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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, 1997
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:
6.80% 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
5 7/8% Debentures Due October 1, 1998 New York Stock Exchange
8 3/4% Debentures Due October 1, 2019 New York Stock Exchange
8 3/4% Debentures Due June 1, 1999 New York Stock Exchange
8 5/8% Debentures Due December 1, 2011 New York Stock Exchange
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SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
------------------------
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 $4,934,057,461 as of January 31, 1998. It was assumed
in this calculation that the registrant's affiliates are all of its directors
and/or officers, and they beneficially owned 242,663 shares of voting stock at
that date.
Shares of Common Stock, $2.75 Par Value, outstanding at January 31, 1998:
91,088,370.
The registrant's "Notice of Annual Meeting and Proxy Statement, 1998" 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, 1997
TABLE OF CONTENTS
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Page
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FORWARD-LOOKING INFORMATION................................. 1
PART I
ITEM 1. BUSINESS
The Company............................. 2
Governmental Regulation................. 3
Capital Expenditures.................... 4
Competitive Conditions.................. 4
Gas Supply.............................. 8
Gas Sales and Transportation............ 12
Gas Sales, Supply, Transportation and
Storage Statistics...................... 13
Market Expansion........................ 14
Rate Matters............................ 15
Executive Officers of the Company....... 16
ITEM 2. PROPERTIES
General Information on Facilities....... 17
Map--Principal Facilities............... 18
Map--Exploration and Production Areas... 19
Gas and Oil Producing Activities........ 20
ITEM 3. LEGAL PROCEEDINGS................................ 22
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS............................... 22
PART II
ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS................... 22
ITEM 6. SELECTED FINANCIAL DATA.......................... 23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS... 23
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK........................... 23
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA...... 23
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE... 23
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE
COMPANY............................... 23
ITEM 11. EXECUTIVE COMPENSATION........................... 23
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT........................ 23
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS... 24
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K................... 24
SIGNATURES.................................................. 28
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CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1997
FORWARD-LOOKING INFORMATION
Certain matters discussed in this Annual Report on Form 10-K for Consolidated
Natural Gas Company and its subsidiaries (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 capital
expenditures, earnings, risk management, litigation, environmental matters, rate
and other regulatory matters, liquidity and capital resources, and financial
accounting 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.
1
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CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1997
PART I
ITEM 1. BUSINESS
THE COMPANY
Consolidated Natural Gas Company is a Delaware corporation organized on July 21,
1942, and a public utility holding company registered under the Public Utility
Holding Company Act of 1935 (PUHCA). It is engaged solely in the business of
owning and holding all of the outstanding equity securities of fourteen directly
owned subsidiary companies.
The Parent Company and subsidiaries at December 31, 1997, are listed below. In
addition to operating in all phases of the natural gas business, the Company
explores for and produces oil and provides a variety of energy marketing
services. At December 31, 1997, the Company had 6,412 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 Energy Services Corporation (CNG Energy Services)..... Delaware
CNG Power Services Corporation (CNG Power Services)....... Delaware
CNG International Corporation (CNG International)......... 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, 1997, the
Company served at retail approximately 1,782,000 residential, commercial and
industrial gas sales customers in Ohio, Pennsylvania, Virginia and West
Virginia. Variations in weather conditions can materially affect the volume of
gas delivered by the distribution subsidiaries, as 98% 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
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ITEM 1. BUSINESS (Continued)
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 Energy Services markets an array of energy sales, management, storage and
other products and services that can be arranged separately or in various
combinations to meet the individual energy needs of customers. It has Federal
Energy Regulatory Commission (FERC) approval to purchase and sell electricity at
market-based prices. Retail gas and electricity sales are made through CNG
Energy Services' subsidiary, CNG Retail Services Corporation (CNG Retail). CNG
Energy Services also holds the Company's ownership interests in six independent
power plants. At December 31, 1997, four of these were being held for sale and
had their carrying values written down.
CNG Power Services is a power marketing subsidiary which also has FERC approval
to purchase and sell electricity at market-based prices.
CNG International was formed in 1996 to engage in energy-related activities
outside of the United States (see "International Activities," page 14).
Consolidated LNG was organized to import and regasify liquefied natural gas
(LNG) for sale to CNG Transmission. However, Consolidated LNG ended its
involvement in LNG operations in 1982 and, as of February 28, 1998, had
recovered its undepreciated investment in LNG-related facilities, plus carrying
charges and taxes, through a FERC-approved amortization surcharge.
CNG Research administers proprietary research activities. Amounts spent on
research activities in the calendar years 1995 through 1997 by all the
subsidiaries were not material.
CNG Coal formerly owned coal reserves and a related plant site. CNG Coal sold
its coal properties to a subsidiary of Cyprus Amax Minerals Company in 1996.
Service Company is a subsidiary service company authorized by the Securities and
Exchange Commission (SEC) under the PUHCA. It advises and assists the other
subsidiary companies on administrative and technical matters and manages
centralized activities and facilities for their benefit. It also provides
services to the Parent Company.
CNG Financial was formed to engage in 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 Energy Services, CNG Power Services and CNG Retail, public utilities
as defined by
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ITEM 1. BUSINESS (Continued)
section 201 of the Federal Power Act, are 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 Energy Services and CNG Retail are classified as public
utilities in Pennsylvania for the limited purpose of their 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 1998 is estimated at $714.7 million, a
17% increase compared with total capital spending in 1997. The estimated 1998
budget has been allocated as follows: distribution, $145.7 million;
transmission, $61.5 million; exploration and production, $312.7 million; energy
marketing services, $25.3 million; international, $151.6 million; and corporate
and other, $17.9 million. The increased level of capital expenditures planned
for 1998 reflects higher spending for unregulated businesses. Exploration and
production operations reflect increased spending on deep-water projects and
increased conventional onshore and offshore drilling. Expenditures for
international operations reflect expected continued expansion of investment
opportunities in Australia and Latin America. 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, primarily to centralize and consolidate services and financial
systems. 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
4
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ITEM 1. BUSINESS (Continued)
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 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.
GAS AND ELECTRIC INDUSTRY DEVELOPMENTS
In the current gas industry environment, competition at the retail level is
receiving increased attention by state regulators. Governments in two 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, and allows retail customers to obtain gas from
an array of suppliers. The Public Utilities Commission of Ohio (PUCO) has
proposed rules to implement the law. Legislation is being considered in
Pennsylvania that would completely unbundle gas utility merchant functions by
January 1999. One aspect of the proposal would permit the Pennsylvania Public
Utility Commission (PUC) to certify marketers, in addition to gas utilities, as
suppliers of last resort, creating competition in a traditional gas utility
function. The proposal requires the PUC to review and act by September 1998 on
plans submitted by gas utilities.
In addition to the further deregulation of the gas industry, the emerging
unbundling of services provided by electric utilities may ultimately result in
the convergence of both industries to create one overall, highly competitive
marketplace for a customer's total energy needs. During 1995 and 1996,
regulators at the federal and state levels finalized initiatives to promote
increased competition in the electric industry. These initiatives included
issuance in 1996 of FERC Order Nos. 888 and 889 (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. A companion order, Order 889,
addresses the timing, information access and other administrative details
associated with the FERC deregulation initiative.
Other signs of an increasingly deregulated electric utility environment include
retail competition plans adopted in several states, pilot retail wheeling
programs and pro-competition legislation proposed at both the federal and state
levels. While no legislation has been enacted in Ohio regarding electric
competition at the retail level, a legislative study committee report issued in
January 1998 calls for full customer choice by 2000. In Pennsylvania, the
Electric Generation Customer Choice and Competition Act enacted in late 1996
requires a transition to a competitive electric market at the retail level
beginning in 1999, with full competition by 2001. In March 1998, the Virginia
Senate and House of Delegates passed an electric industry restructuring bill
calling for a transition to wholesale competition beginning in 2002 and retail
competition in 2004 and sent the bill to the Governor for consideration. In West
Virginia, a bill introduced in February 1998 would authorize the Public Service
Commission (PSC) to prescribe and implement a plan to deregulate the electric
industry that must balance fairly the interests of customers, electric utilities
and the state's economy.
Reflecting the evolution to a more competitive energy environment, the pace and
size of business combinations among natural gas and electric utilities continued
to increase during 1997. 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. Recent and pending regulatory
actions may serve to
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ITEM 1. BUSINESS (Continued)
further facilitate more business combinations in the energy industry. The FERC
has streamlined its regulatory review process regarding pending mergers. In
addition, the SEC has recommended legislation to conditionally repeal the PUHCA,
to which the Company is subject, in conjunction with legislation which would
grant the various state regulatory commissions greater oversight authority of
companies currently subject to the PUHCA. 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. 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.
Through its actions in recent years, the Company believes it is well-positioned
to compete in an evolving and increasingly deregulated energy marketplace. The
creation of CNG Retail and the ongoing development of the energy marketing
services component and participation in international investments, coupled with
streamlining and restructuring of its existing distribution, transmission,
exploration and production and support operations, reflects the Company's
proactive approach to meeting the demands of a more competitive and dynamic
business environment.
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 more recent Energy Policy Act of 1992 contain a number
of provisions relating to the use of alternative fuel vehicles. The Company is
participating in various programs to demonstrate the advantages and
environmental benefits of natural gas powered vehicles.
Competition in the markets served by the distribution subsidiaries continues to
increase. As the gas industry has restructured and government regulations have
changed, a marketplace has evolved with new and traditional competitors--the
usual oil and electric companies, other gas companies, 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 14). 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
6
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ITEM 1. BUSINESS (Continued)
industrial and commercial customers. Also, residential customers in certain of
the Company's service territories can choose an alternative source of gas supply
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 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 14). 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 14).
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. CNG Energy Services is the primary marketing agent for all of the
Company's nonregulated gas production. When the economics warrant, the Company
attempts to sell its gas production under long-term contracts to customers such
as electric power generators and others that require a secure source of supply.
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. As the Company's
gas marketing agent, CNG Energy Services continues to develop marketing
strategies, contracts and arrangements to address customer needs for
intermediate and long-term gas supplies as
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ITEM 1. BUSINESS (Continued)
well as swing, peaking and other energy services. In addition, in the ordinary
course of business, CNG Producing and CNG Energy Services participate in price
risk management activities to manage exposure to price risk in connection with
the production, purchase 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.
ENERGY MARKETING SERVICES
The Company's energy marketing services operations, comprised of CNG Energy
Services and CNG Power Services, are engaged in a variety of energy-related
activities in highly competitive markets. These activities include fuel
management, gas marketing, energy price risk management, pipeline capacity and
storage management, power marketing and electric generation.
Energy marketing services competes with the marketing operations of both
independent and major energy companies in addition to electric utilities,
independent power producers, local distribution companies, and various energy
brokers. As a result of the continuing efforts to deregulate both natural gas
and electric industries to the retail level, the relative energy cost
differences among different forms of energy are expected to be reduced in the
future. Competition is based largely upon pricing, availability and reliability
of supply, technical and financial capabilities, regional presence and
international experience.
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 Energy Services and CNG Retail have the responsibility and price risk for
obtaining their own gas supplies to meet customer needs.
The Company's available gas supply in 1997 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 13.
GAS PURCHASED
Purchased gas volumes were 943.0 Bcf in 1997, representing 84% of the Company's
1997 gas supply of 1,117.9 Bcf. Spot market and short-term purchases were 890.3
Bcf, or about 79% of the total 1997
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ITEM 1. BUSINESS (Continued)
supply. Volumes purchased under contracts with Appalachian area producers
totaled 52.7 Bcf, or 5% of the 1997 supply.
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 market in
a highly reliable manner.
At December 31, 1997, the distribution subsidiaries had 351.0 Bcf of firm
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. CNG Energy Services also uses firm and interruptible transportation
capacity in varying quantities throughout the year to receive supplies from
producers and make deliveries to customers.
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, 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 over 260 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 and CNG Energy Services 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
Increased gas and oil production contributed to improved results from the
exploration and production operations in 1997. In addition to an increased
capital spending plan for the exploration and
9
<PAGE> 12
ITEM 1. BUSINESS (Continued)
production segment during 1998, the Company may pursue exploration and
production acquisition opportunities that meet the Company's longer-term
strategy.
The Company's total gas production in 1997 was 158.1 Bcf, up from 147.5 Bcf in
1996. Oil production was 7.3 million barrels, up 53% from 4.8 million barrels in
1996.
The Company's gas wellhead prices in 1997 averaged $2.43 a thousand cubic feet
(Mcf), down from $2.46 in 1996. The Company's average gas wellhead prices are
generally higher and less volatile than industry spot prices since its average
price reflects a mix of longer-term contracts. However, due to market-based
pricing mechanisms under many of the contracts, the Company's gas prices
generally follow industry trends. The average oil wellhead price in 1997
decreased to $16.07 a barrel, compared with $17.60 in 1996, consistent with the
general decline in world oil prices.
The following table sets forth 1997 drilling activity by region:
<TABLE>
<S> <C> <C> <C> <C>
- -------------------------------------------------------------------------------------------
<CAPTION>
Wells Drilled
Exploratory Development
- -------------------------------------------------------------------------------------------
Gross Net Gross Net
-- -- --- --
<S> <C> <C> <C> <C>
Onshore (Southwest and West)............................... 5 3 24 15
Gulf of Mexico............................................. 12 6 12 7
Appalachian Region......................................... -- -- 38 36
Canada..................................................... -- -- 58 13
-- -- --- --
Total................................................. 17 9 132 71
== == === ==
- -------------------------------------------------------------------------------------------
</TABLE>
Of the total 149 wells drilled in 1997, 134 were successful, a 90% success rate.
Of the 17 exploratory wells drilled, 6 were successful.
Total Company-owned proved gas reserves at year-end were 1,183 Bcf, up from
1,083 Bcf at the end of 1996. Proved oil reserves were 50.6 million barrels,
compared with 50.5 million barrels in 1996. CNG added 315 Bcf of gas equivalent
from additions, revisions, and purchases of gas and oil reserves in 1997. (See
"Company-Owned Reserves," page 20.)
During 1997, major discoveries were made in the Main Pass and West Cameron areas
of the Gulf of Mexico. Production at Nautilus and Nemo, two projects in the Main
Pass area, is expected to begin in late 1998. At Nautilus, facilities are being
constructed to handle 180 million cubic feet of gas and 20,000 barrels of oil a
day for the two projects. CNG owns 65% of Nautilus and 100% of Nemo and West
Cameron Block 130 and is the operator of all three projects.
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 1997, including .8 million barrels of condensate. To continue the high
productivity at Popeye, a third well was drilled during 1997. 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.
Production began in March 1997 at Neptune, a deep-water oil discovery at Viosca
Knoll 826. 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. Additional proved reserves at
Neptune equivalent to 18 Bcf of gas were added during 1996. The Company's
portion of production from this field was the equivalent of 18 Bcf of gas during
1997. This production was comprised almost entirely of oil. Facilities designed
with Oryx Energy Company, the operating partner, to produce up to 25,000 barrels
of oil and 30 million cubic feet of natural gas a day are being modified to
increase daily production limits to 35,000 barrels of oil and 32 million cubic
feet of gas.
10
<PAGE> 13
ITEM 1. BUSINESS (Continued)
CNG Producing was the successful bidder on 18 leases offered in the federal
government's Gulf of Mexico lease sales in 1997, including 14 blocks in deep
water areas of the Gulf of Mexico. At year-end 1997, the Company held 2.0
million net acres of exploration and production properties, approximately the
same as year-end 1996. The Company's lease holdings include about 1.4 million
net acres in the Appalachian area, 373,500 in the offshore Gulf of Mexico, and
217,700 in the inland areas of the Southwest, Gulf Coast and West. The Company
holds a 21% interest in heavy oil properties in Alberta, Canada. Proved reserves
associated with the Canadian properties approximated .8 Bcf of gas and 6.5
million barrels of oil at December 31, 1997. On an energy-equivalent basis,
these reserves represent less than 3% of the Company's total proved reserves at
that date.
The Company drilled 38 wells in the Appalachian Region during 1997. 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 1998, and
sales of selected properties are possible depending on economic conditions.
11
<PAGE> 14
ITEM 1. BUSINESS (Continued)
GAS SALES AND TRANSPORTATION (Five-year statistics are on page 13.)
GAS SALES CUSTOMERS
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
- ------------------------------------------------------------------------------------------
<CAPTION>
Customers Total* Residential Commercial Industrial Wholesale Nonregulated
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
December 31,
1997 1,865,117 1,655,587** 124,141 1,813 39 83,537**
1996 1,841,963 1,713,504 125,842 1,764 37 816
1995 1,824,497 1,695,949 126,304 1,736 12 496
1994 1,799,649 1,672,630 124,803 1,697 14 505
1993 1,777,157 1,656,752 118,170 1,688 31 516
- ------------------------------------------------------------------------------------------
</TABLE>
*Includes residential and commercial space-heating customers as follows:
1997-1,750,136; 1996-1,808,062; 1995-1,788,778; 1994-1,762,207; and
1993-1,738,945.
**Reflects the shift of former residential sales customers to other suppliers,
primarily CNG Retail (see "Retail Unbundling," page 14).
REGULATED GAS SALES
Sales of gas to residential customers in 1997 were 208 Bcf, down 11 Bcf from
1996, while sales to commercial customers were 60 Bcf in 1997, down 7 Bcf
compared to 1996. 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. The weather in the
Company's retail service areas in 1997 was 2% colder than normal but 4% warmer
than 1996.
Industrial sales in 1997 were 4 Bcf, down 3 Bcf from 1996. 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 138 Bcf in 1997, compared with 139 Bcf in 1996.
NONREGULATED SALES
Nonregulated gas sales in 1997 were 808 Bcf, up 412 Bcf from 1996. Gas sales by
CNG Energy Services were 787 Bcf, compared to 369 Bcf in 1996. Almost all of the
gas produced by the Company's exploration and production operations is
transferred to CNG Energy Services for sale. Volumes related to gas brokering
activity were 12 Bcf in 1997, down from 19 Bcf in 1996.
GAS TRANSPORTATION
Total transportation volumes in 1997 were 754 Bcf, down from 758 Bcf in 1996.
Total transportation volumes include volumes transported by the distribution
subsidiaries for commercial, industrial and off-system customers amounting to
189 Bcf in 1997, up 15 Bcf over 1996. This increase reflects transportation
volumes for commercial customers which were up 9 Bcf compared to the prior year
and transportation provided to former sales customers in connection with the
retail unbundling initiative.
12
<PAGE> 15
ITEM 1. BUSINESS (Continued)
GAS SALES, SUPPLY, TRANSPORTATION AND STORAGE STATISTICS (Excludes affiliated
transactions)
<TABLE>
<S> <C> <C> <C> <C> <C>
- ----------------------------------------------------------------------------------------------
<CAPTION>
Years Ended December 31, 1997 1996 1995 1994 1993
<S> <C> <C> <C> <C> <C>
- ----------------------------------------------------------------------------------------------
GAS SALES REVENUES (MILLIONS)
Regulated
Residential........................... $1,449.1 $1,346.1 $1,214.2 $1,254.9 $1,222.5
Commercial............................ 369.7 361.6 345.9 373.4 372.6
Industrial............................ 22.8 30.6 32.6 45.8 55.4
Wholesale............................. 9.4 13.9 4.7 5.2 422.7
Nonregulated............................ 2,339.1 1,092.5 997.7 723.6 541.8
-------- -------- -------- -------- --------
Total.............................. $4,190.1 $2,844.7 $2,595.1 $2,402.9 $2,615.0
======== ======== ======== ======== ========
AVERAGE SALES RATES PER MCF
Regulated
Residential........................... $ 6.97 $ 6.15 $ 5.71 $ 6.09 $ 5.76
Commercial............................ 6.19 5.41 4.95 5.38 5.13
Industrial............................ 5.33 4.47 4.49 4.89 4.43
Wholesale............................. * * * * 5.24
Nonregulated............................ 2.90 2.76 1.79 2.17 2.40
Weighted average................... $ 3.88 $ 4.12 $ 3.07 $ 3.89 $ 4.33
======== ======== ======== ======== ========
GAS REQUIREMENTS (BCF)
Regulated gas sales
Residential........................... 207.8 218.7 212.5 205.9 212.3
Commercial............................ 59.7 66.8 69.8 69.4 72.7
Industrial............................ 4.3 6.9 7.3 9.4 12.5
Wholesale............................. .2 1.6 .3 .3 80.7
Nonregulated gas sales.................. 807.7 396.1 556.6 332.8 226.0
-------- -------- -------- -------- --------
Total sales........................ 1,079.7 690.1 846.5 617.8 604.2
Used and unaccounted for................ 38.2 54.4 51.0 48.3 44.0
-------- -------- -------- -------- --------
Total requirements................. 1,117.9 744.5 897.5 666.1 648.2
======== ======== ======== ======== ========
GAS SUPPLY (BCF)
Purchased gas........................... 943.0 618.3 771.1 559.6 485.2
Storage (input) withdrawal.............. 16.8 (21.3) 19.2 (13.0) 33.5
Gas produced
Gulf region........................... 116.5 108.1 68.3 76.4 81.6
Appalachian area...................... 25.8 26.0 27.2 27.8 29.4
Other areas........................... 15.8 13.4 11.7 15.3 18.5
-------- -------- -------- -------- --------
Total produced..................... 158.1 147.5 107.2 119.5 129.5
-------- -------- -------- -------- --------
Total supply....................... 1,117.9 744.5 897.5 666.1 648.2
======== ======== ======== ======== ========
PURCHASED GAS COSTS (MILLIONS)**........ $2,855.2 $1,843.2 $1,611.9 $1,375.8 $1,349.5
======== ======== ======== ======== ========
AVERAGE PURCHASE RATES PER MCF**........ $ 3.03 $ 2.98 $ 2.09 $ 2.46 $ 2.78
======== ======== ======== ======== ========
GAS TRANSPORTATION
Revenues (Millions)..................... $ 358.9 $ 346.6 $ 333.2 $ 293.7 $ 222.5
======== ======== ======== ======== ========
Gas Transported (Bcf)................... 753.7 758.5 749.8 724.9 587.5
======== ======== ======== ======== ========
GAS STORED AT DECEMBER 31 (BCF)......... 407.2 426.2 406.4 427.4 416.4
======== ======== ======== ======== ========
- ----------------------------------------------------------------------------------------------
</TABLE>
*Demand charges and low sales volumes produce an average rate which is not
meaningful.
**Includes transportation charges.
13
<PAGE> 16
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
recently-announced 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.
In early 1997, the Company formed a new nonregulated subsidiary, CNG Retail, to
market 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 PUCO 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
In March 1998, the Western Australia state government announced its acceptance
of a bid totaling approximately $1.7 billion (US$) from a group of companies
including CNG International to own and operate the AlintaGas Dampier-to-Bunbury
Natural Gas Pipeline in Western Australia. CNG International will hold a 33.3%
interest in the pipeline. Other partners in the project include El Paso Energy
Corporation (33.3%), AMP Asset Management (11.1%), Axiom Funds Management
(11.1%) and Hastings Funds Management (11.1%). The purchase is expected to close
in March 1998 and CNG International's investment will be approximately $145
million.
During December 1997, CNG International acquired 12.5% ownership interests in
two gas utility holding companies, Sodigas Pampeana and Sodigas Sur, and a 20%
ownership interest 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. Camuzzi Argentina S.A. will maintain majority ownership interests in
the holding companies. At December 31, 1997, CNG International's investments in
the Argentine holding companies totaled $79.1 million.
14
<PAGE> 17
ITEM 1. BUSINESS (Continued)
In December 1996, CNG International and El Paso Energy Corporation entered into
a joint venture to own and operate the Australian pipeline assets formerly held
by Tenneco Energy. CNG International owns 30% of Epic Energy Pty Ltd. (Epic
Energy), an Australian entity formed to hold the investment's operating assets.
The primary operating assets of the venture include two major long-distance
natural gas pipelines from Australia's Cooper Basin. CNG International's net
investment in Epic Energy totaled $30.9 million at December 31, 1997.
ADDITIONAL USES FOR NATURAL GAS
During 1997, the Company continued its involvement with a number of gas burning
technologies that provide opportunities to improve customer efficiency while
promoting the use of natural gas in markets that are not sensitive to the
weather or economic downturn. The advancement of such technologies appears
beneficial as business entities strive to comply with provisions of the Clean
Air Act, legislation which applies strict anti-pollution standards to factories,
fleet and mass transit vehicles, and electric power plants. The law is likely to
increase demand for natural gas, but the extent thereof will depend on how the
Act is implemented and enforced. Gas demand could also increase as the result of
the Energy Policy Act of 1992 which requires and encourages large vehicle fleets
to operate on alternative fuels such as natural gas.
The Company is also pursuing other technological opportunities, including gas
cooling equipment, fuel cell power generation, coal drying processes and the
promotion of natural gas powered vehicles (NGVs). Fleet operators and mass
transit authorities are using NGVs for both fuel cost efficiencies and to reduce
environmental pollution. Despite the environmental benefits of NGVs, it appears
unlikely that such vehicles will replace a significant number of gasoline
powered vehicles in the near future, given the lack of a nationwide network of
refueling facilities and the current cost of retrofitting vehicles. However, the
Energy Policy Act now requires state fleets and alternate fuel providers in the
nation's 250 largest urban areas to acquire alternative fuel vehicles. A certain
percentage of new light-duty fleet vehicles must be capable of operating on
alternative fuels, which include natural gas.
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 July 1, 1997, CNG Transmission filed a general rate filing with the FERC
requesting an annual revenue increase of $71 million, related surcharges of
approximately $12 million, and permission to establish market-based pricing for
some of its transportation and storage services. The filing seeks to accelerate
recovery of part of the Company's investment in gathering facilities which will
enable CNG Transmission to fully unbundle its gathering facilities by January 1,
2001, in accordance with prior rate case settlements. The filing reflects a
proposed rate of return on equity of 14.5%. On July 31, 1997, the FERC accepted
in part, and rejected in part, the filing. The FERC's actions included
permission to place increased rates into effect January 1, 1998, subject to
refund, the establishment of hearing procedures and rejection of the proposal to
establish market-based rates.
