UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
_________________
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, 1994
COMMISSION FILE NUMBER 1-3196
_________________
CONSOLIDATED NATURAL GAS COMPANY
A DELAWARE CORPORATION
CNG TOWER, 625 LIBERTY AVENUE, PITTSBURGH, PA 15222-3199
TELEPHONE (412) 227-1000
IRS EMPLOYER IDENTIFICATION NUMBER 13-0596475
_________________
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Common Stock: Registered:
$2.75 Par Value New York Stock Exchange
Debentures:
6 5/8% Debentures Due December 1, 2013 New York Stock Exchange
5 3/4% Debentures Due August 1, 2003 New York Stock Exchange
5 7/8% Debentures Due October 1, 1998 New York Stock Exchange
8 3/4% Debentures Due October 1, 2019 New York Stock Exchange
8 3/4% Debentures Due June 1, 1999 New York Stock Exchange
9 3/8% Debentures Due February 1, 1997 New York Stock Exchange
8 5/8% Debentures Due December 1, 2011 New York Stock Exchange
Convertible Subordinated Debentures:
7 1/4% Convertible Subordinated Debentures
Due December 15, 2015 New York Stock Exchange
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. ________
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 $3,205,797,891 as of January 31, 1995. It was assumed
in this calculation that the registrant's affiliates are all of its directors
and/or officers, and they beneficially owned 107,972 shares of voting stock at
that date.
Number of shares of Common Stock, $2.75 Par Value, outstanding at January 31,
1995: 93,029,650.
The registrant's "Notice of Annual Meeting and Proxy Statement, 1995" is
hereby incorporated by reference into Part III of this Form 10-K.
<PAGE>
CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1994
TABLE OF CONTENTS
PART I Page
ITEM 1. BUSINESS
The Company and its Subsidiaries . . . . . . 1
Governmental Regulation . . . . . . . . . 3
Capital Expenditures . . . . . . . . . . 4
Competitive Conditions . . . . . . . . . 5
Gas Supply . . . . . . . . . . . . . 8
Gas Sales and Transportation . . . . . . . 11
Gas Sales, Supply and Transportation Statistics . 13
Market Expansion . . . . . . . . . . . 14
Rate Matters. . . . . . . . . . . . . 16
Executive Officers of the Company. . . . . . 18
ITEM 2. PROPERTIES
General Information on Facilities. . . . . . 19
Map - Principal Facilities . . . . . . . . 20
Map - Exploration and Production Areas . . . . 21
Gas and Oil Producing Activities . . . . . . 22
ITEM 3. LEGAL PROCEEDINGS. . . . . . . . . . . . 25
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 25
PART II
ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS . . . . . . . . . . . 25
ITEM 6. SELECTED FINANCIAL DATA. . . . . . . . . . 26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS. . . . . . 27
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . 45
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE. . . . . . 78
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY. . 78
ITEM 11. EXECUTIVE COMPENSATION . . . . . . . . . . 78
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT . . . . . . . . . . . . . . 78
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . 78
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K. . . . . . . . . . . . . . 78
SIGNATURES . . . . . . . . . . . . . . . . . 82
<PAGE>
CONSOLIDATED NATURAL GAS COMPANY
FORM 10-K ANNUAL REPORT
For the Year Ended December 31, 1994
PART I
ITEM 1. BUSINESS
THE COMPANY AND ITS SUBSIDIARIES
Consolidated Natural Gas Company is a Delaware corporation organized on July
21, 1942, and a public utility holding company registered under the Public
Utility Holding Company Act of 1935 (PUHCA). It is engaged solely in the
business of owning and holding all of the outstanding equity securities of
sixteen directly owned subsidiary companies.
Consolidated Natural Gas Company and its subsidiaries (Consolidated or the
Company) at December 31, 1994, are listed below. The subsidiary companies are
primarily engaged in, and their total operating revenues are principally
derived from, all phases of the natural gas business -- exploration,
production, purchasing, gathering, transmission, storage, distribution, and
marketing, together with by-product operations (see Note 17 to the
consolidated financial statements, page 70). At December 31, 1994,
Consolidated had 7,566 regular employees.
<TABLE>
<CAPTION>
________________________________________________________________________________
_________________
State of
Name of Company
Incorporation
________________________________________________________________________________
_________________
<S>
<C>
CONSOLIDATED NATURAL GAS COMPANY (Parent Company). . . . . . . . . .
