits under that agreement to become excess parachute payments
under the Internal Revenue Code of 1986, as amended.
These interpretations of provisions of our December 22, 1998, agreement
confirm our intention with regard thereto in all respects, the December 22, 1998
agreement remains in full force and effect. Please indicate your concurrence by
signing both copies of this letter in the space provided.
Very truly yours,
/s/ George A. Davidson, Jr.
-----------------------------------
George A. Davidson, Jr.
Accepted and agreed to
this 12th day of January, 1999
/s/ Steven A. Minter
- ---------------------------
Steven A. Minter
<PAGE> 1
EXHIBIT 11
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
COMPUTATION OF EARNINGS PER COMMON SHARE
(In Thousands, Except Per Share Data)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
Per Share
Year Ended December 31, Net Income Shares Amount
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
1998
EARNINGS PER COMMON SHARE -- BASIC
Income from continuing operations........................................ $287,711 94,836 $3.03
Loss from discontinued energy marketing services operations.............. (17,238) (.18)
Loss from disposal of energy marketing services operations............... (31,707) (.33)
-------- ------ -----
NET INCOME............................................................... $238,766 94,836 $2.52
======== ====== =====
EARNINGS PER COMMON SHARE -- DILUTED
Income from continuing operations........................................ $287,711 94,836
Effect of dilutive securities:
Exercise of stock options.............................................. 511
Vesting of performance shares.......................................... 374
Conversion of 7-1/4% Convertible Subordinated Debentures............... 1,578 614
-------- ------
Income from continuing operations, as adjusted........................... 289,289 96,335 $3.00
Loss from discontinued energy marketing services operations ............. (17,238) (.18)
Loss from disposal of energy marketing services operations............... (31,707) (.33)
-------- ------ -----
NET INCOME, AS ADJUSTED.................................................. $240,344 96,335 $2.49
======== ====== =====
- ---------------------------------------------------------------------------------------------------------------------
Per Share
Year Ended December 31, Net Income Shares Amount
- ---------------------------------------------------------------------------------------------------------------------
1997
EARNINGS PER COMMON SHARE -- BASIC
Income from continuing operations........................................ $318,908 94,868 $3.36
Loss from discontinued energy marketing services operations.............. (14,528) (.15)
-------- ------ -----
NET INCOME............................................................... $304,380 94,868 $3.21
======== ====== =====
EARNINGS PER COMMON SHARE -- DILUTED
Income from continuing operations........................................ $318,908 94,868
Effect of dilutive securities:
Exercise of stock options.............................................. 674
Vesting of performance shares.......................................... 359
Conversion of 7-1/4% Convertible Subordinated Debentures............... 12,128 4,559
-------- -------
Income from continuing operations, as adjusted........................... 331,036 100,460 $3.30
Loss from discontinued energy marketing services operations ............. (14,528) (.15)
-------- ------- -----
NET INCOME, AS ADJUSTED.................................................. $316,508 100,460 $3.15
======== ======= =====
- ---------------------------------------------------------------------------------------------------------------------
Per Share
Year Ended December 31, Net Income Shares Amount
- ---------------------------------------------------------------------------------------------------------------------
1996
EARNINGS PER COMMON SHARE -- BASIC
Income from continuing operations........................................ $309,382 94,076 $3.29
Loss from discontinued energy marketing services operations.............. (11,109) (.12)
-------- ------ -----
NET INCOME............................................................... $298,273 94,076 $3.17
======== ====== =====
EARNINGS PER COMMON SHARE -- DILUTED
Income from continuing operations........................................ $309,382 94,076
Effect of dilutive securities:
Exercise of stock options.............................................. 482
Vesting of performance shares.......................................... 98
Conversion of 7-1/4% Convertible Subordinated Debentures............... 11,823 4,559
-------- ------
Income from continuing operations, as adjusted........................... 321,205 99,215 $3.24
Loss from discontinued energy marketing services operations ............. (11,109) (.11)
-------- ------ -----
NET INCOME, AS ADJUSTED.................................................. $310,096 99,215 $3.13
======== ====== =====
- ---------------------------------------------------------------------------------------------------------------------
</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, 1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Income from continuing operations .. $ 287,711 $ 318,908 $ 309,382 $ 28,833 $ 183,171
Add income taxes ................... 129,649 156,269 162,315 7,381 82,427
--------- --------- --------- --------- ---------
Income from continuing operations
before income taxes .......... 417,360 475,177 471,697 36,214 265,598
Distributed income from
unconsolidated investees, less
equity in earnings thereof ...... (1,880) 1,653 (1,084) 1,501 560
--------- --------- --------- --------- ---------
Subtotal ..................... 415,480 476,830 470,613 37,715 266,158
--------- --------- --------- --------- ---------
Add fixed charges:
Interest on long-term debt,
including amortization of
debt discount and expense
less premium ................. 106,307 104,927 101,814 95,823 88,788
Other interest expense .......... 19,659 5,774 3,374 12,653 7,992
Portion of rentals deemed to
be representative of the
interest factor .............. 10,634 9,681 9,106 9,255 8,486
Fixed charges associated
with 50% projects with debt .. 430 2,016 2,157 1,388 --
--------- --------- --------- --------- ---------
TOTAL FIXED CHARGES ................... 137,030 122,398 116,451 119,119 105,266
--------- --------- --------- --------- ---------
TOTAL EARNINGS ........................ $ 552,510 $ 599,228 $ 587,064 $ 156,834 $ 371,424
========= ========= ========= ========= =========
RATIO OF EARNINGS TO FIXED
CHARGES ............................ 4.03 4.90 5.04 1.32 3.53
========= ========= ========= ========= =========
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE> 1
EXHIBIT 21
<TABLE>
<CAPTION>
SUBSIDIARIES OF CONSOLIDATED NATURAL GAS COMPANY
Percent Voting
Securities
Owned by
Place of Immediate
Name of Company Incorporation Parent Company
- -------------------------------------------- ------------- --------------
<S> <C> <C>
CONSOLIDATED NATURAL GAS COMPANY Delaware
Subsidiary companies:
Consolidated Natural Gas Service Company 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%
CNG Producing Company Delaware 100%
CNG Pipeline Company Texas 100%
CNG Main Pass Gas Gathering Corporation Delaware 100%
CNG Oil Gathering Corporation Delaware 100%
CNG Power Company Delaware 100%
CNG Market Center Services, Inc. Delaware 100%
CNG Bear Mountain, Inc. Delaware 100%
CNG Kauai, Inc. Delaware 100%
Granite Road Cogen, Inc. Texas 100%
CNG Products and Services, Inc. Delaware 100%
CNG Technologies, Inc. Delaware 100%
CNG Retail Services Corporation Delaware 100%
CNG Field Services Company Delaware 100%
CNG International Corporation Delaware 100%
CNG Cayman One Ltd. Cayman Islands 100%
CNGI Australia Pty. Limited Australia 100%
CNG Cayman Three Ltd. Cayman Islands 100%
CNG Argentina S.A. Argentina 100%
CNG Power Services Corporation Delaware 100%
Consolidated System LNG Company Delaware 100%
CNG Research Company Delaware 100%
CNG Coal Company Delaware 100%
CNG Financial Services, Inc. Delaware 100%
</TABLE>
<PAGE> 1
Exhibit 23A
RALPH E. DAVIS ASSOCIATES, INC.
[LETTERHEAD]
February 3, 1999
CONSOLIDATED NATURAL GAS COMPANY
CNG Tower
625 Liberty Avenue
Pittsburgh, Pennsylvania 15222-3199
Report Covering Natural Gas Supply
And Owned Oil Reserves
December 31, 1998
----------------------------------
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.
From 1943 to 1993 Consolidated purchased gas from pipeline companies
which obtained their gas supply from fields in the Gulf Coast and Southwest.
Since 1993, however, all remaining long-term gas purchase contracts with
pipelines have been replaced with firm transport contracts as the result of
Federal Energy Regulatory Commission (FERC) Order 636. Consolidated 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
<PAGE> 2
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 3, 1999
Page 2
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, 1998 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.
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, 1998, to be 318 billion cubic feet (including CNG Producing
Company's Appalachian reserves) from company-owned wells and 233 billion cubic
feet from gas purchase wells, for a total of 551 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 422,382 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 3, 1999
Page 3
CNG PRODUCING COMPANY
CNG Producing Company is Consolidated's primary exploration and
production subsidiary. As of December 31, 1998, the estimated proved working
interest reserves of CNG Producing Company are 1,170 billion cubic feet of gas
and 56,940,563 barrels of crude oil and condensate. The foregoing totals include
approximately 1 billion cubic feet of gas and 5,843,873 barrels of heavy oil
reserves in Canada.
In the United States, CNG Producing Company has proved reserves in 11
states and the offshore area of the Gulf Coast. The majority of CNG Producing
Company's United States reserves are in the Gulf Coast (primarily offshore), the
Mid-Continent area and the Rocky Mountain area. The estimated proved reserves in
the United States are 1,169 billion cubic feet of gas and 51,096,690 barrels of
crude oil and condensate.
The estimated Appalachian proved reserves as of December 31, 1998 for
CNG Producing Company, which are included in the total Appalachian reserves
disclosed earlier in this report, are 174 billion cubic feet of gas and 158,122
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, 1998 are 12 billion cubic feet.
SOUTHWEST GAS
Consolidated's subsidiaries have gas supply contracts with various gas
producing companies and marketing groups with remaining terms ranging from a few
months to as long as seven (7) years. Purchase entitlements under these
contracts total approximately 151 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.
<PAGE> 4
` RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 3, 1999
Page 4
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 Transmission Corporation (Texas Eastern),
one with Tennessee Gas Pipeline Company (Tennessee), one with Penn Fuel Gas,
Inc., one with both Tennessee and National Fuel Gas Supply Corporation, and
another with both Texas Eastern and Transcontinental Gas Pipe Line Corporation.
Consolidated's net injected gas stored at December 31, 1998, was 450 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. Other potential sources of gas could come from
reserves in Alaska, Canada, and 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
57,204,823 barrels as of December 31, 1998 as follows:
<PAGE> 5
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 3, 1999
Page 5
<TABLE>
<CAPTION>
Stock Tank Barrels
------------------
<S> <C>
Appalachian Field Reserves 264,260
- --------------------------
CNG Producing Company
- ---------------------
Southwest 56,782,441
Appalachian 158,122
-----------
Sub Total 56,940,563
TOTAL - OWNED OIL AND CONDENSATE RESERVES 57,204,823
</TABLE>
We have estimated the gas reserves available to Consolidated from
sources in the United States and Canada at 2,148 billion cubic feet as of
December 31, 1998 as follows:
<TABLE>
<CAPTION>
Billion
Cubic Feet
at 14.73 psia
-------------
<S> <C>
Appalachian Field Reserves
- --------------------------
Company-Owned Wells 144
Gas Purchase Contract Wells 233
Gas in Storage Reservoirs 450
-----
Sub-Total 827
CNG Producing Company Reserves
- ------------------------------
Company-Owned Wells
Southwest 996
Appalachian 174
-----
Sub-Total 1,170
Gas Supply Contracts 151
- --------------------
TOTAL - CONTROLLED GAS RESERVES 2,148
</TABLE>
<PAGE> 6
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 3, 1999
Page 6
Consolidated's requirements for the twelve months ended December 31,
1998, including sales of gas produced in Canada, were approximately 452 billion
cubic feet, compared to requirements of 1,118 billion cubic feet in 1997.
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.
[LETTERHEAD]
March 15, 1999
CONSENT OF INDEPENDENT GEOLOGISTS
We hereby consent to the use of our report dated February 3, 1999,
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,
1998. 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. 33-63931, 333-10869 and 333-25347) and
Form S-8 (Nos. 2-77204, 2-97948, 33-40478, 33-44892, 333-18783 and 333-33505) 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, 1998. 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 EXHIBIT 99 OF CONSOLIDATED NATURAL
GAS COMPANY'S ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 1998
AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> DEC-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,092,309
<OTHER-PROPERTY-AND-INVEST> 1,346,155
<TOTAL-CURRENT-ASSETS> 1,161,900
<TOTAL-DEFERRED-CHARGES> 459,229
<OTHER-ASSETS> 302,307
<TOTAL-ASSETS> 6,361,900
<COMMON> 263,848
<CAPITAL-SURPLUS-PAID-IN> 531,692
<RETAINED-EARNINGS> 1,591,543
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,399,608
0
0
<LONG-TERM-DEBT-NET> 1,379,729
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 558,900
<LONG-TERM-DEBT-CURRENT-PORT> 111,125
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,925,063
<TOT-CAPITALIZATION-AND-LIAB> 6,361,900
<GROSS-OPERATING-REVENUE> 2,760,406
<INCOME-TAX-EXPENSE> 129,649
<OTHER-OPERATING-EXPENSES> 2,263,268
<TOTAL-OPERATING-EXPENSES> 2,392,917
<OPERATING-INCOME-LOSS> 367,489
<OTHER-INCOME-NET> 34,700
<INCOME-BEFORE-INTEREST-EXPEN> 402,189
<TOTAL-INTEREST-EXPENSE> 114,478
<NET-INCOME> 238,766
0
<EARNINGS-AVAILABLE-FOR-COMM> 238,766
<COMMON-STOCK-DIVIDENDS> 185,758
<TOTAL-INTEREST-ON-BONDS> 100,132
<CASH-FLOW-OPERATIONS> 812,128
<EPS-PRIMARY> 2.52
<EPS-DILUTED> 2.49
</TABLE>
<PAGE> 1
Exhibit 99
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
LOGO CONSOLIDATED NATURAL GAS COMPANY
1998 Financial
Report
Appendix I
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Management's Discussion and Analysis of Financial Condition and Results of Operations................ 1
Selected Financial Data.............................................................................. 21
Report of Independent Accountants.................................................................... 22
Consolidated Statement of Income for the Years 1996 through 1998..................................... 23
Consolidated Balance Sheet at December 31, 1997 and 1998............................................. 24
Consolidated Statement of Cash Flows for the Years 1996 through 1998................................. 26
Consolidated Statement of Comprehensive Income for the Years 1996 through 1998....................... 27
Notes to Consolidated Financial Statements........................................................... 28
</TABLE>
<PAGE> 3
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
(All per share references, unless indicated, are stated as basic earnings per
share. Prior year amounts have been restated, as applicable, to present
continuing operations separate from discontinued operations.)
SUBSEQUENT EVENT
On February 22, 1999, Consolidated Natural Gas Company (the Company) and
Dominion Resources, Inc. (DRI) announced that a definitive merger agreement
(merger agreement) was approved by the boards of directors of both companies.
Under the terms of the merger agreement, DRI intends to acquire all of the
Company's shares of common stock in a stock-for-stock transaction. Reference is
made to Note 19 to the consolidated financial statements, page 52, regarding
this subsequent event.
RESULTS OF OPERATIONS
NET INCOME
Net income in 1998 was $238.8 million, or $2.52 a share, compared with net
income of $304.4 million, or $3.21 a share, in 1997. Net income in 1996 was
$298.3 million, or $3.17 a share. These results, however, reflect the Company's
decision to discontinue its wholesale energy trading and marketing operations in
1998 (see Note 2 to the consolidated financial statements, page 30). The Company
recognized a loss on discontinued operations in 1998 of $48.9 million, or $.51 a
share. Losses from discontinued operations during 1997 and 1996 totaled $14.5
million and $11.1 million, respectively, or $.15 and $.12 a share.
INCOME FROM CONTINUING OPERATIONS
Income from continuing operations was $287.7 million, $318.9 million and $309.4
million for 1998, 1997 and 1996, respectively. On a per share basis, income from
continuing operations was $3.03 in 1998, compared to $3.36 and $3.29 in 1997 and
1996, respectively.
1998
Income from continuing operations declined $31.2 million in 1998. The effects of
warm winter weather and lower average wellhead prices for gas and oil were only
partially mitigated by ongoing cost reduction efforts and the impact of higher
oil production. Weather in the Company's retail service areas was 17.8% warmer
than normal and 19.3% warmer than 1997. The warmer than normal weather in 1998
reduced earnings by $.47 per share. Normal weather represents a measure of
temperature experienced over an historical time frame, the length of which may
differ depending on the regulatory jurisdiction. When compared to normal, 1998
was the second warmest year in the Company's history.
1997
Income from continuing operations in 1997 increased $9.5 million from the prior
year. The favorable impact of higher gas and oil production and continued cost
containment efforts more than offset the effects of warmer weather and lower
average wellhead prices for both gas and oil. Weather in the Company's retail
service areas was 1.9% colder than normal but 4.3% warmer than 1996.
1996
Income from continuing operations in 1996 reflected higher wellhead prices for
natural gas and oil, increased gas and oil production, colder weather, cost
controls and the full year impact of new rates in place for most of the
Company's gas distribution customers. Weather in the Company's retail service
areas was 5.6% colder than normal and 5.5% colder than 1995.
1
<PAGE> 4
OPERATING REVENUES
Operating revenues include revenues from gas and oil sales, transportation and
storage of gas, gas and oil trading activities and by-product operations. Total
operating revenues in 1998 were $2,760.4 million, a decrease of $416.7 million
from 1997.
Regulated gas sales revenues declined $477.3 million during 1998 compared
to the prior year, to $1,373.7 million. Regulated sales volumes declined 64.9
billion cubic feet (Bcf), to 207.1 Bcf, due chiefly to warmer weather in 1998.
Residential customers switching to transport service also caused a decline in
sales volumes. In addition, lower average sales rates for all three major
customer classes--residential, commercial and industrial--reflecting lower
purchased gas costs contributed to the decline in revenues.
Nonregulated gas sales revenues increased $61.0 million in 1998, to $494.4
million, with sales volumes increasing 36.1 Bcf, to 207.1 Bcf. The increased
sales volumes in 1998 were due to gas sales by CNG Retail Services Corporation
(CNG Retail), in its first full year of operation, and CNG Field Services
Company (CNG Field Services).
Gas transportation and storage revenues rose $53.8 million, to $545.9
million, in 1998. This improvement includes a $47.6 million increase associated
with gas transportation revenues due largely to customers switching from sales
to transport service at certain of the distribution subsidiaries.
Other operating revenues declined $54.2 million in 1998, to $346.4 million,
due primarily to lower revenues from oil production and oil trading activities
as a result of declining oil prices during 1998.
Regulated gas sales revenues of $1,851.0 million in 1997 were up $97.3
million compared to 1996, despite sales volumes decreasing 22.2 Bcf to 272.0
Bcf. The decline in volumes was due to warmer weather and the effect of the
displacement of sales volumes to other suppliers, including CNG Retail. Sales
revenues attributable to the Company's residential and commercial customers
increased during 1997 as higher average sales rates, reflecting the recovery of
previously deferred purchased gas costs, more than offset reduced volumes
compared to 1996.
Nonregulated gas sales revenues increased $37.3 million in 1997 to $433.4
million, with sales volumes increasing 11.3 Bcf to 171.0 Bcf. The increases in
revenues and volumes reflect higher gas production at CNG Producing Company (CNG
Producing). Gas transportation and storage revenues rose $12.5 million in 1997
compared to the prior year, to $492.1 million, reflecting both higher gas
transportation and storage service revenues. Other operating revenues increased
$74.6 million in 1997 to $400.6 million. Revenues from oil trading were up $39.7
million, while revenues from the sale of oil and condensate production increased
$33.5 million. In both cases, the impact of higher volumes more than offset a
decline in oil prices.
OPERATING EXPENSES
Operating expenses, including income taxes, decreased to $2,392.9 million in
1998, compared to $2,766.7 million and $2,555.7 million in 1997 and 1996,
respectively.
Purchased gas consistently represents the largest operating expense
category for the Company. Purchased gas costs were $900.4 million in 1998,
$1,114.1 million in 1997 and $963.2 million in 1996. This expense is influenced
primarily by changes in gas sales requirements, the price of gas supplies, and
the timing of recoveries of deferred purchased gas costs. The decline in 1998
was due primarily to decreased volume requirements in connection with the warm
weather in 1998, while lower average purchase prices also contributed to the
decrease. The recognition of previously deferred purchased gas costs and volumes
sold by CNG Retail were the primary factors for the increase from 1996 to 1997.