On January 5, 1998, Hope Gas filed with the PSC of West Virginia for a $14.5
million annual revenue increase. The rate increase request is intended to cover
improvements and extensions made to its pipeline system. If approved, the new
rates would become effective November 1, 1998.
15
<PAGE> 18
ITEM 1. BUSINESS (Concluded)
EXECUTIVE OFFICERS OF THE COMPANY (Note 1)
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------
Name, Age and Business Experience
Position (Note 2) During Past Five Years
<S> <C>
- -----------------------------------------------------------------------------------------------
George A. Davidson, Jr. (59) 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 (50) Mr. Westfall was elected to his present position on December
Senior Vice President and 1, 1995. He served as Senior Vice President, Financial from
Chief Financial Officer January 1995 to November 1995. From January 1988 to January
1995, he served as Senior Vice President at CNG
Transmission.
Stephen E. Williams (49) Mr. Williams was elected to his present position on January
Senior Vice President and 1, 1993.
General Counsel
Stephen R. McGreevy (47) Mr. McGreevy was elected to his present position on March 1,
Vice President, Accounting 1993. He served as Controller from January 1986 to March
and Financial Control 1993.
Laura J. McKeown (39) Ms. McKeown was elected to her present position on May 16,
Secretary 1989.
Thomas F. Garbe (45) Mr. Garbe was elected to his present position on March 1,
Controller 1993. He served as Senior Assistant Controller from May 1991
to March 1993.
- -----------------------------------------------------------------------------------------------
</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.
16
<PAGE> 19
ITEM 2. PROPERTIES
GENERAL INFORMATION ON FACILITIES (Maps are on pages 18 and 19.)
The Company's total gross investment in property, plant and equipment was $8.7
billion at December 31, 1997. The largest portion of this investment (59%) is in
facilities located in the Appalachian area. Another significant portion (26%) is
located in the Gulf of Mexico.
Of the $8.7 billion investment, $4.0 billion is in production and gathering
systems, of which 62% is invested in the Gulf of Mexico and the Gulf coast and
23% in the Appalachian area. The Company's production subsidiary, CNG Producing,
accounts for $3.4 billion of the $4.0 billion investment, and CNG Transmission
and the distribution subsidiaries account for the remaining $.6 billion. In
addition to the wells and acreage listed elsewhere in ITEM 2, this investment
includes 6,526 miles of gathering lines which are located almost entirely within
the Appalachian area.
The Company's investment in its gas distribution network includes 30,261 miles
of pipe, exclusive of service pipe, the cost of which represents 61% of the $1.9
billion invested in the total function.
The Company's storage operation, the largest in the industry, consists of 26
storage fields, 332,414 acres of operated leaseholds, 2,066 storage wells and
812 miles of pipe. The investment in storage properties is $699 million,
including $98 million of cushion gas stored.
Of the $1.6 billion invested in transmission facilities, 67% represents the cost
of 6,657 miles of pipe required to move large volumes of gas throughout the
Company's operating area.
The Company has 91 compressor stations with 481,824 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 1997 was 10.1 Bcf on January 18.
17
<PAGE> 20
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, 1997
This map shows the primary operating areas of Consolidated Natural Gas Company
in Ohio, Pennsylvania, Virginia and West Virginia. The map shows the principal
cities served at retail including Cleveland, Akron, Youngstown, Canton, Warren,
Lima, Ashtabula and Marietta in Ohio; Pittsburgh (a portion), Altoona and
Johnstown in Pennsylvania; Norfolk, Newport News and Williamsburg in Virginia;
and Clarksburg and Parkersburg in West Virginia. The map also shows the
general location of Consolidated's pipelines and joint venture pipelines,
including gas delivery connections with customers and gas receipt or delivery
connections with other pipelines. Also shown on the map are the general
locations of certain compressor facilities and underground storage fields.
18
<PAGE> 21
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, 1997
This United States map shows the general areas in which Consolidated conducts
its exploration and production activities. These areas include: the Gulf of
Mexico, offshore Louisiana and Texas; the Gulf Coast Basin; Permian Basin;
Anadarko Basin; Arkoma Basin; Black Warrior Basin; San Juan Basin; Williston
Basin; Michigan Basin; Rocky Mountain Basins and the Appalachian Region. Also
shown is the general location of Consolidated's Canadian exploration and
production properties in Alberta, Canada.
19
<PAGE> 22
ITEM 2. PROPERTIES (Continued)
GAS AND OIL PRODUCING ACTIVITIES
Properties and activities subject to cost-of-service rate regulation are shown
together with non-cost-of-service properties and activities in the statistical
presentations which follow.
COMPANY-OWNED RESERVES
Estimated quantities (net before royalty) of proved gas and oil reserves at
December 31, 1995 through 1997, follow:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
December 31, 1997 1996 1995
- ------------------------------------------------------------------------------------------
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....... 925 1,141 900 1,040 717 985
Cost-of-service*.......... 42 42 43 43 56 56
------ ------ ------ ------ ------ ------
Total.................. 967 1,183 943 1,083 773 1,041
====== ====== ====== ====== ====== ======
Oil Reserves (000 Bbls)**... 37,568 50,627 24,989 50,457 19,838 45,791
====== ====== ====== ====== ====== ======
</TABLE>
* Hope Gas sold all of its remaining gas reserves to CNG Producing during 1996.
At December 31, 1997 and 1996, the Company's remaining cost-of-service gas
reserves were held by Peoples Natural Gas.
** Non-cost-of-service.
- --------------------------------------------------------------------------------
CNG Producing and CNG Transmission file Form EIA-23 with the Department of
Energy. The reserves reported on Form EIA-23 at December 31, 1996, as well as
those which will be reported at December 31, 1997, 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, 1997 1996 1995
- -------------------------------------------------------------------------------------
<S> <C> <C> <C>
Gas Production (Bcf)*....................................... 158 148 107
===== ===== =====
Oil Production (000 Bbls)**................................. 7,312 4,766 3,149
===== ===== =====
</TABLE>
* Includes cost-of-service production of 3, 3 and 4 Bcf for 1997, 1996 and
1995, respectively.
** Includes cost-of-service production of 17,000 barrels in 1995.
- --------------------------------------------------------------------------------
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 1997, 1996 and 1995 was $2.43, $2.46 and $1.89,
respectively. The respective average sales prices for oil were $16.07, $17.60
and $16.04 per barrel. The average production (lifting) cost per Mcf equivalent
of non-cost-of-service gas and oil produced during the years 1997, 1996 and 1995
was $.33, $.32 and $.34, respectively.
20
<PAGE> 23
ITEM 2. PROPERTIES (Continued)
PRODUCTIVE WELLS
The number of productive gas and oil wells in which the Company has an interest
at December 31, 1997, follow:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
Gas Wells Oil Wells
------------- -----------
Gross Net Gross Net
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Non-cost-of-service*........................................ 5,115 4,423 1,023 408
Cost-of-service............................................. 1,436 1,162 -- --
----- ----- ----- ---
Total.................................................. 6,551 5,585 1,023 408
===== ===== ===== ===
- ---------------------------------------------------------------------------------------------
</TABLE>
*Includes 82 gross (23 net) multiple completion gas wells and 21 gross (8 net)
multiple completion oil wells.
ACREAGE
The following table sets forth the gross and net developed and undeveloped
acreage at December 31, 1997:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------
Developed Acreage Undeveloped Acreage
-------------------------- ----------------------
Gross Net Gross Net
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Non-cost-of-service.............. 1,552,177 1,152,879 722,861 456,199
Cost-of-service.................. 386,058 386,058 695 695
--------- --------- ------- -------
Total....................... 1,938,235 1,538,937 723,556 456,894
========= ========= ======= =======
- ----------------------------------------------------------------------------------------------
</TABLE>
Approximately 31% of the foregoing non-cost-of-service undeveloped net acreage
and 100% of the cost-of-service undeveloped net acreage are 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,
1997............................ 4 5 69 2 73 7
1996............................ 4 5 33 1 37 6
1995............................ 4 9 12 1 16 10
- ----------------------------------------------------------------------------------------------
</TABLE>
*Includes Canadian completions: 1997--12 wells, 1996--23 wells and 1995--3
wells.
As of December 31, 1997, 24 gross (10 net) non-cost-of-service wells were in
process of drilling, including wells temporarily suspended. During 1997, the
Company was engaged in waterflood projects in Oklahoma and a gas injection
program in the Rocky Mountains.
GAS PURCHASE CONTRACT RESERVES (AT DECEMBER 31, 1997) AND AVAILABILITY OF
SUPPLY (CALENDAR YEAR 1998)
Gas purchase reserves under contract with independent producers in the
Appalachian area total 262 Bcf at December 31, 1997. In addition, at December
31, 1997, the Company had gas supply contracts with various other producers and
marketers with contract lengths ranging from a few months to eight years. The
volume of gas available to the Company under these supply contracts totals 1,132
Bcf if all volumes are requested. These gas purchase contract reserve and gas
supply contract
21
<PAGE> 24
ITEM 2. PROPERTIES (Concluded)
volume amounts are as contained in the February 11, 1998 report of Ralph E.
Davis Associates, Inc. Of the total 262 Bcf under contract from Appalachian
producers, the volume of gas expected to be purchased in 1998 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 1,132 Bcf available under contract from other producers and marketers,
approximately 738 Bcf of gas will be available to the Company in 1998, assuming
all volumes are requested.
The Company anticipates that substantial volumes of gas will be available for
purchase during 1998 on the spot market. Due to the nature of spot market
transactions, the volumes of such gas available to the Company in 1998 cannot be
reasonably estimated. However, for the calendar year 1998, 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.
The volumes expected to be available from Company-owned wells in 1998 amount to
171 Bcf of gas and 9,016 thousand barrels of oil. Included in these amounts are
169 Bcf of gas and 9,016 thousand barrels of oil expected to be available from
the Company's non-cost-of-service properties. The foregoing volumes are based on
the Company's current production estimates of proved gas and oil reserves.
Actual production may differ from these amounts due to a number of factors,
including changing market conditions and the 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 17, page 43. In addition, CNG Producing has self-disclosed to the
Environmental Protection Agency potential violations of its annual discharge
monitoring reports for certain of its Gulf of Mexico operations. As a result of
this self-disclosure, a Consent Agreement and Consent Order (Docket No.
VI-98-1618) is expected to be finalized in March 1998 which alleges that CNG
Producing violated its National Pollution Discharge Elimination System permit,
which CNG Producing does not admit or deny. A civil penalty of $137,500 was
assessed and CNG Producing agreed to comply with the conditions of the permit.
No endangerment to health or the environment resulted from these alleged
violations.
Reference is made to "Rate Matters," page 15, 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 52.
22
<PAGE> 25
ITEM 6. SELECTED FINANCIAL DATA
This information is hereby incorporated by reference to page 18 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 17 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 15.
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 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 48; Quarterly Financial
Data--Note 20(B), page 51.
FINANCIAL STATEMENTS
This information is hereby incorporated by reference to pages 19 through 52 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 16 of this Report.
ITEM 11. EXECUTIVE COMPENSATION
This information is hereby incorporated by reference to the Company's definitive
proxy statement filed with the 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.
23
<PAGE> 26
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
1997, the year for which this Form 10-K is being filed.
On January 16, 1998, the Company filed a Current Report on Form 8-K with the SEC
regarding the impairment of Canadian oil producing properties.
On February 18, 1998, the Company filed a Current Report on Form 8-K with the
SEC regarding two press releases concerning earnings, reserves, production and
other matters.
On March 4, 1998, the Company filed a Current Report on Form 8-K with the SEC
regarding a press release concerning the Company's participation in an
international investment.
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........................... 19
Consolidated Statement of Income for the Years 1995 through 21
1997......................................................
Consolidated Balance Sheet at December 31, 1996 and 1997.... 22
Consolidated Statement of Cash Flows for the Years 1995 24
through 1997..............................................
Notes to Consolidated Financial Statements.................. 25
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 17, 1998, appearing on page 19 of Appendix I to the
Consolidated Natural Gas Company proxy statement for the 1998 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
Prospectuses.
PRICE WATERHOUSE LLP
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
March 19, 1998
24
<PAGE> 27
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
EXHIBITS
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
SEC
Exhibit
Number Description of Exhibit
---------------------------------------------------------------------
<C> <S>
(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 February 17, 1998, are filed herewith
(4) Instruments Defining the Rights of Security Holders,
Including Indentures:
(4A) (1) Indentures of Consolidated Natural Gas Company:
Indentures of Consolidated Natural Gas Company are
incorporated by reference to previously filed material
as indicated on the list filed herewith
(2) Note Purchase Agreement of Virginia Natural Gas:
Note Purchase Agreement dated as of January 1, 1989,
between Virginia Natural Gas, Inc. and the Aid
Association for Lutherans relating to $20,000,000
principal amount of 9.94% Senior Notes, Series A, due
January 1, 1999 (incorporated by reference to Exhibit
B-1 to the Application-Declaration of Consolidated
Natural Gas Company on Form U-1, File No. 70-7667)
(4B) Section 203 of the Delaware General Corporation Law,
"Business Combinations With Interested Stockholders,"
effective February 2, 1988 (incorporated by reference
to Exhibit (4B) filed with Consolidated Natural Gas
Company's Form 10-K for the year ended December 31,
1987, File No. 1-3196). Other portions of the Delaware
General Corporation Law affecting security holder
rights are considered routine and are not filed
hereunder
(4C) Description of Consolidated Natural Gas Company Rights
Agreement, is hereby incorporated by reference to Exhibit 1
to the Current Report on Form 8-K filed on January 23,
1996
(10) Material Contracts: The following exhibits are filed with
this Form 10-K by being incorporated by reference to their
filing in the Company's Forms 10-K for previous years. The
following table indicates for each of such exhibits the Form
10-K, File No. 1-3196, where such exhibit was filed.
Exhibits not included in this table are filed herewith or
incorporated by reference to another source as indicated
below.
Form 10-K Exhibit Number Reporting Year of Form 10-K
----------------- ---------------------------
(10A), (10B), (10C), (10E), (10G) 1987
(10H), (10I) 1989
(10J), (10L) 1994
(10D), (10K), (10N) 1995
(10M), (10O), (10P), (10Q) 1996
(10A) Form of Split Dollar Insurance Agreement between Consolidated
Natural Gas Company and certain employees and Directors
</TABLE>
25
<PAGE> 28
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>
(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,
is filed herewith
(10G) Consolidated Natural Gas Company Cash Incentive
Bonus Deferral Plan
(10H) Form of Change of Control Employment Agreement
between Consolidated Natural Gas Company and certain
employees
(10I) Form of Change of Control Salary Continuation
Agreement between Consolidated Natural Gas Company
and certain employees
(10J) Consolidated Natural Gas Company Annual Executive
Incentive Program, as amended December 13, 1994.
Attachment C as amended February 18, 1997, is
filed herewith
(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
</TABLE>
26
<PAGE> 29
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>
(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, 1995 through 1997, 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
1993-1997, 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 11, 1998, 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, 1997, are filed
herewith
(23B) Consent of Price Waterhouse 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, 1998," is filed herewith
- ----------------------------------------------------------------------
</TABLE>
27
<PAGE> 30
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 19, 1998
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 19, 1998.
/S/ GEORGE A. DAVIDSON, JR. /S/ RAY J. GROVES
- ------------------------------ --------------------------
(George A. Davidson, Jr.) (Ray J. Groves)
Chairman of the Board Director
and Chief Executive Officer,
and Director
/S/ D. M. WESTFALL /S/ PAUL E. LEGO
- ----------------------------- --------------------------
(D. M. Westfall) (Paul E. Lego)
Senior Vice President Director
and Chief Financial Officer
/S/ S. R. MCGREEVY /S/ MARGARET A. MCKENNA
- ----------------------------- --------------------------
(S. R. McGreevy) (Margaret A. McKenna)
Vice President, Accounting Director
and Financial Control
/S/ WILLIAM S. BARRACK, JR. /S/ STEVEN A. MINTER
- -------------------------- --------------------------
(William S. Barrack, Jr.) (Steven A. Minter)
Director Director
/S/ J. W. CONNOLLY /S/ RICHARD P. SIMMONS
- -------------------------- --------------------------
(J. W. Connolly) (Richard P. Simmons)
Director Director
/S/ RAYMOND E. GALVIN
- --------------------------
(Raymond E. Galvin)
Director
28
<PAGE> 31
EXHIBIT INDEX
- --------------------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- --------------------------------------------------------------------------------
(3) Articles of Incorporation and By-Laws:
(3A) Certificate of Incorporation of Consolidated Natural Gas
Company, restated October 4, 1990 (incorporated by reference
to Exhibit A-1 to the Application-Declaration of Consolidated
Natural Gas Company on Form U-1, File No. 70-7811), 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
February 17, 1998, are filed herewith
(4) Instruments Defining the Rights of Security Holders,
Including Indentures:
(4A) (1) Indentures of Consolidated Natural Gas Company:
Indentures of Consolidated Natural Gas Company are
incorporated by reference to previously filed material as
indicated on the list filed herewith
(2) Note Purchase Agreement of Virginia Natural Gas:
Note Purchase Agreement dated as of January 1, 1989, between
Virginia Natural Gas, Inc. and the Aid Association for
Lutherans relating to $20,000,000 principal amount of 9.94%
Senior Notes, Series A, due January 1, 1999 (incorporated by
reference to Exhibit B-1 to the Application-Declaration of
Consolidated Natural Gas Company on Form U-1, File No.
70-7667)
(4B) Section 203 of the Delaware General Corporation Law,
"Business Combinations With Interested Stockholders,"
effective February 2, 1988 (incorporated by reference to
Exhibit (4B) filed with Consolidated Natural Gas Company's
Form 10-K for the year ended December 31, 1987, File
No. 1-3196). Other portions of the Delaware General
Corporation Law affecting security holder rights are
considered routine and are not filed hereunder
(4C) Description of Consolidated Natural Gas Company Rights
Agreement, is hereby incorporated by reference to Exhibit 1
to the Current Report on Form 8-K filed on January 23, 1996
(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.
<TABLE>
<CAPTION>
Form 10-K Exhibit Number Reporting Year of Form 10-K
------------------------ ---------------------------
<S> <C>
(10A), (10B), (10C), (10E), (10G) 1987
(10H), (10I) 1989
(10J), (10L) 1994
(10D), (10K), (10N) 1995
(10M), (10O), (10P), (10Q) 1996
</TABLE>
(10A) Form of Split Dollar Insurance Agreement between Consolidated
Natural Gas Company and certain employees and Directors
<PAGE> 32
- --------------------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- --------------------------------------------------------------------------------
(10) Material Contracts (Continued):
(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, is filed herewith
(10G) Consolidated Natural Gas Company Cash Incentive Bonus
Deferral Plan
(10H) Form of Change of Control Employment Agreement between
Consolidated Natural Gas Company and certain employees
(10I) Form of Change of Control Salary Continuation Agreement
between Consolidated Natural Gas Company and certain
employees
(10J) Consolidated Natural Gas Company Annual Executive Incentive
Program, as amended December 13, 1994. Attachment C as
amended February 18, 1997, is filed herewith
(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> 33
- --------------------------------------------------------------------------------
SEC
Exhibit
Number Description of Exhibit
- --------------------------------------------------------------------------------
(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, 1995 through 1997, 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 1993-1997, 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 11, 1998, 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, 1997, are filed herewith
(23B) Consent of Price Waterhouse 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, 1998," is filed herewith
- --------------------------------------------------------------------------------
<PAGE> 1
EXHIBIT 3B
CONSOLIDATED NATURAL GAS COMPANY
BYLAWS
AS LAST AMENDED
FEBRUARY 17, 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.
1
<PAGE> 3
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 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
2
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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 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 10(A) 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
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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 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.
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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.
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
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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 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.
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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.
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
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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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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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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
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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.
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
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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. 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
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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.
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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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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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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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)
The Chase Manhattan Bank (National Association)
Indenture dated as of December 15, 1990 (Exhibit (4A)(1) to
Consolidated Natural Gas Company's Form 10-K for the year ended
December 31, 1990, File No. 1-3196)
<PAGE> 1
EXHIBIT 10F
Approved February 18, 1997
Effective January 1, 1997
DEFERRED COMPENSATION PLAN FOR DIRECTORS
OF
CONSOLIDATED NATURAL GAS COMPANY
ARTICLE I
1.1 Name and Purpose. The name of this plan is the "Deferred
Compensation Plan for Directors of Consolidated Natural Gas Company" (the
"Plan"). Its purpose is to provide non-employee Directors of the Company with
increased flexibility in timing the receipt of board service fees and to assist
the Company in attracting and retaining qualified individuals to serve as
Directors.
1.2 Definitions. Whenever used in the Plan, the following terms shall
have the meaning set forth below:
(a) "Company" means Consolidated Natural Gas Company.
(b) "Closing Price" means the New York Stock Exchange ("NYSE")
closing price of the Company's Common Stock as reported in The Wall Street
Journal, for the day at issue or the previous trading day if the day at issue is
not a trading day.
(c) "Common Stock" means the Common Stock ($2.75 par value) of
the Company.
(d) "Compensation" means all remuneration paid to a Director for
service as a Director other than reimbursement for expenses and shall include,
but not be limited to, annual cash retainer, fees for attendance at meetings and
any Stock Credits earned and elected by the Director; provided, however, that
for purposes of this Plan, Compensation shall not include any restricted stock,
stock options or other stock based awards.
(e) "Director" means any individual serving on the Board of
Directors of the Company who is not and has never been an employee of the
Company or any of its subsidiaries or affiliates.
(f) "Participant" means a Director who has filed an election to
participate under Section 3.1 with regard to any Plan Year.
(g) "Plan Administrator" means the Nominating Committee of the
Board of Directors, of the Company or such other Board Committee with
responsibility for review of Director's compensation.
(h) "Plan Year" means the calendar year.
(i) "Secretary" means the Secretary of the Corporation.
(j) "Stock Credit" means a credit that is equivalent to one share
of CNG Common Stock.
ARTICLE II
2.
2.1 Participation in the Plan. Any individual who is a non-employee
Director may
<PAGE> 2
participate in the Plan. Notwithstanding the foregoing, the Board of Directors,
in its sole discretion, may withhold all or a part of the value of any
Director's Account if such Director engaged in any act of misconduct or
otherwise engaged in conduct contrary to the best interests of the Company.
ARTICLE III
3.1 Election to Participate.
(a) Generally. Each Director may elect annually to have payment
of all or any portion of his or her Compensation for that Plan Year deferred. If
the Participant ceases to be a Director, the Participant's account balance will
be paid in accordance with Section 3.3 hereof as soon as practicable following
the end of the Plan Year during which the Participant ceased to be a Director.
No election to defer under this Plan may be made after December 31 of the year
preceding the Plan Year during which Compensation would otherwise be paid or,
with respect to the first Plan Year a Director becomes a director, within thirty
days from the date a Director becomes a Director. An election to defer any
Compensation shall be in writing and shall be received by the Secretary in a
form prescribed by the Plan Administrator. An election to defer shall be
irrevocable by the Director and shall be effective only for the Plan Year
immediately following the date on which it was filed. In the absence of a signed
Director's election for the Plan Year to defer delivered to the Secretary, no
Compensation will be deferred under this Plan.
(b) Special Election. Each Director serving as a member of the Board of
Directors on January 1, 1997 (a "Current Director") will have the option of
electing a special one-time election (a "Special Credit") which will result from
the Current Director's waiver of the post-retirement retainer currently provided
upon a Director's normal retirement at age 70. The amount of Special Credit will
be determined based on actuarial assumptions established by the Plan
Administrator, and is designed to preserve the current value of the Current
Director's post retirement retainer benefit assuming retirement at age 70.
This Special Credit (if elected) may be taken in restricted stock
pursuant to and under the 1997 Stock Incentive Plan, or may be deferred as Stock
Credits in this Plan for Directors. If Stock Credits are elected, they will be
applied in accordance with Section 3.2 hereof. Conversion into "Stock Credits"
in this Plan is determined by dividing the dollar amount of the Special Credit
by the closing price of a share of the Common Stock of the Company on the NYSE
on the date this revised Deferred Compensation Plan for Directors is approved by
the Board of Directors of the Company.
The Special Credit elections are to be made on a form, and utilizing
procedures, established by the Plan Administrator.
3.2 Mode of Deferral. Payment of a Participant's Compensation may be
deferred by means of a Cash Credit, a Stock Credit, or a combination of the two
as the Participant shall elect in writing at the same time as the election
provided for in Section 3.1(a). Additional Stock Credits to a Director's account
may also result from his or her election in accordance with Section 3.1(b)
hereof. If a Participant makes an election to defer, but fails to make an
election as to type of deferral, he or she shall be deemed to have elected
deferral by means of a Cash Credit. Cash Credits and Stock Credits shall be
recorded in accounts established in each Participant's name on the books of the
Company.
(a) Cash Credits. If the deferral is wholly or partly by means of
a Cash
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<PAGE> 3
Credit, the Participant's Cash Credit account shall be credited with the dollar
amount of Compensation deferred by means of a Cash Credit at the time it is
earned. As of the last day of each calendar quarter, the Participant's Cash
Credit account shall be credited with an interest equivalent in an amount
determined by applying to the current balance in the account an interest rate
for such quarter which shall be equal to the closing prime commercial rate on
that date at the Chase Manhattan Bank (National Association) located in New York
City.
(b) Stock Credits. If the deferral is wholly or partly by means
of a Stock Credit, the Participant's Stock Credit account shall be credited with
a Common Stock equivalent equal to the number of shares of Common Stock
(including fractions of a share) that could have been purchased with the amount
of the Compensation deferred at the Closing Price of Common Stock on the day the
Compensation is earned. As of the date any dividend is paid to shareholders of
Common Stock, the Participant's Stock Credit account shall also be credited with
an additional Stock Credit equivalent to the number of shares of Common Stock
(including fractions of a share) that could have been purchased at the Closing
Price of Common Stock on such date with the dividend paid on the number of
shares of Common Stock to which the Participant's Stock Credit account is then
equivalent. In case of dividends paid in property, the dividend shall be deemed
to be the fair market value of the property at the time of distribution of the
dividend, as determined by the Plan Administrator.