Delaware
All wholly owned subsidiaries of the Parent Company:
Consolidated Natural Gas Service Company, Inc. (Service Company). . . . .
Delaware
CNG Transmission Corporation (CNG Transmission). . . . . . . . . .
Delaware
The East Ohio Gas Company (East Ohio Gas)* . . . . . . . . . . .
Ohio
The Peoples Natural Gas Company (Peoples Natural Gas). . . . . . . .
Pennsylvania
Virginia Natural Gas, Inc. (Virginia Natural Gas) . . . . . . . . .
Virginia
Hope Gas, Inc. (Hope Gas) . . . . . . . . . . . . . . . . .
West Virginia
West Ohio Gas Company (West Ohio Gas) . . . . . . . . . . . . .
Ohio
CNG Producing Company (CNG Producing) . . . . . . . . . . . . .
Delaware
CNG Energy Company**. . . . . . . . . . . . . . . . . . .
Delaware
CNG Energy Services Corporation (CNG Energy Services). . . . . . . .
Delaware
CNG Power Services Corporation (CNG Power Services) . . . . . . . .
Delaware
CNG Storage Service Company (CNG Storage). . . . . . . . . . . .
Delaware
Consolidated System LNG Company (Consolidated LNG). . . . . . . . .
Delaware
CNG Research Company (CNG Research). . . . . . . . . . . . . .
Delaware
CNG Coal Company (CNG Coal) . . . . . . . . . . . . . . . .
Delaware
CNG Financial Services, Inc. (CNG Financial). . . . . . . . . . .
Delaware
* During 1994, The Public Utilities Commission of Ohio approved the merger of
the Company's former subsidiary, The River Gas Company, into East Ohio Gas.
** Effective January 16, 1995, CNG Energy Company was renamed CNG Power Company
(CNG Power).
________________________________________________________________________________
_________________
</TABLE>
The principal cities served at retail by Consolidated's gas distribution
subsidiaries (East Ohio Gas, West Ohio Gas, Peoples Natural Gas, Virginia
Natural Gas and Hope Gas) are: Cleveland, Akron, Youngstown, Canton, Warren,
Lima, Ashtabula and Marietta in Ohio; Pittsburgh (a portion), Altoona and
Johnstown in Pennsylvania; Norfolk, Newport News, Virginia Beach, Chesapeake,
Hampton and Williamsburg in Virginia; and Clarksburg and Parkersburg in West
Virginia. At December 31, 1994, Consolidated served at retail approximately
1,800,000 residential, commercial and industrial gas sales customers in Ohio,
Pennsylvania, Virginia and West Virginia. Variations in weather
conditions can
1
<PAGE>
ITEM 1. BUSINESS (Continued)
materially affect the volume of gas delivered by the Company's distribution
subsidiaries, as 98 percent of their residential and commercial customers use
gas for space heating.
CNG Transmission is the Company's interstate gas transmission subsidiary. CNG
Transmission operates a regional interstate pipeline system serving each of
the Company's distribution subsidiaries, and nonaffiliated utility and end-
user customers in the Midwest, the Mid-Atlantic states and the Northeast.
Regulatory efforts intended to increase competition in the natural gas
industry have resulted in significant changes in the operations of CNG
Transmission over the past several years. Under the most recent regulatory
initiative, Federal Energy Regulatory Commission (FERC) Order 636, interstate
pipeline companies, including CNG Transmission, were required to revise
customer contracts and service tariffs and further "unbundle" their services
into separate sales, transportation and storage transactions, with such
services offered and priced separately. CNG Transmission implemented Order
636 on October 1, 1993 (see "FERC Order 636," page 38) and thereby abandoned
its traditional "bundled" sales service. CNG Transmission now offers a number
of gas transportation and storage service options, along with related
services, to a broad range of customers. Variations in weather conditions can
materially affect the volume of gas transported and stored by CNG
Transmission, since a substantial portion of its gas deliveries is ultimately
used by space-heating customers. However, operating results are less
influenced by changes in throughput than in the past, as 1994 was the first
full year of applying the straight fixed variable rate design pursuant to
Order 636.