Liquids, capacity and other products purchased expense includes the cost of
oil, condensate and by-products purchased for resale, electricity purchased for
resale by CNG Retail, and pipeline capacity not associated with gas purchased.
During 1998, this expense decreased $65.2 million due primarily to lower average
purchase prices for oil traded by CNG Producing and less pipeline capacity
purchased by CNG Transmission Corporation (CNG Transmission). This expense
increased $31.2 million in 1997 due primarily to increased oil trading activity
by CNG Producing.
2
<PAGE> 5
Combined operation and maintenance expense decreased $48.8 million in 1998
due largely to lower royalty expense, lower amortization expense related to
abandoned facilities and lower general and administrative expenses. The decline
in 1998 was partially offset by workforce reduction charges recognized in the
fourth quarter of 1998 due principally to the plan to reorganize the management
structure of the Company's regulated operations. Excluding the effect of
workforce reduction charges included in the 1996 amounts, combined operation and
maintenance expense increased $14.8 million in 1997. This increase was due in
part to higher royalty expense and production-related costs. These costs were
partially offset by lower employment costs.
Total depreciation and amortization (DD&A) expense increased $5.3 million
in 1998 due to higher oil production volumes and $21.7 million in 1997 due
largely to higher gas and oil production volumes.
Taxes, other than income taxes, declined $14.3 million in 1998 due chiefly
to the timing of the recognition of certain tax expense by one of the
distribution subsidiaries and were up $2.9 million in 1997 due in part to higher
excise taxes.
Income taxes declined $26.7 million in 1998 due to lower pretax income and
a lower effective tax rate. Income taxes decreased $6.0 million in 1997 due
largely to a lower effective tax rate.
OTHER INCOME
Total other income was $34.7 million in 1998, compared to $12.4 million in 1997
and $9.0 million in 1996. "Other-net" increased $20.8 million during 1998 due
principally to increased earnings from equity investments at CNG International.
The increase in "Other-net" in 1997 compared to 1996 is due largely to a charge
of $5.0 million recognized in connection with an early extinguishment of debt in
December 1996. Interest revenues increased $1.5 million in 1998 and decreased
slightly in 1997.
INTEREST CHARGES
Interest on long-term debt increased $1.4 million in 1998 and $3.1 million in
1997. The 1998 increase was primarily due to a full year of interest expense on
the $300 million of debentures issued in the fourth quarter of 1997, partially
offset by reduced interest expense in 1998 resulting from the redemption of the
convertible subordinated debentures. The increase in 1997 was due largely to a
full year of interest expense related to the $300 million of debentures issued
in the fourth quarter of 1996, partially offset by the redemption in early 1997
of $100 million of debentures and the early extinguishment of $53.1 million of
debt in late 1996. Other interest expense increased $13.9 million in 1998 due
primarily to interest on commercial paper borrowings. Other interest expense
increased $2.4 million in 1997.
FOURTH QUARTER RESULTS
Net income for the fourth quarter of 1998 was $95.0 million, or $1.00 per share,
compared to $89.4 million, or $.94 per share, in 1997. Income from continuing
operations for the fourth quarter of 1998 was $97.2 million, or $1.02 per share,
compared to $89.1 million, or $.94 per share, in the prior year quarter. Results
for 1998 reflect lower operating costs which helped offset significantly lower
wellhead prices and warmer weather in that year. Also, the prior year quarter
included a non-cash charge of $6.7 million after taxes, or $.07 per share,
related to an impairment of Canadian oil producing properties. The change in
other income/expenses--net reflects higher equity income from CNG International
and gains on asset dispositions in 1998, while the 1997 fourth quarter includes
a charge in connection with the decision to sell and write down the carrying
value of the Company's interests in four independent power projects. The
Company's 1998 average gas wellhead price was $2.17 per thousand cubic feet
(Mcf), down $.37 per Mcf, while average oil wellhead prices declined $5.95 per
barrel compared to the prior year quarter, to $9.74 per barrel. Weather in the
fourth quarter of 1998 was 16.1% warmer than the prior year quarter.
3
<PAGE> 6
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
Quarters Ended December 31, 1998 1997
- ----------------------------------------------------------------------------------
(In Millions)
<S> <C> <C>
Operating revenues........................................ $ 807.4 $940.9
Operating expenses........................................ (654.4) (781.2)
------ ------
Operating income before income taxes...................... 153.0 159.7
Income taxes.............................................. (45.2) (41.3)
Other income/expenses-net................................. (10.6) (29.3)
------ ------
Income from continuing operations......................... 97.2 89.1
Income (loss) from discontinued operations................ (2.2) .3
------ ------
Net income................................................ $ 95.0 $89.4
====== =====
Earnings (loss) per common share--basic (in dollars)
Continuing operations.................................. $ 1.02 $ .94
Discontinued operations................................ (.02) --
------ ------
Net income................................................ $ 1.00 $ .94
====== ======
Earnings (loss) per common share--diluted (in dollars)
Continuing operations.................................. $ 1.01 $ .92
Discontinued operations................................ (.02) --
------ ------
Net income................................................ $ .99 $ .92
====== ======
- ----------------------------------------------------------------------------------
</TABLE>
NEW ACCOUNTING STANDARDS
During 1998, the Company adopted Statement of Financial Accounting Standards
(SFAS) No. 130, "Reporting Comprehensive Income," SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information," and SFAS No. 132,
"Employers' Disclosures about Pensions and Other Postretirement Benefits." SFAS
No. 130 establishes standards for the reporting and display of comprehensive
income and its components. Reference is made to the Consolidated Statement of
Comprehensive Income, page 27. Reference is also made to Notes 1 and 18 to the
consolidated financial statements, pages 28 and 48, regarding SFAS No. 131. SFAS
No. 132 revises the Company's disclosures about pension and other postretirement
benefit plans. Reference is made to Note 7 to the consolidated financial
statements, page 34, regarding SFAS No. 132. The adoption of SFAS Nos. 130, 131
and 132 did not have a material effect on the Company's financial position,
results of operations or cash flows.
Also during 1998, the American Institute of Certified Public Accountants
(AICPA) issued Statement of Position (SOP) 98-1, "Accounting for the Costs of
Computer Software Developed or Obtained for Internal Use," and SOP 98-5,
"Reporting on the Costs of Start-Up Activities." SOP 98-1 establishes standards
for accounting for costs incurred in developing or procuring computer software
for internal use. SOP 98-5 requires that costs for start-up activities be
expensed as incurred. The provisions of each SOP are effective beginning January
1, 1999, and the adoption of each SOP is not expected to have a material effect
on the Company's financial position, results of operations or cash flows.
The Financial Accounting Standards Board issued SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities," in 1998. SFAS No. 133
establishes new accounting standards for derivative instruments and for hedging
activities. The provisions of SFAS No. 133 are effective beginning January 1,
2000. The adoption of SFAS No. 133 is not expected to have a material effect on
the Company's financial position, results of operations or cash flows.
SEGMENTS OF THE BUSINESS
Due to the regulated nature of the distribution and transmission segments 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
4
<PAGE> 7
portion of the gas sold or transported by the distribution and transmission
operations is ultimately used for space heating.
Operating results for each of the Company's business segments, which
include affiliated transactions, follow. Reference is made to Note 18 to the
consolidated financial statements, page 48, for additional segment information.
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------
OPERATING INCOME BEFORE INCOME TAXES 1998 1997 1996
- ---------------------------------------------------------------------
(In Millions)
<S> <C> <C> <C>
Distribution......................... $208.2 $266.6 $258.4
Transmission......................... 183.6 180.9 181.6
Exploration and production........... 116.6 142.8 133.2
Other (a)............................ (1.4) (7.3) (.9)
Corporate and eliminations........... (9.9) (16.3) (10.3)
------ ------ ------
Total............................. $497.1 $566.7 $562.0
====== ====== ======
</TABLE>
- --------------------------------------------------------------------------------
(a) Includes CNG International, CNG Products and Services, CNG Power, CNG Field
Services (formerly CNG Storage Services), Consolidated LNG, CNG Research
and CNG Coal. Amounts for 1998 and 1997 also include CNG Retail.
DISTRIBUTION
"Distribution" represents the results of the four retail gas distribution
subsidiaries: The East Ohio Gas Company (East Ohio Gas), The Peoples Natural Gas
Company (Peoples Natural Gas), Virginia Natural Gas, Inc. (Virginia Natural Gas)
and Hope Gas, Inc. (Hope Gas).
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, 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%, compared to a growth rate of less than 1% for the other distribution
subsidiaries.
Similar to the unbundling of the services provided by gas pipeline
companies, gas distribution companies are adapting to the deregulation and
unbundling of the retail energy market. Under open access programs, natural gas
suppliers other than the local gas utility can use the utility's existing lines
to deliver gas to customers.
CNG Retail, created in 1997, markets natural gas, electricity, and consumer
products and services to residential, commercial and small industrial customers,
including those within the Company's traditional service territories. CNG Retail
is expected to enable the Company to take advantage of emerging deregulated
energy markets for both gas and electricity.
During the spring of 1997, Peoples Natural Gas opened its system in
Pennsylvania to customer choice. In addition, on July 2, 1997, the Public
Utilities Commission of Ohio approved East Ohio Gas' "Energy Choice" (EOG Energy
Choice) pilot program which allows approximately 15% of East Ohio Gas'
residential and small business customers the opportunity to purchase their
natural gas from competing suppliers, if they so choose.
DISTRIBUTION OPERATING INCOME BEFORE INCOME TAXES
1998
Operating income before income taxes declined $58.4 million in 1998, to $208.2
million, compared to 1997. The impact of warmer weather in 1998 was partially
mitigated by lower operation expenses and the timing of the recognition of
excise tax expense. Weather in the Company's retail service areas was 17.8%
warmer than normal and 19.3% warmer than 1997. The 1998 period also included a
$4.5 million charge for workforce reduction costs recognized in the fourth
quarter in connection with the Company's plan to reorganize and centralize the
management of its regulated operations.
5
<PAGE> 8
1997
Operating income before income taxes was $266.6 million in 1997, up $8.2 million
from the prior year. However, the 1996 period included workforce reduction
charges of $8.2 million. The effect of warmer weather in 1997 offset the impact
of lower operation and maintenance expenses during the year. Weather in the
Company's retail service areas was 1.9% colder than normal and 4.3% warmer than
1996.
1996
Operating income before income taxes increased $50.9 million in 1996. Improved
results for 1996 reflect colder weather, cost control efforts and the full year
impact of general rate increases that went into effect in the latter part of
1995 at Peoples Natural Gas, Hope Gas and East Ohio Gas. Weather in the
Company's retail service areas was 5.5% colder than 1995 and 5.6% colder than
normal. Operating results for 1996 and 1995 include workforce reduction charges
of $8.2 million and $22.3 million, respectively.
DISTRIBUTION OPERATING REVENUES
Operating revenues decreased $414.8 million, to $1,611.8 million, in 1998.
Average sales rates and volumes declined in 1998 compared to the prior year.
Sales rates declined due to the pass-through of lower purchased gas costs. Lower
volumes in 1998 reflected warmer weather during the year and the impact of
former residential sales customers who now purchase gas from other suppliers,
including CNG Retail. Gas transportation and storage revenues increased $44.0
million in 1998 due to both higher volumes and rates. The increase in gas
transportation volumes reflects the switch by residential customers from sales
to transport service.
Operating revenues increased $121.1 million in 1997, to $2,026.6 million.
Gas sales revenues increased $101.1 million as higher average sales rates,
reflecting the recovery of previously deferred purchased gas costs, more than
offset the effect of reduced sales volumes. Gas transportation and storage
revenues increased $21.5 million in 1997 due to both higher volumes and rates.
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 1998 1997 1996
- ---------------------------------------------------
(In Billion Cubic Feet)
<S> <C> <C> <C>
Sales ................. 207.6 272.7 294.2
Transportation......... 198.9 189.4 174.2
----- ----- -----
Throughput....... 406.5 462.1 468.4
===== ===== =====
- ---------------------------------------------------
</TABLE>
Gas sales volumes declined in 1998 compared to the prior year primarily
as a result of warmer weather and the continued displacement of sales volumes to
other suppliers. Residential gas sales volumes declined 47.9 Bcf in 1998, to
159.9 Bcf. The distribution subsidiaries transported 14.6 Bcf of gas in 1998,
compared to 2.7 Bcf in 1997, on behalf of former residential sales customers who
now purchase gas from other suppliers, including CNG Retail. Sales to commercial
customers declined 15.4 Bcf to 44.3 Bcf while volumes transported to these
customers decreased .3 Bcf to 43.0 Bcf, both declines being attributable to the
warm weather. Total deliveries to industrial customers decreased 2.6 Bcf, to
135.7 Bcf. Industrial transport volumes were down .8 Bcf to 133.2 Bcf, while
sales volumes declined 1.8 Bcf to 2.5 Bcf. Off-system transport volumes were
down 1.3 Bcf in 1998, to 8.1 Bcf.
Warmer weather and the effect of the displacement of sales volumes to other
suppliers, including CNG Retail, were the reasons for the decrease in gas sales
volumes in 1997 compared to 1996.
6
<PAGE> 9
Residential gas sales volumes decreased 10.9 Bcf, to 207.8 Bcf, in 1997.
Commercial sales decreased 7.1 Bcf while volumes transported to these customers
were up 9.0 Bcf. Deliveries to industrial customers were lower in 1997,
decreasing .5 Bcf to 138.3 Bcf. Sales to industrial customers declined 2.6 Bcf
to 4.3 Bcf, while transportation volumes increased 2.1 Bcf to 134.0 Bcf.
Transportation to off-system customers increased 4.1 Bcf in 1997.
TRANSMISSION
"Transmission" includes the results of the gas transmission, storage, by-product
and certain other activities of CNG Transmission and the by-products business of
CNG Power. Gas and oil production activities of CNG Transmission are included in
the exploration and production segment.
TRANSMISSION OPERATING INCOME BEFORE INCOME TAXES
1998
Operating income before income taxes was $183.6 million in 1998, an increase of
$2.7 million compared to the prior year. The 1998 results include the impact of
the favorable resolution of a regulatory contingency amounting to $13.9 million
and a charge for workforce reduction costs of $1.1 million. Also, the 1997
results included a charge amounting to $5.8 million recognized in connection
with CNG Transmission's withdrawal from participation in a gas storage
development project.
1997
Operating income before income taxes declined slightly in 1997, to $180.9
million. While the 1997 period included the charge for the storage project
indicated above, 1996 results included a $5.1 million charge for workforce
reduction costs.
1996
Operating income before income taxes was $181.6 million in 1996. Cost control
efforts and increased gas transportation and by-products revenues contributed to
the improved results in 1996. Workforce reduction charges for these operations
were about the same in 1996 and 1995.
TRANSMISSION OPERATING REVENUES
Total operating revenues increased $3.2 million during 1998, to $502.5 million.
Gas transportation revenues increased $4.1 million, as higher average rates more
than offset lower volumes, and gas storage service revenues increased $3.0
million. Revenues from the sale of by-products declined $18.2 million due to
lower sales rates. Higher other operating revenues for 1998 include $13.9
million relating to the favorable resolution of a regulatory contingency.
Total operating revenues declined $17.8 million in 1997, to $499.3 million.
Gas transportation revenues declined $15.7 million due to both lower volumes and
rates, and revenues from the sale of by-products decreased $5.1 million due
primarily to lower sales rates. These decreases were partially offset by an
increase of $2.8 million in gas storage service revenues.
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 its efforts
primarily in the Northeast and along the East Coast. This expansion is supported
by 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.
A further expansion project in conjunction with East Ohio Gas and others will
provide additional capacity at minimal cost. CNG Transmission's pipeline and
storage facilities will continue to enable retail end users to take advantage of
the accessibility of supplies nationwide in the evolving deregulation of the gas
industry at the retail level (see "Distribution," page 5, and "Gas and Electric
Industry Developments," page 11).
7
<PAGE> 10
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.
However, due to the straight fixed variable rate design, operating income for
the transmission operations is not significantly influenced by changes in
throughput.
Total throughput for the gas transmission operations, consisting entirely
of transportation volumes, was 612.5 Bcf, 732.8 Bcf and 758.4 Bcf for the years
1998, 1997 and 1996, respectively.
EXPLORATION AND PRODUCTION
"Exploration and production" (E&P) includes the results of CNG Producing and the
gas and oil production activities of CNG Transmission.
E&P OPERATING INCOME BEFORE INCOME TAXES
1998
Operating income before income taxes in 1998 was $116.6 million, a decline of
$26.2 million from 1997. Results for 1998 reflect the impact of lower average
gas and oil wellhead prices and lower gas production, partially offset by higher
oil production. Both oil and gas production were negatively impacted during the
third quarter of 1998 due to four hurricanes and tropical storms that forced
temporary shutdowns of oil and natural gas wells in the Gulf of Mexico. These
storms also delayed development efforts at the Nautilus complex, delaying
initial production at that location until the first quarter of 1999. During
1998, CNG Producing added 374 Bcf of gas equivalent from additions, revisions,
and purchases of gas and oil reserves and also purchased 39 Bcf of gas reserves
from an affiliate, Peoples Natural Gas. The 1997 results include a non-cash,
pretax charge of $10.4 million related to the Company's impairment of its
Canadian oil producing properties.
1997
Operating income before income taxes in 1997 was $142.8 million, up $9.6 million
from 1996. As noted above, the 1997 results include an impairment charge of
$10.4 million. The 1997 results reflect increased gas and oil production that
more than offset the impact of lower average wellhead prices for gas and oil,
higher royalty expense, increased operating costs related to bringing certain
new production on line and increased workover activity. During 1997, the Company
added 315 Bcf of gas equivalent from additions, revisions, and purchases of gas
and oil reserves.
1996
Operating income before income taxes in 1996 was $133.2 million, compared with
an operating loss before income taxes of $200.5 million in 1995. However, the
1995 results reflect a non-cash charge of $226.2 million for the impairment of
gas and oil producing properties and workforce reduction charges totaling $7.7
million. Excluding these special items, operating income before income taxes
would have been $33.4 million in 1995. The effects of higher gas and oil
wellhead prices and higher gas and oil production contributed to the
significantly improved operating results in 1996. Higher prices and production
also resulted in increased royalty expense and higher production-related costs
compared to the prior year. The Company added 272 Bcf of gas equivalent from
additions, revisions, and purchases of gas and oil reserves in 1996.
GAS AND OIL PRODUCTION, PRICES AND OTHER INFORMATION
The following table sets forth the Company's gas and oil production, average
wellhead prices and other information for the E&P operations for the last three
years:
8
<PAGE> 11
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------
1998 1997 1996
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C>
GAS (BCF)
Nonregulated................................................ 154.9 155.3 144.5
Regulated*.................................................. 2.6 2.8 3.0
----- ----- -----
Total.................................................... 157.5 158.1 147.5
===== ===== =====
OIL (000 BBLS)
Nonregulated................................................ 7,894.7 7,312.0 4,765.9
======= ======= =======
AVERAGE WELLHEAD PRICES--NONREGULATED
Gas (per Mcf)............................................... $ 2.26 $ 2.43 $ 2.46
Oil (per Bbl)............................................... $11.54 $16.07 $17.60
OTHER E&P DATA--NONREGULATED
DD&A (per Mcf equivalent)................................... $.89 $.88 $.93
Average production (lifting) cost (per Mcf equivalent)...... $.31 $.33 $.32
</TABLE>
* Cost-of-service. Cost-of-service gas reserves were held solely by Peoples
Natural Gas and sold to CNG Producing during 1998.