3.3 Distribution of Credits.
(a) Unless a Participant has elected a different number of
installments as provided below, payment of a Participant's account balance shall
be made as a single sum payment as soon as practicable following the end of the
Plan Year in which the Participant ceases to be a Director.
At the election of the Participant made in writing and delivered
to the Plan Administrator no later than six months prior to termination of the
Participant's service as a Director, distribution of the Participant's account,
shall be made in any number of annual installments not exceeding ten annual
installments. Installments will commence as soon as practicable following the
end of the Plan Year in which the Participant ceases to be a Director. Each
installment will be paid in a single sum payment. Any such election, unless made
irrevocable by its terms, may be changed by written notice to the Plan
Administrator at any time prior to six months prior to a Participant's
termination of service as a Director. Any elections made pursuant to this
Section 3.3 must be approved by the Plan Administrator, which may accept or
reject the election in its sole discretion. No election will be accepted if it
is made in the same Plan Year as the termination of service of the Director.
At the written request of a Participant, the Plan Administrator,
in its sole discretion, may authorize payment of all or a part of the
Participant's Cash Credit account balance prior to his or her termination of
service as a Director or acceleration of payment of any installments if the Plan
Administrator in its sole discretion finds that continued deferral will result
in financial hardship to the Participant.
(b) Distribution of a Participant's Cash Credit account balance
shall be made in cash. Distribution of a Participant's Stock Credit account
balance shall also be
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<PAGE> 4
made in cash with the amount of the distribution determined by multiplying the
number of Stock Credits associated with the installment payment by the Closing
Price of Common Stock on the last business day in December immediately prior to
the Plan Year in which the installment is to be paid.
(c) A Participant may not select a different number of
distribution installments for the Cash Credit and Stock Credit accounts.
3.4 Adjustment. If at any time the number of outstanding shares of
Common Stock shall be changed as the result of any stock dividend, subdivision
or reclassification of shares, the number of shares of Common Stock to which
each Participant's Stock Credit account is equivalent shall be changed in the
same proportion as the outstanding number of shares of Common Stock is changed.
In the event the Company shall at any time be consolidated with or merged into
any other corporation and holders of the Company's Common Stock receive common
shares of the resulting or surviving corporation, there shall be credited to
each Participant's Stock Credit account, in place of the shares then credited
thereto, a stock equivalent determined by multiplying the number of common
shares of stock given in exchange for a share of Common Stock upon such
consolidation or merger, by the number of shares of Common Stock to which the
Participant's account is then equivalent. If in such a consolidation or merger,
holders of the Company's Common Stock shall receive any consideration other than
common shares of the resulting or surviving corporation, the Plan Administrator,
in its sole discretion, shall determine the appropriate change in Participants'
accounts.
3.5 Installment Amount. In the event a Participant has elected to
receive distribution of his or her account balance in more than one annual
installment, the amount of each installment shall be determined by multiplying
the current balance in the accounts as determined under Section 3.2, by a
fraction, the numerator of which is one, and the denominator of which is the
number of installments yet to be paid.
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<PAGE> 5
3.6 Distribution Upon Death. In the event of the death of a
Participant, whether before or after cessation of service as a Director, any
Cash Credit account balance and Stock Credit account to which he or she was
entitled, shall be automatically converted to cash and distributed in a single
payment sum to such person or persons or the survivors thereof, including
corporations, unincorporated associations or trusts, as the Participant may have
designated. All such designations shall be made in writing, signed by the
Participant and delivered to the Secretary. A Participant may from time to time
revoke or change any such designation by written notice to the Secretary. If
there is no unrevoked designation on file with the Plan Administrator at the
time of the Participant's death, or if the person or persons designated therein
shall have all predeceased the Participant or otherwise ceased to exist, such
distributions shall be made to the Participant's estate. Any distribution under
this Section 3.6 shall be made as soon as practicable following notification to
the Plan Administrator of the Participant's death. In this case, the
Participant's Stock Credit account shall be converted to cash by multiplying the
number of Stock Credits or fractions thereof in the Participant's account by the
Closing Price of Common Stock on the last business day of the month immediately
preceding the date of death.
3.7 Withholding Taxes. The Company shall deduct from all distributions
under the Plan any taxes required to be withheld by federal, state, or local
governments.
ARTICLE IV
4.1 Plan Administrator. The Plan Administrator shall have full power
and authority to administer and interpret the Plan including the power to
promulgate forms to be used with regard to the Plan, the power to promulgate
rules of Plan administration, the power to settle any disputes as to rights or
benefits arising from the Plan, and the power to make such decisions or take
such action as the Plan Administrator, in its sole discretion, deems necessary
or advisable to aid in the proper operation, maintenance and administration of
the Plan. The Plan Administrator's interpretation of the Plan, and all actions
taken within the scope of its authority, shall be final and binding on the
Company and the Participants.
4.2 Accounts.
(a) The Plan Administrator shall cause an account to be kept for
each Participant. The account shall reflect the amounts as determined under
Section 3.2 hereof.
(b) Any account shall be considered a bookkeeping account
only, kept solely for the convenience of the Plan. The keeping of an account
shall not in any way be interpreted to mean that a Director has any right to
such account or that there are assets set aside for such account.
4.3 Claims Procedure.
(a) All claims for benefits shall be in writing and shall be
filed with the Plan Administrator.
(b) If the Plan Administrator wholly or partially denies a
Participant's or other claimant's claim for benefits, the Plan Administrator
shall within 90 days after the Plan's receipt of the claim give the claimant
written notice setting forth in understandable language: (i) the specific
reason(s) for the denial; (ii) specific reference to pertinent Plan provisions
on which the denial is based; (iii) a description of any additional material or
information which must be submitted to perfect the claim; and (iv) an
explanation of the Plan's review procedure, as set forth below.
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<PAGE> 6
(c) The Participant or other claimant shall have 60 days after
the day on which such written notice of denial is mailed to the Participant or
other claimant in which to apply to the Plan Administrator in writing for a
review of the denial of the claim. In connection with such review, the
Participant or other claimant (or representative) shall be afforded a reasonable
opportunity to review pertinent documents, and may submit issues and comments in
writing with the application for review.
(d) The Plan Administrator shall issue its decision on review
within 60 days after the Plan's receipt of the written request for review,
unless special circumstances require an extension to not later than 120 days
after receipt of the written request for review. Written notice of such
extension shall be furnished to the Participant or other claimant prior to the
commencement of the extension. The decision shall (i) be in writing, (ii) be in
understandable language, (iii) set forth specific reasons for the decision, and
(iv) contain specific references to pertinent Plan provisions on which the
decision is based.
ARTICLE V
5.1 Funding. Benefits payable under this Plan will be funded under the
Trust Agreement between Consolidated Natural Gas Company and Mellon Bank, N.A.,
effective June 1, 1995, or any successor or other similar trust (the "Rabbi
Trust"). Notwithstanding this, benefits will be considered for tax purposes
unfunded and unsecured, and paid by the Company out of its general assets. The
rights of a Director or other claimant and anyone claiming through said Director
or other claimant shall therefore be those of an unsecured general creditor of
the Company. No trust or security interests are created by this document. Any
funding as outlined above may be discontinued by the Company at any time the
Company concludes that adverse tax or other consequences may result.
ARTICLE VI
6.1 Non-Alienation of Benefits. No benefit under the Plan shall be
subject in any manner to anticipation, alienation, sale, transfer, assignment,
pledge, encumbrance, or charge; and any attempt to do so shall be void. No such
benefit shall, prior to receipt thereof by the Participant, be in any manner
liable for or subject to the debts, contracts, liabilities, engagements, or
torts of the Participant.
ARTICLE VII
7.1 Delegation of Administrative Duties. Administrative duties imposed
by this Plan may be delegated by the Plan Administrator.
7.2 Governing Law. This Plan shall be governed by the laws of the State
of Delaware.
7.3 Intent of Plan. It is intended that the Plan and any and all
transactions occurring thereunder be exempt from Section 16 of the Securities
Exchange Act of 1934 (the "Exchange Act") as a cash-only plan not involving an
equity security of the Company pursuant to Rule 16a-1(c)(3) of the regulations
promulgated under the Exchange Act and effective May 1, 1991. The Plan
Administrator shall interpret and administer the Plan in accordance with this
intent.
ARTICLE VIII
8.1 Amendment and Termination. While the Company intends to maintain
this Plan indefinitely, the Company reserves the right to amend and/or terminate
it at any time for whatever reasons it may deem appropriate.
8.2 Contractual Obligation. Notwithstanding Section 8.1, the Company
hereby makes a contractual commitment to pay the benefits under this Plan. No
Plan amendment or termination shall reduce benefits which have accrued prior to
the date of the amendment.
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<PAGE> 7
8.3 No Employment or Nomination Rights. Nothing contained in this Plan
shall be construed as a contract of employment between the Company and any
Director, or as a right of any Director to be continued as a Director of the
Company, or to be nominated for reelection as a Director, or as a limitation of
the right of the Company or its shareholders to discharge any of its Directors
at any time with or without cause.
8.4 Binding on Successors. The Plan shall be binding upon and inure to
the benefit of the Company, its successors and assigns, and each Participant and
his or her heirs, executors, administrators and legal representatives.
8.5 Change in Control. Upon a Change in Control, as defined in the
Rabbi Trust, the Company shall, as soon as possible, but in no event longer than
30 days following the Change in Control, make an irrevocable contribution to the
Rabbi Trust in an amount that is sufficient to fully fund the Plan, i.e.,
provide the Rabbi Trust with funds so that each Plan participant or beneficiary
will receive the benefits to which Plan participants or their beneficiaries
would otherwise be entitled pursuant to the terms of the Plan as of the date on
which the Change in Control occurred.
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<PAGE> 1
EXHIBIT 10J
CONSOLIDATED NATURAL GAS COMPANY
EXECUTIVE INCENTIVE DEFERRAL PLAN
EFFECTIVE 12/13/94
(AMENDED EFFECTIVE FEBRUARY 18, 1997)
<PAGE> 2
CONSOLIDATED NATURAL GAS COMPANY
EXECUTIVE INCENTIVE DEFERRAL PLAN
TABLE OF CONTENTS
Section Page
- ------- ----
1. Purpose 3
2. Definitions 3
3. Eligibility 3
4. Deferral of Awards 4
5. Payment of Deferred Amounts 6
6. Administration 8
7. General Provisions 9
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<PAGE> 3
CONSOLIDATED-NATURAL GAS COMPANY
EXECUTIVE INCENTIVE DEFERRAL PLAN
1. Purpose
The purpose of the Consolidated Natural Gas Company Executive Incentive Deferral
Plan (the "Plan") is to offer each employee of the Company who is eligible to
participate in the Consolidated Natural Gas Company Annual Executive Incentive
Program (the "Program") the opportunity to defer receipt of awards that may be
made under the Program until after termination of employment and to earn
appropriate additional compensation during employment and thereafter with
respect to such deferred awards. THE PROGRAM SHALL ALSO INCLUDE ANY PAYMENT
WHICH IS REQUIRED TO BE DEFERRED BY THE TERMS OF SUCH PAYMENT UNDER THIS PLAN,
OR ANY PAYMENT, THE TERMS OF WHICH PROVIDE THAT THE PARTICIPANT, AT HIS OR HER
ELECTION, MAY DEFER UNDER THE PLAN.
2. Definitions
Whenever used in the Plan, the following terms shall have the meaning
set forth below:
(a) "Closing Price" means the closing price per share of the
Company's Common Stock on the composite tape of New York Stock
Exchange securities transactions as reported in The Wall
Street Journal, for the day at issue or the nearest previous
trading day if no trade is reported for the day at issue.
(b) "Company" means Consolidated Natural Gas Company.
(c) "Committee,' means the Compensation and Benefits Committee of
the Board of Directors of the Company.
(d) "Common Stock" means the Common Stock ($2.75 par value) of the
Company.
(e) "Insider" means those employees of the Company who have been
determined by the Board of Directors of the Company to be an
"officer" of the Company within the meaning of Rule 16a-l(f)
for purposes of Section 16 of the Securities and Exchange Act
of 1934.
(f) "Stock Credit" means a credit that is equivalent to one share
of Company Common Stock.
(g) "Plan Year" means the calendar year.
3. Eligibility
All employees of the Company who are eligible to participate in the
Program are eligible to participate in the Plan.
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<PAGE> 4
4. Deferral of Awards
(a) Each eligible employee may elect to participate in the Plan
(the "Participant") and have all or a specified percentage of
the cash portion or the stock portion of the award that may be
made to such Participant under the Program for services in a
subsequent calendar year deferred under the Plan and paid in
cash as hereafter provided. FOR PURPOSES OF THIS PLAN, "AWARD"
SHALL ALSO INCLUDE ANY OTHER COMPENSATION, INCLUDING BASE PAY,
RECEIVED BY A PARTICIPANT.
(b) An election to defer an award shall be made in writing on a
form supplied by the Company and shall be filed with the
Company by January 31 of the calendar year in which services
will be performed for such award (a "Service Year"). The
Participant must also elect the portion of his or her award he
or she wishes to receive in stock, by such date. However, any
person who is hired or promoted into the class of employees
eligible to participate in the Program, on or after February 1
of any Service Year, may elect to defer any award that may be
made for such Service Year by filing an election to that
effect within 30 days after his or her date of hire or
promotion. An election to defer an award for any Service Year
shall become effective and irrevocable on January 31 of such
Service Year (or, in a case of a newly hired or promoted
employee, upon expiration of 30 days after his or her date of
hire or promotion), and shall also apply to awards for each
subsequent Service Year through and including any Service Year
in which the participant files either a written revocation of
such election or a new deferral election in accordance with
the provisions of this Section 4. Any such written revocation
or new deferral election shall apply only to awards for
Service Years subsequent to the Service Year in which such
revocation or new deferral election is filed with the Company,
and shall become effective and irrevocable on January 31 of
the first such subsequent Service Year.
(c) Any provision of Section 4(b) above to the contrary
notwithstanding, no deferral election shall apply to an award
for any Service Year in which occurs a "Change in Control" of
the Company or to an award for any subsequent Service Year.
For purposes of this Plan, a "Change in Control" of the
Company means a change in control of a nature that would be
required to be reported in response to Item 1(a) of Schedule
14A of Regulation 14A promulgated under the Securities
Exchange Act of 1934 as in effect on the effective date of
this Plan; provided that, without limitation, such a Change in
Control shall be deemed to have occurred if and when any
"Person" (as such term is used in Sections 13(d) and 14(d)
(2) of the Securities Exchange Act of 1934) is or becomes a
beneficial owner, directly or indirectly, of securities of the
Company representing twenty percent (20%) or more of the
combined voting power of the Company's then outstanding
securities or (ii) during any period of 24 consecutive months
commencing before or after the effective date of this Plan,
individuals who at the beginning of such 24-month period were
directors of the Company cease for any reason (other than
death, disability, or retirement in accordance with the
Company's policy relating to retirement of
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<PAGE> 5
directors in effect on the date of this Plan) to constitute at
least a majority of the Board of Directors of the Company.
(d) An award (or percentage thereof) deferred in accordance with
the provision above of this Section 4 shall be credited on the
books of the Company, on the same date on which it would
otherwise have been paid, to a cash credit account or a stock
credit account (defending upon the portion of the award
deferred) and held in the name of the Participant.
Participants in the Plan shall have the rights of unsecured
general creditors of the Company with respect to amounts
payable under the Plan. The Company may provide for payment of
amounts payable under the Plan out of the Company's general
assets. Alternatively, the Company may provide, in whole or in
part, for payments of amounts payable under the Plan from the
assets of a trust established for such purpose, and to the
extent of such funding, payment of amounts due under the Plan
shall be made from such trust and shall pro tanto discharge
the Company's liability for payment under the Plan. However,
no such trust shall place assets beyond the reach of the
creditors, in the event of insolvency or bankruptcy, of the
participating company on whose account assets are held under
such trust.
(e) Amounts equivalent to interest ("Interest Equivalents") shall
accrue quarterly on deferred cash awards previously credited
to a Participant's cash credit account in accordance with
Section 4(d) above and on Interest Equivalents previously
credited to a Participant's account in accordance with this
Section 4(e). Such Interest Equivalents shall be equal to the
product of
(i) the rate of interest quoted and published by the
Chase Manhattan Bank, N. A. for prime commercial
loans on the last business day of the calendar
quarter, and
(ii) the Participant's average daily cash credit account
balance during such calendar quarter.
Interest Equivalents computed in accordance with the preceding
sentence for any calendar quarter shall be added to the
Participant's cash credit account balance as of the first day
of the next succeeding calendar quarter. However, any
provision above of this Section 4(e) to the contrary
notwithstanding, Interest Equivalents for the calendar quarter
in which falls the date on which a Participant's cash credit
account balance (or portion thereof remaining unpaid) is
payable in full (the "Final Payment Date" in the "Final
Calendar Quarter") shall be paid to, rather than credited to
the account of, the Participant and shall be equal to the
product of
(A) The rate of interest quoted and published by the
Chase Manhattan Bank, N. A. for prime commercial
loans on the last business day of the calendar
quarter immediately preceding the Final Calendar
Quarter which coincides with the Final Payment Date
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<PAGE> 6
(B) The Participant's average daily cash credit account
balance during the entire Final Calendar Quarter
(with such balance for each day following the Final
Payment Date being deemed to be zero, and such
balances included in the calculation of the average
daily account balance).
(f) If the deferral is wholly or partly the stock portion of
Participant's award, the Participant's Stock Credit account
shall be credited with Common Stock equivalents equal to the
number of shares of Common Stock (including fractions of a
share to the nearest ten thousandth) that Participant would
have received had he not elected to defer the stock portion of
his award. As of the date any dividend is paid to holders of
Common Stock, the Participant's Stock Credit account shall
also be credited with additional Common Stock equivalents
equal to the number of shares of Common Stock (including
fractions of a share to the nearest ten thousandth) that could
have been purchased at the Closing Price of Common Stock on
such date with the dividend paid on the number of shares of
Common Stock to which the Participant's Stock Credit account
is then equivalent ("Dividend Equivalents"). In case of
dividends paid in property, the dividend shall be deemed to be
the fair market value of the property at the date of
distribution of the dividend, as determined by the Committee.
The amount of Stock Credits credited to each Participant's
Stock Credit account shall be appropriately adjusted upon the
occurrence of any stock split or reverse stock split. [In the
event of any other extraordinary transaction affecting the
Company's Common Stock after which Stock will no longer be
registered under Section 12 of the Securities Exchange Act of
1934, Stock Credits credited to each Participant's Stock
Credit account shall be converted into cash equivalents of
equal value at the date of such transaction, with Interest
Equivalents credited thereafter in the manner provided in
Section 4(e).
(g) A Participant who is not an Insider Participant who has
previously elected to defer any stock portion of an award may,
at any one time prior to his termination of employment but
only once, elect to transfer, the balance of his Stock Credit
account to his cash credit account. The date on which such
transfer shall occur shall be the date on which the Employee
Benefits Department of the Company receives Participant's
election to convert his Stock Credit account to his cash
credit account. Upon effectiveness of such transfer, an amount
shall be credited to the Participant's cash credit account
equal to the number of Stock Credits then credited to the
Participant's Stock Credit account multiplied by the Closing
Price of Common Stock on the business day immediately
preceding the date of transfer, and the balance of the
Participant's Stock Credit account shall be reduced to zero.
(h) A Participant's interest under the Plan shall be deemed to be
fully vested at all times and nonforfeitable.
5. Payment of Deferred Amounts
(a) Subject to the provisions below of this Section 5, the
Participant may elect to have the amounts deferred in the
Participant I s cash credit [and] (and/or] Stock Credit
accounts
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<PAGE> 7
paid in from one to ten annual installments commencing either
on the date on which he or she shall cease to be an employee
of the Company, or as soon as practicable after the January 1
next following such date, and with installments continuing to
be payable as soon as practicable after the first day of
January of each year thereafter. The election authorized by
this Section 5(a) is a one time irrevocable election which
must be made at the same time the Participant initially elects
to participate in the Plan pursuant to Section 4 hereof and
shall apply to all future deferrals made hereunder; provided,
however, that, any provision of this Section 5(a) to the
contrary notwithstanding, (i) if a Participant should fail for
any reason to make an election under the foregoing provisions
of this Section 5 (a), all amounts deferred shall be paid in
one installment on or as soon as practicable after January 1
following the date on which he or she shall cease to be an
employee of the Company, unless clause (ii) below applies, in
which case payment shall be made in accordance therewith; and
(ii) if a Participant's employment with the Company terminates
for any reason other than death, retirement, or disability,
the amount deferred shall be paid in one installment on a date
selected by the Company within six months after such
termination of employment. For this purpose, "retirement"
shall mean termination of employment in accordance with the
retirement regulations of the Company as set forth at the end
of the System Pension Plan of Consolidated Natural Gas Company
and Its Participating Subsidiaries for Employees Who Are Not
Represented By a Recognized Union and "disability" shall mean
termination of employment at any age with entitlement to
benefits under the Company's long-term disability insurance
program and/or a disability pension under the Company's
retirement program. For purposes of this Section 5 (a), a
Participant shall elect only one payment schedule which shall
apply to both his cash credit account and his Stock Credit
account.
(b) Distribution of a Participant's Stock Credit account balance
shall be made in cash with the amount of the distribution
determined by multiplying the number of Stock Credits
attributable to the installment by the Closing Price of Common
Stock on the last business day in December immediately prior
to the Plan Year in which the installment is to be paid;
provided, however, that, if a distribution date elected by a
Participant pursuant to Section 5 (a) is not to be as soon as
practicable after January 1 of a given year, the Closing Price
to be used shall be the Closing Price of Common Stock on the
last business day immediately prior to the date of
Participant's termination of employment.
(c) The amount of each annual installment to a Participant shall
be determined by dividing the balance remaining in the
Participant's account by the number of installments remaining
to be paid.
(d) If, during the lifetime of a Participant, he or she incurs a
severe financial hardship as a result of an unanticipated
emergency, the Company may, in its sole discretion, accelerate
payment of all or any part of the Participant's account
balance under the Plan, except that an Insider Participant's
Stock Account may not be accelerated under this subsection
(d); provided that such accelerated payment shall be limited
to the amount necessary to relieve the financial hardship. In
the event of the death of a Participant either while serving
AS an employee of the Company or thereafter, the amount
deferred shall
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<PAGE> 8
commence or continue to be paid after the death of the
Participant at the time or times and in the installments
provided in Section 5(a) above, but the Company shall have
power to accelerate the payment of any installment or
installments because of hardship or other circumstances
determined by the Company in its discretion to warrant such
acceleration.
(e) Any provision above of this Section 5 to the contrary
notwithstanding, each Participant's account balance, except an
Insider Participant's Stock Account balance, shall be paid in
full upon the occurrence of a "Change in Control" as defined
in Section 4(c) above unless, prior to such "Change in
Control," the Board of Directors of the Company shall have
adopted a resolution to the effect that payment should not be
made at such time.
(F) ANY PAYOUT ELECTION MADE PURSUANT TO THIS SECTION 5, UNLESS
MADE IRREVOCABLE PURSUANT TO ITS TERMS, MAY BE CHANGED BY
WRITTEN NOTICE TO THE COMMITTEE, TOGETHER WITH A NEW ELECTION
FORM, IF APPLICABLE. ANY SUCH NOTICE (AND NEW ELECTION FORM)
WILL NOT BE EFFECTIVE UNLESS APPROVED BY THE COMMITTEE. THE
COMMITTEE WILL NOT APPROVE ANY SUCH NOTICE (AND NEW ELECTION
FORM) IF IT IS MADE LESS THAN SIX (6) MONTHS PRIOR TO
TERMINATION OF EMPLOYMENT OR IS MADE IN THE SAME CALENDAR YEAR
AS TERMINATION OF EMPLOYMENT. THE COMMITTEE SHALL HAVE SOLE
DISCRETION TO APPROVE OR DISAPPROVE SUCH REQUESTS FOR
CHANGE(S) IN PAYOUT ELECTIONS.
6. Administration
(a) The Plan shall be administered, interpreted and construed by
the Committee as such Committee is from time to time
constituted. The Committee shall have authority, subject to
and consistent with the provisions of the Plan, to prescribe
the form of any agreement, instrument, form, or other
communication relating to the Plan, to adopt, amend, suspend,
waive, and rescind rules and regulations and appoint such
agents as the Committee may deem necessary or advisable to
administer the Plan, to construe and interpret the Plan, the
rules and regulations or any agreement or instrument entered
into under the Plan, and to make all other decisions and
determinations as may be required under the terms of the Plan
or as the Committee may deem necessary or advisable for the
administration of the Plan. Decisions of the Committee under
the Plan shall be final, conclusive and binding on the
Company, all employees, Participants and beneficiaries and
anyone claiming under or through any of them. Any instrument
or communication under the Plan to a Participant, employee or
beneficiary shall be deemed to have been properly delivered if
and when delivered in person or deposited in a Post Office Box
regularly maintained by the U.S. Government in an envelope
properly stamped and addressed to such Participant, employee
or beneficiary at his or her address as it appears on the
books of the Company. Any instrument or communication under
the Plan to the Company shall be deemed to have been properly
delivered if and when received by the Employee Benefits
Department of the Company.
(b) For purposes of the Employee Retirement Income Security Act of
1974, the Plan is intended to be an unfunded deferred
compensation plan for a select executive group of
-8-
<PAGE> 9
employees. The Plan shall be administered, interpreted and
construed to carry out such intention, and any provision of
the Plan that cannot be so administered, interpreted and
construed shall, to that extent, be disregarded.
(c) Any costs incidental to the administration of the Plan shall
be borne by the Company.