Through its wholly owned subsidiary, CNG Iroquois, Inc., CNG Transmission
holds a 9.4 percent general partnership interest in the Iroquois Gas
Transmission System, L.P., a Delaware limited partnership formed to construct,
own and operate an interstate natural gas pipeline extending from the Canada-
United States border near Iroquois, Ontario, to Long Island, New York. The
Iroquois pipeline transports Canadian gas to utility and power generation
customers in metropolitan New York and New England.
CNG Producing is Consolidated's exploration and production subsidiary. Gas
and oil exploration and production activities are conducted by this subsidiary
primarily in the Gulf of Mexico, the southern and western United States, the
Appalachian region, and in Canada. In addition, CNG Producing participates in
several coalbed methane projects.
CNG Power develops new business opportunities for the Company in energy-
related markets. It invests in and develops independent power producer
projects and conducts a gas liquids business. CNG Power holds a 34% limited
partnership interest in Lakewood Cogeneration, L.P. (Lakewood Partnership),
which operates a 237-megawatt cogeneration facility in Lakewood, New Jersey.
CNG Energy Services (formerly CNG Gas Services Corporation) is Consolidated's
unregulated energy marketing subsidiary. CNG Energy Services markets a
portion of Company-owned gas production and offers the equivalent of the
"bundled" services previously provided by CNG Transmission. CNG Energy
Services offers an array of gas sales, transportation, storage and other
services that can be arranged separately or in various combinations to meet
the individual needs of customers in the post-Order 636 environment.
CNG Power Services, created in 1994, is the power marketing subsidiary of
Consolidated and has received FERC approval to purchase and resell electricity
at market-based rates. CNG Lakewood, Inc., a wholly owned subsidiary of CNG
Power Services, owns a 1% general partnership interest in the Lakewood
Partnership.
CNG Storage was formed to engage in providing natural gas storage facilities
and a wide range of storage-related services to affiliates and other
customers, including the sale or lease of base gas, and the sale, lease or
brokerage of gas storage capacity obtained from third parties.
Consolidated LNG was organized to import and regasify liquefied natural gas
(LNG) for sale to CNG Transmission. However, Consolidated LNG has ended its
involvement in LNG operations and is currently
2
<PAGE>
ITEM 1. BUSINESS (Continued)
recovering its undepreciated investment in LNG-related facilities, plus
carrying charges and taxes, through a FERC-approved amortization surcharge.
CNG Research administers the Company's proprietary research activities.
Amounts spent on research activities in the calendar years 1992 through 1994
by all the subsidiary companies were not material.
CNG Coal owns Consolidated's coal reserves and a related plant site. The
Company's recoverable raw coal reserves are approximately 615 million tons, as
estimated by John T. Boyd Company, Mining and Geological Engineers. Most of
these coal reserves are located in Greene County, Pennsylvania, principally in
the Sewickley and Pittsburgh coal seams. Consolidated's investment in CNG
Coal at December 31, 1994 amounted to $41.2 million. The Company has various
options under review with respect to these assets.
Service Company is a subsidiary service company, authorized by the Securities
and Exchange Commission (SEC) under the PUHCA. It advises and assists the
other subsidiary companies on administrative and technical matters and manages
centralized activities and facilities for their benefit. It also provides
services to the Parent Company.
CNG Financial was formed to engage in certain financing transactions, but has
not yet engaged in any such transactions.
GOVERNMENTAL REGULATION
The Company and its subsidiaries are subject to regulation by the SEC pursuant
to the PUHCA. The SEC is currently undertaking an in-depth study of the PUHCA
in the context of increased competition in the energy industry which has
occurred pursuant to deregulation over the past decade. It is not known at
this time what the result of this study will be, although it is anticipated
that there will be some effort by the SEC to reform the PUHCA regulation.
CNG Transmission and Consolidated LNG are "natural-gas companies" subject to
the Natural Gas Act of 1938, as amended. CNG Transmission's interstate
transportation and storage activities are regulated under such Act and are
conducted in accordance with tariffs and service agreements on file with the
FERC. The distribution subsidiaries of the Company are subject to regulation
by the respective utility commissions in the states within which they operate.
CNG Power Services, a public utility as defined by section 201 of the Federal
Power Act, is subject to FERC regulation.
Certain subsidiaries are subject to various provisions of the five statutes
which are referred to as the National Energy Act of 1978. One of these
statutes, the National Energy Conservation Policy Act, requires utilities to
offer home energy audits and other assistance to residential customers.