- --------------------------------------------------------------------------------
The Company's average gas wellhead price was $2.26 per Mcf in 1998, down
$.17 from 1997 but still favorable compared to industry-wide prices in 1998 due
to a market price hedging program. For 1999, the Company has used derivatives to
effectively sell forward approximately 102.3 Bcf of gas production as of
February 1, 1999 at an average price of $2.25 per Mcf. Gas production in 1998
was down .6 Bcf, to 157.5 Bcf, compared to 1997. Average oil wellhead prices
were $11.54 per barrel in 1998, down $4.53 from 1997, while oil production
increased nearly 600,000 barrels, to 7.9 million barrels. The increase in oil
production in 1998 was due in part to a full year of production at Neptune, a
deep-water project in the Gulf of Mexico which began production in March 1997.
The Company's average gas wellhead price was $2.43 per Mcf in 1997, down
slightly from 1996. Gas production for 1997 was 158.1 Bcf, an increase of 10.6
Bcf compared to the prior year. Production from several new fields in the Gulf
of Mexico contributed to the 1997 increase. Oil wellhead prices averaged $16.07
a barrel during 1997, down $1.53 from 1996, while production increased 53%
compared to the prior year. The increase in oil production in 1997 was due
largely to the impact of Neptune.
E&P OPERATING REVENUES
Total operating revenues for the E&P operations were $631.1 million in 1998, a
decline of $74.6 million from 1997. Gas sales revenues decreased $9.4 million
due to both lower volumes and lower average gas prices compared to 1997.
Revenues from oil and condensate production and trading declined $71.9 million
in 1998 as the effect of lower average sales prices outweighed the impact of
higher sales volumes. Revenues from oil trading decreased $45.6 million and
revenues from oil and condensate production declined $26.3 million. Other
operating revenues increased $6.7 million in 1998.
Total operating revenues were $705.7 million in 1997, an increase of $73.4
million compared to 1996. Gas sales revenues decreased $.5 million, as increased
sales volumes were more than offset by the effect of lower average gas prices.
Revenues from oil and condensate production and trading increased $73.0 million
in 1997, with higher sales volumes more than offsetting the impact of lower
rates. Revenues from oil trading rose $39.7 million and revenues from oil and
condensate production increased $33.3 million.
OTHER
This component, as described in the operating results table on page 5, reported
operating losses before income taxes of $1.4 million, $7.3 million and $.9
million in 1998, 1997 and 1996, respectively. Start-up costs of CNG Retail and
CNG Products and Services are reflected in their combined losses of $5.3
million, $3.8 million and $1.5 million in 1998, 1997 and 1996, respectively.
Partially offsetting the 1998 losses was $8.8 million of pretax operating income
from CNG Field Services. Also helping to offset start-up costs somewhat was
pretax operating income from Consolidated LNG of $.2 million, $1.4 million and
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$2.6 million for the years 1998, 1997 and 1996, respectively, reflecting the
recognition of deferred income pursuant to a regulatory order.
Results of this component for 1998, 1997 and 1996 also reflect the
operations of CNG International, which had pretax operating losses of $4.7
million, $6.8 million and $3.8 million, respectively. However, earnings from CNG
International's operations are attributable to investments in foreign utilities
and pipelines which are accounted for under the equity method and are excluded
from the operating income amounts. CNG International reported net income of $2.5
million for 1998 and reported net losses of $3.8 million in 1997 and $2.6
million in 1996.
DISCONTINUED OPERATIONS
During April 1998, management approved a plan to discontinue the Company's
wholesale trading and marketing of natural gas and electricity, including
integrated energy management. On July 31, 1998, the sale of the capital stock of
CNG Energy Services Corporation, formerly a wholly-owned subsidiary of the
Company, to Sempra Energy Trading, a subsidiary of Sempra Energy, was finalized.
Included in the transaction were contracts for the purchase and sale of natural
gas as well as rights to natural gas pipeline and storage capacity, mainly in
the Northeast and Mid-Atlantic regions, and related working capital. Proceeds of
$37.4 million were received from the sale of the stock, as adjusted for working
capital items. The Company's transition out of the wholesale gas business was
substantially complete at December 31, 1998.
Losses from discontinued operations, net of applicable tax benefits, were
$17.2 million, $14.5 million and $11.1 million for the years 1998, 1997 and
1996, respectively. In addition, during 1998 the Company recognized a loss on
disposal of the discontinued operations, including a provision for operating
losses during the phase out period, of $31.7 million, net of applicable tax
benefit.
INTERNATIONAL ACTIVITIES
During December 1997, CNG International acquired ownership interests in two gas
utility holding companies, Sodigas Pampeana S.A. and Sodigas Sur S.A., and in an
electric utility holding company, Buenos Aires Energy Company (BAECO), from CEI
Citicorp Holdings S.A. in Argentina. The gas utility holding companies have
ownership interests in two gas distribution companies, Camuzzi Gas Pampeana and
Camuzzi Gas del Sur, and BAECO has an ownership interest in an electric
distribution company, EDEA. The service territories of these companies span from
Buenos Aires province to the southernmost tip of Argentina. In March 1998 CNG
International purchased additional interests in Sodigas Pampeana S.A., Sodigas
Sur S.A. and BAECO from Loma Negra, bringing the Company's ownership interests
in these entities to 21.55%, 21.55% and 25%, respectively. Camuzzi Argentina
S.A. maintains majority ownership interests in the holding companies. At
December 31, 1998, CNG International's investments in the Argentine holding
companies totaled $122.8 million.
In March 1998 CNG International purchased a 33.3% ownership interest in the
Dampier-to-Bunbury Natural Gas Pipeline (DBNGP) in Western Australia from the
Western Australia Government. One of CNG International's partners in the
purchase was El Paso Energy Corporation (El Paso), which also holds a 33.3%
ownership interest. In connection with their investments in DBNGP, CNG
International and El Paso formed DBNGP Finance Company LLC (DBNGP Finance).
DBNGP Finance is owned 50% by CNG International and 50% by EPED Holding Company,
a wholly-owned subsidiary of El Paso. Subsequent to the formation of DBNGP
Finance, the equity ownership interests of CNG International and El Paso in
DBNGP were transferred to this entity.
In October 1998 DBNGP Finance borrowed $250 million under a Senior Term
Loan Facility (Term Loan). The Term Loan matures October 2, 2001, can be
extended in one-year increments to October 2, 2003, and will bear interest at a
variable rate. Of the gross proceeds received by DBNGP Finance under the Term
Loan, $100 million was distributed to CNG International. In connection with the
Term Loan, CNG International entered into an Equity Contribution Agreement with
DBNGP Finance. CNG International is contractually obligated to make equity
contributions to DBNGP Finance equal to the Term Loan proceeds distributed to
CNG International, plus interest on such proceeds, in the event that DBNGP
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<PAGE> 13
Finance is unable to service this debt. The Company is contractually obligated
to cause CNG International to make such contributions.
CNG International's investments in Australia at December 31, 1998,
including DBNGP Finance, totaled $77.6 million.
LIMITATION ON CAPITALIZED COSTS
As indicated in Note 1 to the consolidated financial statements, the Company
follows the full cost method of accounting for its gas and oil producing
activities prescribed by the Securities and Exchange Commission (SEC). Reference
is made to Note 5 to the consolidated financial statements, page 33, regarding
the Company's recognition under the SEC full cost rules of an impairment of its
gas and oil producing properties at December 31, 1997.
There are a number of factors, including prices, that determine whether or
not an impairment is required. Because gas wellhead prices are subject to sudden
and seasonal fluctuations, an 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 a
price decline.
FEDERAL AND STATE REGULATORY MATTERS
GAS AND ELECTRIC INDUSTRY DEVELOPMENTS
Gas industry competition at the retail level is receiving increased attention
from both regulators and legislators. Governments in three of the states in
which the Company operates distribution subsidiaries have enacted or considered
legislation regarding deregulation of natural gas at the retail level. In Ohio,
a 1996 law established customer choice as a state policy in the supply of
natural gas services. Implementation of the law, which allows retail customers
to obtain gas from an array of suppliers, is under way. In Pennsylvania, pending
legislation would unbundle gas utility merchant functions and permit the
Pennsylvania Public Utility Commission to certify marketers, in addition to gas
utilities, as suppliers of last resort, creating competition in a traditional
gas utility function. Most recently, Virginia has begun to consider gas
unbundling legislation.
In addition to restructuring of the gas industry, the emerging unbundling
of services provided by electric utilities is leading toward the convergence of
the two industries to create one overall, highly competitive marketplace for a
customer's total energy needs. Regulators and legislators at the federal level
and in many states are considering, or are already implementing, initiatives to
promote increased competition in the electric industry. A major development was
the issuance in 1996 of FERC Orders 888 and 889. By requiring open access to the
national electric transmission grid, Order 888 fosters increased competition in
both the generation of electricity and the supply of bulk power to major
wholesale customers. The companion order, Order 889, addresses the timing,
information access and other administrative details associated with the FERC
deregulation initiative. Congress also is considering legislation intended to
facilitate the move to competition in the electric industry.
Although progress status varies, pro-competition electric legislation is at
least under consideration in many states. In Ohio, leaders of the General
Assembly have predicted passage in 1999 of a bill to assure customer choice. In
Pennsylvania, the 1996 Electric Generation Customer Choice and Competition Act
required the transition to a competitive retail electric market to begin in
January 1999, with full competition by 2001. In Virginia, the General Assembly
may enact a restructuring bill which would phase in retail competition starting
on January 1, 2002. Regulators and legislators in West Virginia are also
debating issues related to electric industry restructuring.
Reflecting the evolution to a more competitive energy environment, the pace
and size of business combinations among natural gas and electric utilities has
increased in recent years (reference is made to Note 19 to the consolidated
financial statements, page 52, regarding the Company's proposed merger with
DRI). These business combinations have generally been initiated to provide
benefits from economies of scale, to reduce costs by the elimination of
duplicate facilities and processes, and to improve the strategic and competitive
position of the surviving entity.
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<PAGE> 14
Recent and pending regulatory actions may serve to further facilitate more
business combinations in the energy industry. The FERC has streamlined its
regulatory review process regarding pending mergers. In addition, Congress has
considered legislation to conditionally repeal the Public Utility Holding
Company Act of 1935 (PUHCA), to which the Company is subject. While it seems
unlikely that Congress will enact PUHCA legislation on a stand-alone basis, it
appears more likely that any comprehensive electric restructuring bill will
include a PUHCA repeal provision. If legislation to repeal or significantly
modify the provisions of the PUHCA becomes law, certain federal restrictions
related to diversification activities, including business combinations, for gas
and electric companies subject to the PUHCA may be eased.
To focus the distribution and transmission operations on being more
responsive to customer needs and to enable them to more effectively seize growth
opportunities in the competitive marketplace, the Company announced a
significant reorganization of the management structure of its regulated
businesses in December 1998. The new structure brings all five regulated
subsidiaries--CNG Transmission, East Ohio Gas, Peoples Natural Gas, Virginia
Natural Gas and Hope Gas--under the leadership of a single management team. This
new team will manage by business process rather than by company. However, all
five companies will remain separate legal entities and will retain their names.
FEDERAL AND STATE REGULATORY ISSUES
On April 29, 1998, the Virginia State Corporation Commission issued a final
order in connection with the September 25, 1996 expedited rate application of
Virginia Natural Gas. The order resulted in an annual revenue increase of $7.2
million, retroactive to October 25, 1996, the date new rates went into effect
subject to refund. Customer refunds resulting from the order were made in 1998.
The order reflects an imputed return on equity of 10.9%. In its filing, Virginia
Natural Gas had requested a $13.9 million increase in annual revenues and a
return on equity of 11.3%.
On July 28, 1998, the Public Service Commission of West Virginia approved a
settlement agreement filed by Hope Gas in connection with its January 5, 1998
general rate filing. The new rates became effective November 1, 1998. Under the
settlement, Hope Gas is not permitted to request an increase in rates prior to
January 1, 2002, nor is it obligated to file for new rates after that date. The
approved settlement agreement grants Hope Gas a combined $6.5 million annual
revenue increase for both base rates and gas costs. Hope Gas had originally
proposed a $14.5 million annual increase in revenues.
On November 24, 1998, the FERC approved a settlement filed by CNG
Transmission in connection with its July 1, 1997 general rate filing. The
settlement resolves the outstanding issues in the case and maintains the
preexisting level of annual revenues. The settlement reflects an imputed return
on equity of 10.7%. CNG Transmission made interim customer refunds amounting to
$39.2 million in December 1998, and expects to make a final settlement refund of
approximately $19 million by the end of the first quarter of 1999. In its
filing, CNG Transmission had requested a $71 million increase in annual revenues
and a return on equity of 14.5%.
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
46, 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.
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EFFECTS OF INFLATION
Although inflation rates have been low to 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 1998, the Board of Directors continued the quarterly dividend on the
common stock at $.485 a share. Total dividends paid to common shareholders in
1998 were $185.9 million compared with $184.6 million in 1997 and $183.0 million
in 1996.
During 1998, a total of 335,333 original issue shares were issued through
various Company-sponsored plans, including 282,273 shares acquired by employees
through the exercise of outstanding stock options.
Under the Company's stock repurchase plan, up to 10 million shares of the
Company's common stock can be repurchased in the open market. Shares may also be
purchased in private transactions. The Company may also acquire shares of its
common stock through certain provisions of the various stock incentive plans.
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. In January 1998, the Company purchased approximately 4.6
million shares of its common stock in a private transaction for use in
satisfying the conversion rights of debentures called for redemption (see "Call
of Debentures," Page 14). The Company acquired 220,462 shares in 1997 at a cost
of $12.3 million, or an average price of $55.73 a share, primarily to fund
certain nonqualified benefit plans via a grantor trust. At December 31, 1998 and
1997, a total of 495,123 and 659 shares, respectively, were being held as
treasury stock.
CAPITAL SPENDING
The current capital spending program for 1999 is estimated at $524.5 million, a
31% decrease compared with total capital spending in 1998. The estimated 1999
budget has been allocated as follows: exploration and production, $337.0
million; distribution, $128.4 million; transmission, $51.3 million; and
corporate and other, $7.8 million. The decreased level of capital expenditures
planned for 1999 anticipates lower spending for international projects, which
will be evaluated on a case-by-case basis. Exploration and production operations
reflect increased spending on deep-water projects and increased conventional
onshore and offshore drilling. Transmission and distribution operations
expenditures will primarily be limited to spending for enhancements and
improvements in the pipeline system and related facilities. 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. The Company may require long-term financing in 1999 to
support capital spending, and may also utilize the capital markets to take
advantage of other opportunities, including exploration and production
acquisitions, or 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 from continuing operations was $767.4 million,
$784.1 million and $424.9 million for the years 1998, 1997 and 1996,
respectively. The increase in net cash provided by operating activities in 1997
was due in part to higher gas sales revenues in 1997, including the
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<PAGE> 16
recovery of previously deferred purchased gas costs by the distribution
subsidiaries, and the payment of customer refunds in 1996 that did not recur in
1997.
In October 1998, the Company sold $200 million of 6% Debentures Due October
15, 2010. The proceeds were used for general corporate purposes including
capital expenditures, reduction of short-term debt, repurchase of Company stock,
and the acquisition, retirement or redemption of debt securities.
The Company has a shelf registration with the SEC which would allow it to
sell up to an additional $338.3 million of debt or equity securities. The amount
and timing of any future sale of these securities will depend on capital
requirements, including financing necessary to enable the Company to pursue
asset acquisition opportunities, and financial market conditions.
The Company's embedded long-term debt cost, excluding current maturities,
at year-end 1998 was 6.96%, compared with 7.20% for 1997 and 7.27% for 1996. The
long-term debt to capitalization ratio was 36.5%, 39.7% and 39.3% at the end of
1998, 1997 and 1996, respectively. Under the provisions of one of the indentures
covering the Company's outstanding senior debenture issues, the ratio cannot
exceed 60%. The Company's senior debentures are rated A2 by Moody's Investors
Service, AA-- by Standard & Poor's, AA-- by Duff and Phelps, and AA by Fitch
Investors Service.
At December 31, 1998, the Company had a short-term credit agreement with a
group of banks for $775 million. The Company made no borrowings under this
agreement during 1998 and there were no amounts outstanding under any credit
agreements at December 31, 1998 or 1997.
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 1998, of which $558.9 million was
outstanding at year-end. The Company may utilize unused portions of its credit
agreements to provide support for commercial paper notes.
CALL OF DEBENTURES
In January 1998 the Company called for redemption the entire principal amount
outstanding of its 7-1/4% Convertible Subordinated Debentures, totaling $246.2
million. These debentures were convertible into shares of the Company's common
stock at an initial conversion price of $54 per share. The redemption price was
102.18% of the principal amount plus accrued interest payable on February 23,
1998. In anticipation of the call, in January 1998 the Company purchased
approximately 4.6 million shares of its common stock in a private transaction to
satisfy the potential conversion obligation. The right to convert expired on
February 13, 1998, and approximately 1.6 million of the acquired shares were
issued on conversion. The remaining acquired shares were sold in two
underwritten offerings during February and March 1998.
YEAR 2000 TECHNOLOGY ISSUE
Similar to all business entities, the Company will be impacted by the inability
of some computer application software programs to distinguish between the year
1900 and 2000 due to a commonly-used programming convention.
In the early 1990s, the Company identified business systems in need of
technology updates to successfully adapt to changes in the business climate and
the emerging competitive marketplace. These changes required the Company to move
toward common, integrated systems and computing platforms. Accordingly, many
systems representing older technology, which were not year 2000 ready, were
targeted for replacement. This plan is being executed through major initiatives
such as a company-wide implementation of Oracle Financial Applications, the
development of a new revenue and customer information system for the
distribution subsidiaries called "CAMP," and the development and implementation
of applications for gas control management and asset and facilities mapping.
Through these initiatives over 75 application systems, including associated
technical infrastructure, are being replaced.
In 1997, the Company formalized its approach to year 2000 issues with the
creation of a Year 2000 Project Office (Project Office) at the corporate level
to coordinate company-wide year 2000 activities. All of the Company's operating
subsidiaries are participating in this effort under the direction of the Project
Office.
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<PAGE> 17
The Company is addressing year 2000 issues via a systematic methodology
that mitigates risk and incorporates a thorough due diligence process. This
strategy recognizes that the definition of "year 2000 compliance" varies broadly
depending on the industry, component, vendor, and/or device. The Company's
strategy prioritizes the critical areas of the business to eliminate any
potential impact on safety, and to mitigate or eliminate any adverse effect on
revenues, assets, customer service and the environment that may result from the
date change event.
PROJECT DESCRIPTION AND ACTIVITIES
The major areas of focus of the Company's year 2000 efforts include application
systems, process control components, technical infrastructure, physical
infrastructure, and business partner and vendor relationships.
These project areas are summarized below:
Application Systems. Application systems encompass all automated systems,
including those developed internally and those purchased from vendors. These
systems include traditional business applications, as well as operations and
engineering applications.
Process Control Components (embedded technology). Process control devices
automate certain production, transportation and delivery functions in connection
with natural gas, oil and liquids. These devices, such as flow computers and
pressure regulators, generally include embedded computer technology.
Technical Infrastructure. This category represents the underlying technical
architecture which supports the Company's application systems, e-mail, and
similar infrastructure. This infrastructure includes mainframe hardware and
software, application servers, local and wide area networks, desktop personal
computers and telecommunications.
Physical Infrastructure. This category represents the Company's physical
plant, including office buildings. Building infrastructure such as elevators,
HVAC systems, security and fire alarm systems are examples of components
included in this category.
Business Partner and Vendor Relationships. This area involves analysis of
critical business partner and vendor relationships and third party commitment to
addressing year 2000 issues via discussion, contract reviews and additional
detailed assessment as considered necessary.
For each of the areas described above, the Company employs a five-phase
process methodology as follows:
(1) Inventory: In this phase, the Company compiles comprehensive
inventories of each of the major project areas.
(2) Assessment and Analysis: This phase is performed to determine the
extent to which year 2000 issues exist in any of the inventoried
areas and, if so, whether the issue is controllable (can be remedied
by the Company) or non-controllable (is dependent upon vendor
representation and/or remediation and can only be tested by the
Company).
(3) Repair and Replacement: Renovations, replacements, and upgrades are
made during this phase to remedy year 2000 issues.