7. General Provisions
(a) The Board of Directors of the Company may modify or amend the
Plan, in whole or in part, from time to time, or terminate the
Plan at any time, without the consent of any Participant or
beneficiary of any Participant; provided, however, that no
such modification, amendment or termination shall permit the
acceleration of payment of any installment of deferred amounts
except as provided in Section 5(d) or 5(e) above and that any
modification, amendment or termination shall be of general
application to all Participants and beneficiaries and shall
not, without the consent of any affected Participant or, in
the event of his or her death any affected, beneficiary of a
Participant, affect adversely (i) any amount theretofore
deferred or credited to the Participant's account or (ii) the
right of the Participant to receive all amounts theretofore
credited to the Participant's account, including Interest
Equivalents or Dividend Equivalents computed to the date of
such modification, amendment or termination, at the time or
times provided by the Plan prior to such modification,
amendment or termination. The Plan shall remain in effect
until terminated pursuant to this Section 8(a).
(b) No rights under the Plan may be pledged, hypothecated,
encumbered, transferred or assigned, except that Participant
may designate, in writing on a form approved by the Company, a
beneficiary or beneficiaries to receive any unpaid amounts
under the Plan after the death of the Participant. The Company
may at any time and from time to time limit the number of
categories of persons or entities who or which may be
designated as beneficiaries by a Participant. In the absence
of a beneficiary designation or in the event that the
designated person or entity shall not be in existence at the
time a payment under the Plan comes due, the beneficiary of
the Participant shall be the legal representative of the
Participant's estate.
(c) The Plan shall be binding upon and inure to the benefit of the
Company and its successors and assigns, including any
corporation which may succeed to all or substantially all of
its assets whether by merger, sale of assets or otherwise, and
the Participants, their heirs and legal representatives.
(d) Neither the adoption of the Plan nor any aspect of its
operation or administration, including any document delivered
pursuant to or describing the Plan, shall limit or restrict in
any way the right of the Company to terminate the employment
of any employee at any time with or without cause or assigning
a reason therefor, or shall be construed to impose upon the
Company any liability not expressly and specifically assumed
by the Company under the Plan. Each employee of the Company
shall remain subject to discharge to the same extent as if the
Plan had never been adopted.
-9-
<PAGE> 10
No Participant or employee shall have any claim to be granted
an award under the Program based upon participation in the
Plan. No Participant or beneficiary shall have any of the
rights or privileges of a stockholder of the Company as a
result of any deferral under the Plan in the form of Stock
Credits or otherwise based upon rights conferred under the
Plan.
(e) By electing to participate in the Plan, each Participant and
each person claiming under or through any Participant, shall
be conclusively deemed to have indicated his acceptance and
ratification of, and consent to, any action or decision taken
or made or to be taken or made under the Plan by the Company
and the Committee.
(f) The place of administration of the Plan shall be conclusively
deemed to be within the State of Pennsylvania, and the
validity, construction, interpretation and administration of
the Plan, and of any determinations or decisions made
thereunder, and the rights of any and all persons having or
claiming to have any interest therein or thereunder, shall be
governed by, and determined exclusively and solely in
accordance with, the internal laws of the State of
Pennsylvania.
(g) The Company may withhold any taxes that it determines are
required to be withheld in respect of amounts payable under
the Plan under the laws of regulations of any governmental
authority, whether Federal, state or local and whether
domestic or foreign. Such withholding may be made, at the
election of the Company, from amounts payable under the Plan
and/or from any other amounts payable to the Participant by
the Company.
(h) The Plan shall become effective when duly adopted by the Board
of Directors of the Company.
(i) It is intended that the Plan and any and all transactions
occurring thereunder be exempt from Section 16 of the
Securities Exchange Act of 1934 (the "Exchange Act") as a
cash-only plan not involving an equity security of the Company
pursuant to Rule 16a1(c)(3) of the regulations promulgated
under the Exchange Act and effective May 1, 1991. The Plan
Administrator shall interpret and administer the Plan in
accordance with this intent.
-10-
<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
Net Income Shares Amount*
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
For the year ended December 31, 1997
BASIC EPS ................................................................ $304,380 94,868 $3.21
======== ====== =====
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 .............................................................. $316,508 100,460 $3.15
======== ======= =====
- -------------------------------------------------------------------------------------------------------------------
For the year ended December 31, 1996
BASIC EPS ................................................................ $298,273 94,076 $3.17
======== ====== =====
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 .............................................................. $310,096 99,215 $3.13
======== ====== =====
- -------------------------------------------------------------------------------------------------------------------
For the year ended December 31, 1995
BASIC EPS ................................................................ $ 21,344 93,246 $ .23
======== ====== =====
Effect of dilutive securities:
Exercise of stock options............................................... 67
-------- ------
DILUTED EPS .............................................................. $ 21,344 93,313 $ .23
======== ====== =====
- -------------------------------------------------------------------------------------------------------------------
*Prior year per share amounts have been restated in conformity with SFAS No. 128.
</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, 1997 1996 1995 1994 1993
- -------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Earnings:
Income before cumulative
effect of change
in accounting principle ....... $304,380 $ 298,273 $ 21,344 $183,171 $188,494
Add income taxes (excluding
cumulative effect of change
in accounting principle) ...... 147,053 155,830 2,943 82,427 99,906
-------- --------- -------- -------- --------
Income before income taxes . 451,433 454,103 24,287 265,598 288,400
Distributed income from
unconsolidated investees, less
equity in earnings thereof .... 1,653 (1,084) 1,501 560 2,960
-------- --------- -------- -------- --------
Subtotal ................... 453,086 453,019 25,788 266,158 291,360
-------- --------- -------- -------- --------
Add fixed charges:
Interest on long-term debt,
including amortization of
debt discount and expense
less premium ............... 104,927 101,814 95,823 88,788 85,265
Other interest expense ........ 9,116 7,224 14,732 7,992 4,995
Portion of rentals deemed to
be representative of the
interest factor ............ 10,112 9,449 9,565 8,486 8,378
Fixed charges associated
with 50% projects with debt 2,016 2,157 1,388 -- --
-------- --------- -------- -------- --------
TOTAL FIXED CHARGES ................. 126,171 120,644 121,508 105,266 98,638
-------- --------- -------- -------- --------
TOTAL EARNINGS ...................... $579,257 $ 573,663 $147,296 $371,424 $389,998
======== ========= ======== ======== ========
RATIO OF EARNINGS TO FIXED
CHARGES .......................... 4.59 4.76 1.21 3.53 3.95
======== ========= ======== ======== ========
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
<PAGE> 1
EXHIBIT 21
SUBSIDIARIES OF CONSOLIDATED NATURAL GAS COMPANY
<TABLE>
<CAPTION>
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 Energy Services Corporation Delaware 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 Storage Service Company Delaware 100%
CNG International, Inc. Delaware 100%
CNG Cayman One Ltd. Cayman Islands 100%
CNGI Australia Pty. Limited Australia 99%
CNG Cayman Two Ltd. Cayman Islands 100%
CNGI Australia Pty. Limited Australia 1%
CNG Cayman Three Ltd. Cayman Islands 100%
CNG Power Services Corporation Delaware 100%
CNG Lakewood, Inc. 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.
Consultants - Petroleum and Natural Gas
3555 Timmons Lane - Suite 1105
Houston, Texas 77027
(713) 622-8955
FEBRUARY 11, 1998
CONSOLIDATED NATURAL GAS COMPANY
CNG Tower
625 Liberty Avenue
Pittsburgh, Pennsylvania 15222-3199
Report Covering Natural Gas Supply
And Owned Oil Reserves
December 31, 1997
----------------------------------
Gentlemen:
Consolidated Natural Gas Company, through its subsidiaries (collectively
Consolidated or the Company) is engaged in exploring for, developing, producing,
purchasing, gathering, transporting, storing and distributing natural gas,
together with by-product operations. The principal market area of the Company's
retail operations is in Ohio, Pennsylvania, Virginia and West Virginia.
Consolidated operates a regional interstate pipeline system that supplies
natural gas to affiliates, and to utilities and end-users in the Midwest,
Mid-Atlantic states and the Northeast. Exploration and production activities are
carried on primarily in the Appalachian area, the Gulf Coast area (including
offshore), the Mid-Continent area, the Permian Basin area, the Rocky Mountain
area and in Canada.
The history of the operations in the Appalachian area covers a period of
over 100 years. Prior to 1943, Consolidated's gas supply was obtained from
company-owned production and by purchase from fields located within the
Appalachian area. From 1943 to 1993 Consolidated purchased gas from pipeline
companies which obtained their gas supply from fields in the Gulf Coast and
Southwest. 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
<PAGE> 2
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 11, 1998
Page 2
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 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, 1997 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, 1997, to be 301 billion cubic feet, (including CNG Producing
Company's Appalachian reserves) from company-owned wells and 262 billion cubic
feet from gas purchase wells, for a total of 563 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 419,367 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 11, 1998
Page 3
CNG PRODUCING COMPANY
CNG Producing Company is Consolidated's primary exploration and production
subsidiary. As of December 31, 1997, the estimated proved working interest
reserves of CNG Producing Company are 998 billion cubic feet of gas and
50,473,622 barrels of crude oil and condensate. The foregoing totals include
approximately 1 billion cubic feet of gas and 6,466,843 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 997 billion cubic feet of gas and 44,006,779
barrels of crude oil and condensate.
The estimated Appalachian proved reserves as of December 31, 1997 for CNG
Producing Company, which are included in the total Appalachian reserves
disclosed earlier in this report, are 116 billion cubic feet of gas and 168,958
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, 1997 are 7 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 eight (8) years. Purchase entitlements under these
contracts total approximately 1,132 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 11, 1998
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, one with Tennessee, one with North Penn
Gas, one with both Tennessee and National Fuel Gas Supply Corporation, and
another with both Texas Eastern and Transcontinental. Consolidated's net
injected gas stored at December 31, 1997, was 460 billion cubic feet (including
53 billion cubic feet of remaining non-recoverable native gas, and 60 billion
cubic feet of non-recoverable base gas.)
The proximity of these storage fields to principal markets and their high
deliverability are important factors in enabling the Company to meet peak loads
and daily requirements during the heating season, and permit the gas purchased
to be taken relatively uniformly in summer and winter.
There are additional depleted, or nearly depleted, gas fields in the
Appalachian area which can be converted to storage fields if needed.
POTENTIAL SUPPLY SOURCES
In order to meet the demands for gas in its market area over the long-term
future, Consolidated may need additional supplies over those available from the
sources discussed above. 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
50,724,031 barrels as of December 31, 1997, as follows:
<PAGE> 5
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 11, 1998
Page 5
<TABLE>
<CAPTION>
Stock Tank Barrels
------------------
<S> <C>
Appalachian Field Reserves 250,409
CNG Producing Company
Southwest 50,304,664
Appalachian 168,958
----------
Sub Total 50,473,622
TOTAL - OWNED OIL AND CONDENSATE RESERVES 50,724,031
</TABLE>
We have estimated the gas reserves available to Consolidated from sources
in the United States and Canada at 3,037 billion cubic feet as of December 31,
1997 as follows:
<TABLE>
<CAPTION>
Billion
Cubic Feet
at 14.73 psia
-------------
<S> <C>
Appalachian Field Reserves
Company-Owned Wells 185
Gas Purchase Contract Wells 262
Gas in Storage Reservoirs 460
-----
Sub-Total 907
CNG Producing Company Reserves
Company-Owned Wells
Southwest 882
Appalachian 116
-----
Sub-Total 998
Gas Supply Contracts 1,132
TOTAL - CONTROLLED GAS RESERVES 3,037
</TABLE>
Consolidated's requirements for the twelve months ended December 31, 1997,
including sales of gas produced in Canada, were approximately 1,118 billion
cubic feet, compared to requirements of 744 billion cubic feet in 1996.
<PAGE> 6
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 11, 1998
Page 6
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.
CONSULTANTS-PETROLEUM AND NATURAL GAS
3555 TIMMONS LANE - SUITE 1105
HOUSTON, TEXAS 77027
(713) 622-8955
March 19, 1998
CONSENT OF INDEPENDENT GEOLOGISTS
We hereby consent to the use of our report dated February 11, 1998,
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, 1997. 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, 1997. 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, 1997 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-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,054,656
<OTHER-PROPERTY-AND-INVEST> 1,168,147
<TOTAL-CURRENT-ASSETS> 1,453,641
<TOTAL-DEFERRED-CHARGES> 413,350
<OTHER-ASSETS> 223,900
<TOTAL-ASSETS> 6,313,694
<COMMON> 262,964
<CAPITAL-SURPLUS-PAID-IN> 526,475
<RETAINED-EARNINGS> 1,539,587
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,358,318
0
0
<LONG-TERM-DEBT-NET> 1,552,890
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 238,700
<LONG-TERM-DEBT-CURRENT-PORT> 154,000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,039,078
<TOT-CAPITALIZATION-AND-LIAB> 6,313,694
<GROSS-OPERATING-REVENUE> 5,710,020
<INCOME-TAX-EXPENSE> 147,053
<OTHER-OPERATING-EXPENSES> 5,164,834
<TOTAL-OPERATING-EXPENSES> 5,311,887
<OPERATING-INCOME-LOSS> 398,133
<OTHER-INCOME-NET> 13,516
<INCOME-BEFORE-INTEREST-EXPEN> 411,649
<TOTAL-INTEREST-EXPENSE> 107,269
<NET-INCOME> 304,380
0
<EARNINGS-AVAILABLE-FOR-COMM> 304,380
<COMMON-STOCK-DIVIDENDS> 184,942
<TOTAL-INTEREST-ON-BONDS> 121,682
<CASH-FLOW-OPERATIONS> 742,108
<EPS-PRIMARY> 3.21
<EPS-DILUTED> 3.15
</TABLE>
<PAGE> 1
EXHIBIT 99
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED 1997 Financial
CNG NATURAL GAS Report
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY
CONSOLIDATED
CNG NATURAL GAS
COMPANY 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..................................... 18
Report of Independent Accountants........................... 19
Consolidated Statement of Income for the Years 1995 through
1997...................................................... 21
Consolidated Balance Sheet at December 31, 1996 and 1997.... 22
Consolidated Statement of Cash Flows for the Years 1995
through 1997.............................................. 24
Notes to Consolidated Financial Statements.................. 25
</TABLE>
<PAGE> 3
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
NET INCOME
Net income in 1997 was $304.4 million, or $3.21 a share, compared with net
income of $298.3 million, or $3.17 a share, in 1996. Net income in 1995 was
$21.3 million, or $.23 a share. Basic earnings per share reported for each year
reflects the Company's adoption of Statement of Financial Accounting Standards
(SFAS) No. 128 (see page 4, "New Accounting Standards").
Earnings for 1997, 1996 and 1995 include special charges in each year.
During the fourth quarter of 1997, the Company recorded a non-cash charge to
write down the cost of its Canadian oil producing properties, amounting to $6.7
million after taxes, or $.07 a share. Excluding this item, net income for 1997
would have been $311.1 million, or $3.28 a share. Excluding the impact of
charges related to workforce reduction programs totaling $9.9 million after
taxes, or $.10 a share, 1996 net income would have been $308.2 million, or $3.27
a share. The Company recorded non-cash charges during 1995 to write down the
cost of gas and oil producing properties amounting to $145.0 million after
taxes, or $1.56 a share, and to write down coal properties amounting to $20.3
million after taxes, or $.22 a share. Also in 1995, the Company recorded charges
totaling $25.6 million after taxes, or $.27 a share, for workforce reductions.
Excluding these special items, net income for 1995 would have been $212.3
million, or $2.28 a share. Reference is made to Notes 4 and 5 to the
consolidated financial statements, page 30, for details of these special
charges.
1997
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 gas and oil. Weather in the Company's retail service
areas was 1.9% colder than normal and 4.3% warmer than 1996. Normal weather
represents a measure of temperature experienced over an historical time frame,
the length of which may differ depending on the regulatory jurisdiction.
1996
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 contributed to the
improved results. Weather in the Company's retail service areas was 5.6% colder
than normal and 5.5% colder than 1995.
1995
The favorable effects of new rates in place for most of the Company's gas
distribution and transmission customers, colder weather and lower aggregate wage
and benefit costs in the latter part of the year resulting from the workforce
reduction programs more than offset the impact of low wellhead prices for
natural gas and lower gas and oil production.
OPERATING REVENUES
Operating revenues include revenues from gas and oil sales, transportation and
storage of gas, brokering activities, by-product operations and wholesale
electric sales. Total operating revenues in 1997 were $5,710.0 million, an
increase of $1,915.7 million compared to $3,794.3 million in 1996. Significantly
increased sales of gas and electricity by the energy marketing services
operations was the primary reason for the revenue growth. Consistent with
industry conditions, these operations generate high sales volumes at low
margins.
Regulated gas sales revenues of $1,851.0 million in 1997 were up $98.8
million compared to 1996, despite sales volumes decreasing 22.0 billion cubic
feet (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
1
<PAGE> 4
Retail Services Corporation (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. The impact of
lower sales volumes for the Company's industrial customers more than offset
higher average sales rates for that customer class during 1997.
Nonregulated gas sales revenues increased $1,246.6 million in 1997 to
$2,339.1 million, with sales volumes increasing 411.6 Bcf to 807.7 Bcf. The
increases in both revenues and volumes during 1997 were attributable chiefly to
the energy marketing services operations. The increases also reflect higher gas
production at CNG Producing Company (CNG Producing).
Gas transportation and storage revenues rose $14.4 million in 1997 compared
to the prior year, to $479.5 million, reflecting both higher gas transportation
and storage service revenues. Wholesale electricity sales by the energy
marketing services operations increased $485.1 million in 1997 due chiefly to
higher volumes. Other operating revenues increased $70.8 million in 1997 to
$445.8 million. Revenues from oil brokering 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.
Total operating revenues in 1996 increased $487.0 million from $3,307.3
million in 1995. Regulated gas sales revenues in 1996 increased $154.8 million
to $1,752.2 million, with sales volumes increasing 4.1 Bcf to 294.0 Bcf due
mainly to colder weather. Nonregulated gas sales revenues increased $94.8
million in 1996, while sales volumes decreased 160.5 Bcf to 396.1 Bcf. The
effect of higher prices, coupled with the impact of higher production by the
exploration and production operations, more than offset the effect of reduced
transaction volumes of the energy marketing services component. Gas
transportation and storage revenues of $465.1 million in 1996 were up $8.7
million over 1995. The increase was due to higher transportation revenues as a
result of increased volumes and rates. Wholesale electricity revenues of the
energy marketing services component were up $87.7 million in 1996 due to higher
quantities of electricity sold. Other operating revenues increased $141.0
million in 1996, to $375.0 million, due chiefly to an increase of $108.8 million
in revenues from oil and condensate production and brokering.
OPERATING EXPENSES
Operating expenses, including income taxes, increased to $5,311.8 million in
1997, compared to $3,402.1 million and $3,160.8 million in 1996 and 1995,
respectively. Excluding the impact of impairments of gas and oil producing
properties in 1997 and 1995 and workforce reduction charges in 1996 and 1995,
operating expenses would have been $5,305.1 million, $3,392.2 million and
$2,990.2 million for the years 1997, 1996 and 1995, respectively.
Purchased gas consistently represents the largest operating expense
category for the Company. Purchased gas costs were $2,960.2 million in 1997,
$1,615.0 million in 1996 and $1,590.1 million in 1995. This expense is
influenced primarily by changes in gas sales requirements, the price and mix of
gas supplies, and the timing of recoveries of deferred purchased gas costs.
Increased volume requirements in connection with nonregulated gas sales and the
recognition of previously deferred purchased gas costs contributed to the
increase in 1997. For 1996, the effect of higher average purchase prices more
than offset the impact of decreased volume requirements in connection with
nonregulated gas sales and the deferral of purchased gas costs by the regulated
subsidiaries.
Electricity, liquids and capacity purchased expense includes the cost of
electricity, oil, condensate and by-products purchased for resale and pipeline
capacity not associated with gas purchased. This expense increased $523.0
million in 1997 and $193.1 million in 1996 due primarily to electricity
purchased for resale by the energy marketing services component and oil
purchased for resale by CNG Producing.
Excluding the effect in 1996 of workforce reduction charges, combined
operation and maintenance expense increased $24.4 million in 1997. This increase
was due largely to adjustments of reserves for pipeline settlements and
receivables recorded during 1997 by the energy marketing services component, in
addition to higher royalty expense and production-related costs. These costs
were partially offset by lower employment costs. Maintenance expense increased
slightly in 1997.
2
<PAGE> 5
Excluding the effect of 1996 and 1995 workforce reduction charges totaling
$15.2 million and $42.6 million, respectively, combined operation and
maintenance expense increased $77.2 million in 1996. This increase was due in
large part to increased royalty expense, partially offset by lower employee-
related costs and reductions in certain administrative expenses. Maintenance
expense increased $4.2 million in 1996 to $90.1 million.
Total depreciation and amortization expense increased $25.9 million in 1997
and $47.6 million in 1996 due largely to higher gas and oil production volumes
each year. Depreciation expense for the regulated subsidiaries increased in both
1997 and 1996 due principally to the increased level of plant investment.
Taxes, other than income taxes, were up $4.8 million in 1997 due in part to
higher excise taxes, and decreased $.7 million in 1996 due largely to lower
excise and payroll taxes.
Income taxes decreased $8.8 million in 1997, due largely to a lower
effective tax rate, and increased $152.8 million in 1996. The 1996 increase was
due to higher pretax earnings compared to 1995.
OTHER INCOME
Total other income was $13.5 million in 1997, compared to $9.3 million in 1996
and total other deductions of $20.5 million in 1995. Excluding the write-down of
coal properties of $31.3 million, total other income in 1995 would have been
$10.8 million. Interest revenues decreased slightly in 1997, and declined $6.8
million in 1996 compared to 1995 due largely to the lower level of temporary
cash investments in 1996. The increase in "Other-net" in 1997 of $4.3 million
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. Increased
earnings from the Company's equity investments and losses related to minor
property dispositions at certain regulated subsidiaries in 1995 that did not
recur in 1996, partially offset by the debt extinguishment charge, were the
primary reasons for the increase in "Other-net" of $5.4 million in 1996 compared
to 1995.
INTEREST CHARGES
Interest on long-term debt increased $3.1 million in 1997. This increase 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 effects
of the redemption in early 1997 of $100 million of debentures and the early
extinguishment of $53.1 million of debt in late 1996. Interest on long-term debt
increased $6.0 million in 1996 due primarily to debenture sales of $150 million
each in April 1995, October 1996 and December 1996. Other interest expense
increased $1.9 million in 1997. Other interest expense declined $7.5 million in
1996 due largely to lower interest expense related to customer refunds.
FOURTH QUARTER RESULTS
Net income for the fourth quarter of 1997 was $89.4 million compared to $88.0
million in 1996. On a basic earnings per share basis, the 1997 quarter was $.94
compared with $.93 in 1996. However, the 1997 fourth quarter reflects a special
charge for the impairment of oil producing properties totaling $6.7 million
after taxes, or $.07 per share, while the 1996 quarter includes special charges
for workforce reductions totaling $7.8 million after taxes, or $.08 per share.
The Company's 1997 average gas wellhead price was $2.54 per thousand cubic feet
(Mcf), down $.08 per Mcf, and average oil wellhead prices declined $2.90 per
barrel, to $15.69. These negative factors were partially offset by the impact of
weather that was 2.2% colder than in 1996.
3
<PAGE> 6
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
QUARTERS ENDED DECEMBER 31, 1997 1996
- -----------------------------------------------------------------------------------
(In Millions)
<S> <C> <C>
Operating revenues.......................................... $ 1,850.1 $ 1,229.2
Operating expenses.......................................... (1,689.4) (1,066.4)
--------- ---------
Operating income before income taxes........................ 160.7 162.8
Income taxes................................................ (40.8) (46.1)
Other income/expenses-net................................... (30.5) (28.7)
--------- ---------
Net income.................................................. $ 89.4 $ 88.0
========= =========
Earnings per common share--basic (in dollars)............... $.94 $.93
Earnings per common share--diluted (in dollars)............. $.92 $.91
- -----------------------------------------------------------------------------------
</TABLE>
NEW ACCOUNTING STANDARDS
In 1997, the Financial Accounting Standards Board (FASB) issued SFAS No. 128,
"Earnings per Share," which established new requirements for computing and
presenting earnings per share. The Company has adopted the provisions of SFAS
No. 128 for the year ended December 31, 1997, and has restated earnings per
share amounts for all prior periods presented in conformity with the new
standard. The adoption of SFAS No. 128 did not have a material effect on the
Company's earnings per share for any of the periods presented. Reference is made
to Note 2 to the consolidated financial statements, page 28, regarding SFAS No.
128.
Also in 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income," and SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information." SFAS No. 130 establishes standards for the reporting and
display of comprehensive income and its components. The Company is required to
adopt the provisions of SFAS No. 130 beginning with its consolidated financial
statements for the three months ending March 31, 1998. SFAS No. 131 requires
certain disclosures about segment information in interim and annual financial
statements and related information about products and services, geographic areas
and major customers. The Company must adopt the provisions of SFAS No. 131 for
its consolidated financial statements for the year ending December 31, 1998. The
adoptions of SFAS Nos. 130 and 131 are not expected to have a material effect on
the Company's financial position, results of operations or cash flows.
COMPONENTS OF THE BUSINESS
Due to the regulated nature of the distribution and transmission components of
the Company's business, operating results can be affected by regulatory delays
when price increases are sought through general rate filings to recover certain
higher costs of operations. Weather is also an important factor since a major
portion of the gas sold or transported by the distribution and transmission
operations is ultimately used for space heating.
4
<PAGE> 7
Operating results for each of the Company's business components follow.
Reference is made to Note 19 to the consolidated financial statements, page 45,
for additional disaggregated information.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
OPERATING INCOME BEFORE INCOME TAXES 1997(a) 1996(b) 1995(c)
- -----------------------------------------------------------------------------------------
(In Millions)
<S> <C> <C> <C>
Distribution................................................ $266.6 $258.4 $ 207.5
Transmission................................................ 178.4 178.8 150.4
Exploration and production.................................. 142.8 133.2 (200.5)
Energy marketing services................................... (17.1) (9.1) (5.7)
Other(d).................................................... (9.3) (3.2) 2.9
Corporate and eliminations.................................. (16.2) (10.1) (5.1)
------ ------ -------
Total..................................................... $545.2 $548.0 $ 149.5
====== ====== =======
</TABLE>
(a) Amount for the exploration and production operations includes the impact of
the write-down of oil producing properties in Canada amounting to $10.4
million.