The Natural Gas Pipeline Safety Act of 1968 (which, among other things,
authorizes the establishment and enforcement of federal pipeline safety
standards) subjects the interstate pipeline of CNG Transmission to the safety
jurisdiction of the Department of Transportation. Intrastate facilities
remain within the safety jurisdiction of the state regulatory agencies,
presuming compliance by such agencies with certain prerequisites contained in
such Act.
Consolidated is subject to the provisions of various federal laws dealing with
the protection of the environment. In addition, the subsidiary companies are
subject to the environmental laws and regulations of state and local
governmental authorities in the areas within which the subsidiaries have
operations or facilities. Reference is made to "Environmental Matters" on
page 41 and to Note 15 to the consolidated financial statements for additional
information on environmental-related matters.
3
<PAGE>
ITEM 1. BUSINESS (Continued)
CAPITAL EXPENDITURES
Consolidated's current capital budget for 1995 is estimated at $444.6 million,
a 2 percent increase over the $437.8 million spent in 1994. The 1995 budget
reflects increased expenditures for the Company's nonregulated and
distribution operations and a reduction in spending on transmission
operations.
Expenditures for the exploration and production operations are estimated to be
$170.2 million in 1995, up from $166.0 million in 1994. The higher amount in
1995 includes funds for development of the Viosca Knoll 826 and Popeye deep-
water projects in the Gulf of Mexico. Distribution operations spending in
1995 is expected to be $164.8 million, compared with $146.9 million in 1994.
The increased level of spending will allow for continued growth, as well as
improvements in the gas distribution system and related facilities. Although
the multi-year expansion program of the transmission operations is complete,
the Company continues to make enhancements to its pipeline network to better
serve customers. Transmission expenditures in 1995 are budgeted at $91.0
million, down from $108.6 million spent in 1994. The 1995 capital budget also
includes $18.6 million allocated to "other operations," including expenditures
to upgrade information systems technology at CNG Energy Services.
Consolidated's capital budget will be reviewed during the year in light of
market conditions and is subject to revision. (See "Capital Spending," page
43.)
CNG Transmisson and certain of the Company's distribution subsidiaries are
subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments
of 1990 (1990 amendments) which added significantly to the existing
requirements established by the Federal Clean Air Act. As a result of the
1990 amendments, these subsidiaries are required to install Reasonably
Available Control Technology (RACT) at some compressor stations to reduce
nitrogen oxide emissions. The subsidiaries will have until May 31, 1995, to
comply with the requirement to install RACT. Compliance requires capital
expenditures to similarly retrofit some of the compressor engines along the
Company's pipeline system. In this regard, approximately $23.3 million was
expended during 1994 and up to $17 million is expected to be expended in 1995
to complete installation of emission control equipment. The Company
anticipates completing the installation of emission controls by the May 31,
1995 deadline required in the 1990 amendments. While the Company believes
that it will be in compliance with the 1990 amendments, additional compliance
requirements which may be imposed by state regulation could require additional
capital expenditures. In any event, the total actual capital expenditures
required to comply with the 1990 amendments are expected to be recoverable
through future regulatory proceedings.
RESTRICTIONS UNDER CERTAIN DEBT AGREEMENTS
At December 31, 1994, Consolidated had senior debentures outstanding under a
1971 indenture between Consolidated and Chemical Bank, as trustee (the "1971
Indenture"). The 1971 Indenture contains covenants which limit, among other
things, the incurrence of funded debt. Funded debt is indebtedness maturing
(or, at the Company's option, renewable or extendable for) more than one year
after the date of issuance. One of these covenants provides that the Company
may not issue funded debt unless (a) consolidated income available for
interest and subsidiary preferred stock dividends (computed before income and
excess or other profits taxes) of Consolidated for any twelve consecutive
months within the preceding fifteen months shall have been not less than 2-1/2
times the sum of the total annual interest charges upon the funded debt of
Consolidated and the total annual dividend requirements on subsidiary
preferred stock, in each case to be outstanding immediately thereafter and (b)
after giving effect to such issuance the sum of the principal amount of funded
debt of Consolidated outstanding and the amount of subsidiary preferred stock
outstanding shall not be more than 60 percent of the consolidated net tangible
assets of Consolidated. The Company has a shelf registration with the SEC for
the sale of up to $500 million of debt securities. Debt securities to be
issued under this shelf registration would be classified as funded debt and,
therefore, the 1971 Indenture would limit the Company's ability to issue such
securities if the provisions of the covenant summarized above were not met.