(4) Testing: During this phase, independent testing is performed to
ensure year 2000 issues have been mitigated.
(5) Continuity Planning: This phase is focused on ensuring continuity of
major and critical business processes that could be affected by year
2000 events. This effort includes "zero-day" (December 31, 1999),
contingency, and recovery planning in combination to consider and
mitigate the effects of unknown internal and external year 2000
risks.
The Company utilizes a multi-vendor strategy to maximize the effectiveness
of its year 2000 efforts. The Company's primary external consultants include
Compuware Inc. (analysis and renovation of mainframe and client/server
application systems, tools for testing of application systems and professional
services for application systems test planning) and Keane, Inc. (process control
component analysis, test planning and execution; operations and engineering
application systems inventory and analysis; continuity planning; and
facilities/physical infrastructure inventory and analysis).
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<PAGE> 18
PROJECT STATUS
The following summarizes the Company's progress in the major project areas
through December 31, 1998:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
PHASE
- -----------------------------------------------------------------------------------------
PROJECT AREA Inventory Assessment Repair/ Testing Continuity
Replace Planning
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
APPLICATION Complete Complete In progress In progress In progress
SYSTEMS
- -----------------------------------------------------------------------------------------
PROCESS CONTROL Complete Complete In progress In progress In progress
COMPONENTS
- -----------------------------------------------------------------------------------------
TECHNICAL Complete Complete In progress In progress In progress
INFRASTRUCTURE
- -----------------------------------------------------------------------------------------
PHYSICAL In progress In progress In planning In planning In planning
INFRASTRUCTURE
- -----------------------------------------------------------------------------------------
BUSINESS Ongoing Ongoing Not Not In progress
PARTNERS AND process process applicable applicable
SUPPLIERS
- -----------------------------------------------------------------------------------------
</TABLE>
Application Systems. During the assessment phase, approximately 80
application systems were identified requiring some degree of repair or
replacement. However, the Company's actions to upgrade to newer, more functional
versions of vendor software have mitigated many existing year 2000 issues. These
upgrade activities will continue through mid-1999. Repair and replacement
activities for internally developed application systems began in March 1998 and
are substantially complete at year end 1998, with testing continuing through
mid-1999. Reference is made to "Risks," page 17, for information on the status
of CAMP.
Process Control Components. For process control components inventoried by
the Company, approximately 43% are not date sensitive, and therefore are not
affected by year 2000 issues. For date sensitive components, the Company
estimates a year 2000 failure rate of approximately 10% to 12%. Replacement of a
small number of non-compliant components will continue through early 1999, while
testing of components believed to be year 2000 ready continues and is
approximately 44% complete.
Technical Infrastructure. Technical infrastructure has been analyzed
directly with vendors and via the use of an external vendor research database
service. This information is being used to guide year 2000 upgrades of
infrastructure as necessary. Repair, replacement and testing activities are
approximately 92% complete for all categories of technical infrastructure, while
efforts in the critical area of application servers are 93% complete. The
Company had completed a substantial portion of year 2000 upgrades by the end of
1998, and is continuing with testing into 1999.
The Company has developed plans to determine the status of year 2000
readiness of its desktop personal computers. Inventory activities began in
December 1998, and are expected to continue through February 1999, after which
any repair or replacement activities will commence. Updated desktop
infrastructure continues to be deployed that is year 2000 ready concurrent with
the implementation of many new application systems described above. The Company
plans to confirm year 2000 readiness of this infrastructure via testing, which
is expected to be completed by mid-1999.
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Physical Infrastructure. The Company has completed the inventorying of
non-gas related physical infrastructure components that may be subject to year
2000 problems, and is currently verifying its inventory of gas-related
facilities. Critical physical infrastructure components that are related to
process control have been inventoried and assessed in the process control area
of the project. Repair activities, if necessary, will follow the verification
process. Where facilities are leased, the Company is identifying and working
with building managers/lessors to ensure they are actively addressing the year
2000 issue as a primary effort in continuity planning.
Business Partner and Vendor Relationships. Strategic business partner and
vendor relationships have been given priority in the inventory phase, and
assessment continues via questionnaires and interviews. Over 1,000 strategic
relationships had been identified and queried by the end of 1998. The Company
will continue to prioritize, identify and assess business partner and vendor
relationships until significant areas of risk have been identified and
mitigated, and is also preparing contingency plans in the event mitigation
efforts are not successful. The Company had performed a preliminary analysis of
all significant relationships by the end of 1998, including the year 2000 status
of operations in Argentina and Australia in which the Company has investments.
Continuity Planning. The Company has completed development of a continuity
planning methodology and has identified critical business processes. Business
continuity managers have been identified and will be trained in the continuity
planning methodology in early 1999. Continuity plans are expected to be
developed commencing February 1999, drawing upon an extensive inventory of
contingency and recovery plans already in operation.
Costs
Based upon project status as described above, the Company expects to spend a
total of approximately $22.6 million in connection with its Project Office
efforts, its use of external consultants and the remediation of affected
application systems. This estimate includes $6.8 million of capitalized costs
for hardware and software used (or expected to be used) in the testing phase,
and for application system and technical infrastructure replacements. This
estimate excludes costs incurred or expected to be incurred in connection with
the development and installation of major new application systems which are
expected to be year 2000 ready, the Company's potential share of year 2000 costs
that may be incurred by partnerships and joint ventures in which the Company
participates but is not the operator, and internal labor costs other than those
of the core Project Office. As of December 31, 1998, the Company has incurred
costs approximating $5.4 million (of which $1.5 million has been capitalized) in
connection with its year 2000 efforts. Total costs incurred as of December 31,
1998, as a proportion of the total year 2000 budget, is not indicative of the
overall completion rate of the project, which is estimated to be over 50%.
Risks
Significant progress has been made in the development of CAMP for use at Hope
Gas and EOG Energy Choice. However, previous technical difficulties and delays
have caused the Company to invoke a contingency plan which involves renovation
of the current revenue application system for the other distribution
subsidiaries and 20 related application systems to make such systems year 2000
ready. These current systems collectively address the business processes which
were to be handled by CAMP. Renovation activities have been completed in
connection with this contingency plan and implementation, including testing, is
scheduled to be completed by August 1999. Under a worst case scenario, the
current revenue application systems would not be year 2000 ready by the end of
1999 for the other distribution subsidiaries and CAMP would not be successfully
implemented or year 2000 ready at Hope Gas and EOG Energy Choice. The estimate
of $22.6 million referred to above includes approximately $2.3 million of costs
in connection with the CAMP contingency plan. Concurrent with this effort, the
Company is continuing the development of CAMP and has capitalized $53.0 million
related to this project as of December 31, 1998. The CAMP core software is a
licensed product of the Company's independent accountants,
PricewaterhouseCoopers LLP (PwC), and PwC is the primary information systems
consultant on this project.
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If a material year 2000 problem is not corrected in a timely manner, an
interruption in, or a failure of, certain normal business activities or
operations of the Company could occur. Such instances could materially and
adversely affect the Company's financial position, cash flows and/or results of
operations. Due to the uncertainty inherent in the year 2000 issue, including
the uncertainty of year 2000 readiness of third party vendors, business partners
and customers, the Company cannot determine at this time whether the
consequences of any year 2000 failures will have a material impact on its
financial position, cash flows or results of operations. However, the Company's
Project Office activities and the implementation of new application systems are
expected to reduce the risk of a material year 2000 failure.
PRICE RISK MANAGEMENT ACTIVITIES
In the normal course of business, certain of the Company's operations are
subject to market risk and credit risk in connection with the production,
purchase and sale of natural gas and oil and stored gas inventories. In
addition, the Company's foreign equity investments are subject to foreign
currency risk. Reference is made to Note 15 to the consolidated financial
statements, Page 45, regarding the fair value of the Company's long-term debt
which is comprised of fixed-rate instruments.
MARKET AND CREDIT RISK
Price risk management activities expose the Company to market risk. Market risk
represents the potential loss that can be caused by the change in market value
of a particular commitment. The Company has appropriate operating procedures in
place that are administered by experienced management to help ensure that proper
internal controls are maintained. In addition, the Company has established an
independent function at the Corporate level to monitor compliance with the price
risk management policies of all subsidiaries.
Price risk management activities also expose the Company to credit risk.
Credit risk represents the potential loss that the Company would incur as a
result of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The Company maintains credit policies with respect to
its counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. The Company also monitors the financial condition of
existing counterparties on an ongoing basis. Considering the system of internal
controls in place and credit reserve levels at December 31, 1998, the Company
believes it unlikely that a material adverse effect on its financial position,
results of operations or cash flows would occur as a result of counterparty
nonperformance.
The Company uses over-the-counter (OTC) price swap agreements,
exchange-traded futures contracts, and option contracts to manage market risk
inherent in the production, purchase and sale of natural gas and oil and stored
gas inventories. The level of market risk exposure from these activities is
maintained within risk management guidelines.
USE OF DERIVATIVES--NATURAL GAS
Information as of December 31, 1998 and 1997 for derivatives that are sensitive
to changes in natural gas prices follow. Net notional quantities are used to
calculate the payments and quantities to be exchanged under the contractual
terms of the futures contracts and swap agreements and are not a measure of the
Company's exposure to the use of these derivatives. It should also be noted that
these disclosures exclude information about the Company's natural gas commodity
purchase and sale commitments which are sensitive to changes in natural gas
prices, and information related to firm transportation and storage agreements
for which the Company must make specified minimum payments each month.
Therefore, the information presented regarding the use of derivatives by the
Company does not reflect the earnings impact of the physical transactions that
may offset the financial gains and losses arising from the use of derivatives.
18
<PAGE> 21
The following table presents net notional quantities and weighted average
settlement prices by expected maturity date for futures contracts used to hedge
natural gas price risk. All of the contracts included in the table below have
been designated as hedges of the future production, purchase and/or sale of
natural gas. At December 31, 1998, the Company held no futures contracts with
maturity dates extending beyond 2001.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------
Expected Maturity Date Unrealized
--------------------------- Gain
Exchange-Traded Futures Contracts 1999 2000 2001 Total at 12/31/98
- --------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C>
Contract volumes (in 10,000 mmbtu), purchased (sold)......... (7,048) 314 51 (6,683) $16,418
Weighted average settlement price (per mmbtu)................ $2.18 $2.17 $2.29
- --------------------------------------------------------------------------------------------------------------------
</TABLE>
At December 31, 1997, the Company held futures contracts related to
natural gas purchase and sale commitments and storage inventory covering 2.9 Bcf
of gas on a net basis maturing through 2000 having a net unrealized loss of $1.1
million.
The following table presents natural gas price swap information for
agreements in which the Company is obligated to pay or receive a fixed price in
exchange for receiving or paying a variable price at a location, and those in
which the Company pays or receives an amount based on prices at different
locations. At December 31, 1998, the Company had not entered into any price swap
agreements extending beyond 2003. All of the swap agreements included in the
table below have been entered into to hedge the risk of market price changes in
connection with the future production, purchase and/or sale of natural gas. The
weighted average variable pay and receive forward prices are based upon quotes
obtained from third party brokers and dealers that are active in the respective
markets.
PRICE SWAP AGREEMENTS
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------
Expected Maturity Date
---------------------------------------
(Quantities in 10,000 mmbtu) Fair Value
(Rates per mmbtu) 1999 2000 2001 2002 2003 Total at 12/31/98
- --------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Pay Fixed, Receive Variable
- ---------------------------
Net notional quantities............. 7,922 4,734 3,958 16,614 $(23,491)
Weighted average pay rate........ $.99 $.97 $1.31
Weighted average receive rate.... $.78 $.88 $1.24
Receive Fixed, Pay Variable
- ---------------------------
Net notional quantities............. 4,540 2,708 1,854 1,718 1,704 12,524 $ 13,388
Weighted average pay rate........ $1.27 $1.68 $2.12 $2.22 $2.27
Weighted average receive rate.... $1.57 $1.68 $2.08 $2.23 $2.28
- --------------------------------------------------------------------------------------------------------------
</TABLE>
At December 31, 1997, the Company had price swap agreements of varying
duration outstanding to exchange monthly payments on net notional quantities of
gas over the ensuing five years. Net notional quantities and related fair value
at that date for swap agreements in which the Company pays a fixed price in
exchange for a variable price totaled 324.5 Bcf and $(26.3) million,
respectively. For swap agreements in which the Company pays a variable price in
exchange for a fixed price, net notional quantities and related fair value at
December 31, 1997 totaled 297.2 Bcf and $28.7 million, respectively.
USE OF DERIVATIVES--OTHER
At December 31, 1998, the Company was not a party to price swap agreements,
futures or option contracts in connection with the production or sale of crude
oil.
At December 31, 1997, the Company held futures contracts expiring in 1998
covering the sale of 1,750,000 barrels of oil with a weighted average settlement
price of $18.24 per barrel and an aggregate unrealized gain of approximately
$4.4 million. Also at December 31, 1997, the Company had a foreign currency swap
agreement with an aggregate notional amount of $51.0 million and an unrealized
gain of $4.5 million. The Company terminated its involvement in this swap
agreement during 1998 in connection with the sale of its wholesale marketing
business.
19
<PAGE> 22
FORWARD-LOOKING INFORMATION
Certain matters discussed in this Management's Discussion and Analysis of
Financial Condition and Results of Operations and elsewhere herein are
"forward-looking statements" intended to qualify for the safe harbors from
liability established by the Private Securities Litigation Reform Act of 1995.
These forward-looking statements can generally be identified as such because the
context of the statement will include words such as the Company "believes,"
"anticipates," "expects" or words of similar import. Similarly, statements that
describe the Company's future plans, objectives or goals are also
forward-looking statements. Such statements may address future events and
conditions concerning the Company's proposed merger with DRI, capital
expenditures, earnings, risk management, litigation, the year 2000 technology
issues and costs, environmental matters, rate and other regulatory matters,
liquidity and capital resources, and financial accounting and reporting matters.
Actual results in each instance could differ materially from those currently
anticipated in such statements, due to factors such as: natural gas and electric
industry restructuring, including ongoing state and federal activities; the
weather; demographics, general economic conditions and specific economic
conditions in the Company's distribution service areas; developments in the
legislative, regulatory and competitive environment in which the Company
operates; and other circumstances affecting anticipated revenues and costs.
Risks in connection with the Company's year 2000 efforts include the
Company's ability to successfully identify, correct and test, in a timely
manner, potential year 2000 problems which could have a significant impact on
specific business functions or processes, and the ability of third party
vendors, business partners and customers to ensure year 2000 readiness of their
systems and business operations.
SUMMARY OF FINANCIAL DATA
The Company's Summary of Financial Data is on page 21.
20
<PAGE> 23
<TABLE>
<CAPTION>
SELECTED FINANCIAL DATA
- ----------------------------------------------------------------------------------------------------------------
SUMMARY OF FINANCIAL DATA (THOUSAND $) 1998 1997 1996(b) 1995(b) 1994
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
EARNINGS (a)
Gas sales........................................ $1,868,110 $2,284,384 $2,149,771 $1,837,159 $2,402,861
Gas transportation, storage and other............ 892,296 892,726 805,687 666,416 633,167
Total operating revenues...................... 2,760,406 3,177,110 2,955,458 2,503,575 3,036,028
Purchased gas.................................... 900,401 1,114,080 963,217 864,591 1,424,020
Liquids, capacity and other products purchased... 145,277 210,575 179,307 87,434 107,094
Operation and maintenance........................ 708,378 757,220 757,321 719,273 689,575
Depreciation and amortization.................... 329,913 324,638 302,883 255,949 279,317
Impairment of gas and oil producing properties... -- 10,351 -- 226,209 --
Taxes, other than income taxes................... 179,299 193,584 190,683 190,716 192,617
Operating income before income taxes.......... 497,138 566,662 562,047 159,403 343,405
Income taxes..................................... 129,649 156,269 162,315 7,381 82,427
Other income-net................................. 34,700 12,442 8,975 10,661 9,694
Write-down of coal properties.................... -- -- -- 31,266 --
Interest charges................................. 114,478 103,927 99,325 102,584 87,501
Income from continuing operations................ 287,711 318,908 309,382 28,833 183,171
DISCONTINUED OPERATIONS (Note 2)
Loss from discontinued energy marketing services (17,238) (14,528) (11,109) (7,489) --
operations, net of applicable tax benefit.....
Loss from disposal of energy marketing services
operations, including provision for operating
losses during the phase out period, net of
applicable tax benefit........................ (31,707) -- -- -- --
NET INCOME....................................... 238,766 304,380 298,273 21,344 183,171
EARNINGS PER COMMON SHARE--BASIC
Income from continuing operations................ $3.03 $3.36 $3.29 $.31 $1.97
Loss from discontinued operations................ (.18) (.15) (.12) (.08) --
Loss from disposal of discontinued operations.... (.33) -- -- -- --
NET INCOME....................................... $2.52 $3.21 $3.17 $.23 $1.97
EARNINGS PER COMMON SHARE--DILUTED
Income from continuing operations................ $3.00 $3.30 $3.24 $.31 $1.97
Loss from discontinued operations................ (.18) (.15) (.11) (.08) --
Loss from disposal of discontinued operations.... (.33) -- -- -- --
NET INCOME....................................... $2.49 $3.15 $3.13 $.23 $1.97
Return on average stockholders' equity........... 10.0% 13.3% 14.0% 1.0% 8.4%
Times fixed charges earned....................... 4.03 4.90 5.04 1.32 3.53
- ----------------------------------------------------------------------------------------------------------------
DIVIDENDS--CASH
Paid per common share............................ $1.94 $1.94 $1.94 $1.94 $1.94
Payout ratio.................................. 77.0% 60.4% 61.2% 843.5% 98.5%
Declared per common share........................ $1.94 $1.94 $1.94 $1.94 $1.94
- ----------------------------------------------------------------------------------------------------------------
ASSETS
Total assets..................................... $6,361,900 $6,313,694 $6,000,605 $5,418,293 $5,518,673
Property, plant and equipment
Total investment.............................. 9,172,465 8,714,758 8,304,205 7,929,350 7,676,956
Accumulated depreciation...................... 4,734,001 4,491,955 4,226,905 4,016,945 3,650,310
Capital expenditures and acquisitions............ 762,916 609,373 560,293 439,393 437,785
- ----------------------------------------------------------------------------------------------------------------
CAPITAL STRUCTURE
Total common stockholders' equity................ $2,399,608 $2,358,318 $2,205,152 $2,045,818 $2,184,334
Long-term debt................................... 1,379,729 1,552,890 1,426,315 1,291,811 1,151,973
--------- --------- --------- --------- ---------
Total capitalization.......................... $3,779,337 $3,911,208 $3,631,467 $3,337,629 $3,336,307
========== ========== ========== ========== ==========
Long-term debt ratio............................. 36.5% 39.7% 39.3% 38.7% 34.5%
Shares outstanding at year-end................... 95,449,428 95,622,622 94,933,631 93,591,623 93,027,847
Common stockholders' equity per share............ $25.14 $24.66 $23.23 $21.86 $23.48
- ----------------------------------------------------------------------------------------------------------------
</TABLE>
(a) Amounts for the years 1995 through 1997 have been restated, as applicable,
to present continuing operations separate from discontinued operations.
(b) Certain amounts and ratios are not comparable with prior years due to
special charges.
21
<PAGE> 24
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of
Consolidated Natural Gas Company
In our opinion, the consolidated financial statements appearing on pages 23
through 58 of this Appendix I to the proxy statement for the 1999 annual meeting
of stockholders present fairly, in all material respects, the financial position
of Consolidated Natural Gas Company and subsidiaries (collectively, the Company)
at December 31, 1998 and 1997, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 1998, 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.