(b) Amounts for the distribution, transmission, exploration and production,
energy marketing services and corporate components include the effect of
workforce reduction charges totaling $8.2 million, $5.1 million, $.6
million, $.3 million and $1.0 million, respectively.
(c) Amount for the exploration and production operations includes the impact of
the write-down of gas and oil producing properties in the United States
amounting to $226.2 million. Amounts for the distribution, transmission,
exploration and production, energy marketing services and corporate
components include the effect of workforce reduction charges totaling $22.3
million, $6.0 million, $7.7 million, $.5 million and $4.6 million,
respectively.
(d) Includes Consolidated LNG, CNG Research and CNG Coal. Amounts for 1997 and
1996 include CNG International and CNG Products and Services. Amounts for
1997 also include CNG Retail.
- --------------------------------------------------------------------------------
DISTRIBUTION
"Distribution" represents the results of the four retail gas distribution
subsidiaries, including their minor gas and oil production activities.
Sales growth in the Company's residential service areas in Ohio,
Pennsylvania and West Virginia has generally been limited since such areas have
experienced minimal population growth, and the vast majority of households in
these areas already use natural gas for space heating. Opportunity for growth in
the retail sales market is expected to continue at Virginia Natural Gas, Inc.
(Virginia Natural Gas), due to customer conversions from other energy sources
and the past and potential future expansion of its service territory. Since the
Company's acquisition of this subsidiary in 1990, it has experienced an annual
customer growth rate of about 4%, compared to a growth rate of less than 1% for
the other distribution subsidiaries.
Similar to the unbundling in recent years 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.
In early 1997, the Company formed a new nonregulated subsidiary, CNG
Retail, to market 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, The Peoples Natural Gas Company (Peoples Natural
Gas) opened its system in Pennsylvania to customer choice. In addition, on July
2, 1997, the Public Utilities Commission of Ohio (PUCO) approved The East Ohio
Gas Company's (East Ohio Gas) "Energy Choice" pilot program which will allow
approximately 15% of East Ohio Gas's residential and small business customers
the opportunity to purchase their natural gas from competing suppliers, if they
so choose.
5
<PAGE> 8
DISTRIBUTION OPERATING INCOME BEFORE INCOME TAXES
1997
Excluding workforce reduction charges during 1996, operating income before
income taxes of $266.6 million in 1997 was unchanged from the prior year. 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 but 4.3% warmer than 1996.
1996
Excluding workforce reduction charges amounting to $8.2 million in 1996 and
$22.3 million in 1995, operating income before income taxes for those years
would have been $266.6 million and $229.8 million, respectively. 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, Inc. (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.
1995
Excluding workforce reduction charges, operating income before income taxes in
1995 was up $70.8 million. In addition to the general rate increases placed into
effect in late 1994 and 1995, colder weather, the addition of new customers,
higher transport volumes and lower wage and benefit costs in the latter part of
the year due to the workforce reduction programs contributed favorably to 1995
results. Weather was 2.2% colder than 1994 and .5% colder than normal.
DISTRIBUTION OPERATING REVENUES
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.
Revenues in 1996 increased $160.3 million to $1,905.5 million. Gas sales
revenues were up $152.3 million reflecting both higher average sales prices and
higher sales volumes. Average sales prices increased due to the impact of both
higher unit purchased gas costs passed through to customers and higher rates in
place for most of the Company's distribution customers. Colder weather was a
major factor in the increased sales volumes. Gas transportation and storage
revenues increased $10.1 million resulting from 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 1997 1996 1995
- -------------------------------------------------------------------------------------
(In Billion Cubic Feet)
<S> <C> <C> <C>
Sales....................................................... 272.7 294.2 289.9
Transportation.............................................. 189.4 174.2 164.8
----- ----- -----
Throughput............................................. 462.1 468.4 454.7
===== ===== =====
- -------------------------------------------------------------------------------------
</TABLE>
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 compared to 1996. 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 transporta-
6
<PAGE> 9
tion volumes increased 2.1 Bcf to 134.0 Bcf. Transportation to off-system
customers increased 4.1 Bcf in 1997.
In 1996, colder weather and the net addition of approximately 17,000
residential and commercial customers contributed to the slight increase in gas
sales volumes compared to 1995. Residential gas sales volumes increased 6.2 Bcf,
to 218.7 Bcf, in 1996. Commercial sales decreased 3.0 Bcf while volumes
transported to these customers were up 7.2 Bcf. Deliveries to industrial
customers were higher in 1996, increasing .6 Bcf to 138.8 Bcf. Sales to
industrial customers declined .4 Bcf to 6.9 Bcf, while transportation volumes
increased 1.0 Bcf to 131.9 Bcf. Transportation to off-system customers increased
1.2 Bcf in 1996.
TRANSMISSION
"Transmission" includes the results of the gas transmission, storage, by-product
and certain other activities of CNG Transmission Corporation (CNG Transmission).
Gas and oil production activities of CNG Transmission are included in
exploration and production operations.
TRANSMISSION OPERATING INCOME BEFORE INCOME TAXES
1997
Excluding workforce reduction charges in 1996, operating income before income
taxes declined $5.5 million in 1997, to $178.4 million. However, the 1997
results include a charge amounting to $5.8 million recognized in the fourth
quarter in connection with CNG Transmission's withdrawal from participation in a
gas storage development project.
1996
Excluding workforce reduction charges of $5.1 million in 1996 and $6.0 million
in 1995, operating income before income taxes for those years would have been
$183.9 million and $156.4 million, respectively. Cost control efforts and
increased gas transportation and by-products revenues contributed to the
improved results in 1996.
1995
Excluding workforce reduction charges, operating income before income taxes
increased $10.1 million in 1995. Higher rates resulting from CNG Transmission's
general rate filing, which became effective July 1, 1994, and cost controls were
the major factors for the improved results in 1995.
TRANSMISSION OPERATING REVENUES
Total operating revenues declined $16.4 million in 1997, to $487.0 million. Gas
transportation revenues declined $15.7 million due to both lower volumes and
rates, and revenues from the sale of by-products decreased $3.7 million due
primarily to lower sales rates. These decreases were partially offset by an
increase of $2.8 million in gas storage service revenues.
Total operating revenues were $32.4 million higher in 1996 compared to
1995. Gas transportation and storage revenues increased $9.7 million due to
higher gas transportation revenues, which increased $14.9 million due to higher
volumes and rates. This increase was partly offset by decreased storage service
revenues. Revenues from the sale of by-products increased $9.7 million due
chiefly to higher sales rates.
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.
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
7
<PAGE> 10
deregulation of the gas industry at the retail level (see "Distribution," page
5, and "Gas and Electric Industry Developments," page 11).
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 and including intercompany activity, was 732.8 Bcf,
758.4 Bcf, and 744.0 Bcf for the years 1997, 1996 and 1995, 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
1997
Operating income before income taxes in 1997 was $142.8 million, compared to
$133.2 million in 1996. However, the 1997 results include a non-cash charge of
$10.4 million related to the Company's impairment of Canadian oil producing
properties. In addition, workforce reduction charges totaling $.6 million are
reflected in the 1996 results. Excluding these items, 1997 operating income
would have been $153.2 million, an increase of $19.4 million compared to the
prior year. 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, excluding $.6 million of workforce
reduction charges, was $133.8 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 for 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.
1995
Excluding special items described above, operating results for 1995 would have
been slightly lower than the prior year. The impact of low gas wellhead prices
and lower gas and oil production slightly offset the favorable impact of higher
oil wellhead prices, a $7.5 million reduction in production-related expenses,
and reductions in overhead costs in 1995. In addition, depreciation and
amortization expense was $32.1 million lower in 1995 resulting from the
impairment of gas and oil producing properties, the effect of gas and oil
reserve additions, and lower production. Reserves equal to 210 Bcf of gas
equivalent were added in 1995.
8
<PAGE> 11
GAS AND OIL PRODUCTION AND PRICES
The following table sets forth the Company's gas and oil production and average
wellhead prices for the E&P operations for the last three years:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
PRODUCTION 1997 1996 1995
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C>
GAS (BCF)
Nonregulated................................................ 155.3 144.5 102.6
Regulated*.................................................. 2.8 3.0 4.6
------- ------- -------
Total.................................................. 158.1 147.5 107.2
======= ======= =======
OIL (000 BBLS)
Nonregulated................................................ 7,312.0 4,765.9 3,131.7
Regulated*.................................................. -- -- 17.2
------- ------- -------
Total.................................................. 7,312.0 4,765.9 3,148.9
======= ======= =======
AVERAGE WELLHEAD PRICES
(NONREGULATED ONLY)
Gas (per Mcf)............................................... $ 2.43 $ 2.46 $ 1.89
Oil (per Bbl)............................................... $16.07 $17.60 $16.04
</TABLE>
* Cost-of-service. Hope Gas sold all of its remaining gas reserves to CNG
Producing during 1996. At December 31, 1997 and 1996, the Company's remaining
cost-of-service gas reserves were held by Peoples Natural Gas.
- --------------------------------------------------------------------------------
The Company's average gas wellhead price was $2.43 per Mcf in 1997, down
from $2.46 in 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 is due
largely to the impact of Neptune, one of the Company's deep-water projects in
the Gulf of Mexico which began production in March 1997.
The Company's average gas wellhead price in 1996 was $2.46 per Mcf, up $.57
from $1.89 in 1995. Gas production in 1996 was 147.5 Bcf, up 38% from 1995. The
increase in gas production during 1996 was due partially to the impact of two
significant Gulf of Mexico projects which commenced production in the 1996 first
quarter, Popeye and Main Pass 225. Production also benefited from the effect of
production enhancement efforts at existing Company-operated fields. Average oil
wellhead prices were $17.60 per barrel in 1996, up $1.56 from 1995, while oil
production increased 51% from the prior year. The increase in oil production in
1996 was due in large part to production from the Popeye project.
E&P OPERATING REVENUES
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 brokering increased $73.0
million in 1997, with higher sales volumes more than offsetting the impact of
lower rates. Revenues from oil brokering rose $39.7 million and revenues from
oil and condensate production increased $33.3 million.
Total operating revenues increased 75% in 1996, to $632.3 million. Of the
$159.3 million increase in gas sales revenues in 1996, $90.8 million was due to
higher average gas prices and $68.5 million reflected increased volumes.
Revenues from oil and condensate production and brokering increased $108.9
million in 1996, with $77.7 million of the increase attributable to increased
volumes and the remaining increase due to higher rates. Revenues from oil
brokering increased $74.6 million while revenues from the sale of oil and
condensate production increased $34.3 million.
9
<PAGE> 12
ENERGY MARKETING SERVICES
"Energy marketing services" represents the results of CNG Energy Services
Corporation (CNG Energy Services) and CNG Power Services Corporation (CNG Power
Services). CNG Energy Services markets Company-owned gas production and arranges
gas supplies, transportation, storage and related services for large volume
customers. CNG Energy Services also holds the Company's ownership interests in
six independent power plants. CNG Power Services purchases and resells
electricity at market-based prices.
The energy marketing services component reported an operating loss before
income taxes of $17.1 million in 1997, an increased loss of $8.0 million
compared to 1996. The higher operating loss in 1997 was due chiefly to charges
recorded in connection with the establishment of reserves for pipeline
settlements and receivables. Reduced gross margins and higher overhead costs
also contributed to the 1997 operating loss. Total throughput for this component
was 856.4 Bcf in 1997, an increase of 429.3 Bcf compared to 1996. Electricity
marketed in 1997 totaled 25.2 million megawatt-hours, an increase of 20.2
million megawatt-hours over the prior year.
This component reported operating losses before income taxes of $9.1
million in 1996 and $5.7 million in 1995. The 1996 and 1995 results include
workforce reduction charges totaling $.3 million and $.5 million, respectively.
In addition to higher overhead costs, the 1996 loss occurred in part because
this component contracted for quantities of natural gas to supply power plants
during the summer air-conditioning season; these quantities proved to be too
high when third quarter 1996 weather turned cooler than expected. Reduced
transaction volumes during 1996 also adversely impacted 1996 operating results.
Total throughput for this component was 427.1 Bcf in 1996 compared to 570.8 Bcf
in 1995. Power marketing, which includes the sale of wholesale electricity,
increased to 5.0 million megawatt-hours in 1996 compared to 1.9 million
megawatt-hours in 1995.
In addition to depressed gas margins throughout the year, 1995 operating
results also reflected a $5.3 million pretax charge recognized by CNG Energy
Services in December 1995 in connection with a mark-to-market valuation of
exchange-traded futures contracts used to manage price risk exposure related to
its stored gas inventories.
Income recognized in connection with CNG Energy Services investments in
1997, 1996 and 1995 totaled $8.2 million, $5.8 million and $3.9 million,
respectively. In addition, this component recorded a charge of $7.0 million in
the fourth quarter of 1997 in connection with the decision to sell and write
down the carrying value of its interests in four independent power projects.
These amounts are not included in operating income or loss before income taxes
but are reflected in "Other income" for the component.
OTHER
"Other" in the operating income table on page 5 represents the results of
Consolidated System LNG Company (Consolidated LNG), CNG Research Company (CNG
Research) and CNG Coal Company (CNG Coal) for all three years, CNG International
Corporation (CNG International) and CNG Products and Services Corporation (CNG
Products and Services) for 1997 and 1996, and CNG Retail for 1997 only.
This segment reported an operating loss before income taxes of $9.3 million
in 1997 and $3.2 million in 1996 and operating income of $2.9 million in 1995.
Results for 1997 and 1996 reflect start-up costs incurred in connection with CNG
International, which reported pretax operating losses of $6.8 million and $3.8
million, respectively. Start-up costs of CNG Retail and CNG Products and
Services are reflected in their combined pretax operating losses of $3.8 million
and $1.5 million in 1997 and 1996, respectively. Helping to offset these
start-up costs somewhat is pretax operating income for Consolidated LNG of $1.4
million, $2.6 million and $3.7 million for the years 1997, 1996 and 1995,
respectively, reflecting the recognition of deferred income pursuant to a
regulatory order.
INTERNATIONAL ACTIVITIES
During December 1997, CNG International acquired 12.5% ownership interests in
two gas utility holding companies, Sodigas Pampeana and Sodigas Sur, and a 20%
ownership interest 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
10
<PAGE> 13
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. Camuzzi
Argentina S.A. will maintain majority ownership interests in the holding
companies. At December 31, 1997, CNG International's investments in the
Argentine holding companies totaled $79.1 million.
In December 1996, CNG International and El Paso Energy Corporation entered
into a joint venture to own and operate the Australian pipeline assets formerly
held by Tenneco Energy. CNG International owns 30% of Epic Energy Pty Ltd. (Epic
Energy), an Australian entity formed to hold the investment's operating assets.
The primary operating assets of the venture include two major long-distance
natural gas pipelines from Australia's Cooper Basin. CNG International's net
investment in Epic Energy totaled $30.9 million at December 31, 1997.
LIMITATION ON CAPITALIZED COSTS
As indicated in Note 1 to the consolidated financial statements, CNG Producing
and CNG Transmission follow the full cost method of accounting for their gas and
oil producing activities prescribed by the Securities and Exchange Commission
(SEC). Reference is made to Note 4 to the consolidated financial statements,
page 30, regarding the Company's recognition under the SEC full cost rules of
impairments of its gas and oil producing properties at December 31, 1997 and
March 31, 1995.
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
In the current gas industry environment, competition at the retail level is
receiving increased attention by state regulators. Governments in two 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, and allows retail customers to obtain gas from
an array of suppliers. The PUCO has proposed rules to implement the law.
Legislation is being considered in Pennsylvania that would completely unbundle
gas utility merchant functions by January 1999. One aspect of the proposal would
permit the Pennsylvania Public Utility Commission (PUC) to certify marketers, in
addition to gas utilities, as suppliers of last resort, creating competition in
a traditional gas utility function. The proposal requires the PUC to review and
act by September 1998 on plans submitted by gas utilities.
In addition to the further deregulation of the gas industry, the emerging
unbundling of services provided by electric utilities may ultimately result in
the convergence of both industries to create one overall, highly competitive
marketplace for a customer's total energy needs. During 1995 and 1996,
regulators at the federal and state levels finalized initiatives to promote
increased competition in the electric industry. These initiatives included
issuance in 1996 of FERC Order Nos. 888 and 889 (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. A companion order, Order 889,
addresses the timing, information access and other administrative details
associated with the FERC deregulation initiative.
Other signs of an increasingly deregulated electric utility environment
include retail competition plans adopted in several states, pilot retail
wheeling programs and pro-competition legislation proposed at both the federal
and state levels. While no legislation has been enacted in Ohio regarding
electric competition at the retail level, a legislative study committee report
issued in January 1998 calls for full customer choice by 2000. In Pennsylvania,
the Electric Generation Customer Choice and Competition Act enacted in late 1996
requires a transition to a competitive electric market at the retail level
beginning in 1999, with full competition by 2001. In February 1998, the Virginia
General Assembly passed an electric industry restruc-
11
<PAGE> 14
turing bill calling for wholesale competition beginning in 2001 and retail
competition in 2004 and sent the bill to the Virginia Senate for consideration.
In West Virginia, a bill introduced in February 1998 would authorize the Public
Service Commission (PSC) to prescribe and implement a plan to deregulate the
electric industry that must balance fairly the interests of customers, electric
utilities and the state's economy.
Reflecting the evolution to a more competitive energy environment, the pace
and size of business combinations among natural gas and electric utilities
continued to increase during 1997. 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. 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, the SEC has recommended legislation to
conditionally repeal the Public Utility Holding Company Act of 1935 (PUHCA), to
which the Company is subject, in conjunction with legislation which would grant
the various state regulatory commissions greater oversight authority of
companies currently subject to the PUHCA. 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. 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.
Through its actions in recent years, the Company believes it is
well-positioned to compete in an evolving and increasingly deregulated energy
marketplace. The creation of CNG Retail and the ongoing development of the
energy marketing services component and participation in international
investments, coupled with streamlining and restructuring of its existing
distribution, transmission and exploration and production operations, reflects
the Company's proactive approach to meeting the demands of a more competitive
and dynamic business environment.
FEDERAL AND STATE REGULATORY ISSUES
On July 1, 1997, CNG Transmission filed a general rate filing with the FERC
requesting an annual revenue increase of $71 million, related surcharges of
approximately $12 million, and permission to establish market-based pricing for
some of its transportation and storage services. The filing seeks to accelerate
recovery of part of the Company's investment in gathering facilities which will
enable CNG Transmission to fully unbundle its gathering facilities by January 1,
2001 in accordance with prior rate case settlements. The filing reflects a
proposed rate of return on equity of 14.5%. On July 31, 1997 the FERC accepted
in part, and rejected in part, the filing. The FERC's actions included
permission to place increased rates into effect January 1, 1998, subject to
refund, the establishment of hearing procedures and rejection of the proposal to
establish market based rates.
On July 2, 1997, the PUCO approved East Ohio Gas's "Energy Choice" program
(see "Distribution," page 5).
On January 5, 1998, Hope Gas filed with the Public Service Commission of
West Virginia for a $14.5 million annual revenue increase. The rate increase
request is intended to cover improvements and extensions made to its pipeline
system. If approved, the new rates would become effective November 1, 1998.
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 17 to the consolidated financial statements, page
43, 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 encoun-
12
<PAGE> 15
ter in the future cannot be predicted. Additional environmental liabilities may
result in the future as more stringent environmental laws and regulations are
implemented and as the Company obtains more specific information about its
existing sites and production facilities. At present, no estimate of any such
additional liability, or range of liability amounts, can be made. However, the
amount of any such liabilities could be material.
EFFECTS OF INFLATION
Although inflation rates have been 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 1997, the Board of Directors continued the quarterly dividend on the
common stock at 48.5 cents a share. Total dividends paid to common shareholders
in 1997 were $184.6 million compared with $183.0 million in 1996 and $180.8
million in 1995.
During 1997, a total of 773,283 original issue shares were issued through
various Company-sponsored plans, including 612,158 shares acquired by employees
through the exercise of outstanding stock options.
Under the Company's stock repurchase plan, authorization was granted during
1997 to increase the maximum amount of outstanding common stock that can be
repurchased from 4 million shares to 10 million shares. The shares may be
purchased in the open market from time-to-time, depending on market conditions,
or 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. No treasury shares were held by the Company at December 31, 1996.
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 non-qualified benefit
plans via a grantor trust. At December 31, 1997, a total of 659 shares were
being held as treasury stock. On January 15, 1998, the Company purchased
approximately 4.6 million shares of its common stock in a private transaction to
be used to satisfy the conversion rights of debentures called for redemption
(see "Call of Debentures," page 14).
CAPITAL SPENDING
The current capital spending program for 1998 is estimated at $714.7 million, a
17% increase compared with total capital spending in 1997. The estimated 1998
budget has been allocated as follows: distribution, $145.7 million;
transmission, $61.5 million; exploration and production, $312.7 million; energy
marketing services, $25.3 million; international, $151.6 million; and corporate
and other, $17.9 million. The increased level of capital expenditures planned
for 1998 anticipates higher spending for unregulated businesses. Exploration and
production operations reflect increased spending on deep-water projects and
increased conventional onshore and offshore drilling. Expenditures for
international operations reflect expected continued expansion of investment
opportunities in Australia and Latin America. 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, primarily to centralize and consolidate services and financial
systems.
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 1998 to
support capital spending, and may also utilize the capital markets to take
advantage of other opportunities, including possible exploration and production
acquisitions, or to increase its financial flexibility.
13
<PAGE> 16
CAPITAL RESOURCES AND LIQUIDITY
Because of the seasonal nature of the regulated subsidiaries' heating business,
a substantial portion of the Company's cash receipts are realized in the first
half of the year. However, cash requirements for capital expenditures,
dividends, debt retirements and other working capital needs do not track this
pattern of cash receipts. Consequently, additional cash needs are satisfied
through the sale of short-term commercial paper notes or by the issuance of
long-term debt. As shown in the Consolidated Statement of Cash Flows, net cash
provided by operating activities was $742.1 million, $407.2 million and $552.7
million for the years 1997, 1996 and 1995, 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 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. The decline in net cash provided by
operating activities in 1996 was due in part to the deferral of purchased gas
costs in excess of costs currently recovered in rates and the payment of
customer refunds during the period.
In December 1997, the Company sold $300 million of 6.8% Debentures Due
December 15, 2027. The debentures are redeemable, as a whole or in part, at the
option of the Company at any time. The proceeds will be 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 $700 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 1997 was 7.20%, compared with 7.27% for 1996 and 7.69% for 1995. The
long-term debt to capitalization ratio was 39.7%, 39.3% and 38.7% at the end of
1997, 1996 and 1995, 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 A1 by Moody's Investors
Service, AA- by Standard & Poor's, AA- by Duff and Phelps, and AA by Fitch
Investors Service.
At December 31, 1997, 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 1997 and there were no amounts outstanding under any credit
agreements at December 31, 1997 or 1996. On February 13, 1998, the Company
entered into a $250 million short-term credit agreement with a bank. Borrowings
under the agreement are in the form of revolving credits which may be used for
general corporate purposes.
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 1997, of which $238.7 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
The Company's 7 1/4% Convertible Subordinated Debentures, due December 15, 2015,
were convertible into shares of the Company's common stock at an initial
conversion price of $54 per share. On January 23, 1998, the Company called for
redemption the entire principal amount outstanding totaling $246.2 million. The
redemption price was 102.18% of the principal amount plus accrued interest
payable on February 23, 1998. In anticipation of the call of this debt, on
January 15, 1998, the Company purchased approximately 4.6 million shares of its
common stock in a private transaction to satisfy the conversion obligation to
holders of the Convertible Subordinated Debentures who chose to convert. This
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 are
expected to be sold in underwritten offerings during 1998. The Company will
record an expense in the first quarter of 1998 in connection with the redemption
of the Convertible Subordinated Debentures, but such expense is not expected to
be material.
14
<PAGE> 17
YEAR 2000 TECHNOLOGY ISSUE
Similar to all business entities, the Company will be impacted by the inability
of computer application software programs to distinguish between the year 1900
and 2000 due to a commonly-used programming convention. Unless such programs are
modified or replaced prior to 2000, calculations and interpretations based on
date-based arithmetic or logical operations performed by such programs may be
incorrect.
Management is continuing to assess the Company's exposure on this issue,
including the impact on software programs and on automated process control
systems used in the operations of the Company's business. Concurrent with this
assessment, the Company is making renovations to its existing software programs
and automated process control systems to become Year 2000 compliant. While the
Company's assessment of its exposure is expected to be completed during 1998,
renovation and replacement of existing programs will continue through 1999. The
Company has budgeted approximately $10.0 million for these Year 2000 compliance
efforts.
In addition to the activities described above, the Company is currently
replacing many of its financial and operating software programs with new
programs that will be Year 2000 compliant. These new programs have significantly
reduced the costs expected to be incurred to become Year 2000 compliant.
PRICE RISK MANAGEMENT ACTIVITIES
In the normal course of business, certain of the nonregulated subsidiary
operations are subject to market risk and credit risk in connection with the
production, purchase and sale of natural gas and oil, purchase and sale of
electricity, and stored gas inventories. In addition, certain of the Company's
activities, including foreign equity investments, are subject to foreign
currency risk. Reference is made to Note 16 to the consolidated financial
statements, page 42, regarding the fair value of the Company's long-term debt
which is comprised of fixed rate instruments.
MARKET 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 CNG Energy Services. These policies include
value-at-risk and notional contract and stop loss limit structures designed to
maintain exposure levels within the parameters established by management.
CREDIT RISK
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 regards 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, 1997, the Company
believes it is unlikely that a material adverse effect on its financial
position, results of operations or cash flows would occur as a result of
counterparty nonperformance.
Price risk management activities are conducted by two of the Company's
subsidiaries, CNG Energy Services and CNG Producing.