Reference is made to "Recent Developments," page 38, for a discussion of
possible 1995 events which could restrict Consolidated's ability to issue
additional funded debt.
4
<PAGE>
ITEM 1. BUSINESS (Continued)
COMPETITIVE CONDITIONS
Various regulatory and market trends have combined to increase competition for
Consolidated in recent years, and for the gas industry in general. The
factors affecting the Company include: regulatory efforts, such as the FERC's
various initiatives to increase competition in the industry; the overall
availability of gas nationwide; competition from local producers and other
sellers and brokers of gas for the retail and wholesale markets; competition
with existing and proposed pipelines, and projects to import gas from Canada
and other foreign countries; and competition with other energy forms, such as
electricity, fuel oil and coal.
RESTRUCTURING OF INTERSTATE PIPELINE INDUSTRY
During 1993, the final portion of the FERC's plan to restructure the
interstate natural gas pipeline industry was set in motion as pipeline
companies began implementing the provisions of Order 636. Similar to previous
FERC actions to enable more direct access to gas supplies and open access to
pipeline transportation systems, Order 636 has significantly increased
competition in the natural gas industry. In the restructured marketplace,
local gas utilities and large-volume end users, including former pipeline
sales customers, now bear all the responsibilities and risks for arranging the
procurement of their gas supplies and contracting with pipelines to transport
purchases. Other significant changes required by Order 636 included a basic
change in the way rates are designed. Under the new rate design, return on
equity and related income taxes are recovered as part of a fixed monthly
charge. Previously, these costs were recovered through usage or commodity
rates. CNG Transmission implemented Order 636 on October 1, 1993 (see "FERC
Order 636," page 38) and thereby abandoned its traditional "bundled" sales
service. CNG Transmission now offers a number of gas transportation and
storage service options, along with related services, to a broad range of
customers.
The restructuring of the interstate natural gas pipeline industry has also
affected the distribution subsidiaries. Industrial and large commercial gas
users now purchase a large portion of their gas supplies directly from
producers, from marketers, or on the spot market. The distribution
subsidiaries have, for the most part, however, been able to retain these
customers by providing transportation service for such supplies. The most
significant effect on local distribution companies of Order 636 has been on
their gas supply procurement and storage practices. Since bundled pipeline
sales service is no longer available, these companies now bear all the
responsibilities and risks for arranging the acquisition, delivery and storage
of their own gas supplies. However, as a result of previous FERC initiatives,
Consolidated's distribution subsidiaries have been managing a part of their
own gas supplies for the last several years. Therefore, the transition to the
more competitive environment under Order 636 did not have a significant impact
on their operations. Additionally, as a result of Order 636, storage
facilities owned and operated by the Company's distribution and transmission
operations as well as storage capacity acquired will be even more important
factors in gas supply management.
Also, as a result of the restructuring, gas producers throughout the industry,
including CNG Producing, now face a more diverse and active market with
purchasers seeking to balance the advantage of lower-cost spot market supplies
with the security of higher-priced, longer-term contracts. The continued
emergence of gas and energy marketing firms has added to the competition
facing CNG Producing. As a result, effective January 1, 1995, CNG Energy
Services, Consolidated's energy marketing subsidiary, became the primary
marketing agent for all of Consolidated's nonregulated gas production.
5
<PAGE>
ITEM 1. BUSINESS (Continued)
DISTRIBUTION
Consolidated's distribution subsidiaries generally operate in long-established
service areas and have extensive facilities already in place. Growth in the
Company's traditional service areas in Ohio, Pennsylvania and West Virginia is
limited in that natural gas is already the fuel of choice for heating and for
most significant industrial applications. These areas have experienced
minimal population growth in the past, and almost all customers have become
more energy efficient, resulting in lower gas usage per customer. In
addition, the economies of these areas, which were formerly based mainly on
heavy industry, have diversified with increased emphasis on high technology
and service oriented firms.