PRICEWATERHOUSECOOPERS LLP
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
February 9, 1999, except for Note 19,
which is as of February 22, 1999
22
<PAGE> 25
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
For the Years Ended December 31, 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
OPERATING REVENUES
Regulated gas sales..................................................... $1,373,691 $1,851,001 $1,753,667
Nonregulated gas sales.................................................. 494,419 433,383 396,104
---------- ---------- ----------
Total gas sales.................................................... 1,868,110 2,284,384 2,149,771
Gas transportation and storage.......................................... 545,933 492,080 479,588
Other................................................................... 346,363 400,646 326,099
---------- ---------- ----------
Total operating revenues (Note 4).................................. 2,760,406 3,177,110 2,955,458
---------- ---------- ----------
OPERATING EXPENSES
Purchased gas........................................................... 900,401 1,114,080 963,217
Liquids, capacity and other products purchased.......................... 145,277 210,575 179,307
Operation expense (Note 6).............................................. 618,010 666,612 667,254
Maintenance............................................................. 90,368 90,608 90,067
Depreciation and amortization (Note 5).................................. 329,913 324,638 302,883
Impairment of gas and oil producing properties (Note 5)................. -- 10,351 --
Taxes, other than income taxes.......................................... 179,299 193,584 190,683
---------- ---------- ----------
Subtotal........................................................... 2,263,268 2,610,448 2,393,411
---------- ---------- ----------
Operating income before income taxes............................... 497,138 566,662 562,047
Income taxes (Note 8)................................................... 129,649 156,269 162,315
---------- ---------- ----------
Operating income................................................... 367,489 410,393 399,732
---------- ---------- ----------
OTHER INCOME
Interest revenues....................................................... 3,165 1,663 2,024
Other-net............................................................... 31,535 10,779 6,951
---------- ---------- ----------
Total other income................................................. 34,700 12,442 8,975
---------- ---------- ----------
Income before interest charges..................................... 402,189 422,835 408,707
---------- ---------- ----------
INTEREST CHARGES
Interest on long-term debt.............................................. 106,307 104,927 101,814
Other interest expense.................................................. 19,659 5,774 3,374
Allowance for funds used during construction............................ (11,488) (6,774) (5,863)
---------- ---------- ----------
Total interest charges............................................. 114,478 103,927 99,325
---------- ---------- ----------
INCOME FROM CONTINUING OPERATIONS....................................... 287,711 318,908 309,382
DISCONTINUED OPERATIONS (Note 2)
Loss from discontinued energy marketing services operations,
net of applicable tax benefit........................................ (17,238) (14,528) (11,109)
Loss from disposal of energy marketing services operations,
including provision for operating losses during the phase out period,
net of applicable tax benefit........................................ (31,707) -- --
---------- ---------- ----------
NET INCOME.............................................................. $ 238,766 $ 304,380 $ 298,273
=========- =========- =========
EARNINGS PER COMMON SHARE--BASIC
Income from continuing operations (Note 3)........................... $3.03 $3.36 $3.29
Loss from discontinued operations.................................... (.18) (.15) (.12)
Loss from disposal of discontinued operations........................
(.33) -- --
---------- ---------- ----------
NET INCOME.............................................................. $2.52 $3.21 $3.17
========== ========== ==========
EARNINGS PER COMMON SHARE--DILUTED
Income from continuing operations (Note 3)........................... $3.00 $3.30 $3.24
Loss from discontinued operations.................................... (.18) (.15) (.11)
Loss from disposal of discontinued operations........................
(.33) -- --
---------- ---------- ----------
NET INCOME.............................................................. $2.49 $3.15 $3.13
========== ========== ==========
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
23
<PAGE> 26
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
At December 31, 1998 1997
- -------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Note 5)
Gas utility and other plant...................................... $5,091,793 $5,004,139
Accumulated depreciation and amortization........................ (1,999,484) (1,949,483)
---------- ----------
Net gas utility and other plant............................ 3,092,309 3,054,656
---------- ----------
Exploration and production properties............................ 4,080,672 3,710,619
Accumulated depreciation and amortization........................ (2,734,517) (2,542,472)
---------- ----------
Net exploration and production properties.................. 1,346,155 1,168,147
---------- ----------
Net property, plant and equipment.......................... 4,438,464 4,222,803
---------- ----------
CURRENT ASSETS
Cash and temporary cash investments.............................. 135,453 65,035
Accounts receivable
Customers..................................................... 363,503 804,015
Unbilled revenues and other................................... 221,833 176,787
Allowance for doubtful accounts............................... (23,039) (29,590)
Inventories, at cost
Gas stored--current portion (Note 9)........................... 120,665 139,157
Materials and supplies (average cost method).................. 27,940 30,256
Unrecovered gas costs (Note 4)................................... 34,860 55,062
Deferred income taxes--current (net) (Note 8)..................... 21,786 --
Prepayments and other current assets............................. 258,899 212,919
---------- ----------
Total current assets....................................... 1,161,900 1,453,641
---------- ----------
REGULATORY AND OTHER ASSETS
Other investments................................................ 302,307 223,900
Deferred charges and other assets (Notes 4, 6, 7, 8 and 16)...... 459,229 413,350
---------- ----------
Total regulatory and other assets.......................... 761,536 637,250
---------- ----------
Total assets............................................... $6,361,900 $6,313,694
========== ==========
- -------------------------------------------------------------------------------------------------
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
24
<PAGE> 27
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
At December 31, 1998 1997
- ------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
STOCKHOLDERS' EQUITY AND LIABILITIES
CAPITALIZATION
Common stockholders' equity (Note 10)
Common stock, par value $2.75 per share
Authorized--400,000,000 shares
Issued, 1998--95,944,551 shares, 1997--95,623,281 shares........... $ 263,848 $ 262,964
Capital in excess of par value........................................ 571,972 566,755
Retained earnings (Note 12)........................................... 1,591,543 1,539,587
Treasury stock, at cost (1998--495,123 shares, 1997--659 shares)...... (26,359) (38)
Unearned compensation................................................. (1,396) (10,950)
----------- -----------
Total common stockholders' equity.................................. 2,399,608 2,358,318
Long-term debt (Note 13)................................................. 1,379,729 1,552,890
----------- -----------
Total capitalization............................................... 3,779,337 3,911,208
----------- -----------
CURRENT LIABILITIES
Current maturities on long-term debt..................................... 111,125 154,000
Commercial paper (Note 14)............................................... 558,900 238,700
Accounts payable......................................................... 423,695 651,365
Estimated rate contingencies and refunds (Note 4)........................ 78,266 29,112
Amounts payable to customers (Note 4).................................... 48,339 880
Taxes accrued............................................................ 122,788 125,056
Deferred income taxes--current (net) (Note 8)............................. -- 13,735
Dividends declared....................................................... 46,277 46,377
Other current liabilities................................................ 154,947 127,016
----------- -----------
Total current liabilities.......................................... 1,544,337 1,386,241
----------- -----------
DEFERRED CREDITS
Deferred income taxes (Note 8)........................................... 780,928 712,118
Accumulated deferred investment tax credits.............................. 24,475 26,658
Deferred credits and other liabilities (Notes 4, 7 and 8)................ 232,823 277,469
----------- -----------
Total deferred credits............................................. 1,038,226 1,016,245
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 17)
----------- -----------
Total stockholders' equity and liabilities......................... $ 6,361,900 $ 6,313,694
=========== ===========
- ------------------------------------------------------------------------------------------------------------
</TABLE>
25
<PAGE> 28
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- -------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Income from continuing operations................................... $ 287,711 $ 318,908 $ 309,382
Adjustments to reconcile income from continuing operations to net
cash provided by operating activities
Depreciation and amortization.................................. 329,913 324,638 302,883
Impairment of gas and oil producing properties................. -- 10,351 --
Pension cost (credit)-net...................................... (56,496) (46,011) (24,317)
Stock award amortization....................................... 7,460 8,209 7,774
Deferred income taxes-net...................................... 17,901 4,186 62,164
Investment tax credit.......................................... (2,171) (2,193) (2,201)
Changes in current assets and current liabilities
Accounts receivable-net..................................... 4,244 (14,953) (54,040)
Inventories................................................. (2,584) 38,125 (55,277)
Unrecovered gas costs....................................... 20,202 52,954 (82,893)
Accounts payable............................................ 92,795 (1,511) 3,064
Estimated rate contingencies and refunds.................... 49,154 7,510 (37,761)
Amounts payable to customers................................ 47,459 880 (40,315)
Taxes accrued............................................... (614) 23,834 (17,063)
Other-net................................................... (40,282) 3,517 6,791
Changes in other assets and other liabilities.................. 14,716 55,750 46,985
Other-net...................................................... (2,015) (70) (252)
--------- --------- ---------
Net cash provided by continuing operations.................. 767,393 784,124 424,924
Net cash provided by (or used in) discontinued operations........... 44,735 (42,016) (17,759)
--------- --------- ---------
Net cash provided by operating activities................... 812,128 742,108 407,165
--------- --------- ---------
CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions..................... (561,654) (514,705) (434,247)
Proceeds from dispositions of property, plant and equipment-net..... (1,267) 1,056 9,067
Cost of other investments-net....................................... (104,233) (86,763) (88,214)
--------- --------- ---------
Net cash used in continuing operations...................... (667,154) (600,412) (513,394)
Net cash provided by (or used in) discontinued operations........... 35,605 (6,256) (4,751)
--------- --------- ---------
Net cash used in investing activities....................... (631,549) (606,668) (518,145)
--------- --------- ---------
CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Issuance of common stock............................................ 11,719 28,722 37,726
Issuance of debentures.............................................. 196,888 294,945 299,567
Repayments of long-term debt........................................ (327,323) (119,625) (72,750)
Commercial paper-net................................................ 318,159 (134,368) 37,853
Dividends paid...................................................... (185,858) (184,608) (183,020)
Purchase of treasury stock.......................................... (280,863) (12,286) (8,144)
Sale of treasury stock.............................................. 162,763 12,266 8,142
Other-net (2,987) 25 (147)
--------- --------- ---------
Net cash provided by (or used in) financing activities...... (107,502) (114,929) 119,227
--------- --------- ---------
Net increase in cash and temporary cash investments......... 73,077 20,511 8,247
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1.................... 65,035 44,524 36,277
--------- --------- ---------
CASH AND TEMPORARY CASH INVESTMENTS AT DECEMBER 31.................. $ 138,112 $ 65,035 $ 44,524
=========- ========= =========
Continuing operations............................................... $ 135,453 $ 49,566 $ 21,583
Discontinued operations............................................. 2,659 15,469 22,941
--------- --------- ---------
Total cash and temporary cash investments at December 31.... $ 138,112 $ 65,035 $ 44,524
========= ========= =========
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for
Interest (net of amounts capitalized)............................ $ 121,924 $ 114,314 $ 109,602
Income taxes (net of refunds).................................... $ 92,380 $ 126,372 $ 108,742
Non-cash financing activities
Issuance of common stock under benefit plans..................... $ (240) $ 2,742 $ 25,570
Conversion of 7-1/4% Convertible Subordinated Debentures......... $ 88,467 $ 40 $ --
- --------------------------------------------------------------------------------------------------------
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
26
<PAGE> 29
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
For the Years Ended December 31, 1998 1997 1996
- ---------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
NET INCOME........................................... $238,766 $304,380 $298,273
OTHER COMPREHENSIVE INCOME, NET OF TAX
Pension liability adjustment.................. 60 (309) 116
Foreign currency translation adjustment....... (1,112) (4,166) --
-------- -------- --------
COMPREHENSIVE INCOME................................ $237,714 $299,905 $298,389
======== ======== ========
- ---------------------------------------------------------------------------------------------
</TABLE>
The Notes to Consolidated Financial Statements are an integral part of this
statement.
27
<PAGE> 30
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Methods of allocating costs to accounting periods by the subsidiaries 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 (collectively, 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 Company follows the equity method of accounting for investments in
partnerships and corporate joint ventures when the Company is able to influence
the financial and operating policies of the investee. For all other investments,
the cost method is applied.
SEGMENT INFORMATION
In 1998, the Company adopted the provisions of SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." SFAS No. 131 supersedes SFAS
No. 14, "Financial Reporting for Segments of a Business Enterprise," and
replaces an "industry segment" disclosure approach with a "management" approach.
SFAS No. 131 requires the internal organization used by management for making
operating decisions and assessing performance to be the basis of the Company's
reportable segments.
REVENUE RECOGNITION
Revenues from sales and transportation services are recognized in the same
period in which the related volumes are delivered to customers. The Company
bills and recognizes 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 to the end of the period.
UNRECOVERED GAS COSTS
Where permitted by regulatory authorities, the Company defers 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.
PRICE RISK MANAGEMENT ACTIVITIES
In the normal course of business, the Company utilizes derivative financial
instruments and derivative commodity 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. These derivatives include exchange-traded
futures and options contracts, which permit settlement by physical delivery of
the commodity, and over-the-counter (OTC) commodity price swap agreements and
options, which require settlement in cash.
28
<PAGE> 31
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
For derivatives 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 revenues or expense, in the same
period the hedged transaction occurs.
Under the OTC price swap agreements, the Company makes payments to, or
receives payments from, counterparties generally based on the difference between
fixed and variable gas and oil prices or on prices at different receipt points
as specified in the contracts. Settlement takes place under the swap agreements
on a monthly basis for the portion of the swap that has expired, and amounts
received or paid are recognized as an adjustment to gas and oil sales revenues,
purchased gas expense or transport capacity costs in the applicable settlement
month.
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. Maintenance, repairs and related costs are
charged principally to expense as incurred.
EXPLORATION AND PRODUCTION PROPERTIES
The Company follows the full cost method of accounting for gas and oil producing
activities prescribed by the 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 limitation test is performed
separately for each cost center, with cost centers established on a
country-by-country basis.
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.
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.
29
<PAGE> 32
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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: 1998--5-1/2% to 7-1/8%; 1997--5-5/8% to
7-5/8% and 1996--5-1/2% to 8-1/8%. Equity funds capitalized in those years were
not significant.
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.
PENSION AND OTHER BENEFIT PROGRAMS
The Company has qualified noncontributory defined benefit pension plans covering
substantially 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 and the payment of benefits to certain retired
executives under company-sponsored nonqualified employee benefit plans. Certain
of these nonqualified plans are funded through contributions to a grantor trust.
The Company also sponsors defined benefit postretirement plans, covering
both salaried and hourly employees and certain dependents, that provide medical
and life insurance coverage benefits. 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 and cost-sharing
features are adjusted annually.
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 considered probable.
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. DISCONTINUED OPERATIONS
During April 1998, management approved a plan to discontinue the Company's
wholesale trading and marketing of natural gas and electricity, including
integrated energy management. On July 31, 1998, the
30
<PAGE> 33
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
sale of the capital stock of CNG Energy Services Corporation, formerly a
wholly-owned subsidiary of the Company, to Sempra Energy Trading, a subsidiary
of Sempra Energy, was finalized. Included in the transaction were contracts for
the purchase and sale of natural gas as well as rights to natural gas pipeline
and storage capacity, mainly in the Northeast and Mid-Atlantic regions, and
related working capital. Proceeds of $37.4 million were received from the sale
of the stock, as adjusted for working capital items. The Company's transition
out of the wholesale gas business was substantially complete at December 31,
1998. The remaining net liabilities associated with discontinued operations at
December 31, 1998 were not material.
The results of operations of these activities for the years ended December
31, 1998, 1997 and 1996 are classified as "Discontinued Operations" in the
Consolidated Statement of Income. Cash flows in connection with operating and
investing activities for discontinued operations are reported separately in the
Consolidated Statement of Cash Flows. There were no cash flows provided by, or
used in, financing activities related to discontinued operations for the years
ended December 31, 1998, 1997 or 1996.
Summarized results of operations of the discontinued operations are as
follows:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
Years Ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Total operating revenues.................... $ 792,586 $ 2,532,910 $ 838,851
Operating expenses.......................... (818,105) (2,554,386) (852,924)
--------- ---------- ---------
Operating loss before income taxes....... (25,519) (21,476) (14,073)
Income tax benefit.......................... 9,011 9,216 6,485
Other income................................ 80 1,074 329
Interest charges............................ (810) (3,342) (3,850)
--------- ----------- ---------
Loss from discontinued operations........... $ (17,238) $ (14,528) $ (11,109)
========= =========== =========
Loss from disposal before income taxes...... $ (48,263) $ -- $ --
Income tax benefit.......................... 16,556 -- --
-------- ----------- ---------
Net loss from disposal...................... $ (31,707) $ -- $ --
========= =========== =========
- -----------------------------------------------------------------------------------------
</TABLE>
3. EARNINGS PER SHARE
In 1997, the Company adopted the provisions of SFAS No. 128, "Earnings per
Share," and restated earnings per share (EPS) amounts for all prior annual and
quarterly periods presented. The adoption of SFAS No. 128 did not have a
material effect on the Company's EPS for any of the periods presented.
A reconciliation of the income from continuing operations and common stock
share amounts used in the calculation of basic and diluted EPS for each of the
years ended December 31, 1998, 1997 and 1996 follows (income and share amounts
in thousands):
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------
Income From
Continuing Per Share
Operations Shares Amount
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
For the year ended December 31, 1998
BASIC EPS.............................................................. $287,711 94,836 $ 3.03
======== ====== ======
Effect of dilutive securities:
Exercise of stock options........................................... 511
Vesting of performance shares....................................... 374
Conversion of 7-1/4% Convertible Subordinated Debentures............ 1,578 614
-------- ---
DILUTED EPS............................................................ $289,289 96,335 $ 3.00
======== ====== ======
- -----------------------------------------------------------------------------------------------------------
</TABLE>
31
<PAGE> 34
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------
Income From
Continuing Per Share
Operations Shares Amount
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
For the year ended December 31, 1997
BASIC EPS.............................................................. $318,908 94,868 $3.36
======== ====== =====
Effect of dilutive securities:
Exercise of stock options........................................... 674
Vesting of performance shares....................................... 359
Conversion of 7-1/4% Convertible Subordinated Debentures............ 12,128 4,559
-------- -------
DILUTED EPS............................................................ $331,036 100,460 $3.30
======== ======= =====
- ---------------------------------------------------------------------------------------------------------------
For the year ended December 31, 1996
BASIC EPS.............................................................. $309,382 94,076 $3.29
======== ====== =====
Effect of dilutive securities:
Exercise of stock options........................................... 482
Vesting of performance shares....................................... 98
Conversion of 7-1/4% Convertible Subordinated Debentures............ 11,823 4,559
-------- ------
DILUTED EPS............................................................ $321,205 99,215 $3.24
======== ====== =====
- ---------------------------------------------------------------------------------------------------------------
</TABLE>
Performance shares are considered contingent shares as defined by SFAS No.
128. Although such shares are issued and outstanding, they are excluded from the
calculation of basic earnings per share.
4. RATE MATTERS
The Company accounts for its regulated operations in accordance with SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation." When the
accounting allocations prescribed by regulatory authorities are used for
ratemaking, the allocation of costs among accounting periods by the Company's
regulated subsidiaries resulted in the recognition of regulatory assets and
liabilities at December 31, 1998 and 1997 as follows:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------
December 31, 1998 1997
- ---------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Regulatory assets:
Unrecovered gas costs (Note 1)............................ $ 34,860 $ 55,062
Order 636 transition costs................................ 6,461 17,020
Workforce reduction costs (Note 6)........................ 9,275 8,832
Other postretirement benefits (Note 7).................... 52,142 55,070
Deferred income taxes (Note 8)............................ 102,797 103,323
Environmental-related expenditures (Note 16).............. 7,291 7,322
Other 11,642 19,215
-------- --------
Total regulatory assets................................. $224,468 $265,844
======== ========
Regulatory liabilities:
Amounts payable to customers (Note 1)..................... $48,339 $ 880
Estimated rate contingencies and refunds.................. 78,266 29,112
Income taxes refundable to customers-net (Note 8)......... 27,170 55,035
-------- --------
Total regulatory liabilities............................ $153,775 $ 85,027
======== ========
- ---------------------------------------------------------------------------------------
</TABLE>
32
<PAGE> 35
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company assesses on an ongoing basis the recoverability of costs
recognized as regulatory assets and its ability to continue to apply SFAS No. 71
to its regulated operations. In the event that all or a portion of these
operations ceased to meet the requirements of SFAS No. 71, the Company would be
required to assess the carrying value of certain assets and liabilities
previously subject to regulation.