CNG ENERGY SERVICES
CNG Energy Services engages in wholesale energy marketing activities in the
United States and Canada. It provides energy risk management products and
services to gas and electric utilities, municipals, large industrial end users,
oil and gas producers, and other energy marketers, and to CNG Producing Company
15
<PAGE> 18
for its production and sale of natural gas. CNG Energy Services uses
over-the-counter (OTC) price swap agreements, exchange-traded futures contracts,
and option contracts to manage market risk inherent in its marketing and energy
risk management activities. The level of market risk exposure from these
activities is maintained within risk management guidelines. CNG Energy Services
also has a foreign currency swap agreement effective through April 2005 to
manage foreign exchange rate risk in connection with the payment of demand
charges for pipeline capacity in Canada.
Tables disclosing fair value and related information at December 31, 1997
for derivatives that are sensitive to changes in natural gas prices and foreign
exchange rates 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 the tables do not include information about
CNG Energy Services' natural gas and electricity commodity purchases and sales
commitments which are sensitive to changes in natural gas and electricity
prices, and information related to firm transportation and storage agreements
for which CNG Energy Services must make specified minimum payments each month.
Therefore, the information presented regarding the use of derivatives by CNG
Energy Services does not reflect the earnings impact of the physical
transactions that may offset the financial gains and losses arising from the use
of derivatives.
The following table presents net notional quantities and weighted average
settlement prices by expected maturity date for futures contracts utilized to
manage natural gas price risk. At December 31, 1997, CNG Energy Services held no
futures contracts with maturity dates extending beyond 2000.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Expected Maturity Date Unrealized
------------------------ Gain (Loss)
Exchange-Traded Futures Contracts 1998 1999 2000 Total at 12/31/97
- -------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C>
Contract volumes (in 10,000 mmbtu), purchased
(sold)............................................ (537) 144 105 (288) $(1,090)
Weighted average settlement price (per mmbtu)....... $2.30 $2.35 $2.15
- -------------------------------------------------------------------------------------------------------
</TABLE>
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, 1997, CNG Energy Services had not entered into any
price swap agreements extending beyond 2002. 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.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Price Swap Agreements Expected Maturity Date
(Quantities in 10,000 mmbtu) -------------------------------------- Fair Value
(Rates per mmbtu) 1998 1999 2000 2001 2002 Total at 12/31/97
- -----------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Pay Fixed, Receive Variable
Net notional quantities.................. 27,840 2,805 1,488 231 90 32,454 $(26,294)
Weighted average pay rate.............. $0.46 $0.55 $0.30 $1.06 $0.41
Weighted average receive rate.......... $0.36 $0.58 $0.31 $1.12 $0.47
Receive Fixed, Pay Variable
Net notional quantities.................. 25,065 3,628 759 270 29,722 $ 28,749
Weighted average pay rate.............. $0.53 $0.59 $0.43 $0.37
Weighted average receive rate.......... $0.65 $0.59 $0.43 $0.34
- -----------------------------------------------------------------------------------------------------------
</TABLE>
16
<PAGE> 19
The following table presents notional amounts and weighted average exchange
rates, by expected maturity date, for the foreign currency swap agreement:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Expected Maturity Date
Foreign Currency Swap ------------------------------------------ Fair Value
Pay Fixed, Receive Variable 1998 1999 2000 2001 2002 Thereafter Total at 12/31/97
- ----------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Notional amounts
(US$ In Thousands)...... $5,581 $6,861 $6,789 $6,611 $6,470 $18,679 $50,991 $4,528
Weighted average pay rate
(US$/Can$).............. 0.71 0.70 0.68 0.67 0.66 0.63 0.66
Weighted average receive
rate (US$/Can$)......... 0.70 0.71 0.72 0.72 0.72 0.73 0.72
- ----------------------------------------------------------------------------------------------------------------
</TABLE>
Information regarding the fair value of OTC and exchange-traded options
contracts held by CNG Energy Services is not presented at December 31, 1997,
since the use of these derivatives was not significant.
CNG PRODUCING
CNG Producing uses price swap agreements and exchange-traded futures and options
contracts to manage commodity price risk in connection with the production and
sale of crude oil. CNG Producing's price risk management activities related to
the production and sale of natural gas are executed through intercompany
transactions with CNG Energy Services.
At December 31, 1997, CNG Producing held futures contracts 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. All of these contracts expire during 1998. These contracts qualify and
have been designated as hedges of crude oil production, with any gains or losses
from market price changes expected to be generally offset by the earnings impact
of the related physical transaction. The fair value of options contracts and
price swap agreements held by CNG Producing at December 31, 1997 is not
presented since the use of these financial instruments was not significant.
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 capital expenditures, earnings, risk management,
litigation, rate and other regulatory matters, liquidity and capital resources,
and financial accounting 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.
SUMMARY OF FINANCIAL DATA
The Company's Summary of Financial Data is on page 18.
17
<PAGE> 20
SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
SUMMARY OF FINANCIAL DATA (THOUSAND $) 1997 1996(a) 1995(a) 1994 1993
- -------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
EARNINGS
Gas sales.............................. $4,190,158 $2,844,709 $2,595,103 $2,402,861 $2,615,036
Electricity sales, gas transportation,
storage and other.................... 1,519,862 949,600 712,222 633,167 569,049
Total operating revenues.......... 5,710,020 3,794,309 3,307,325 3,036,028 3,184,085
Purchased gas.......................... 2,960,204 1,614,983 1,590,137 1,424,020 1,594,373
Electricity, liquids and capacity
purchased............................ 869,670 346,747 153,577 107,094 79,001
Operation and maintenance.............. 798,620 789,356() 739,612() 689,575 677,666
Depreciation and amortization.......... 330,144 304,171 256,636 279,317 294,648
Impairment of gas and oil producing
properties........................... 10,351 -- 226,209 -- --
Taxes, other than income taxes......... 195,845 191,078 191,698 192,617 181,053
Operating income before
income taxes.................... 545,186 547,974 149,456 343,405 357,344
Income taxes........................... 147,053 155,830 2,943 82,427 99,906
Other income-net....................... 13,516 9,304 10,760 9,694 10,531
Write-down of coal properties.......... -- -- 31,266 -- --
Interest charges....................... 107,269 103,175 104,663 87,501 79,475
Income before change in accounting
principle............................ 304,380 298,273 21,344 183,171 188,494
Cumulative effect of applying SFAS No.
109.................................. -- -- -- -- 17,422
Net income........................ 304,380 298,273 21,344 183,171 205,916
Earnings per common share--basic(b)
Income before change in accounting
principle....................... $3.21 $3.17 $.23 $1.97 $2.03
Cumulative effect of applying SFAS
No. 109......................... -- -- -- -- .19
Net income........................ $3.21 $3.17 $.23 $1.97 $2.22
Earnings per common share--diluted(b)
Income before change in accounting
principle....................... $3.15 $3.13 $.23 $1.97 $2.02
Cumulative effect of applying SFAS
No. 109......................... -- -- -- -- .19
Net income........................ $3.15 $3.13 $.23 $1.97 $2.21
Return on average stockholders'
equity............................... 13.3% 14.0% 1.0% 8.4% 9.6%
Times fixed charges earned............. 4.59 4.76 1.21 3.53 3.95
- -------------------------------------------------------------------------------------------------------
DIVIDENDS--CASH
Paid per common share.................. $1.94 $1.94 $1.94 $1.94 $1.92
Payout ratio...................... 60.4% 61.2% 843.5% 98.5% 86.5%
Declared per common share.............. $1.94 $1.94 $1.94 $1.94 $1.925
- -------------------------------------------------------------------------------------------------------
ASSETS
Total assets........................... $6,313,694 $6,000,605 $5,418,293 $5,518,673 $5,437,188
Property, plant and equipment
Total investment.................. 8,714,758 8,304,205 7,929,350 7,676,956 7,346,028
Accumulated depreciation.......... 4,491,955 4,226,905 4,016,945 3,650,310 3,429,760
Capital expenditures and
acquisitions......................... 609,373 560,293 439,393 437,785 342,569
- -------------------------------------------------------------------------------------------------------
CAPITAL STRUCTURE
Total common stockholders' equity...... $2,358,318 $2,205,152 $2,045,818 $2,184,334 $2,176,432
Long-term debt......................... 1,552,890 1,426,315 1,291,811 1,151,973 1,158,648
---------- ---------- ---------- ---------- ----------
Total capitalization.............. $3,911,208 $3,631,467 $3,337,629 $3,336,307 $3,335,080
========== ========== ========== ========== ==========
Long-term debt ratio................... 39.7% 39.3% 38.7% 34.5% 34.7%
Shares outstanding at year-end......... 95,622,622 94,933,631 93,591,623 93,027,847 92,933,828
Common stockholders' equity per
share................................ $24.66 $23.23 $21.86 $23.48 $23.42
</TABLE>
- --------------------------------------------------------------------------------
(a) Certain amounts and ratios are not comparable with prior years due to
special charges.
(b) Prior year per share amounts have been restated in conformity with SFAS No.
128.
- --------------------------------------------------------------------------------
18
<PAGE> 21
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 21
through 52 of this Appendix I to the proxy statement for the 1998 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, 1997 and 1996, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 1997, 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.
PRICE WATERHOUSE LLP
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
February 17, 1998
19
<PAGE> 22
(THIS PAGE WAS INTENTIONALLY LEFT BLANK)
20
<PAGE> 23
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31, 1997 1996 1995
- ----------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
OPERATING REVENUES
Regulated gas sales..................................... $1,851,001 $1,752,223 $1,597,379
Nonregulated gas sales.................................. 2,339,157 1,092,486 997,724
---------- ---------- ----------
Total gas sales.................................... 4,190,158 2,844,709 2,595,103
Gas transportation and storage.......................... 479,505 465,110 456,370
Electricity sales....................................... 594,532 109,446 21,768
Other................................................... 445,825 375,044 234,084
---------- ---------- ----------
Total operating revenues (Note 3).................. 5,710,020 3,794,309 3,307,325
---------- ---------- ----------
OPERATING EXPENSES
Purchased gas........................................... 2,960,204 1,614,983 1,590,137
Electricity, liquids and capacity purchased............. 869,670 346,747 153,577
Operation expense (Note 5).............................. 708,012 699,289 653,731
Maintenance............................................. 90,608 90,067 85,881
Depreciation and amortization (Note 4).................. 330,144 304,171 256,636
Impairment of gas and oil producing properties (Note
4).................................................... 10,351 -- 226,209
Taxes, other than income taxes.......................... 195,845 191,078 191,698
---------- ---------- ----------
Subtotal........................................... 5,164,834 3,246,335 3,157,869
---------- ---------- ----------
Operating income before income taxes............... 545,186 547,974 149,456
Income taxes (Note 8)................................... 147,053 155,830 2,943
---------- ---------- ----------
Operating income................................... 398,133 392,144 146,513
---------- ---------- ----------
OTHER INCOME (DEDUCTIONS)
Interest revenues....................................... 2,178 2,281 9,095
Write-down of coal properties (Note 4).................. -- -- (31,266)
Other-net............................................... 11,338 7,023 1,665
---------- ---------- ----------
Total other income (deductions).................... 13,516 9,304 (20,506)
---------- ---------- ----------
Income before interest charges..................... 411,649 401,448 126,007
---------- ---------- ----------
INTEREST CHARGES
Interest on long-term debt.............................. 104,927 101,814 95,823
Other interest expense.................................. 9,116 7,224 14,732
Allowance for funds used during construction............ (6,774) (5,863) (5,892)
---------- ---------- ----------
Total interest charges............................. 107,269 103,175 104,663
---------- ---------- ----------
NET INCOME.............................................. $ 304,380 $ 298,273 $ 21,344
========== ========== ==========
Earnings per common share--basic (Note 2).......... $3.21 $3.17 $.23
Earnings per common share--diluted (Note 2)........ $3.15 $3.13 $.23
</TABLE>
- --------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
21
<PAGE> 24
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
AT DECEMBER 31, 1997 1996
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Note 4)
Gas utility and other plant................................. $ 5,004,139 $ 4,848,392
Accumulated depreciation and amortization................... (1,949,483) (1,840,129)
----------- -----------
Net gas utility and other plant........................ 3,054,656 3,008,263
----------- -----------
Exploration and production properties....................... 3,710,619 3,455,813
Accumulated depreciation and amortization................... (2,542,472) (2,386,776)
----------- -----------
Net exploration and production properties.............. 1,168,147 1,069,037
----------- -----------
Net property, plant and equipment...................... 4,222,803 4,077,300
----------- -----------
CURRENT ASSETS
Cash and temporary cash investments......................... 65,035 44,524
Accounts receivable
Customers................................................. 804,015 647,207
Unbilled revenues and other............................... 176,787 161,525
Allowance for doubtful accounts........................... (29,590) (15,167)
Inventories, at cost
Gas stored--current portion (Note 9)...................... 139,157 170,513
Materials and supplies (average cost method).............. 30,256 33,070
Unrecovered gas costs (Note 3).............................. 55,062 108,016
Prepayments and other current assets........................ 212,919 243,333
----------- -----------
Total current assets................................... 1,453,641 1,393,021
----------- -----------
REGULATORY AND OTHER ASSETS
Other investments........................................... 223,900 149,858
Deferred charges and other assets (Notes 3, 5, 6, 7, 8, 10
and 17)................................................... 413,350 380,426
----------- -----------
Total regulatory and other assets...................... 637,250 530,284
----------- -----------
Total assets........................................... $ 6,313,694 $ 6,000,605
=========== ===========
</TABLE>
- --------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
22
<PAGE> 25
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
AT DECEMBER 31, 1997 1996
- ---------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C>
STOCKHOLDERS' EQUITY AND LIABILITIES
CAPITALIZATION
Common stockholders' equity (Note 11)
Common stock, par value $2.75 per share
Authorized-- 400,000,000 shares
Issued, 1997--95,623,281 shares, 1996--94,933,631
shares................................................. $ 262,964 $ 261,068
Capital in excess of par value............................ 566,755 537,002
Retained earnings (Note 13)............................... 1,539,587 1,424,624
Treasury stock, at cost (1997--659 shares)................ (38) --
Unearned compensation..................................... (10,950) (17,542)
----------- -----------
Total common stockholders' equity...................... 2,358,318 2,205,152
Long-term debt (Note 14).................................... 1,552,890 1,426,315
----------- -----------
Total capitalization................................... 3,911,208 3,631,467
----------- -----------
CURRENT LIABILITIES
Current maturities on long-term debt........................ 154,000 104,000
Commercial paper (Note 15).................................. 238,700 374,000
Accounts payable............................................ 651,365 535,296
Estimated rate contingencies and refunds (Note 3)........... 29,112 21,602
Amounts payable to customers................................ 880 --
Taxes accrued............................................... 125,056 97,336
Deferred income taxes--current (net) (Note 8)............... 13,735 36,096
Dividends declared.......................................... 46,377 46,043
Other current liabilities................................... 127,016 150,047
----------- -----------
Total current liabilities.............................. 1,386,241 1,364,420
----------- -----------
DEFERRED CREDITS
Deferred income taxes (Note 8).............................. 712,118 681,334
Accumulated deferred investment tax credits................. 26,658 28,838
Deferred credits and other liabilities (Notes 3, 6, 7 and
8)........................................................ 277,469 294,546
----------- -----------
Total deferred credits................................. 1,016,245 1,004,718
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 18)
----------- -----------
Total stockholders' equity and liabilities............. $ 6,313,694 $ 6,000,605
=========== ===========
</TABLE>
- --------------------------------------------------------------------------------
23
<PAGE> 26
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
FOR THE YEARS ENDED DECEMBER 31, 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income.................................................. $ 304,380 $ 298,273 $ 21,344
Adjustments to reconcile net income to net cash provided by
operating activities
Depreciation and amortization........................... 330,144 304,171 256,636
Impairment of gas and oil producing properties.......... 10,351 -- 226,209
Write-down of coal properties........................... -- -- 31,266
Pension cost (credit)................................... (49,841) (28,604) 7,105
Stock award amortization................................ 9,620 8,436 620
Deferred income taxes-net............................... 1,881 63,230 (48,767)
Investment tax credit................................... (2,193) (2,201) (2,198)
Changes in current assets and current liabilities
Accounts receivable-net.............................. (160,887) (139,179) (116,529)
Inventories.......................................... 34,170 (55,339) 77,024
Unrecovered gas costs................................ 52,954 (82,893) (11,988)
Accounts payable..................................... 119,625 94,131 69,761
Estimated rate contingencies and refunds............. 7,510 (37,761) (24,041)
Amounts payable to customers......................... 880 (40,315) (55,825)
Taxes accrued........................................ 27,720 (16,999) 19,922
Other-net............................................ 6,984 (6,006) 13,643
Changes in other assets and other liabilities........... 48,880 48,473 84,828
Other-net............................................... (70) (252) 3,714
--------- --------- ---------
Net cash provided by operating activities............ 742,108 407,165 552,724
--------- --------- ---------
CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions............. (520,961) (439,489) (434,739)
Proceeds from dispositions of property, plant and
equipment-net............................................. 1,056 9,079 14,066
Cost of other investments-net............................... (86,763) (87,735) (7,464)
--------- --------- ---------
Net cash used in investing activities................ (606,668) (518,145) (428,137)
--------- --------- ---------
CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Issuance of common stock.................................... 28,722 37,726 19,058
Issuance of debentures...................................... 294,945 299,567 148,899
Repayments of long-term debt................................ (119,625) (72,750) (4,000)
Commercial paper-net........................................ (134,368) 37,853 (103,399)
Dividends paid.............................................. (184,608) (183,020) (180,782)
Other-net................................................... 5 (149) (9)
--------- --------- ---------
Net cash provided by (or used in) financing
activities........................................... (114,929) 119,227 (120,233)
--------- --------- ---------
Net increase in cash and temporary cash
investments.......................................... 20,511 8,247 4,354
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1............ 44,524 36,277 31,923
--------- --------- ---------
CASH AND TEMPORARY CASH INVESTMENTS AT DECEMBER 31.......... $ 65,035 $ 44,524 $ 36,277
========= ========= =========
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for
Interest (net of amounts capitalized)................... $ 114,314 $ 109,602 $ 102,663
Income taxes (net of refunds)........................... $ 126,372 $ 108,742 $ 58,949
Non-cash financing activities
Issuance of common stock under benefit plans............ $ 2,742 $ 25,570 $ 1,121
Conversion of 7 1/4% Convertible Subordinated
Debentures............................................ $ 40 $ -- $ --
</TABLE>
- --------------------------------------------------------------------------------
The Notes to Consolidated Financial Statements are an integral part of this
statement.
24
<PAGE> 27
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.
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, certain of the nonregulated subsidiaries
utilize 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, purchase and sale of electricity, and for stored
gas inventories. Derivative financial instruments are also used to manage
foreign currency risk in connection with certain contractual commitments. The
derivatives utilized by the subsidiaries include exchange-traded futures and
options contracts, which permit settlement by physical delivery of the
commodity, and OTC commodity price swap agreements, OTC foreign currency swap
agreements and OTC options which require settlement in cash.
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. The value of derivatives that do not
qualify for hedge accounting treatment are marked-to-market each period, with
gains and losses recognized in the
25
<PAGE> 28
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
operating income of that period. The market prices used to value these
derivatives are based on closing prices quoted by an exchange and OTC quotations
when exchange quotes are not available.
Under the OTC price swap agreements, the subsidiaries make payments to, or
receive 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. Under foreign currency swap agreements, payments
are made to, or received from, counterparties generally based on the difference
in the current foreign exchange rate. Settlement takes place under the swap
agreements on a monthly basis 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.
Margin accounts for open futures contracts are recorded in the Consolidated
Balance Sheet under "Prepayments and other current assets." Deferred losses or
gains are reflected in the Consolidated Balance Sheet under "Prepayments and
other current assets" and "Other current liabilities," respectively. Cash flows
from price risk management activities are reported in the Consolidated Statement
of Cash Flows as an operating activity--consistent with the category of the cash
flows from the underlying physical transaction.
PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
GAS UTILITY AND OTHER PLANT
The property, plant and equipment accounts are stated at the cost incurred or,
where required by regulatory authorities, "original cost." Additions and
betterments are charged to the property accounts at cost. Upon normal retirement
of a plant asset, its cost is charged to accumulated depreciation together with
costs of removal less salvage. The costs of maintenance, repairs and replacing
minor items are charged principally to expense as incurred.
EXPLORATION AND PRODUCTION PROPERTIES
CNG Producing and CNG Transmission follow the full cost method of accounting for
gas and oil producing activities prescribed by the 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.
The gas producing activities of Peoples Natural Gas are subject to
cost-of-service rate regulation and are exempt from the accounting methods
prescribed by the SEC.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization are recorded over the estimated service lives of
plant assets by application of the straight-line method or, in the case of gas
and oil producing properties, the unit-of-production method.
Under the full cost method of accounting, amortization is also accrued on
estimated future costs to be incurred in developing proved gas and oil reserves,
and on estimated dismantlement and abandonment costs net of projected salvage
values. However, the costs of investments in unproved properties and major
development projects are excluded from amortization until it is determined
whether or not proved reserves are attributable to such properties.
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
26
<PAGE> 29
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
service. The remaining subsidiaries capitalize interest costs as part of the
cost of acquiring certain assets. Generally, interest is capitalized on unproved
properties and major construction and development projects on which amortization
is not yet being recognized.
In determining the allowance for funds used during construction, the
following ranges of rates reflect the pretax cost of borrowed funds used to
finance construction expenditures: 1997--5 5/8% to 7 5/8%; 1996--5 1/2% to 8
1/8% and 1995--5 3/4% to 8 3/8%. 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
PENSION PROGRAM
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 depending on retirement dates, and the payment of
benefits to certain retired executives under company-sponsored nonqualified
employee benefit plans. Certain of these nonqualified benefit plans are funded
through contributions to a grantor trust.
OTHER POSTRETIREMENT BENEFITS
In addition to pension plans, the Company sponsors defined benefit
postretirement plans covering both salaried and hourly employees and certain
dependents. The plans provide medical benefits as well as life insurance
coverage. These benefits are provided through insurance companies and other
providers with the annual cash outlays based on the claim experience of the
related plans.
Employees who retire on or after attaining age 55 and having rendered at
least 15 years of service, or employees retiring on or after attaining age 65,
are eligible to receive benefits under the plans. The plans are both
contributory and noncontributory, depending on age, retirement date, the plan
elected by the employee, and whether the employee is covered under a collective
bargaining agreement. Most of the medical plans contain cost-sharing features
such as deductibles and coinsurance. For certain of the contributory medical
plans, retiree contributions are adjusted annually.
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.
27
<PAGE> 30
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
TEMPORARY CASH INVESTMENTS
Temporary cash investments consist of short-term, highly liquid investments that
are readily convertible to cash and present no significant interest rate risk.
For purposes of the Consolidated Statement of Cash Flows, temporary cash
investments are considered to be cash equivalents.
2. EARNINGS PER SHARE
In February 1997, the FASB issued SFAS No. 128, "Earnings per Share," which
establishes new requirements for computing and presenting earnings per share.
The Company has adopted the provisions of SFAS No. 128 for the year ended
December 31, 1997, and has restated earnings per share amounts for all prior
annual and quarterly periods presented as required by the new standard. The
adoption of SFAS No. 128 did not have a material effect on the Company's
earnings per share for any of the periods presented.
A reconciliation of the income and common stock share amounts used in the
calculation of basic and diluted earnings per share (EPS) for each of the years
ended December 31, 1997, 1996 and 1995 follows (net income and share amounts in
thousands):
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Per Share
Net Income Shares Amount
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
For the year ended December 31, 1997
BASIC EPS................................................... $304,380 94,868 $3.21
======== ======= =====
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................................................. $316,508 100,460 $3.15
======== ======= =====
- ----------------------------------------------------------------------------------------------
For the year ended December 31, 1996
BASIC EPS................................................... $298,273 94,076 $3.17
======== ======= =====
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................................................. $310,096 99,215 $3.13
======== ======= =====
- ----------------------------------------------------------------------------------------------
For the year ended December 31, 1995
BASIC EPS................................................... $ 21,344 93,246 $ .23
======== ======= =====
Effect of dilutive securities:
Exercise of stock options.............................. 67
-------- -------
DILUTED EPS................................................. $ 21,344 93,313 $ .23
======== ======= =====
- ----------------------------------------------------------------------------------------------
</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.
3. 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
28
<PAGE> 31
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
subsidiaries resulted in the recognition of regulatory assets and liabilities at
December 31, 1997 and 1996 as follows:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
DECEMBER 31, 1997 1996
- -----------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Regulatory assets:
Unrecovered gas costs (Note 1)......................... $ 55,062 $108,016
Order 636 transition costs (Note 3).................... 17,020 27,727
Workforce reduction costs (Note 5)..................... 8,832 11,139
Other postretirement benefits (Note 7)................. 55,070 58,966
Deferred income taxes (Note 8)......................... 103,323 101,825
Abandoned facilities (Note 10)......................... 2,271 15,791
Environmental-related expenditures (Note 17)........... 7,322 11,047
Other.................................................. 16,944 21,357
-------- --------
Total regulatory assets.......................... $265,844 $355,868
======== ========
Regulatory liabilities:
Amounts payable to customers (Note 1).................. $ 880 $ --
Estimated rate contingencies and refunds (Note 3)...... 29,112 21,602
Income taxes refundable to customers-net (Note 8)...... 55,035 57,867
-------- --------
Total regulatory liabilities..................... $ 85,027 $ 79,469
======== ========
</TABLE>
- --------------------------------------------------------------------------------
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 the Company's
regulated 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 $15.7 million and $6.9 million at
December 31, 1997 and 1996, including interest. These amounts are reported in
the Consolidated Balance Sheet under "Estimated rate contingencies and refunds"
together with $13.4 million and $14.7 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 or are expected to incur 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 $17.0 million and $27.7 million at December 31,
1997 and 1996, respectively. Additional amounts may be accrued in the future if
the pipeline companies receive final FERC approval to recover such costs. Based
on management's current estimates, the distribution subsidiaries' portion of
such additional costs is not expected to be material. Due to regulatory actions
in two jurisdictions and the past rate-making treatment of similar costs in the
other jurisdictions, management believes that the distribution subsidiaries
should generally be able to pass through all Order 636 transition costs to their
customers.