However, opportunities for growth in the Company's distribution operations are
expected to continue at Virginia Natural Gas. This subsidiary offers the
potential for future growth through its expanding service territory and the
prospect of conversion of space-heating customers and commercial and
industrial applications to gas. The completion in 1992 of the intrastate
pipeline in Virginia has provided Virginia Natural Gas and its customers with
new gas supply sources through access to Consolidated's transmission system
and storage facilities, and has afforded additional opportunities for growth
in both gas sales and transportation, especially in the power generation
markets.
The Clean Air Act may also provide opportunities for increased throughput in
the Company's distribution markets. Consolidated is promoting the use of
natural gas as a means for industrial customers and electric generators to
reduce emissions. The Clean Air Act and the more recent Energy Policy Act of
1992 contain a number of provisions relating to the use of alternative fuel
vehicles. Consolidated is participating in various programs to demonstrate
the advantages and environmental benefits of natural gas powered vehicles.
The Company's distribution markets continue to be competitive. As the gas
industry has restructured and government regulations have changed, a
marketplace has evolved with new and traditional competitors -- the usual oil
and electric companies, other gas companies, local producers seeking to gain
direct access to the Company's customers, and gas brokers and dealers seeking
to supplant supplies with spot market gas. Natural gas faces price
competition with other energy forms, and certain of the distribution
companies' industrial customers have the ability to switch to fuel oil or coal
if desired. Local distribution companies operate in what are essentially dual
markets -- a traditional utility market, where a utility has an obligation to
provide service and offers a "bundled" package of services to all customers;
and a "contract" market, where obligations are defined by contract terms and
large customers can elect individually or in various combinations whatever gas
supplies, storage and/or transportation services they require. Consolidated
has responded to this competitive environment by offering an expanded range of
services to its customers. The Company's distribution subsidiaries now
routinely provide a variety of firm and interruptible services, including gas
transportation, storage, supply pooling and balancing, and brokering, to
industrial and commercial customers.
TRANSMISSION
CNG Transmission operates a regional interstate pipeline system with the
principal pipeline and storage facilities located in Ohio, Pennsylvania, West
Virginia and New York. Beginning with open access transportation and
culminating with the significant service restructuring required by Order 636,
the role of the Company's transmission operations has changed from primarily
that of a merchant, or wholesaler, of gas to one that provides a wide range of
services. Although CNG Transmission no longer provides its traditional
bundled sales service, it continues to offer gas transportation, storage and
related services to its affiliates, as well as to utilities and end users in
the Northeast, Mid-Atlantic and Midwest regions of the country.
6
<PAGE>
ITEM 1. BUSINESS (Continued)
The changing regulatory policies have provided CNG Transmission and other
pipeline companies with unique opportunities for expansion. CNG Transmission
has directed its expansion efforts toward potential high-volume, weather-
sensitive markets and areas with growing power generation needs. This
expansion has occurred in many directions, with particular emphasis on
Northeast and East Coast markets. CNG Transmission's large underground
storage capacity and the location of its pipeline system as a link between the
country's major gas pipelines and large markets on the East Coast have been
key factors in the success of these expansion efforts.
CNG Transmission competes with domestic as well as Canadian pipeline companies
and gas marketers seeking to provide or arrange transportation, storage and
other services for customers. Also, certain end users have the ability to
switch to fuel oil or coal if desired. Although competition is based
primarily on price, the range of services that can be provided to customers is
also an important factor. The combination of capacity rights held on certain
longline pipelines, a large storage capability and the availability of
numerous receipt and delivery points along its own pipeline system, enables
CNG Transmission to tailor its services to meet the individual needs of
customers.
With CNG Transmission's implementation of Order 636, former wholesale sales
customers now have the responsibility and risk inherent in contracting for
their own gas supplies. However, since customers have greater access to the
Company's pipeline and storage capacity, both increased gas transportation and
storage service have offset the impact of CNG Transmission's abandonment of
its traditional sales service. Consolidated continues to provide the
equivalent of bundled services through its unregulated marketing subsidiary,
CNG Energy Services. This company offers a range of gas sales,
transportation, storage and other service options that can be arranged
separately or in various combinations to meet the individual needs of
customers.
EXPLORATION AND PRODUCTION
Consolidated's exploration and production operations are conducted by CNG
Producing in several of the major gas and oil producing basins in the United
States, both onshore and offshore. In this highly competitive business,
Consolidated competes with a large number of companies ranging in size from
large international oil companies with extensive financial resources to small,
cash flow-driven independent producers.