ESTIMATED RATE CONTINGENCIES AND REFUNDS
Certain increases in prices by the Company and other rate-making issues are
subject to final modification in regulatory proceedings. The related accumulated
provisions pertaining to these matters were $59.9 million and $15.7 million at
December 31, 1998 and 1997, including interest. These amounts are reported in
the Consolidated Balance Sheet under "Estimated rate contingencies and refunds"
together with $18.4 million and $13.4 million, respectively, which are primarily
refunds received from suppliers and refundable to customers under regulatory
procedures.
ORDER 636 TRANSITION COSTS
The distribution subsidiaries have incurred obligations to upstream pipeline
companies for costs resulting from the pipeline companies' transition to
restructured services under FERC Order 636. The total estimated liability for
such costs was $6.5 million and $17.0 million at December 31, 1998 and 1997,
respectively. Additional amounts, if any, to be accrued in the future are not
expected to be material. These transition costs are being passed through to
customers of the Company's distribution subsidiaries.
5. PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
IMPAIRMENT OF GAS AND OIL PRODUCING PROPERTIES
As described in Note 1, the Company follows the full cost method of accounting
for gas and oil producing activities. Under these rules, the Company recognized
an impairment of its Canadian oil producing properties at December 31, 1997, due
primarily to the decline in market prices for heavy oil production. This
non-cash charge amounted to $10.4 million and reduced 1997 net income by $6.7
million, or $.07 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 $.89 per Mcf
equivalent of gas and oil produced in 1998, $.88 in 1997 and $.93 in 1996.
Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 1998, and the
years in which such excluded costs were incurred, follow:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------
DECEMBER 31, Incurred in Years Ended December 31,
-------------------------------------
1998 1998 1997 1996 Prior
- --------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C>
Property acquisition costs... $ 59,315 $20,874 $31,164 $4,181 $3,096
Exploration costs............ 48,679 23,469 18,121 2,316 4,773
Capitalized interest......... 9,995 1,604 5,363 1,181 1,847
--------- ------- ------- ------ ------
Total................... $ 117,989 $45,947 $54,648 $7,678 $9,716
========= ======= ======= ====== ======
- --------------------------------------------------------------------------------------
</TABLE>
There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 1998. 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.
33
<PAGE> 36
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
6. WORKFORCE REDUCTION COSTS
During the fourth quarter of 1998, the Company recorded a provision for
severance and other employee-related costs in connection with actions to improve
efficiencies and reorganize business processes at both its corporate and
regulated subsidiaries. The Company anticipates that these actions will be
substantially completed during 1999.
During 1996, unions at two subsidiaries implemented a workforce reduction
program that consisted of a voluntary early retirement program and a voluntary
separation program. A voluntary early retirement program for West Ohio Gas (now
a division of East Ohio Gas) was also offered during 1996. In conjunction with
these programs, 119 eligible employees elected to accept early retirement offers
and an additional 57 were separated from the Company. In addition, during the
fourth quarter of 1996 the Company recorded a provision for severance and
related benefits to be paid to affected employees in connection with the
Company's efforts to combine and streamline certain business functions.
As a result of its workforce reduction programs, the Company recorded
charges in 1998 and 1996 amounting to $9.4 million and $15.2 million,
respectively. These charges reduced 1998 and 1996 net income by $6.1 million, or
$.06 per share, and $9.9 million, or $.10 per share, respectively. In addition,
certain of the regulated subsidiaries have deferred, as a regulatory asset, a
portion of workforce reduction costs from previous years' programs pending
recovery in rates. The balance of these deferrals was $9.3 million at December
31, 1998.
7. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS
The following table provides reconciliations of the changes in the Company's
pension and other postretirement benefit plan obligations and asset fair values
for each of the years ended December 31, 1998 and 1997, and a statement of the
funded status as of December 31, 1998 and 1997:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Pension Other Postretirement
Benefit Plans Benefit Plans
-------------------- --------------------
Years Ended December 31, 1998 1997 1998 1997
- ----------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
Change in benefit obligation:
Benefit obligation--January 1.............. $1,037,728 $ 959,951 $358,748 $378,435
Service cost.............................. 24,852 21,374 10,021 9,901
Interest cost............................. 69,320 68,635 23,714 25,854
Participant contributions................. -- -- 3,027 3,000
Plan amendments........................... -- -- (569) (6,723)
Actuarial (gain) loss..................... 60,981 55,378 (11,331) (29,342)
Curtailment (gain)........................ (1,658) -- (130) --
Benefit payments.......................... (67,539) (67,610) (21,407) (22,377)
---------- --------- -------- --------
Benefit obligation--December 31............ $1,123,684 $1,037,728 $362,073 $358,748
========== ========== ======== ========
Change in plan assets:
Fair value of plan assets--January 1....... $1,804,852 $1,539,039 $ 79,740 $ 53,153
Actual return on plan assets.............. 328,928 330,296 5,207 2,972
Employer contributions.................... 2,911 3,127 45,326 42,992
Participant contributions................. -- -- 3,027 3,000
Benefit payments.......................... (67,539) (67,610) (21,407) (22,377)
---------- --------- -------- --------
Fair value of plan assets--December 31..... $2,069,152 $1,804,852 $111,893 $ 79,740
========== ========== ======== ========
- ----------------------------------------------------------------------------------------------------
</TABLE>
34
<PAGE> 37
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------
Pension Other Postretirement
Benefit Plans Benefit Plans
----------------- --------------------
December 31, 1998 1997 1998 1997
- --------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
FUNDED STATUS:
Funded status--December 31 ................... $945,468 $767,124 $(250,180) $(279,008)
Unrecognized net obligation (asset) .......... (33,195) (40,237) 158,231 170,102
Unrecognized (gain) loss-net ................. (774,732) (649,740) 11,711 24,253
Unrecognized prior service cost .............. 4,755 5,720 (5,562) (6,178)
-------- -------- --------- ---------
Net amount recognized ........................ $142,296 $ 82,867 $ (85,800) $ (90,831)
======== ======== ========= =========
- --------------------------------------------------------------------------------------------------------
</TABLE>
Amounts recognized in the Consolidated Balance Sheet at December 31
consist of the following:
<TABLE>
<S> <C> <C> <C> <C>
Prepaid benefit cost......................... $159,317 $97,527 $ -- $ --
Accrued benefit liability...................... (28,536) (27,607) (85,800) (90,831)
Intangible asset............................... 9,006 10,346 -- --
Accumulated other comprehensive income......... 2,509 2,601 -- --
-------- -------- -------- --------
Net amount recognized.......................... $142,296 $ 82,867 $(85,800) $(90,831)
======== ======== ======== ========
- --------------------------------------------------------------------------------------------------------
</TABLE>
The Company has nonqualified pension and supplemental pension plans which
do not have "plan assets" as defined by generally accepted accounting
principles. The total projected benefit obligation for these plans was $33.3
million and $32.3 million at December 31, 1998 and 1997, respectively, and is
included in the table above. The minimum liability recognized relating to these
plans was $11.5 million and $12.9 million at December 31, 1998 and 1997. The
related intangible asset recognized as of those dates amounted to $9.0 million
and $10.3 million, respectively. Adjustments of the minimum liability and
intangible asset due to changes in assumptions or the financial status of these
plans resulted in a credit (charge) to other comprehensive income of $.1
million, $(.3) million and $.1 million for the years ended December 31, 1998,
1997 and 1996, respectively.
The majority of estimated other postretirement benefit costs (SFAS No. 106
costs) and related transition obligation is attributable to the rate-regulated
subsidiaries. Pending the expected recovery of SFAS No. 106 costs and related
deferrals in regulatory proceedings, these subsidiaries have deferred the
differences between SFAS No. 106 costs and amounts included in rates. The
rate-regulated subsidiaries have obtained approval for recovery in rates from
their respective regulatory commissions for the increased level of expense
resulting from SFAS No. 106. The amount of SFAS No. 106 costs deferred at
December 31, 1998 and 1997, was $52.1 million and $55.1 million, respectively.
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, four subsidiaries fund postretirement
benefit costs via voluntary employees' beneficiary associations (VEBAs). 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.
35
<PAGE> 38
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Weighted average assumptions used in the determination of the benefit
obligations include the following:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------
Other
Pension Postretirement
Benefit Plans Benefit Plans
------------- --------------
December 31, 1998 1997 1998 1997
- -------------------------------------------------------------------
<S> <C> <C> <C> <C>
Discount rate..................... 6.5% 7.0% 6.5% 7.0%
Expected return on plan assets.... 9.0% 9.0% 6.5% 6.5%
Rate of compensation increase..... 5.5% 5.5% 5.5% 5.5%
- -------------------------------------------------------------------
</TABLE>
Net periodic benefit costs, as determined by independent actuaries,
included the following components:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Other Postretirement
Pension Benefit Plans Benefit Plans
------------------------------ --------------------------------
Years Ended December 31, 1998 1997 1996 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C>
Service cost............................ $ 24,852 $ 21,374 $ 23,741 $10,021 $9,901 $11,940
Interest cost........................... 69,320 68,635 67,426 23,714 25,854 26,450
Expected return on assets............... (131,640) (118,671) (108,753) (4,413) (2,859) (645)
Prior service cost amortization......... 965 1,125 1,128 (406) (408) (406)
Actuarial (gain) loss................... (11,315) (10,402) (3,545) 206 271 2,689
Transition obligation amortization...... (7,042) (7,929) (7,789) 11,302 11,418 11,801
Curtailment and special
termination benefits................. (1,658) -- 3,644 (215) -- 1,292
Special voluntary retirement
programs............................. 800 800 800 -- -- --
-------- -------- -------- ------- ------ -------
Net periodic benefit cost (credit)...... $(55,718) $(45,068) $(23,348) $40,209 $44,177 $53,121
======== ======== ======== ======= ======= =======
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
For measurement purposes, a 6.5% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 1999. The rate was assumed
to decrease gradually to 4% for 2003 and remain at that level thereafter.
Assumed health care cost trend rates have a significant effect on the
amounts reported for the postretirement health care plans. A 1% change in the
assumed health care cost trend rate would have the following effects on 1998
service and interest cost and the accumulated postretirement benefit obligation
at December 31, 1998:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
1% Increase 1% Decrease
(In Thousands)
<S> <C> <C>
Effect on aggregate service and interest cost components of net
periodic cost................................................................. $ 4,014 $ (3,587)
Effect on the health care component of the accumulated postretirement
benefit obligation............................................................ $28,564 $(25,247)
- -------------------------------------------------------------------------------------------------------------
</TABLE>
36
<PAGE> 39
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. INCOME TAXES
"Income taxes" in the Consolidated Statement of Income include the following:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------
Years Ended December 31, 1998 1997 1996
- -------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Income tax expense attributable to continuing operations:
Current provision
Federal.................................................... $96,295 $136,095 $88,447
State...................................................... 17,624 18,181 13,904
Deferred income taxes-net
Federal.................................................... 21,390 4,175 59,619
State...................................................... (3,489) 11 2,546
Investment tax credit........................................ (2,171) (2,193) (2,201)
-------- -------- --------
Income tax expense attributable to continuing operations........ 129,649 156,269 162,315
Income tax benefit attributable to discontinued operations...... (25,567) (9,216) (6,485)
-------- -------- --------
Total...................................................... $104,082 $147,053 $155,830
======== ======== ========
- -------------------------------------------------------------------------------------------------------
</TABLE>
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
pretax income from continuing operations. The reasons for the differences
follow:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------
Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Income before taxes--continuing operations...................... $417,360 $475,177 $471,697
======== ======== ========
Computed "expected" tax expense--continuing operations........ $146,076 $166,312 $165,094
Increases (or reductions) in tax resulting from:
Production tax credit....................................... (11,351) (10,359) (9,344)
Investment tax credit....................................... (2,171) (2,193) (2,201)
State income taxes.......................................... 9,188 11,825 10,693
Miscellaneous............................................... (12,093) (9,316) (1,927)
--------- --------- ---------
Income taxes attributable to continuing operations............. $129,649 $156,269 $162,315
======== ======== ========
Effective tax rate.......................................... 31.1% 32.9% 34.4%
- --------------------------------------------------------------------------------------------------------
</TABLE>
37
<PAGE> 40
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The current and noncurrent deferred income taxes reported in the
Consolidated Balance Sheet at December 31, 1998 and 1997 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>
- ------------------------------------------------------------------------------------------------------------------
1998 1997
----------------------------- ------------------------------
Deferred Deferred Income Deferred Deferred Income
December 31, Income Taxes Taxes-Current Income Taxes Taxes-Current
- ------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
Deferred tax liabilities:
Excess of tax over book depreciation.......... $ 559,430 $ -- $ 537,684 $ --
Exploration and intangible well drilling
costs...................................... 244,832 -- 225,111 --
Unrecovered gas costs......................... -- 15,908 -- 19,424
Net pension credits........................... 78,212 -- 52,420 --
Other 36,145 -- 25,721 --
--------- ---------- --------- ---------
Total liabilities........................... 918,619 15,908 840,936 19,424
--------- ---------- --------- ---------
Deferred tax assets:
Tax basis step-up in connection with
acquisition of subsidiary.................. 18,096 -- 18,619 --
Deferred investment tax credits............... 14,443 -- 15,854 --
Overheads capitalized for tax purposes........ 11,138 -- 8,226 --
Supplier and other refunds.................... -- 18,503 -- 187
Other 94,014 19,191 86,119 5,502
Valuation allowance........................... -- -- -- --
--------- ---------- --------- ---------
Total assets................................ 137,691 37,694 128,818 5,689
--------- ---------- --------- ---------
Total deferred tax liability (asset)........ $ 780,928 $ (21,786) $ 712,118 $ 13,735
========= ========== ========= =========
- ------------------------------------------------------------------------------------------------------------------
</TABLE>
A regulatory liability amounting to $27.2 million has been recorded at
December 31, 1998 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 $102.8 million has been recorded at December 31, 1998.
9. GAS STORED
The distribution subsidiaries, except Virginia Natural Gas, value their stored
gas inventory under the LIFO method. Based upon the average price of gas
purchased during 1998, the current cost of replacing the inventory of "Gas
stored--current portion" exceeded the amount stated on a LIFO basis by
approximately $171.3 million at December 31, 1998. Virginia Natural Gas and CNG
Retail value their stored gas inventory under the weighted average cost method.
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
amount of $126.4 million at December 31, 1998 and 1997.
38
<PAGE> 41
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
10. COMMON STOCKHOLDERS' EQUITY
A summary of the changes in stockholders' equity follows:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------
Common Stock Capital in Excess
Issued of Par Value Treasury
----------------- ------------------------ Stock
Number Value Retained Unearned Number
of Shares at Par Paid-In Other Total Earnings Compensation of Shares Cost
- ----------------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1995 93,592 $ 257,377 $ 438,255 $ 40,280 $ 478,535 $1,309,906 $ -- -- $ --
Net income.................. -- -- -- -- -- 298,273 -- -- --
Cash dividends declared
Common stock ($1.94 per
share).................. -- -- -- -- -- (183,671) -- -- --
Common stock issued
Stock options............. 769 2,113 29,662 -- 29,662 -- -- -- --
Performance shares-net.... 378 1,040 16,336 -- 16,336 -- (17,376) -- --
Stock awards-net.......... 98 270 4,404 -- 4,404 -- (4,560) -- --
DRP*...................... 97 268 4,688 -- 4,688 -- -- -- --
Amortization and adjustment -- -- 3,520 -- 3,520 -- 4,394 -- --
Purchase of treasury stock.. -- -- -- -- -- -- -- (147) (8,144)
Sale of treasury stock and
other..................... -- -- (143) -- (143) -- -- 147 8,144
Pension liability adjustment
(Note 7)..................
-- -- -- -- -- 116 -- -- --
------ --------- --------- -------- --------- ---------- ---------- ------ --------
Balance at December 31, 1996 94,934 261,068 496,722 40,280 537,002 1,424,624 (17,542) -- --
Net income.................. -- -- -- -- -- 304,380 -- -- --
Cash dividends declared
Common stock ($1.94 per
share).................. -- -- -- -- -- (184,942) -- -- --
Common stock issued
Stock options............. 612 1,683 23,615 -- 23,615 -- -- -- --
DRP*...................... 62 171 3,244 -- 3,244 -- -- -- --
Stock awards-net.......... 25 69 1,318 -- 1,318 -- (1,350) -- --
Conversion of debentures.. 1 2 38 -- 38 -- -- -- --
Performance shares-net.... (11) (29) (106) -- (106) -- 135 -- --
Amortization and adjustment -- -- 1,490 -- 1,490 -- 7,807 -- --
Purchase of treasury stock.. -- -- -- -- -- -- -- (220) (12,286)
Sale of treasury stock and
other....................... -- -- 154 -- 154 -- -- 219 12,248
Pension liability adjustment
(Note 7).................. -- -- -- -- -- (309) -- -- --
Cumulative translation
adjustment................
-- -- -- -- -- (4,166) -- -- --
------ --------- --------- -------- --------- ---------- ---------- ------ --------
Balance at December 31, 1997 95,623 262,964 526,475 40,280 566,755 1,539,587 (10,950) (1) (38)
Net income.................. -- -- -- -- -- 238,766 -- -- --
Cash dividends declared
Common stock ($1.94 per
share).................. -- -- -- -- -- (185,758) -- -- --
Common stock issued
Stock options............. 282 777 11,548 -- 11,548 -- -- -- --
Stock awards-net.......... 32 86 1,364 -- 1,364 -- (1,283) -- --
Performance shares-net.... 8 21 402 -- 402 -- (423) -- --
Amortization and adjustment -- -- (2,393) -- (2,393) -- 11,321 -- --
Purchase of treasury stock.. -- -- -- -- -- -- -- (5,081) (280,326)
Sale of treasury stock and -- -- (3,863) -- (3,863) -- (61) 2,949 163,290
other.......................
Conversion of debentures.... -- -- (1,841) -- (1,841) -- -- 1,638 90,715
Pension liability adjustment
(Note 7).................. -- -- -- -- -- 60 -- -- --
Cumulative translation
adjustment................
-- -- -- -- -- (1,112) -- -- --
------ --------- --------- -------- --------- ---------- ---------- ------ --------
Balance at December 31, 1998 95,945 $ 263,848 $ 531,692 $ 40,280 $ 571,972 $1,591,543 $ (1,396) (495) $(26,359)
====== ========= ========= ======== ========= ========== ========== ====== ========
- ----------------------------------------------------------------------------------------------------------------------------
</TABLE>
*Dividend Reinvestment Plan.
39
<PAGE> 42
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
SHAREHOLDER RIGHTS PLAN
During 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. 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, 1998, 304,055,449 shares of common stock were unissued. Shares
have been registered with the SEC for possible issuance under various benefit
plans or to shareholders under the Dividend Reinvestment Plan. Shares acquired
pursuant to these plans can consist of original issue shares, treasury shares or
shares purchased in the open market. In addition, at December 31, 1998, the
Company has a shelf registration with the SEC which would allow it to sell up to
an additional $338.3 million of debt or equity securities.
TREASURY STOCK
Under a plan approved by the Board of Directors, the Company can purchase in the
open market up to 10,000,000 shares of its common stock. The Company may also
acquire shares of its common stock through certain provisions of the Company's
various stock incentive plans. 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." At December 31, 1998
and 1997, a total of 495,123 and 659 shares, respectively, were being held as
treasury stock.
PRE-1997 STOCK AWARD AND OPTION PLANS
Prior to 1997, stock awards, stock options and other stock-based awards were
granted to employees under the Long-Term Incentive Plan, the 1991 Stock
Incentive Plan (1991 Plan) and the 1995 Employee Stock Incentive Plan (1995
Plan). The Long-Term Incentive Plan terminated by its terms on November 9, 1991.
In addition, there were no shares authorized for issuance under either the 1991
Plan or the 1995 Plan at December 31, 1998. However, the provisions of these
plans continue with respect to stock awards granted whose restrictions have not
yet lapsed and stock options granted which have not been exercised at December
31, 1998.