29
<PAGE> 32
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
4. PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
IMPAIRMENTS OF GAS AND OIL PRODUCING PROPERTIES
As described in Note 1, certain of the subsidiaries follow the full cost method
of accounting for gas and oil producing activities as prescribed by the SEC.
Under these rules, at December 31, 1997, the Company recognized an impairment of
its Canadian oil producing properties 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.
The Company recognized an impairment of its United States gas and oil
producing properties at March 31, 1995, due primarily to the decline in gas
wellhead prices. The non-cash charge amounted to $226.2 million and reduced 1995
net income by $145.0 million, or $1.56 per share.
DEPRECIATION AND AMORTIZATION
Amortization of capitalized costs under the full cost method of accounting for
the Company's exploration and production operations amounted to $.88 per Mcf
equivalent of gas and oil produced in 1997, $.93 in 1996, and $.98 in 1995.
Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 1997, and the
years in which such excluded costs were incurred, follow:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Incurred in Years Ended December 31,
DECEMBER 31, ---------------------------------------
1997 1997 1996 1995 Prior
- ----------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C>
Property acquisition costs.................. $48,975 $37,858 $ 5,855 $2,753 $2,509
Exploration costs........................... 41,366 29,682 3,826 4,654 3,204
Capitalized interest........................ 6,925 2,458 1,098 1,461 1,908
------- ------- ------- ------ ------
Total.................................. $97,266 $69,998 $10,779 $8,868 $7,621
======= ======= ======= ====== ======
</TABLE>
- --------------------------------------------------------------------------------
There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 1997. As gas and oil reserves are proved through
drilling or as properties are judged to be impaired, excluded costs and any
related reserves are transferred on an ongoing, well-by-well basis into the
amortization calculation.
WRITE-DOWN AND SUBSEQUENT SALE OF COAL PROPERTIES
In early 1995, the Company initiated an evaluation of the possible disposition
of the coal reserves and related properties owned by CNG Coal. A property
appraisal was completed by an independent geological firm, which indicated that
a write-down was warranted. Accordingly, the cost of these properties was
written down in 1995 resulting in a pretax charge amounting to $31.3 million.
This charge reduced 1995 net income by $20.3 million, or 22 cents per share, but
had no effect on the Company's cash flow. In 1996, CNG Coal completed the sale
of its coal properties to a subsidiary of Cyprus Amax Minerals Company. The
proceeds from the sale approximated the remaining book value of the properties.
5. WORKFORCE REDUCTION COSTS
During 1996, unions at two subsidiaries implemented a workforce reduction
program that consisted of a voluntary early retirement program and a voluntary
separation program. The early retirement incentives were similar to those
offered by the Company during 1995. The early retirement program was offered
from February 1 through March 31, 1996, with eligible employees retiring
effective April 1, 1996. The voluntary separation program involved severance
benefit payments to affected employees. A separate voluntary early
30
<PAGE> 33
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
retirement program for West Ohio Gas (now a division of East Ohio Gas) was
offered from October 1 through November 29, 1996, with eligible employees
retiring effective December 1, 1996. The program included early retirement
incentives similar to those offered previously at other subsidiaries.
Workforce reduction programs implemented during 1995 consisted of a
voluntary early retirement program and an involuntary separation program. The
early retirement incentives included five additional years of age and service
for determining pension benefits and were offered at seven subsidiaries during
1995. Eligible employees at each subsidiary were required to retire before
December 31, 1995. The involuntary separation program involved severance benefit
payments to affected employees.
During 1996 and 1995, a total of 119 and 571 eligible employees,
respectively, elected to accept the early retirement offer and an additional 57
and 217, respectively, were separated from the Company in conjunction with these
workforce reduction programs. 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 these workforce reduction
programs, the Company recorded charges to "Operation expense" in the 1996 and
1995 Consolidated Statements of Income amounting to $15.2 million and $42.6
million, respectively. These charges reduced 1996 and 1995 net income by $9.9
million, or 10 cents per share, and $25.6 million, or 27 cents per share,
respectively. The portion of the 1996 charges recognized in the fourth quarter
amounted to $11.8 million and reduced net income for the quarter by $7.8
million, or 8 cents per share. In addition, certain of the regulated
subsidiaries have deferred, as a regulatory asset, a portion of their workforce
reduction costs pending recovery in future rates. The balance of these deferrals
was $8.8 million at December 31, 1997. The total workforce reduction costs
include the impact of curtailment accounting for the pension and postretirement
benefit plans. Details of the costs incurred during 1996 and 1995 are shown in
the following table.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1996 1995
------------------------------- -------------------------------
Amounts Amounts Total Amounts Amounts Total
Expensed Deferred Costs Expensed Deferred Costs
- ---------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C>
Pension and nonqualified
benefit plans:
Special termination
benefits.................. $ 4,436 $-- $ 4,436 $30,284 $ 6,893 $37,177
Curtailment gain-net......... (792) -- (792) (5,891) (277) (6,168)
Postretirement benefit plans:
Special termination
benefits.................. -- -- -- 1,086 62 1,148
Curtailment loss-net......... 1,292 -- 1,292 6,008 9,656 15,664
Severance and other............... 10,259 91 10,350 11,068 45 11,113
------- --- ------- ------- ------- -------
Total........................ $15,195 $91 $15,286 $42,555 $16,379 $58,934
======= === ======= ======= ======= =======
- ---------------------------------------------------------------------------------------------------------
</TABLE>
31
<PAGE> 34
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
6. PENSION COSTS
Net pension cost, as determined by an independent actuary, included the
following components:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Service cost--benefits earned during the period.......... $ 21,374 $ 23,741 $ 23,741
Interest cost on projected benefit obligation............ 68,635 67,426 62,125
Return on plan assets.................................... (330,296) (205,481) (265,460)
Net amortization and deferral............................ 194,419 86,522 162,002
Curtailment and special termination benefits............. -- 3,644 24,393
Special voluntary retirement programs.................... 800 800 800
--------- --------- ---------
Net pension cost (or credit)........................ $ (45,068) $ (23,348) $ 7,601
========= ========= =========
</TABLE>
- --------------------------------------------------------------------------------
The following table sets forth the funded status of the plans, as
determined by an independent actuary, at December 31, 1997 and 1996:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Plans Where Assets Plans Where
Exceed Accumulated Accumulated Benefits
Benefits Exceed Assets
------------------------------------- -------------------------------------
DECEMBER 31, 1997 1996 1997 1996
- ---------------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
Actuarial present value of:
Vested benefit obligation.............. $ 755,169 $ 708,224 $ 22,368 $ 22,111
========== ========== ======== ========
Accumulated benefit obligation......... $ 788,265 $ 737,868 $ 27,607 $ 26,627
========== ========== ======== ========
Projected benefit obligation........... $1,005,439 $ 927,531 $ 32,289 $ 32,420
Plan assets at fair value................... 1,804,852 1,539,039 -- --
---------- ---------- -------- --------
Plan assets in excess of (or less than)
projected benefit obligation........ 799,413 611,508 (32,289) (32,420)
Unrecognized net gain....................... (648,048) (501,869) (1,692) (2,076)
Unrecognized net obligation (or asset)...... (58,660) (67,980) 18,423 19,864
Unrecognized prior service cost............. 4,822 5,227 898 1,617
Recognition of minimum liability............ -- -- (12,947) (13,612)
---------- ---------- -------- --------
Prepaid pension cost (or pension
liability).......................... $ 97,527 $ 46,886 $(27,607) $(26,627)
========== ========== ======== ========
- ---------------------------------------------------------------------------------------------------------------------------
</TABLE>
The projected benefit obligation at December 31, 1997 and 1996, was
determined using an annual discount rate of 7.0% and 7.5%, respectively, and an
average assumed annual rate of salary increase of 5.5%. The expected long-term
rate of return on plan assets was 9.0% per year at December 31, 1997 and 1996.
The minimum liability recognized relating to both the Company's
nonqualified employee benefit and supplemental pension plans was $12.9 million
and $13.6 million at December 31, 1997 and 1996. The related intangible asset
recognized as of those dates amounted to $10.3 million and $11.5 million,
respectively. These amounts are included in the Consolidated Balance Sheet under
"Deferred credits and other liabilities" and "Deferred charges and other
assets." Adjustments of the minimum liability and intangible asset due to
changes in assumptions or the financial status of the plans resulted in a charge
to retained earnings of $.3 million at December 31, 1997, and a credit to
retained earnings of $.1 million at December 31, 1996.
32
<PAGE> 35
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. OTHER POSTRETIREMENT BENEFITS
Net periodic postretirement benefit cost, as determined by an independent
actuary, included the following components:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Service cost--benefits attributed to service during the
period................................................. $ 9,901 $11,940 $11,549
Interest cost on accumulated postretirement benefit
obligation............................................. 25,854 26,450 28,017
Return on plan assets.................................... (2,972) (645) (145)
Amortization of transition obligation.................... 11,418 11,801 14,420
Curtailment and special termination benefits............. -- 1,292 7,094
Net amortization and deferral............................ (24) 2,283 380
------- ------- -------
Net periodic postretirement benefit cost............ $44,177 $53,121 $61,315
======= ======= =======
- --------------------------------------------------------------------------------------------------------------------
</TABLE>
The following table reconciles the plans' combined funded status, as
determined by an independent actuary, with amounts included in the Consolidated
Balance Sheet at December 31, 1997 and 1996:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
DECEMBER 31, 1997 1996
- ---------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees............................................... $ 279,555 $ 280,593
Fully eligible active plan participants................ 7,615 16,882
Other active plan participants......................... 71,578 80,960
--------- ---------
Total accumulated postretirement benefit
obligation...................................... 358,748 378,435
Plan assets at fair value................................... 79,740 53,153
--------- ---------
Accumulated postretirement benefit obligation in excess
of plan assets....................................... (279,008) (325,282)
Unrecognized prior service cost............................. (6,178) (6,591)
Unrecognized net loss....................................... 24,253 54,088
Unrecognized transition obligation.......................... 170,102 188,248
--------- ---------
Accrued postretirement benefit liability............... $ (90,831) $ (89,537)
========= =========
- ---------------------------------------------------------------------------------------------------
</TABLE>
The Company is amortizing the accumulated postretirement benefit obligation
that existed at January 1, 1993 (transition obligation) over a 20-year period.
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation at December 31, 1997 and 1996, was 7.0% and
7.5%, respectively. The average assumed annual rate of salary increase for the
applicable life insurance plans was 5.5% for both 1997 and 1996.
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation for the medical plans is 6.5% for 1998,
declining gradually to 4.5% in 2003 and remaining at that level thereafter. The
health care cost trend rate assumption has a significant effect on the amounts
reported. If the health care cost trend rate were increased by 1% in each year,
the accumulated postretirement benefit obligation as of December 31, 1997, would
be increased by $30.9 million. A 1% change would also increase the aggregate of
the service and interest cost components of net periodic postretirement benefit
cost for 1997 by $4.5 million.
The majority of the estimated postretirement benefit costs and the
transition obligation is attributable to the rate-regulated subsidiaries.
Pending the expected recovery of SFAS No. 106 costs and related 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
33
<PAGE> 36
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 1997 and 1996, was $55.1 million and $59.0 million, respectively,
which is included in the Consolidated Balance Sheet under "Deferred charges and
other assets."
The FERC and certain state regulatory authorities have indicated that when
SFAS No. 106 costs are recovered in rates, amounts collected must be deposited
in irrevocable trust funds dedicated for the sole purpose of paying
postretirement benefits. Accordingly, 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.
8. INCOME TAXES
"Income taxes" in the Consolidated Statement of Income include the following:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- --------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Current provision
Federal................................................... $128,825 $ 80,962 $ 44,705
State..................................................... 18,540 13,839 9,203
Deferred income taxes-net
Federal................................................... 2,806 60,758 (47,146)
State..................................................... (925) 2,472 (1,621)
Investment tax credit....................................... (2,193) (2,201) (2,198)
-------- -------- --------
Total..................................................... $147,053 $155,830 $ 2,943
======== ======== ========
- --------------------------------------------------------------------------------------------
</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
income before taxes. The reasons for the differences follow:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- -------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Income before taxes...................................... $451,433 $454,103 $ 24,287
======== ======== ========
Computed "expected" tax expense.......................... $158,002 $158,936 $ 8,500
Increases (or reductions) in tax resulting from:
Production tax credit............................... (10,359) (9,344) (8,472)
Investment tax credit............................... (2,193) (2,201) (2,198)
State income taxes.................................. 11,450 10,602 4,928
Miscellaneous....................................... (9,847) (2,163) 185
-------- -------- --------
Total income taxes............................ $147,053 $155,830 $ 2,943
======== ======== ========
Effective tax rate.................................. 32.6% 34.3% 12.1%
- -------------------------------------------------------------------------------------------
</TABLE>
The current and noncurrent deferred income taxes reported in the
Consolidated Balance Sheet at December 31, 1997 and 1996 represent the net
expected future tax consequences attributable to
34
<PAGE> 37
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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>
1997 1996
------------------------------ ------------------------------
Deferred Deferred income Deferred Deferred income
December 31, income taxes taxes-current income taxes taxes-current
<S> <C> <C> <C> <C>
- -----------------------------------------------------------------------------------------------------------
<CAPTION>
(In Thousands)
<S> <C> <C> <C> <C>
Deferred tax liabilities:
Excess of tax over book
depreciation...................... $537,684 $ -- $516,241 $ --
Exploration and intangible well
drilling costs.................... 225,111 -- 215,415 --
Unrecovered gas costs................ -- 19,424 -- 38,863
Other................................ 78,603 -- 76,906 --
-------- ------- -------- -------
Total liabilities.............. 841,398 19,424 808,562 38,863
-------- ------- -------- -------
Deferred tax assets:
Tax basis step-up in connection with
acquisition of subsidiary......... 18,619 -- 19,170 --
Deferred investment tax credits...... 15,854 -- 17,114 --
Overheads capitalized for tax
purposes.......................... 8,226 -- 13,747 --
Supplier and other refunds........... -- 187 -- 277
Other................................ 86,581 5,502 77,197 2,490
Valuation allowance.................. -- -- -- --
-------- ------- -------- -------
Total assets................... 129,280 5,689 127,228 2,767
-------- ------- -------- -------
Total deferred income taxes.... $712,118 $13,735 $681,334 $36,096
======== ======= ======== =======
- -----------------------------------------------------------------------------------------------------------
</TABLE>
A regulatory liability amounting to $55.0 million has been recorded at
December 31, 1997 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 $103.3 million has been recorded at December 31, 1997. These
amounts are included in the Consolidated Balance Sheet under "Deferred credits
and other liabilities" and "Deferred charges and other assets," respectively.
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 1997, the current cost of replacing the inventory of "Gas
stored--current portion" exceeded the amount stated on a LIFO basis by
approximately $200.5 million at December 31, 1997. Virginia Natural Gas and CNG
Energy Services 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, 1997 and 1996.
10. UNAMORTIZED ABANDONED FACILITIES
In 1988, Consolidated LNG received FERC approval for the abandonment of its
interest in liquefied natural gas facilities at Cove Point, Maryland. In
connection with the abandonment, Consolidated LNG recorded a deferred asset in
accordance with the provisions of SFAS No. 90, "Accounting for Abandonments and
35
<PAGE> 38
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Disallowances of Plant Costs." This deferred asset, which represents the present
value of allowable costs expected to be recovered, has been amortized over a
10-year recovery period which will end February 28, 1998, as prescribed in the
FERC order.
11. COMMON STOCKHOLDERS' EQUITY
A summary of the changes in stockholders' equity follows:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Common Stock Capital in Excess
Issued of Par Value
--------------------- -----------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Number Value Retained Unearned
of Shares at Par Paid-In Other Total Earnings Compensation
- ----------------------------------------------------------------------------------------------------------------
<CAPTION>
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31,
1994....................... 93,028 $255,827 $418,348 $40,280 $458,628 $1,469,879 $ --
Net income................... -- -- -- -- -- 21,344 --
Cash dividends declared
Common stock ($1.94 per
share)................... -- -- -- -- -- (181,055) --
Common stock issued
Stock options.............. 217 596 7,453 -- 7,453 -- --
System Thrift Plans........ 213 586 7,586 -- 7,586 -- --
DRP*....................... 104 287 3,837 -- 3,837 -- --
Stock awards-net........... 30 81 1,040 -- 1,040 -- --
Purchase of treasury stock... -- -- -- -- -- -- --
Sale of treasury stock....... -- -- (9) -- (9) -- --
Pension liability
adjustment................. -- -- -- -- -- (262) --
------ -------- -------- ------- -------- ---------- --------
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... -- -- -- -- -- -- --
Sale of treasury stock and
other...................... -- -- (143) -- (143) -- --
Pension liability adjustment
(Note 6)................... -- -- -- -- -- 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... -- -- -- -- -- -- --
Sale of treasury stock and
other...................... -- -- 154 -- 154 -- --
Pension liability adjustment
(Note 6)................... -- -- -- -- -- (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)
====== ======== ======== ======= ======== ========== ========
<CAPTION>
Treasury Stock
----------------------
Number
of Shares Cost
- -------------------------------------------------------------
<S> <C> <C>
Balance at December 31,
1994....................... -- $ --
Net income................... -- --
Cash dividends declared
Common stock ($1.94 per
share)................... -- --
Common stock issued
Stock options.............. -- --
System Thrift Plans........ -- --
DRP*....................... -- --
Stock awards-net........... -- --
Purchase of treasury stock... (17) (634)
Sale of treasury stock....... 17 634
Pension liability
adjustment................. -- --
---- --------
Balance at December 31,
1995....................... -- --
Net income................... -- --
Cash dividends declared
Common stock ($1.94 per
share)................... -- --
Common stock issued
Stock options.............. -- --
Performance shares-net..... -- --
Stock awards-net........... -- --
DRP*....................... -- --
Amortization and
adjustment............... -- --
Purchase of treasury stock... (147) (8,144)
Sale of treasury stock and
other...................... 147 8,144
Pension liability adjustment
(Note 6)................... -- --
---- --------
Balance at December 31,
1996....................... -- --
Net income................... -- --
Cash dividends declared
Common stock ($1.94 per
share)................... -- --
Common stock issued
Stock options.............. -- --
DRP*....................... -- --
Stock awards-net........... -- --
Conversion of debentures... -- --
Performance shares-net..... -- --
Amortization and
adjustment............... -- --
Purchase of treasury stock... (220) (12,286)
Sale of treasury stock and
other...................... 219 12,248
Pension liability adjustment
(Note 6)................... -- --
Cumulative translation
adjustment................. -- --
---- --------
Balance at December 31,
1997....................... (1) $ (38)
==== ========
</TABLE>
- --------------------------------------------------------------------------------
* Dividend Reinvestment Plan.
36
<PAGE> 39
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. Each
Right would entitle the holder to purchase from the Company one-half of one
share of common stock at a price of $175 per share ($87.50 per half-share),
subject to adjustment (Purchase Price), if certain conditions are met in
connection with a possible acquisition of the common stock of the Company by a
third party. If the Rights become exercisable, each holder may exercise a Right
and receive common stock (or, in certain cases, cash, property or other
securities) of the Company or common stock of the acquiring company having a
value equal to twice the Right's then current Purchase Price.
Also, under certain conditions, the Board of Directors may exchange the
Rights, in whole or in part, at an exchange ratio of one share of common stock
(and/or other securities, cash or other assets having the same value as a share
of common stock) per Right, subject to adjustment, or may redeem the Rights in
whole at a price of $0.01 per Right. Until a Right is exercised or exchanged for
common stock, the holder, as such, is not a stockholder of the Company. Unless
earlier exercised or redeemed, the Rights will expire on February 28, 2006.
UNISSUED SHARES
At December 31, 1997, 304,376,719 shares of common stock were unissued. Shares
have been registered with the SEC for possible issuance under various benefit
plans. Shares acquired by these plans can consist of original issue shares,
treasury shares or shares purchased in the open market. Shares have also been
registered with the SEC for possible issuance to shareholders under the Dividend
Reinvestment Plan and for issuance upon conversion of the Company's convertible
subordinated debentures. In addition, the Company has a shelf registration with
the SEC which would allow it to sell up to an additional $700 million of debt or
equity securities at December 31, 1997.
TREASURY STOCK
Under a stock repurchase 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." The cost of any shares held as treasury stock is shown as a reduction in
common stockholders' equity in the Consolidated Balance Sheet. No treasury
shares were held at December 31, 1996. At December 31, 1997, a total of 659
shares 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, 1997. 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, 1997.
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
37
<PAGE> 40
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 1997, 5,832,110 shares were available for issuance
under the 1997 Plan.
Stock awards granted under the plan may be in the form of restricted stock
or deferred stock. Shares issued as restricted stock awards are held by the
Company until the attached restrictions lapse. Deferred stock awards generally
consist of a right to receive shares at the end of specified deferral periods.
The market value of the stock award on the date granted is recorded as
compensation expense over the applicable restriction or deferral period.
Stock options granted under the plan allow the purchase of common shares at
a price not less than fair market value at the date of grant and not less than
par value. 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 ten years from the date of grant.
Stock appreciation rights may also be granted, either alone or in tandem
with stock options. These rights permit the recipient to receive, upon exercise,
the excess of the fair market value of a share on the date of exercise over the
grant price. The grant price is generally the fair market value of the stock on
the date of grant. As of December 31, 1997, no stock appreciation rights have
been granted under the plan.
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) 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 allowed by SFAS No. 123, "Accounting for Stock-Based Compensation," the
Company continues to follow Accounting Principles Board Opinion No. 25 and
related interpretations (APB No. 25), for accounting for stock-based
compensation. The Company granted stock awards totaling 43,000 shares in 1997,
103,000 shares in 1996, and 34,000 shares in 1995 with weighted average market
prices per share on award dates of $51.89, $47.43, and $39.15, respectively. In
addition, performance shares totaling 55,000 shares in 1997 and 404,000 shares
in 1996 were issued at a weighted average market price of $53.02 and $45.87 per
share, respectively. The Company recorded compensation expense of $9.7 million,
$8.7 million and $.8 million for the years ended December 31, 1997, 1996 and
1995, 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.
38
<PAGE> 41
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
A summary of the Company's stock option activity under the plans described
above for the years ended December 31, 1995 through 1997, follows:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Weighted Average
Number Option Price
of Shares Per Share
- -----------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Shares under option:
At January 1, 1995..................................... 2,557 $42.43
Granted................................................ 1,078 $37.32
Exercised.............................................. (217) $35.88
Cancelled.............................................. (470) $41.14
-----
At December 31, 1995................................... 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
=====
</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.
Options were exercisable for the purchase of 599,534 shares, 673,305 shares, and
1,048,064 shares at December 31, 1997, 1996 and 1995, respectively. Effective
January 2, 1998, additional options for the purchase of 529,500 shares were
granted to eligible employees.
- --------------------------------------------------------------------------------
The following table summarizes information about stock options outstanding
at December 31, 1997.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
--------------------------------------------------- --------------------------------
<S> <C> <C> <C> <C> <C>
Weighted Average Weighted Weighted
Number Remaining Average Number Average
Range of Exercise Prices Outstanding Contractual Life Exercise Price Exercisable Exercise Price
- --------------------------------------------------------------------------------------------------------------------
<CAPTION>
(In Thousands) (In Thousands)
<S> <C> <C> <C> <C> <C>
$34.75--$40.00 712 6.33 YRS. $37.12 205 $36.59
$40.01--$50.00 3,369 7.42 YRS. $44.92 310 $44.95
$50.01--$59.94 1,126 8.35 YRS. $54.01 85 $50.77
- --------------------------------------------------------------------------------------------------------------------
</TABLE>
39
<PAGE> 42
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 1995 through 1997 and the weighted-average assumptions
used to compute fair values under the Black-Scholes option-pricing model:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Option fair value........................................... $8.96 $5.84 $5.50
Assumptions
Dividend yield......................................... 3.6% 4.3% 5.0%
Expected volatility.................................... 16.8% 17.5% 19.2%
Risk-free interest rate................................ 6.4% 5.4% 6.9%
Expected option life (years)........................... 4.8 4.9 4.9
- ----------------------------------------------------------------------------------------
</TABLE>
If compensation expense for stock options granted during 1995 through 1997
had been determined based on the fair value at the grant dates for such awards
in accordance with SFAS No. 123, the effect on the Company's net income and
earnings per share for each of the years would have been as follows:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
NET INCOME (In Millions):
As reported............................................ $304.4 $298.3 $ 21.3
Pro forma.............................................. $298.8 $294.1 $ 20.7
BASIC EPS:
As reported............................................ $ 3.21 $ 3.17 $ .23
Pro forma.............................................. $ 3.15 $ 3.13 $ .22
DILUTED EPS:
As reported............................................ $ 3.15 $ 3.13 $ .23
Pro forma.............................................. $ 3.10 $ 3.08 $ .22
- ----------------------------------------------------------------------------------------
</TABLE>
12. 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, 1997 or 1996.
13. 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, $720.4 million of consolidated retained
earnings was free from such restrictions at December 31, 1997. The indenture
also imposes dividend limitations on the subsidiaries, but at December 31, 1997,
these limitations did not restrict their ability to pay dividends to the
Company.
40
<PAGE> 43
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. LONG-TERM DEBT
Long-term debt, excluding current maturities, follows:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
DECEMBER 31, 1997 1996
- --------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Debentures
6.8%, Due December 15, 2027............................ $ 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
5 7/8%, Due October 1, 1998............................ -- 150,000
8 3/4%, Due October 1, 2019............................ 150,000 150,000
8 3/4%, Due June 1, 1999............................... 100,000 100,000
8 5/8%, Due December 1, 2011........................... 15,625 31,250
Unamortized debt discount, less premium................ (11,319) (7,429)
Convertible Subordinated Debentures
7 1/4%, Due December 15, 2015.......................... 246,165 246,205
Unamortized debt discount.............................. (1,581) (1,711)
9.94% Unsecured loan due January 1, 1999.................... 4,000 8,000
---------- ----------
Total.................................................. $1,552,890 $1,426,315
========== ==========
- --------------------------------------------------------------------------------------
</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 Company's 7 1/4% Convertible Subordinated Debentures, due December 15,
2015, were convertible into shares of the Company's common stock at an initial
conversion price of $54 per share. On January 23, 1998, the Company called for
redemption the entire principal amount outstanding totaling $246.2 million. The
redemption price was 102.18% of the principal amount plus accrued interest
payable on February 23, 1998. In anticipation of the call of this debt, on
January 15, 1998, the Company purchased approximately 4.6 million shares of its
common stock in a private transaction to satisfy the conversion obligation to
holders of the Convertible Subordinated Debentures who chose to convert. 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 are
expected to be sold in underwritten offerings during 1998.