CNG Producing faces significant competition in the bidding for federal
offshore leases and in obtaining leases and drilling rights for onshore
properties. Since CNG Producing is the operator of a number of properties, it
also faces competition in securing drilling equipment and supplies for
exploration and development. From the production perspective, the marketing
of gas and oil is also highly competitive with price being the most
significant factor. When the economics warrant, Consolidated attempts to sell
its gas production under long-term contracts to customers such as electric
power generators and others that require a secure source of supply. These
arrangements generally command a premium over spot market prices. Further,
the implementation by pipeline companies of Order 636 could impact the
deliverability of gas produced due to increased competition for limited
downstream pipeline transportation capacity. In response to the unbundling of
sales services previously offered by pipelines, CNG Producing and CNG Energy
Services have taken actions to expand and diversify the Company's customer
base. CNG Energy Services continues to develop new marketing strategies and
contracts to address customer needs for intermediate and long-term gas
supplies as well as other services in the post-Order 636 era. Effective
January 1, 1995, CNG Energy Services became the primary marketing agent for
all of Consolidated's nonregulated gas production.
The exploration for and production of gas and oil is subject to various
federal and state laws and regulations which may, among other things, limit
well drilling activity and volumes produced. Changes in these laws and
regulations can impact Consolidated's exploration and production operations.
7
<PAGE>
ITEM 1. BUSINESS (Continued)
RECENT DEVELOPMENTS
Based on current competitive conditions, the Company is considering a variety
of measures to permanently reduce costs, the implementation of which may have
a material adverse impact on 1995 earnings. In this regard, on March 20,
1995, the Board of Directors approved a work force reduction program. The
program includes a voluntary early retirement program, with eligibility based
upon the employee's age and years of service as of December 31, 1995, and an
involuntary separation program. The early retirement incentives include
additional years of age and pension service for calculating pension benefits.
The Company will offer the early retirement program between April 1, 1995 and
May 31, 1995, with eligible employees retiring on various dates before
December 31, 1995. The involuntary separation program will involve the
payment of severance benefits to affected employees. At certain subsidiaries,
provisions of the program are still subject to union approval. The recovery
of the costs attributable to the work force reduction program at the rate-
regulated subsidiaries may be sought, if appropriate, in future rate-making
proceedings. (See "Recent Developments," page 38.)
GAS SUPPLY
GENERAL INFORMATION
Consolidated's gas supply is obtained from various sources including:
purchases from major and independent producers in the Southwest and Midwest
regions; purchases from local producers in the Appalachian area; purchases
from gas marketers; purchases on the spot market; production from Company-
owned wells in the Appalachian area, the Southwest, and the Midwest; and
withdrawals from the Company's underground storage fields.
Regulatory actions, economic factors, and changes in customers and their
preferences over the past several years have reshaped the Company's gas sales
markets. A significant number of industrial customers and some commercial
customers now purchase a large portion of their gas supplies from producers,
marketers, or on the spot market, and contract with the Company's transmission
and distribution subsidiaries for transportation and other services. Since
these customers are less reliant on the distribution subsidiaries for sales
service, the volume of gas that these subsidiaries must obtain to meet sales
requirements has been reduced. In addition, the implementation of Order 636
by CNG Transmission removed that subsidiary from its merchant role thereby
eliminating its need to purchase gas for resale. The former merchant service
contracted for by wholesale customers was converted to transportation and
storage services in 1993. Since CNG Transmission no longer provides
traditional sales service, its former sales customers, including the Company's
distribution subsidiaries, now have the responsibility and risk for obtaining
their own gas supplies.
Consolidated's available gas supply in 1994 was again in a surplus position --
where available supplies exceed sales requirements. Considering the Company's
large storage capacity, the volumes obtainable under its gas purchase and gas
supply contracts, Company-owned gas reserves, and assuming the future
availability of spot market gas, the Company believes that supplies will be
available to meet requirements for several years. Gas supply statistics for
the past five years are on page 13.
GAS PURCHASED
Purchased gas volumes were 559.6 billion cubic feet (Bcf) in 1994,
representing 84 percent of the Company's total 1994 gas supply of 666.1 Bcf.
Spot market and short-term purchases were 493.5 Bcf, or about 74 percent of
the total 1994 supply. Volumes purchased under contracts with Appalachian
area producers totaled 66.1 Bcf, or 10 percent of the 1994 supply.