1997 STOCK INCENTIVE PLAN
The 1997 Stock Incentive Plan (1997 Plan) provides for the granting of stock
awards, stock options and other stock-based awards to employees and directors of
the Company effective January 1, 1997, including grants made on or after that
date pursuant to the Long-Term Strategic Incentive Program described below. The
maximum number of shares authorized for issuance in each calendar year is
determined in accordance with a formula contained in the 1997 Plan. At December
31, 1998, 6,235,017 shares were authorized for issuance under the 1997 Plan.
40
<PAGE> 43
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Stock awards granted under the plan may be in the form of restricted stock
or deferred stock. Shares issued as restricted stock awards are held by the
Company until the attached restrictions lapse. Deferred stock awards generally
consist of a right to receive shares at the end of specified deferral periods.
The market value of the stock award on the date granted is recorded as
compensation expense over the applicable restriction or deferral period.
Stock options granted under the plan allow the purchase of common shares at
a price not less than fair market value at the date of grant and not less than
par value. These options, other than tri-annual options granted under the
Long-Term Strategic Incentive Program, 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.
The granting of stock awards constitutes a non-cash financing activity of
the Company.
LONG-TERM STRATEGIC INCENTIVE PROGRAM
Grants under the Long-Term Strategic Incentive Program, consisting of
performance restricted stock awards (performance shares or performance stock
credits) and stock options, are expected to be made every three years, with the
first such grants made on January 2, 1996.
Performance shares will vest contingent upon attainment of certain
strategic business results over a three-year period. The market value of the
performance shares on the grant date, as adjusted quarterly for changes in the
current market price of the Company's common stock, is recorded as compensation
expense over the three-year vesting period.
Stock options granted under this program (tri-annual options) vest after
three years and will be exercisable from the vesting date until ten years from
the grant date if certain strategic business results are attained during the
vesting period. However, the exercise period will be reduced to one day for all
or a portion of the options granted if such results are not achieved. As the
number of options are known and the option price equals the market price at the
grant date, no compensation expense is recognized for these options under
generally accepted accounting principles.
ACCOUNTING FOR STOCK AWARDS AND STOCK OPTIONS
As permitted by generally accepted accounting principles, the Company follows
Accounting Principles Board Opinion No. 25 and related interpretations (APB No.
25) for accounting for stock-based compensation. The Company granted stock
awards, including performance shares, totaling 54,000 shares in 1998, 98,000
shares in 1997, and 507,000 shares in 1996 with weighted average market prices
per share on award dates of $49.54, $52.53 and $46.19, respectively. The Company
recorded compensation expense of $9.4 million, $9.7 million and $8.7 million for
the years ended December 31, 1998, 1997 and 1996, respectively, in connection
with its performance shares, restricted stock and other stock compensation
awards. In accordance with APB No. 25, no compensation expense has been
recognized for the Company's stock options.
In addition, performance stock credits equal to 475,400 shares of common
stock were granted January 4, 1999, related to the 1999-2001 performance period.
41
<PAGE> 44
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
A summary of stock option activity for the years ended December 31, 1996
through 1998, follows:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------
Weighted Average
Number Option Price
of Shares Per Share
- ----------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Shares under option:
At January 1, 1996.......... 2,948 $41.25
Granted (1)................. 3,534 $45.53
Exercised .................. (769) $41.37
Cancelled (1)............... (196) $43.13
----- ------
At December 31, 1996........ 5,517 $43.90
Granted (2)................. 885 $54.09
Exercised .................. (612) $41.33
Cancelled (2)............... (583) $45.74
----- ------
At December 31, 1997........ 5,207 $45.73
Granted (3)................. 914 $58.34
Exercised .................. (309) $41.73
Cancelled (3)............... (307) $51.32
----- ------
At December 31, 1998........ 5,505 $47.73
===== ======
</TABLE>
(1) Includes 3,006,000 tri-annual options granted and 65,000 tri-annual options
cancelled.
(2) Includes 332,084 tri-annual options granted and 367,883 tri-annual options
cancelled.
(3) Includes 106,750 tri-annual options granted and 96,114 tri-annual options
cancelled.
Options were exercisable for the purchase of 734,741 shares, 599,534 shares and
673,305 shares at December 31, 1998, 1997 and 1996, respectively. Effective
January 4, 1999, additional options for the purchase of 3,662,000 shares were
granted to eligible employees.
- --------------------------------------------------------------------------------
The following table summarizes information about stock options outstanding
at December 31, 1998.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------
Options Outstanding Options Exercisable
--------------------------------------------- ---------------------------
Weighted Average Weighted Weighted
Number Remaining Average Number Average
Range of Exercise Prices Outstanding Contractual Life Exercise Price Exercisable Exercise Price
- ------------------------------------------------------------------------------------------------------
(In Thousands) (In Thousands)
<S> <C> <C> <C> <C> <C>
$34.75--$40.00 549 5.48 YRS. $37.06 230 $36.69
$40.01--$50.00 3,088 6.58 YRS. $44.97 440 $44.93
$50.01--$59.94 1,868 7.69 YRS. $56.00 65 $50.87
- ------------------------------------------------------------------------------------------------------
</TABLE>
42
<PAGE> 45
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents the weighted-average fair value of stock
options granted during 1996 through 1998 and the weighted-average assumptions
used to compute fair values under the Black-Scholes option-pricing model:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------
Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------
<S> <C> <C> <C>
Option fair value...................... $10.49 $ 8.96 $ 5.84
Assumptions
Dividend yield.................... 3.3% 3.6% 4.3%
Expected volatility............... 19.8% 16.8% 17.5%
Risk-free interest rate........... 5.7% 6.4% 5.4%
Expected option life (years)...... 4.8 4.8 4.9
- --------------------------------------------------------------------
</TABLE>
If compensation expense for the Company's stock options granted during
1996 through 1998 had been determined based on the fair value at the grant dates
for such awards, the effect on the Company's net income and EPS for each of the
years would have been as follows:
<TABLE>
<CAPTION>
- ----------------------------------------------------------
Years Ended December 31, 1998 1997 1996
- ----------------------------------------------------------
<S> <C> <C> <C>
NET INCOME (In Millions):
As reported............. $238.8 $304.4 $298.3
Pro forma............... $231.7 $298.8 $294.1
BASIC EPS:
As reported............. $2.52 $3.21 $3.17
Pro forma............... $2.44 $3.15 $3.13
DILUTED EPS:
As reported............. $2.49 $3.15 $3.13
Pro forma............... $2.42 $3.10 $3.08
- ----------------------------------------------------------
</TABLE>
11. PREFERRED STOCK
The Company's authorized preferred stock consists of 5,000,000 shares at a par
value of $100 each. There were no shares of preferred stock issued or
outstanding at December 31, 1998 or 1997.
12. DIVIDEND RESTRICTIONS
One of the Company's indentures relating to senior debenture issues contains
restrictions on dividend payments by the Company and acquisitions of its capital
stock. Under the indenture provisions, $493.1 million of consolidated retained
earnings was free from such restrictions at December 31, 1998. The indenture
also imposes dividend limitations on the subsidiaries, but at December 31, 1998,
these limitations did not restrict their ability to pay dividends to the
Company.
43
<PAGE> 46
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
13. LONG-TERM DEBT
Long-term debt, excluding current maturities, follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------
December 31, 1998 1997
- -------------------------------------------------------------------------------------
(In Thousands)
Debentures
<S> <C> <C>
6%, Due October 15, 2010..................... $200,000 $ --
6.8%, Due December 15, 2027.................... 300,000 300,000
6-5/8%, Due December 1, 2008..................... 150,000 150,000
6-7/8%, Due October 15, 2026..................... 150,000 150,000
7-3/8%, Due April 1, 2005........................ 150,000 150,000
6-5/8%, Due December 1, 2013..................... 150,000 150,000
5-3/4%, Due August 1, 2003....................... 150,000 150,000
8-3/4%, Due October 1, 2019...................... 142,875 150,000
8-3/4%, Due June 1, 1999......................... -- 100,000
8-5/8%, Due December 1, 2011..................... -- 15,625
Unamortized debt discount, less premium.......... (13,146) (11,319)
Convertible Subordinated Debentures
7-1/4%, Due December 15, 2015.................... -- 246,165
Unamortized debt discount........................ -- (1,581)
9.94% Unsecured loan due January 1, 1999.............. -- 4,000
---------- ----------
Total....................................... $1,379,729 $1,552,890
========== ==========
- -------------------------------------------------------------------------------------
</TABLE>
Discounts and premiums and the expenses incurred in connection with the
issuance of debentures are being amortized on a basis which will equitably
distribute the amount to "Interest on long-term debt" over the life of each
debenture issue.
The aggregate principal amounts of the Company's debentures maturing in the
years 1999 through 2003 are: $107.1 million; $7.1 million; $7.1 million; $7.1
million and $157.1 million.
In January 1998 the Company called for redemption the entire principal
amount outstanding of its 7-1/4% Convertible Subordinated Debentures, totaling
$246.2 million. These debentures were convertible into shares of the Company's
common stock at an initial conversion price of $54 per share. The redemption
price was 102.18% of the principal amount plus accrued interest payable on
February 23, 1998. In anticipation of the call, in January 1998 the Company
purchased approximately 4.6 million shares of its common stock in a private
transaction to satisfy the potential conversion obligation. The right to convert
expired on February 13, 1998, and approximately 1.6 million of the acquired
shares were issued on conversion. The remaining acquired shares were sold in two
underwritten offerings during February and March, 1998.
In March 1998, CNG International purchased a 33.3% ownership interest in
the Dampier-to-Bunbury Natural Gas Pipeline (DBNGP) in Western Australia from
the Western Australia Government. One of CNG International's partners in the
purchase was El Paso Energy Corporation (El Paso), which also holds a 33.3%
ownership interest. In connection with their investments in DBNGP, CNG
International and El Paso formed DBNGP Finance Company LLC (DBNGP Finance).
DBNGP Finance is owned 50% by CNG International and 50% by EPED Holding Company,
a wholly-owned subsidiary of El Paso. Subsequent to the formation of DBNGP
Finance, the equity ownership interests of CNG International and El Paso in
DBNGP were transferred to this entity.
In October 1998, DBNGP Finance borrowed $250.0 million under a Senior Term
Loan Facility (Term Loan). The Term Loan matures October 2, 2001, can be
extended in one-year increments to October 2, 2003, and bears interest at a
variable rate. Of the gross proceeds received by DBNGP Finance under the
44
<PAGE> 47
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Term Loan, $100.0 million was distributed to CNG International. In connection
with the Term Loan, CNG International entered into an Equity Contribution
Agreement with DBNGP Finance. CNG International is contractually obligated to
make equity contributions to DBNGP Finance equal to the Term Loan proceeds
distributed to CNG International, plus interest on such proceeds, in the event
that DBNGP Finance is unable to service this debt. The Company is contractually
obligated to cause CNG International to make such equity contributions.
14. SHORT-TERM BORROWINGS
The weighted average interest rate on the Company's commercial paper notes
outstanding at December 31, 1998 and 1997, was 5.22% and 6.21%, respectively.
The Company has a $775.0 million credit agreement with a group of banks.
Borrowings under this agreement are in the form of revolving credits and may, at
the option of the Company, be structured either as syndicated loans by a group
of participating banks or money market loans by individual 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. This agreement may be used for general corporate purposes,
including the support of commercial paper notes. This agreement is currently
scheduled to expire on June 25, 1999; however, the Company expects that the
agreement will be renewed or replaced by a comparable agreement. A facility fee
is charged under this agreement but is not considered significant. There were no
borrowings under this agreement at December 31, 1998.
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, 1998 and 1997:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------
1998 1997
-------------------- --------------------
Carrying Fair Carrying Fair
December 31, Amount Value Amount Value
- ---------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
Long-term debt.... $1,504,000 $1,584,633 $1,719,790 $1,789,577
- ---------------------------------------------------------------------------
</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.
Derivatives and Price Risk Management Activities
The Company's price risk management activities include exchange-traded futures
and options contracts, which can be settled through the purchase or delivery of
commodities, and OTC price swap agreements and options, which require settlement
in cash. These instruments are used to manage commodity price risk regarding the
production, purchase and sale of natural gas and oil and for stored gas
inventories.
FUTURES CONTRACTS
At December 31, 1998, the Company had natural gas futures contracts related to
gas purchase and sale commitments and gas storage inventory covering 66.8 Bcf of
gas on a net basis maturing through 2001. As 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 Company's net unrealized gain related to futures contracts was approximately
$16.4 million at December 31, 1998.
45
<PAGE> 48
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
SWAP AGREEMENTS
In addition to futures and options contracts, the Company enters into OTC price
swap agreements to manage its exposure to commodity price risk under existing
sales commitments. At December 31, 1998, the Company had swap agreements of
varying duration outstanding with several counterparties to exchange monthly
payments on net notional quantities of gas over the ensuing five years. Net
notional quantities at December 31, 1998 related to those swap agreements in
which the Company pays a fixed price in exchange for a variable price totaled
166.1 Bcf, while net notional quantities related to agreements in which the
Company pays a variable price in exchange for a fixed price totaled 125.2 Bcf.
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
Company's net unrealized loss related to swap agreements was approximately $10.1
million at December 31, 1998. Profits expected on anticipated sales related to
the hedged transactions should generally offset the estimated unrealized losses
on the swap agreements.
MARKET AND CREDIT RISK
Price risk management activities expose the Company to market risk. Market risk
represents the potential loss that can be caused by the change in market value
of a particular commitment. The Company has appropriate operating procedures in
place that are administered by experienced management to help ensure that proper
internal controls are maintained. In addition, the Company has established an
independent function at the Corporate level to monitor compliance with the price
risk management policies of all subsidiaries.
Price risk management activities also expose the Company to credit risk.
Credit risk represents the potential loss that the Company would incur as a
result of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The Company maintains credit policies with respect to
its counterparties that management believes minimize overall credit risk. Such
policies include the evaluation of a prospective counterparty's financial
condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated
with a single counterparty. The Company also monitors the financial condition of
existing counterparties on an ongoing basis. Considering the system of internal
controls in place and credit reserve levels at December 31, 1998, the Company
believes it unlikely that a material adverse effect on its financial position,
results of operations or cash flows would occur as a result of counterparty
nonperformance.
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 audits 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
46
<PAGE> 49
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
have been assessed. Pursuant to the Order and Agreement, CNG Transmission
continues to perform sampling, testing and analysis, and conducts 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. The Company has recognized an estimated liability amounting to
$10.0 million at December 31, 1998, 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 has been
recognized amounting to $7.3 million at December 31, 1998. Also, uncontested
claims amounting to $1.5 million at December 31, 1998, 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, 1998 1997 1996
- --------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Recurring costs for ongoing operations.................. $2,595 $3,430 $4,174
Mandated remediation and other compliance costs......... 3,538 1,473 (419)
Voluntary remediation costs............................. 11 228 2,705
Other................................................... 195 14 3
------ ------ ------
Total.............................................. $6,339 $5,145 $6,463
====== ====== ======
- --------------------------------------------------------------------------------------
</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 at
some compressor stations to reduce nitrogen oxide emissions and to acquire Title
V permits for major facilities. Progress is on schedule for these permits, with
no major expenditures anticipated.
The 1990 amendments will also require installation of Maximum Available
Control Technology (MACT) to control the emissions of certain hazardous air
pollutants from compressor engines. The Company cannot estimate what its
expenditures for MACT-related controls will be. However, the mandated controls
will not affect a large number of its compressor engines and the related costs
are not expected to be material.
Additionally, the Company may be required, under an Environmental
Protection Agency nitrogen oxide state implementation program call, to include
additional compressor engines in the control mandates for the 1990 Amendments.
The estimated costs of such federal and/or state imposed hardware additions are
not expected to be material.
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.
47
<PAGE> 50
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Estimates of liability in the environmental area are based on current
environmental laws 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 Company 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 1996 through 1998 was not material, and future rental payments required
under leases in effect at December 31, 1998, are not material.
It is estimated that the Company's 1999 capital spending program will
amount to $524.5 million, and that approximately $337.0 million of that amount
will be directed to gas and oil producing activities. In connection with the
capital spending program, the Company has entered into certain contractual
commitments.
The Company has claims and suits arising in the ordinary course of business
pending against it, but, in the opinion of management and counsel, the ultimate
liability will not have a material effect on its financial position, results of
operations or cash flows.
18. SEGMENT INFORMATION
As indicated in Note 1, in 1998 the Company adopted the provisions of SFAS No.
131. The Company is organized primarily on the basis of products and services
sold in the United States.
The operations of the four retail gas distribution subsidiaries have been
aggregated into the "Distribution" segment. 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. CNG
Transmission also holds a 16% general partnership interest in the Iroquois Gas
Transmission System, L.P., a limited partnership that owns and operates an
interstate natural gas pipeline that transports Canadian gas to utility and
power generation customers in New York and New England. Transmission operations
also include the by-products business of CNG Power.
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.
The activities of CNG International, CNG Field Services, CNG Retail, CNG
Products and Services Company (CNG Products and Services), CNG Power,
Consolidated LNG, CNG Research Company and CNG Coal are included in the "Other"
category. CNG International engages in energy-related activities outside of the
United States and holds equity investments in Australia, Argentina and Latin
America. CNG Retail was established in 1997 to pursue opportunities arising from
the deregulation of the energy industry at the retail level. CNG Products and
Services provides certain energy-related services to customers of the Company's
distribution subsidiaries and others.
The accounting policies of the segments are the same as those described in
the "Summary of Significant Accounting Policies." Transactions between
affiliates are recognized at prices which approximate market value. Significant
transactions between the operating components are eliminated to reconcile the
segment information to consolidated amounts.