In late 1996, the Company called for redemption $53.1 million principal
amount of the 8 5/8% Debentures Due December 1, 2011. In connection with the
call, the Company placed funds into an irrevocable trust in December 1996 for
the sole purpose of paying the principal amount and related call premium and
accrued interest. As such, the debt was removed from the Consolidated Balance
Sheet at December 31, 1996. Payment was made from the trust on February 1, 1997.
This transaction resulted in a 1996 charge to "Other Income" of $5.0 million.
The aggregate principal amounts of the Company's debentures maturing in the
years 1998 through 2002 are: $150.0 million; $107.1 million; $7.1 million; $7.1
million and $7.1 million.
The 9.94% unsecured loan due January 1, 1999, is an obligation of Virginia
Natural Gas. This $20.0 million loan, which is being repaid in five annual
installments of $4.0 million each beginning January 1, 1995, has been guaranteed
by the Company.
41
<PAGE> 44
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. SHORT-TERM BORROWINGS
The weighted average interest rate on the Company's commercial paper notes
outstanding at December 31, 1997 and 1996, was 6.21% and 5.70%, 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 26, 1998; 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, 1997.
On February 13, 1998, the Company entered into a $250.0 million short-term
credit agreement with a bank. Borrowings under the agreement are in the form of
revolving credits which may be used for general corporate purposes.
16. FINANCIAL INSTRUMENTS
FAIR VALUES
The estimated fair value of the Company's long-term debt, including current
maturities, was as follows at December 31, 1997 and 1996:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
1997 1996
----------------------- -----------------------
Carrying Fair Carrying Fair
December 31, Amount Value Amount Value
- ------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C>
Long-term debt........................... $1,719,790 $1,789,577 $1,539,455 $1,563,440
- ------------------------------------------------------------------------------------------------
</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
FUTURES AND OPTIONS CONTRACTS
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 options, which require settlement in cash. CNG Energy
Services uses such instruments to manage commodity price risk regarding gas and
electricity purchase and sale commitments and stored gas inventories, while CNG
Producing uses them to manage risk in connection with the production and sale of
crude oil.
At December 31, 1997, CNG Energy Services had natural gas futures contracts
related to gas purchase and sale commitments and gas storage inventory covering
2.9 Bcf of gas on a net basis maturing through 2000. Also at December 31, 1997,
CNG Producing held crude oil futures contracts maturing through 1998 covering
1,750,000 barrels of oil.
For contracts used by the Company that 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 $5.1 million at
December 31, 1997.
42
<PAGE> 45
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
SWAP AGREEMENTS
In addition to futures and options contracts, CNG Energy Services and CNG
Producing enter into OTC price swap agreements to manage their exposure to
commodity price risk under existing sales commitments.
At December 31, 1997, CNG Energy Services 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, 1997 related to those swap agreements in which CNG
Energy Services pays a fixed price in exchange for a variable price totaled
324.5 Bcf, while net notional quantities related to agreements in which CNG
Energy Services pays a variable price in exchange for a fixed price totaled
297.2 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
$4.7 million at December 31, 1997. Profits expected on anticipated sales related
to the hedged transactions should generally offset the estimated unrealized
losses on the swap agreements.
CNG Energy Services also has a foreign currency swap agreement effective
through April 2005 to manage foreign exchange rate risk in connection with the
payment of demand charges for pipeline capacity in Canada. The aggregate
notional amount underlying this swap agreement was approximately $51.0 million
at December 31, 1997. The unrealized gain related to this swap agreement was
$4.5 million at December 31, 1997.
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 CNG Energy Services. These policies include
value-at-risk and notional contract and stop loss limit structures designed to
maintain exposure levels within the parameters established by management.
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 regard 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, 1997, the Company
believes it is unlikely that a material adverse effect on its financial
position, results of operations or cash flows would occur as a result of
counterparty nonperformance.
17. ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and regulations
relating to the protection of the environment. These laws and regulations govern
both current and future operations and potentially extend to plant sites
formerly owned or operated by the subsidiaries, or their predecessors.
The Company has taken a proactive position with respect to environmental
concerns. As part of normal business operations, subsidiaries periodically
monitor their properties and facilities to identify and resolve potential
environmental matters, and the Company conducts general environmental surveys on
a continuing basis at its operating facilities to monitor compliance with
environmental laws and regulations.
43
<PAGE> 46
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 had
been assessed as of December 31, 1997. Pursuant to the Order and Agreement, CNG
Transmission continues to perform sampling, testing and analysis, and conducting
a program of remediation at some of its Pennsylvania facilities. Total
remediation costs in connection with these sites and the Order and Agreement are
not expected to be material with respect to the Company's financial position,
results of operations or cash flows. Based on current information, the Company
has recognized a gross estimated liability amounting to $10.9 million at
December 31, 1997, for future costs expected to be incurred to remediate or
mitigate hazardous substances at these sites and at facilities covered by the
Order and Agreement.
Inasmuch as certain environmental-related expenditures are expected to be
recoverable in future regulatory proceedings, a regulatory asset amounting to
$7.3 million at December 31, 1997, is included in the Consolidated Balance Sheet
under the caption "Deferred charges and other assets." Also, uncontested claims
amounting to $1.5 million at December 31, 1997, 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, 1997 1996 1995
- ---------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Recurring costs for ongoing operations...................... $3,430 $4,174 $3,094
Mandated remediation and other compliance costs............. 1,473 (419) 2,307
Voluntary remediation costs................................. 228 2,705 1,630
Other....................................................... 14 3 79
------ ------ ------
Total.................................................. $5,145 $6,463 $7,110
====== ====== ======
</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. Compliance required
capital expenditures to similarly retrofit some of the compressor engines along
the Company's pipeline system. The Company has completed the installation of
emission control equipment and the installation and testing of compressor
engines and related equipment required by the 1990 amendments. In addition,
several of the subsidiaries are required by the Clean Air Act Amendments to
acquire Title V permits for major facilities. Progress is on schedule for these
permits, with no major expenditures anticipated. The 1990 amendments may also
require installation of Maximum Available Control Technology (MACT) to control
the emissions of certain hazardous air pollutants. The Company is participating
with industry groups and the Environmental Protection Agency (EPA) in the
development of these regulations but is unable to estimate the cost of
installing MACT, if required.
The Company expended de minimis amounts in 1997, $6.8 million in 1996 and
$11.3 million in 1995, to comply with the 1990 amendments. 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
44
<PAGE> 47
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
manufactured gas plants have indicated that their sites contain coal tar and
other potentially harmful materials. None of the 16 former sites with which the
Company is associated is under investigation by any state or federal
environmental agency, and no investigation or action is currently anticipated.
At this time it is not known if, or to what degree, these sites may contain
environmental contamination. Therefore, the Company is not able to estimate the
cost, if any, that may be required for the possible remediation of these sites.
The Company discovered in the course of conducting a routine environmental
survey at East Ohio Gas that some of its practices for collecting and handling
pipeline fluids that may have been contaminated with polychlorinated biphenyls
(PCBs) may not have complied with environmental regulations. The appropriate
agencies have been notified as part of the federal self-disclosure process and
discussions are continuing with the agencies to gain approval of revised
collection and handling procedures. The discrepancies in the procedures were
primarily in connection with recordkeeping and did not involve spills, leaks, or
other mishandling of PCB contaminated fluids and did not damage the environment.
A thorough investigation of all collection and handling practices at East Ohio
Gas has been conducted and the Company provided the results of this
investigation to the EPA in 1997. One partial penalty assessment has been
received from the EPA, and the Company has entered into a Consent Agreement
Consent Order with the EPA. The penalty assessment was developed by EPA under
its Voluntary Disclosure Policy of April 22, 1995 and was approximately one
thousand dollars. The Company anticipates that additional penalties incurred in
connection with this matter will be mitigated as a result of the Company's self
disclosure. The amount of any liabilities in connection with this matter is not
expected to be material with respect to the Company's financial position,
results of operations or cash flows.
Estimates of liability in the environmental area are based on current
environmental laws and regulations and existing technology. The exact nature of
environmental issues which the Company may encounter in the future cannot be
predicted. Additional environmental liabilities may result in the future as more
stringent environmental laws and regulations are implemented and as the Company
obtains more specific information about its existing sites and production
facilities. At present, no estimate of any such additional liability, or range
of liability amounts, can be made. However, the amount of any such liabilities
could be material.
18. 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 1995 through 1997 was not material, and future rental payments required
under leases in effect at December 31, 1997, are not material.
It is estimated that the Company's 1998 capital spending program will
amount to $714.7 million, and that approximately $312.7 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. Contractual commitments in the ordinary course of business include
requirements by CNG Energy Services to purchase capacity on nonaffiliated
pipelines to meet both committed and anticipated future long-term customer gas
supply needs.
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.
19. DISAGGREGATED INFORMATION
In addition to operating in all phases of the natural gas business, the Company
explores for and produces oil and provides a variety of energy marketing
services.
45
<PAGE> 48
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Distribution represents the retail gas distribution subsidiaries. These
subsidiaries sell gas and/or provide transportation services to residential,
commercial and industrial customers in Ohio, Pennsylvania, Virginia and West
Virginia, and are subject to price regulation by their respective state utility
commissions.
Transmission operations include the activities of CNG Transmission, an
interstate pipeline company regulated by the FERC which provides gas
transportation, storage and related services to affiliates and to utilities and
end users in the Midwest, the Mid-Atlantic states and the Northeast. 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.
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.
Energy marketing services is comprised of CNG Energy Services and CNG Power
Services. CNG Energy Services markets Company-owned gas production and arranges
gas supplies, transportation, storage and related services throughout North
America. CNG Energy Services also holds the Company's ownership interests in six
independent power plants. CNG Power Services is the power marketing subsidiary
that purchases and resells electricity at market-based prices.
The activities of CNG International, CNG Retail, CNG Products and Services,
Consolidated LNG, CNG Research and CNG Coal are included in the "Other"
category. CNG International was formed in 1996 to engage in energy-related
activities outside of the United States and holds equity investments in
Australia 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 began operations in 1996 and provides certain
energy-related services to customers of the Company's distribution subsidiaries
and others.
Transactions between affiliates are recognized at prices which approximate
market value. Significant transactions between the operating components are
eliminated to reconcile the disaggregated information to consolidated amounts.
Identifiable assets of each component are those assets that are used in its
operations.
46
<PAGE> 49
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table represents disaggregated information pertaining to the
Company's operations:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Exploration Energy Corporate
and Marketing and
Distribution Transmission Production Services Other Eliminations Total
- ---------------------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
1997
Operating revenues
Nonaffiliated
Regulated gas sales........... $1,844,221 $ -- $ -- $ -- $ 6,780 $ -- $1,851,001
Nonregulated gas sales........ -- -- 48,379 2,259,436 31,342 -- 2,339,157
Gas transportation and
storage..................... 153,503 318,086 701 7,215 -- -- 479,505
Electricity sales............. -- -- -- 594,253 279 -- 594,532
Other......................... 23,695 47,853 300,370 68,400 5,507 -- 445,825
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total nonaffiliated......... 2,021,419 365,939 349,450 2,929,304 43,908 -- 5,710,020
Affiliated...................... 5,142 121,037 356,230 176,463 15,257 (674,129) --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues...... 2,026,561 486,976 705,680 3,105,767 59,165 (674,129) 5,710,020
Other operating expenses........ 1,682,602 246,617 381,475 3,116,964 68,100 (661,068) 4,834,690
Depreciation and amortization... 77,389 61,920 181,356 5,884 366 3,229 330,144
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income before income
taxes......................... $ 266,570 $ 178,439 $ 142,849 $ (17,081) $ (9,301) $ (16,290) $ 545,186
========== ========== ========== ========== ========== ========== ==========
Capital expenditures............ $ 147,213 $ 49,251 $ 293,337 $ 12,865 $ 95,801 $ 10,906 $ 609,373
Identifiable assets............. $2,879,960 $1,482,652 $1,314,468 $ 757,028 $ 288,006 $ (408,420) $6,313,694
- ---------------------------------------------------------------------------------------------------------------------------------
1996
Operating revenues
Nonaffiliated
Regulated gas sales........... $1,745,206 $ -- $ -- $ -- $ 7,017 $ -- $1,752,223
Nonregulated gas sales........ -- -- 66,126 1,026,360 -- -- 1,092,486
Gas transportation and
storage..................... 132,134 331,637 532 807 -- -- 465,110
Electricity sales............. -- -- -- 109,446 -- -- 109,446
Other......................... 25,211 51,471 226,306 70,235 1,821 -- 375,044
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total nonaffiliated......... 1,902,551 383,108 292,964 1,206,848 8,838 -- 3,794,309
Affiliated...................... 2,961 120,292 339,323 149,635 9,834 (622,045) --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues...... 1,905,512 503,400 632,287 1,356,483 18,672 (622,045) 3,794,309
Other operating expenses........ 1,572,959 264,542 333,336 1,363,871 21,780 (614,324) 2,942,164
Depreciation and amortization... 74,132 60,107 165,715 1,681 48 2,488 304,171
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income before income
taxes......................... $ 258,421 $ 178,751 $ 133,236 $ (9,069) $ (3,156) $ (10,209) $ 547,974
========== ========== ========== ========== ========== ========== ==========
Capital expenditures............ $ 143,050 $ 85,904 $ 247,103 $ 35,531 $ 42,570 $ 6,135 $ 560,293
Identifiable assets............. $2,902,917 $1,481,612 $1,232,992 $ 473,766 $ 94,608 $ (185,290) $6,000,605
- ---------------------------------------------------------------------------------------------------------------------------------
1995
Operating revenues
Nonaffiliated
Regulated gas sales........... $1,594,397 $ (4,275) $ -- $ -- $ 7,257 $ -- $1,597,379
Nonregulated gas sales........ -- -- 57,778 939,946 -- -- 997,724
Gas transportation and
storage..................... 122,175 333,185 423 587 -- -- 456,370
Electricity sales............. -- -- -- 21,768 -- -- 21,768
Other......................... 22,375 36,978 116,241 58,488 2 -- 234,084
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total nonaffiliated......... 1,738,947 365,888 174,442 1,020,789 7,259 -- 3,307,325
Affiliated...................... 6,280 105,138 187,012 87,611 10,168 (396,209) --
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues...... 1,745,227 471,026 361,454 1,108,400 17,427 (396,209) 3,307,325
Other operating expenses........ 1,466,776 261,091 438,477 1,113,014 14,543 (392,668) 2,901,233
Depreciation and amortization... 70,972 59,552 123,492 1,072 -- 1,548 256,636
---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating income before income
taxes......................... $ 207,479 $ 150,383 $ (200,515) $ (5,686) $ 2,884 $ (5,089) $ 149,456
========== ========== ========== ========== ========== ========== ==========
Capital expenditures............ $ 160,480 $ 81,557 $ 176,789 $ 19,567 $ -- $ 1,000 $ 439,393
Identifiable assets............. $2,645,004 $1,483,631 $1,155,092 $ 317,490 $ 54,425 $ (237,349) $5,418,293
- ---------------------------------------------------------------------------------------------------------------------------------
</TABLE>
47
<PAGE> 50
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
20. SUPPLEMENTARY FINANCIAL INFORMATION--UNAUDITED
(A) GAS AND OIL PRODUCING ACTIVITIES (EXCLUDING COST-OF-SERVICE RATE-REGULATED
ACTIVITIES)
This information has been prepared in accordance with SFAS No. 69, "Disclosures
about Oil and Gas Producing Activities," and related SEC pronouncements.
Statement No. 69 is a comprehensive, standard set of required disclosures about
the gas and oil producing activities of publicly traded companies. The following
disclosures exclude the gas and oil producing activities subject to
cost-of-service rate regulation. Certain disclosures about these gas and oil
activities, which are exempt from the accounting methods prescribed by the SEC,
are included under "Cost-of-Service Properties" in this Note (A).
CAPITALIZED COSTS
The aggregate amounts of costs capitalized by subsidiaries for their gas and oil
producing activities, and related aggregate amounts of accumulated depreciation
and amortization, follow:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
DECEMBER 31, 1997 1996
- -----------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C>
Capitalized costs of
Proved properties......................................... $3,293,851 $3,057,682
Unproved properties....................................... 328,174 317,462
---------- ----------
Subtotal............................................... 3,622,025 3,375,144
---------- ----------
Accumulated depreciation of
Proved properties......................................... 2,367,105 2,224,471
Unproved properties....................................... 146,417 134,481
---------- ----------
Subtotal............................................... 2,513,522 2,358,952
---------- ----------
Net capitalized costs.................................. $1,108,503 $1,016,192
========== ==========
</TABLE>
- --------------------------------------------------------------------------------
As described in Note 4, 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.
TOTAL COSTS INCURRED
The following costs were incurred by subsidiaries in their gas and oil producing
activities during the years 1995 through 1997:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Property acquisition costs
Proved properties...................................... $ 14,142 $ 42,880 $ 5,824
Unproved properties.................................... 43,951 17,911 9,686
-------- -------- --------
Subtotal............................................ 58,093 60,791 15,510
Exploration costs........................................ 101,891 49,622 50,974
Development costs........................................ 118,746 125,139 102,574
-------- -------- --------
Total............................................... $278,730 $235,552 $169,058
======== ======== ========
</TABLE>
- --------------------------------------------------------------------------------
RESULTS OF OPERATIONS
The elements of the "results of operations for gas and oil producing activities"
that follow are as required and defined by the FASB. The Company cautions that
these standardized disclosures do not represent the
48
<PAGE> 51
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Revenues (net of royalties) from:
Sales to nonaffiliated companies....................... $111,181 $ 84,239 $ 60,139
Transfers to other operations.......................... 300,025 289,892 150,930
-------- -------- ---------
Total............................................... 411,206 374,131 211,069
-------- -------- ---------
Less: Production (lifting) costs......................... 65,286 55,679 40,812
Depreciation and amortization...................... 172,046 157,358 117,163
Impairment of producing properties................. 10,351 -- 226,209
Income tax expense................................. 48,987 49,367 (68,615)
-------- -------- ---------
Results of operations.................................... $114,536 $111,727 $(104,500)
======== ======== =========
</TABLE>
- --------------------------------------------------------------------------------
COMPANY-OWNED RESERVES (NON-COST-OF-SERVICE RESERVES)
Estimated net quantities of proved gas and oil (including condensate) reserves
in the United States and Canada at December 31, 1995 through 1997, and changes
in the reserves during those years, are shown in the two schedules which follow:
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- --------------------------------------------------------------------------------------------------------------------
(In Bcf)
<S> <C> <C> <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES* -- GAS
At January 1........................................... 1,040 985 901
Changes in reserves
Extensions, discoveries and other additions......... 210 124 167
Revisions of previous estimates..................... 31 5 17
Production.......................................... (155) (145) (103)
Purchases of gas in place........................... 29 96 7
Sales of gas in place............................... (14) (25) (4)
------ ------ -----
At December 31......................................... 1,141 1,040 985
====== ====== =====
PROVED DEVELOPED RESERVES* -- GAS
At January 1........................................... 900 717 730
At December 31......................................... 925 900 717
*Net before royalty.
</TABLE>
- --------------------------------------------------------------------------------
Included in the caption "Extensions, discoveries and other additions" for
1995 are 110 Bcf of proved undeveloped reserves for which development costs will
be incurred in future years. The preceding proved developed and undeveloped gas
reserves at December 31, 1997, 1996 and 1995, include United States reserves of
1,140, 1,039 and 984 Bcf which, together with the Canadian reserves and the gas
reserves
49
<PAGE> 52
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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, 1997 1996 1995
- --------------------------------------------------------------------------------------------------
(In Thousand Bbls)
<S> <C> <C> <C>
PROVED DEVELOPED AND UNDEVELOPED RESERVES* -- OIL
At January 1.............................................. 50,457 45,791 46,255
Changes in reserves
Extensions, discoveries and other additions............ 4,582 5,976 1,965
Revisions of previous estimates........................ 1,741 2,711 1,117
Production............................................. (7,312) (4,766) (3,132)
Purchases of oil in place.............................. 1,182 804 163
Sales of oil in place.................................. (23) (59) (577)
------ ------ ------
At December 31............................................ 50,627 50,457 45,791
====== ====== ======
PROVED DEVELOPED RESERVES* -- OIL
At January 1.............................................. 24,989 19,838 20,379
At December 31............................................ 37,568 24,989 19,838
*Net before royalty.
</TABLE>
- --------------------------------------------------------------------------------
The foregoing proved developed and undeveloped oil reserves at December 31,
1997, 1996 and 1995 include United States reserves of 44,160, 41,818 and 39,964
thousand barrels, respectively. These, together with the Canadian reserves, are
as contained in reports of Ralph E. Davis Associates, Inc.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES
THEREIN
The following tabulation has been prepared in accordance with the FASB's rules
for disclosure of a standardized measure of discounted future net cash flows
relating to Company-owned proved gas and oil reserve quantities.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
DECEMBER 31, 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Future cash inflows..................................... $3,197,532 $4,022,381 $2,668,837
Less: Future development and production costs........... 658,281 711,067 659,532
Future income tax expense........................ 766,233 1,049,234 602,158
---------- ---------- ----------
Future net cash flows................................... 1,773,018 2,262,080 1,407,147
Less annual discount (10% a year)....................... 606,509 830,083 565,404
---------- ---------- ----------
Standardized measure of discounted future net cash
flows................................................. $1,166,509 $1,431,997 $ 841,743
========== ========== ==========
</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
50
<PAGE> 53
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
imprecise and subject to revision, and the 10% discount rate is arbitrary. In
addition, present costs and prices are used in the determinations and no value
may be assigned to probable or possible reserves.
The following tabulation is a summary of changes between the total
standardized measure of discounted future net cash flows at the beginning and
end of each year.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
YEARS ENDED DECEMBER 31, 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------
(In Thousands)
<S> <C> <C> <C>
Standardized measure of discounted future net cash flows
at January 1.......................................... $1,431,997 $ 841,743 $ 704,492
Changes in the year resulting from
Sales and transfers of gas and oil produced during the
year, less production costs........................ (345,920) (318,583) (170,257)
Prices and production and development costs related to
future production.................................. (660,014) 632,118 150,634
Extensions, discoveries and other additions, less
production and development costs................... 256,366 295,236 181,664
Previously estimated development costs incurred during
the year........................................... 38,409 62,706 62,958
Revisions of previous quantity estimates.............. 101,352 106,800 8,336
Accretion of discount................................. 209,210 119,555 98,736
Income taxes.......................................... 159,528 (306,290) (70,927)
Purchases and sales of proved reserves in place-net... 40,815 112,601 1,794
Other (principally timing of production).............. (65,234) (113,889) (125,687)
---------- ---------- ---------
Standardized measure of discounted future net cash flows
at December 31........................................ $1,166,509 $1,431,997 $ 841,743
========== ========== =========
- -------------------------------------------------------------------------------------------------------------------
</TABLE>
COST-OF-SERVICE PROPERTIES
As previously stated, activities subject to cost-of-service rate regulation are
excluded from the foregoing information. At December 31, 1997 and 1996, net
capitalized costs of cost-of-service properties amounted to $8.4 million and
$10.0 million, respectively. Related proved reserves of gas are located in the
United States and amounted to 42, 43 and 56 Bcf at December 31, 1997, 1996 and
1995. There were no cost-of-service oil reserves at December 31, 1997, 1996 or
1995. Gas production for the years 1997, 1996 and 1995 amounted to 3, 3 and 4
Bcf, respectively. Oil production for 1995 amounted to 17,000 barrels.
Future revenues associated with production of the foregoing gas reserves
would be based upon cost-of-service ratemaking and historical asset costs, with
rate of return levels determined by various state regulatory commissions.
(B) QUARTERLY FINANCIAL DATA
A summary of the quarterly results of operations for the years 1997 and 1996
follows. Per share amounts for the first three quarters of 1997 and all 1996
quarters have been restated in connection with the Company's adoption of SFAS
No. 128. 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
51
<PAGE> 54
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
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>
1997
Total operating revenues................... $1,698,599 $1,030,854 $1,130,477 $1,850,090
Operating income before income taxes....... 280,688 76,990 26,859 160,649
Net income................................. 171,491 38,985 4,538 89,366
Earnings per common share -- basic......... 1.81 .41 .05 .94
Earnings per common share -- diluted*...... 1.74 .41 .05 .92
1996
Total operating revenues................... $1,315,084 $ 654,950 $ 595,057 $1,229,218
Operating income before income taxes....... 302,176 71,949 11,045 162,804
Net income (loss).......................... 180,800 34,617 (5,118) 87,974
Earnings (loss) per common
share -- basic........................... 1.93 .37 (.05) .93
Earnings (loss) per common
share -- diluted*........................ 1.87 .37 (.05) .91
</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, 1997, there were 35,498 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 1997 and
1996 follow. Restrictions on the payment of dividends are discussed in Note 13.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Quarter
-------------------------------------------------------------------------
First Second Third Fourth
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Market Price Range
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
1996--High.................................... $ 47 1/8 $ 52 1/4 $ 57 1/8 $ 59 5/8
--Low................................... $ 41 1/2 $ 43 1/2 $ 49 $ 51 1/8
Dividends Declared per Share
1997.......................................... $ .485 $ .485 $ .485 $ .485
1996.......................................... $ .485 $ .485 $ .485 $ .485
</TABLE>
- --------------------------------------------------------------------------------
52