48
<PAGE> 51
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table presents segment information pertaining to the Company's
operations:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
Exploration Corporate
and and
Distribution Transmission Production Other Eliminations Total
- -----------------------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C>
1998
Operating revenues
Nonaffiliated
Regulated gas sales .......... $ 1,372,568 $ -- $ -- $ 1,123 $ -- $ 1,373,691
Nonregulated gas sales ....... -- -- 369,736 124,683 -- 494,419
Gas transportation and storage 197,888 347,600 436 9 -- 545,933
Liquid sales ................. -- -- 204,030 -- -- 204,030
Other ........................ 35,498 54,887 34,042 12,899 5,007 142,333
----------- ----------- ----------- ----------- ----------- -----------
Total nonaffiliated ........ 1,605,954 402,487 608,244 138,714 5,007 2,760,406
Affiliated ...................... 5,855 100,060 22,860 23,684 (152,459) --
----------- ----------- ----------- ----------- ----------- -----------
Total operating revenues ... 1,611,809 502,547 631,104 162,398 (147,452) 2,760,406
Operating expenses
Purchased gas ................... 835,222 46,559 39,972 125,223 (146,575) 900,401
Liquids, capacity and other
products purchased ........... -- 24,662 115,397 5,218 -- 145,277
Operation expense ............... 311,154 128,701 156,024 25,406 (3,275) 618,010
Maintenance ..................... 50,579 28,011 9,823 245 1,710 90,368
Depreciation and amortization ... 75,064 57,343 185,902 6,769 4,835 329,913
Taxes, other than income taxes .. 131,575 33,684 7,344 916 5,780 179,299
----------- ----------- ----------- ----------- ----------- -----------
Operating income before
income taxes ............ 208,215 183,587 116,642 (1,379) (9,927) 497,138
----------- ----------- ----------- ----------- ----------- -----------
Income taxes .................... 58,314 60,708 23,117 (300) (12,190) 129,649
Interest revenues ............... 703 4,394 1,118 2,379 (5,429) 3,165
Equity in earnings of equity
investees .................... -- 8,667 4,791 11,917 -- 25,375
Other revenues-net .............. 6,678 1,122 250 1,699 (3,589) 6,160
Interest charges ................ 46,847 25,098 21,650 8,249 12,634 114,478
----------- ----------- ----------- ----------- ----------- -----------
Income from continuing
operations...................... $ 110,435 $ 111,964 $ 78,034 $ 6,667 $ (19,389) $ 287,711
=========== =========== =========== =========== =========== ===========
- -----------------------------------------------------------------------------------------------------------------------------------
Other significant non-cash items:
Pension cost (credit)-net .... $ (42,529) $ (15,801) $ 1,423 $ 213 $ 198 $ (56,496)
Stock award amortization ..... $ 1,039 $ 634 $ 1,708 $ 322 $ 3,757 $ 7,460
- -----------------------------------------------------------------------------------------------------------------------------------
Investment in equity investees .. $ -- $ 36,785 $ 47,834 $ 210,608 $ -- $ 295,227
Total assets .................... $ 2,946,758 $ 1,553,518 $ 1,523,936 $ 350,258 $ (12,570) $ 6,361,900
Capital expenditures ............ $ 146,563 $ 56,748 $ 352,781 $ 193,118 $ 11,903 $ 761,113
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
49
<PAGE> 52
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
Exploration Corporate
and and
Distribution Transmission Production Other Eliminations Total
- ------------------------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C>
1997
Operating revenues
Nonaffiliated
Regulated gas sales ................. $ 1,844,221 $ -- $ -- $ 6,780 $ -- $ 1,851,001
Nonregulated gas sales .............. -- -- 396,282 37,101 -- 433,383
Gas transportation and storage ...... 153,904 337,475 701 -- -- 492,080
Liquid sales ........................ -- -- 275,902 -- -- 275,902
Other ............................... 24,577 60,639 27,287 5,787 6,454 124,744
----------- ----------- ----------- ----------- ----------- -----------
Total nonaffiliated ............... 2,022,702 398,114 700,172 49,668 6,454 3,177,110
Affiliated ............................. 3,859 101,179 5,508 12,962 (123,508) --
----------- ----------- ----------- ----------- ----------- -----------
Total operating revenues .......... 2,026,561 499,293 705,680 62,630 (117,054) 3,177,110
Operating expenses
Purchased gas .......................... 1,158,721 8,592 31,535 34,817 (119,585) 1,114,080
Liquids, capacity and other
products purchased .................. -- 53,203 157,101 271 -- 210,575
Operation expense ...................... 324,150 133,681 166,990 34,056 7,735 666,612
Maintenance ............................ 50,533 28,426 9,604 47 1,998 90,608
Depreciation and amortization .......... 77,389 62,258 181,356 406 3,229 324,638
Impairment of gas and oil
producing properties ................ -- -- 10,351 -- -- 10,351
Taxes, other than income taxes ......... 149,198 32,263 5,917 347 5,859 193,584
----------- ----------- ----------- ----------- ----------- -----------
Operating income before
income taxes ................... 266,570 180,870 142,826 (7,314) (16,290) 566,662
----------- ----------- ----------- ----------- ----------- -----------
Income taxes ........................... 74,699 64,512 31,686 (2,940) (11,688) 156,269
Interest revenues ...................... 1,172 2,011 1,330 2,322 (5,172) 1,663
Equity in earnings of equity
investees ........................... -- 8,929 3,275 5,462 -- 17,666
Other revenues-net ..................... (2,152) (86) 217 (6,996) 2,130 (6,887)
Interest charges ....................... 48,419 24,051 22,372 1,983 7,102 103,927
----------- ----------- ----------- ----------- ----------- -----------
Income from continuing operations ...... $ 142,472 $ 103,161 $ 93,590 $ (5,569) $ (14,746) $ 318,908
=========== =========== =========== =========== =========== ===========
- ------------------------------------------------------------------------------------------------------------------------------------
Other significant non-cash items:
Impairment of gas and oil
producing properties .............. $ -- $ -- $ 10,351 $ -- $ -- $ 10,351
Pension cost (credit)-net ........... $ (33,335) $ (12,819) $ 1,257 $ 81 $ (1,195) $ (46,011)
Stock award amortization ............ $ 1,201 $ 836 $ 1,847 $ 279 $ 4,046 $ 8,209
- ------------------------------------------------------------------------------------------------------------------------------------
Investment in equity investees ......... $ -- $ 34,518 $ 38,558 $ 143,122 $ -- $ 216,198
Total assets ........................... $ 2,879,312 $ 1,501,640 $ 1,360,068 $ 827,497 $ (254,823) $ 6,313,694
Capital expenditures ................... $ 147,213 $ 49,300 $ 299,897 $ 95,801 $ 10,906 $ 603,117
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
50
<PAGE> 53
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------------------
Exploration Corporate
and and
Distribution Transmission Production Other Eliminations Total
- -------------------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C>
1996
Operating revenues
Nonaffiliated
Regulated gas sales .................. $ 1,746,650 $ -- $ -- $ 7,017 $ -- $ 1,753,667
Nonregulated gas sales ............... -- -- 396,104 -- -- 396,104
Gas transportation and storage ....... 132,486 346,570 532 -- -- 479,588
Liquid sales ......................... -- -- 202,907 -- -- 202,907
Other ................................ 26,377 65,713 26,456 1,878 2,768 123,192
----------- ----------- ----------- ----------- ----------- -----------
Total nonaffiliated ................ 1,905,513 412,283 625,999 8,895 2,768 2,955,458
Affiliated .............................. (1) 104,891 6,288 13,299 (124,477) --
----------- ----------- ----------- ----------- ----------- -----------
Total operating revenues ........... 1,905,512 517,174 632,287 22,194 (121,709) 2,955,458
Operating expenses
Purchased gas ........................... 1,025,186 7,421 51,691 -- (121,081) 963,217
Liquids, capacity and other
products purchased ................... -- 63,599 115,708 -- -- 179,307
Operation expense ....................... 352,706 142,265 147,851 22,369 2,063 667,254
Maintenance ............................. 53,774 24,494 10,791 11 997 90,067
Depreciation and amortization ........... 74,132 60,394 165,715 154 2,488 302,883
Taxes, other than income taxes .......... 141,293 37,403 7,299 545 4,143 190,683
----------- ----------- ----------- ----------- ----------- -----------
Operating income before
income taxes .................... 258,421 181,598 133,232 (885) (10,319) 562,047
----------- ----------- ----------- ----------- ----------- -----------
Income taxes ............................ 76,334 63,105 34,609 1,760 (13,493) 162,315
Interest revenues ....................... 1,051 4,244 4,359 2,073 (9,703) 2,024
Equity in earnings of equity
investees ............................ -- 7,199 1,967 3,792 -- 12,958
Other revenues-net ...................... (503) 177 125 53 (5,859) (6,007)
Interest charges ........................ 44,853 23,962 20,130 1,842 8,538 99,325
----------- ----------- ----------- ----------- ----------- -----------
Income from continuing operations ....... $ 137,782 $ 106,151 $ 84,944 $ 1,431 $ (20,926) $ 309,382
=========== =========== =========== =========== =========== ===========
- -------------------------------------------------------------------------------------------------------------------------------
Other significant non-cash items:
Pension cost (credit)-net ............ $ (19,142) $ (6,494) $ 1,900 $ -- $ (581) $ (24,317)
Stock award amortization ............. $ 876 $ 546 $ 1,225 $ -- $ 5,127 $ 7,774
- -------------------------------------------------------------------------------------------------------------------------------
Investment in equity investees .......... $ -- $ 34,389 $ 31,460 $ 72,820 $ -- $ 138,669
Total assets ............................ $ 2,900,620 $ 1,496,976 $ 1,264,453 $ 519,861 $ (181,305) $ 6,000,605
Capital expenditures .................... $ 143,050 $ 85,904 $ 271,392 $ 48,570 $ 6,135 $ 555,051
- -------------------------------------------------------------------------------------------------------------------------------
</TABLE>
51
<PAGE> 54
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
19. SUBSEQUENT EVENT
On February 22, 1999, the Company and Dominion Resources, Inc. (DRI) announced
that a definitive merger agreement (merger agreement) was approved by the boards
of directors of both companies. Under the terms of the merger agreement, DRI
intends to acquire all of the Company's shares of common stock in a
stock-for-stock transaction. Pursuant to the merger agreement, each share of the
Company's common stock will be converted into 1.52 shares of DRI common stock.
The transaction is conditioned, among other things, upon approvals of
shareholders of both companies, opinions of independent accountants that the
transaction will be treated as a pooling of interests for accounting purposes,
approvals of various federal regulatory agencies and the completion of
regulatory processes in states where the combined company will operate. DRI is a
holding company with businesses in regulated and competitive electric power,
natural gas and oil development and selected financial services. DRI's principal
business subsidiary is Virginia Electric and Power Company, a regulated public
utility engaged in the generation, transmission, distribution and sale of
electric energy in Virginia and northeastern North Carolina.
20. SUPPLEMENTARY FINANCIAL INFORMATION--UNAUDITED
(A) GAS AND OIL PRODUCING ACTIVITIES (EXCLUDING COST-OF-SERVICE RATE-REGULATED
ACTIVITIES)
The following disclosures exclude the Company's gas producing activities subject
to cost-of-service rate regulation. Certain disclosures about these activities
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, 1998 1997
- -----------------------------------------------------
(In Thousands)
<S> <C> <C>
Capitalized costs of
Proved properties ...... $3,594,042 $3,293,851
Unproved properties .... 389,977 328,174
---------- ----------
Subtotal ............. 3,984,019 3,622,025
---------- ----------
Accumulated depreciation of
Proved properties ...... 2,542,026 2,367,105
Unproved properties .... 160,222 146,417
---------- ----------
Subtotal ............. 2,702,248 2,513,522
---------- ----------
Net capitalized costs $1,281,771 $1,108,503
========== =========
- -----------------------------------------------------
</TABLE>
As described in Note 5, the Company recognized an impairment of its
Canadian oil producing properties at December 31, 1997. The non-cash charge
amounted to $10.4 million and is reflected in the amounts included above.
52
<PAGE> 55
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TOTAL COSTS INCURRED
The following costs were incurred by subsidiaries in their gas and oil producing
activities during the years 1996 through 1998:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------
Years Ended December 31, 1998 1997 1996
- ------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Property acquisition costs
Proved properties ....... $ 20,597 $ 14,142 $ 42,880
Unproved properties ..... 29,512 43,951 17,911
-------- -------- --------
Subtotal .............. 50,109 58,093 60,791
Exploration costs .......... 115,429 101,891 49,622
Development costs .......... 176,220 118,746 125,139
-------- -------- --------
Total ................. $341,758 $278,730 $235,552
======== ======== ========
- ------------------------------------------------------------------
</TABLE>
RESULTS OF OPERATIONS
The Company cautions that the following standardized disclosures required by the
FASB do not represent the results of operations based on its historical
financial statements. In addition to requiring different determinations of
revenues and costs, the disclosures exclude the impact of interest expense and
corporate overheads.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
Years Ended December 31, 1998 1997* 1996*
- ----------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Revenues (net of royalties) from:
Sales to nonaffiliated companies.............. $357,729 $403,233 $360,973
Transfers to other operations................. 24,785 7,973 13,158
-------- -------- --------
Total....................................... 382,514 411,206 374,131
-------- -------- --------
Less: Production (lifting) costs................. 62,937 65,286 55,679
Depreciation and amortization............. 176,587 172,046 157,358
Impairment of producing properties........ -- 10,351 --
Income tax expense........................ 40,977 48,987 49,367
-------- -------- --------
Results of operations............................ $102,013 $114,536 $111,727
======== ======== ========
</TABLE>
*Certain amounts reclassified to reflect discontinued operations.
- --------------------------------------------------------------------------------
53
<PAGE> 56
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 1996 through 1998, and changes
in the reserves during those years, are shown in the two schedules which follow:
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------
Years Ended December 31, 1998 1997 1996
- --------------------------------------------------------------------------------------
(In Bcf)
<S> <C> <C> <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--GAS
At January 1......................................... 1,141 1,040 985
Changes in reserves
Extensions, discoveries and other additions....... 214 210 124
Revisions of previous estimates................... 70 31 5
Production........................................ (155) (155) (145)
Purchases of gas in place**....................... 43 29 96
Sales of gas in place............................. -- (14) (25)
----- ----- ------
At December 31....................................... 1,313 1,141 1,040
===== ===== =====
PROVED DEVELOPED RESERVES*--GAS
At January 1......................................... 925 900 717
At December 31....................................... 1,052 925 900
</TABLE>
*Net before royalty.
**Amount for 1998 includes 39 Bcf of reserves transferred by sale to CNG
Producing from an affiliate, Peoples Natural Gas.
- --------------------------------------------------------------------------------
The preceding proved developed and undeveloped gas reserves at December 31,
1998, 1997 and 1996, include United States reserves of 1,312, 1,140 and 1,039
Bcf which, together with the Canadian reserves and the gas reserves reported
under "Cost-of-Service Properties," are as contained in reports of Ralph E.
Davis Associates, Inc., independent geologists.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------
Years Ended December 31, 1998 1997 1996
- -----------------------------------------------------------------------------------------
(In Thousand Bbls)
<S> <C> <C> <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES*--OIL
At January 1......................................... 50,627 50,457 45,791
Changes in reserves
Extensions, discoveries and other additions....... 11,275 4,582 5,976
Revisions of previous estimates................... 2,960 1,741 2,711
Production........................................ (7,895) (7,312) (4,766)
Purchases of oil in place......................... 107 1,182 804
Sales of oil in place............................. -- (23) (59)
------ ------ ------
At December 31....................................... 57,074 50,627 50,457
====== ====== ======
PROVED DEVELOPED RESERVES*--OIL
At January 1......................................... 37,568 24,989 19,838
At December 31....................................... 42,750 37,568 24,989
</TABLE>
*Net before royalty.
- --------------------------------------------------------------------------------
The foregoing proved developed and undeveloped oil reserves at December 31,
1998, 1997 and 1996 include United States reserves of 51,230, 44,160 and 41,818
thousand barrels, respectively. These, together with the Canadian reserves, are
as contained in reports of Ralph E. Davis Associates, Inc.
54
<PAGE> 57
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 1998 1997 1996
(In Thousands)
<S> <C> <C> <C>
Future cash inflows............................................. $2,562,741 $3,197,532 $4,022,381
Less: Future development and production costs.................. 756,352 658,281 711,067
Future income tax expense................................ 482,585 766,233 1,049,234
---------- ---------- ----------
Future net cash flows........................................... 1,323,804 1,773,018 2,262,080
Less annual discount (10% a year)............................... 435,540 606,509 830,083
---------- ---------- ----------
Standardized measure of discounted future net cash flows........ $ 888,264 $1,166,509 $1,431,997
========== ========== ==========
- ------------------------------------------------------------------------------------------------------------
</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 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.
55
<PAGE> 58
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 1998 1997 1996
- ------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Standardized measure of discounted future
net cash flows at January 1................................ $1,166,509 $1,431,997 $ 841,743
Changes in the year resulting from
Sales and transfers of gas and oil produced
during the year, less production costs................... (319,577) (345,920) (318,583)
Prices and production and development costs
related to future production............................ (657,675) (660,014) 632,118
Extensions, discoveries and other additions,
less production and development costs................... 144,595 256,366 295,236
Previously estimated development costs
incurred during the year................................ 71,172 38,409 62,706
Revisions of previous quantity estimates................... 38,015 101,352 106,800
Accretion of discount...................................... 166,707 209,210 119,555
Income taxes............................................... 180,611 159,528 (306,290)
Purchases and sales of proved reserves in place-net........ 35,639 40,815 112,601
Other (principally timing of production)................... 62,268 (65,234) (113,889)
--------- ---------- ----------
Standardized measure of discounted future
net cash flows at December 31.............................. $ 888,264 $1,166,509 $1,431,997
========= ========== ==========
- ------------------------------------------------------------------------------------------------------------
</TABLE>
COST-OF-SERVICE PROPERTIES
As previously stated, activities subject to cost-of-service rate regulation,
consisting solely of gas reserves and related production, are excluded from the
foregoing information. In December 1998, Peoples Natural Gas, a subsidiary,
transferred by sale all of its remaining gas production properties to CNG
Producing, a nonregulated subsidiary. At December 31, 1997, net capitalized
costs of cost-of-service properties amounted to $8.4 million. Related proved
reserves of gas are located in the United States and amounted to 42 and 43 Bcf
at December 31, 1997 and 1996. Gas production for the years 1998, 1997 and 1996
amounted to 2, 3 and 3 Bcf, respectively.
56
<PAGE> 59
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(B) Quarterly Financial Data
A summary of the quarterly results of operations for the years 1998 and 1997
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
- ----------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
1998
Total operating revenues..................................... $999,165 $530,428 $423,448 $807,365
Operating income before income taxes......................... $234,850 $ 83,710 $ 25,516 $153,062
Income from continuing operations............................ $138,033 $ 46,814 $ 5,627 $ 97,237
Discontinued operations (Note 2)
Loss from discontinued energy marketing services
operations, net of applicable tax benefit............... $ (17,238) $ -- $ -- $ --
Income (loss) from disposal of energy marketing
services operations, including provision for
operating losses during the phase out period,
net of applicable tax or tax benefit.................... $ (42,900) $ 10,989 $ 2,425 $ (2,221)
Net income................................................... $ 77,895 $ 57,803 $ 8,052 $ 95,016
Earnings per common share--basic*
Income from continuing operations......................... $ 1.48 $ .49 $ .06 $ 1.02
Loss from discontinued operations......................... (.18) -- -- --
Income (loss) from disposal of discontinued
operations.............................................. (.46) .12 .02 (.02)
--------- -------- -------- -------
Net income................................................... $ .84 $ .61 $ .08 $ 1.00
========= ======== ======== ========
Earnings per common share--diluted*
Income from continuing operations......................... $1.45 $.49 $.06 $1.01
Loss from discontinued operations......................... (.18) -- -- --
Income (loss) from disposal of discontinued
operations.............................................. (.45) .11 .02 (.02)
--------- -------- -------- -------
Net income $ .82 $.60 $.08 $ .99
========= ======== ======== ========
- ----------------------------------------------------------------------------------------------------------------
</TABLE>
57
<PAGE> 60
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------------
Quarter
-------------------------------------------------
First Second Third Fourth
- -------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
1997
Total operating revenues..................................... $1,143,768 $629,418 $462,980 $940,944
Operating income before income taxes......................... $ 283,358 $ 90,130 $ 33,536 $159,638
Income from continuing operations............................ $ 173,028 $ 48,036 $ 8,761 $ 89,083
Discontinued operations (Note 2)
Income (loss) from discontinued energy marketing
services operations, net of applicable tax or tax
benefit................................................. $ (1,537) $ (9,051) $ (4,223) $ 283
Net income................................................... $ 171,491 $ 38,985 $ 4,538 $ 89,366
Earnings per common share--basic*
Income from continuing operations......................... $1.83 $ .51 $ .09 $.94
Income (loss) from discontinued operations................ (.02) (.10) (.04) --
---------- -------- -------- --------
Net income................................................... $1.81 $ .41 $ .05 $.94
========== ======== ======== ========
Earnings per common share--diluted*
Income from continuing operations......................... $1.76 $ .50 $ .09 $.92
Income (loss) from discontinued operations................ (.02) (.09) (.04) --
---------- -------- -------- --------
Net income................................................... $1.74 $ .41 $ .05 $.92
========== ======== ======== ========
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
*The sum of the quarterly amounts does not equal the year's amount because the
quarterly calculations are based on a changing number of average shares.
(C) Common Stock Market Prices and Related Matters
At December 31, 1998, there were 33,121 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 1998 and
1997 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
1998--High....................... $60 1/2 $60 1/8 $59 $55 15/16
--Low........................ $53 1/4 $54 15/16 $41 11/16 $50 7/16
1997--High....................... $57 3/4 $54 7/8 $60 11/16 $60 15/16
--Low........................ $49 5/8 $47 3/8 $53 9/16 $52 5/16
Dividends Declared per Share
1998............................. $.485 $.485 $.485 $.485
1997............................. $.485 $.485 $.485 $.485
- ----------------------------------------------------------------------------------
</TABLE>
58