8
<PAGE>
ITEM 1. BUSINESS (Continued)
In response to the regulatory and market changes over the past several years,
including Order 636, the Company has converted its long-term gas purchase
contracts with interstate pipelines to firm transport contracts. As a result
of these contract conversions, gas volumes purchased from the pipeline
companies have been eliminated and replaced, in large part, with contracts
directly with producers and marketers.
While spot market gas supplies have historically been obtained at lower
prices, the availability of spot market gas supplies to distribution companies
can be severely impacted by sudden swings in supply and demand. The
distribution subsidiaries now must weigh the benefits of generally lower-cost
spot market purchases with the security of longer-term contract arrangements.
To ensure a secure supply in the post-Order 636 market, the Company's
distribution subsidiaries have purchased a larger portion of their gas
supplies directly from producers on a firm basis. Spot market gas will
continue to be part of the Company's supply mix, particularly for CNG Energy
Services.
Gas purchased from producers and on the spot market is delivered to the
distribution subsidiaries using the firm transport capacity they have
contracted for on interstate pipelines. At December 31, 1994, the
subsidiaries had 419 Bcf of firm transport capacity on upstream pipelines,
yielding deliveries of up to 1,156 million cubic feet a day. These upstream
pipelines include Tennessee Gas Pipeline Company, Panhandle Eastern Pipe Line
Company, Texas Eastern Transmission Corporation (Texas Eastern), ANR Pipeline
Company, Texas Gas Transmission Corporation, Transcontinental Gas Pipe Line
Corporation and Columbia Gas Transmission Corporation.
GAS STORAGE
Consolidated's vast underground storage complex plays an important part in
balancing gas supply with sales demand and is essential to servicing the
Company's large volume of space-heating business. The Company operates 26
underground gas storage fields located in Ohio, Pennsylvania, West Virginia
and New York. The Company owns 21 of these storage fields and has joint-
ownership with other companies in 5 of the fields. The total designed
capacity of the storage fields is approximately 885 Bcf. The Company's share
of the total capacity is about 669 Bcf. About one-half of the total capacity
is base gas which remains in the reservoirs at all times to provide the
primary pressure which enables the balance of the gas to be withdrawn as
needed.
CNG Transmission operates 719 Bcf of the total designed storage capacity and
owns 503 Bcf of the Company's capacity. CNG Transmission utilizes a large
portion of its turnable capacity to provide approximately 252 Bcf of gas
storage service for others. This service is provided to pipelines and
utilities whose primary service areas are along the East Coast. CNG
Transmission also provides storage service to affiliates, end users and to
many of its former wholesale gas sales customers.
Two of the Company's distribution subsidiaries, East Ohio Gas and Peoples
Natural Gas, own and operate the remaining 166 Bcf of storage capacity. In
addition to owning their own storage, these companies, as well as most of the
Company's other subsidiaries, have ready access to a part of the storage
capacity operated by CNG Transmission. Certain distribution subsidiaries also
have capacity available in storage fields owned by others. In the post-Order
636 environment, available storage capacity is an important element in the
effective management of both gas supply and pipeline transport capacity.
Consolidated controls other acreage in the Appalachian area suitable for the
development of additional storage facilities which would enable further
expansion of capacity to meet possible future storage needs.
9
<PAGE>
ITEM 1. BUSINESS (Continued)
GAS AND OIL PRODUCING ACTIVITIES
Over the past several years, Consolidated's exploration and production
operations have been affected by the generally adverse conditions in the
industry. The effects of continued warm weather, the lingering gas oversupply
situation, and low gas and oil wellhead prices have all contributed to a
difficult operating environment. However, Consolidated's level of capital
spending on its exploration and production operations has increased during the
past two years, and is expected to increase again in 1995, reflecting its
commitment to these operations. Consolidated will continue to invest in two
deep-water projects in the Gulf of Mexico -- Popeye and Viosca Knoll 826 -- in
addition to onshore and other offshore projects.
Consolidated's gas wellhead prices in 1994 averaged $2.16 a thousand cubic
feet (Mcf), down from $2.24 in 1993. Gas wellhead prices were strong in the
first quarter of 1994 but declined and remained considerably below 1993 levels
for most of the balance of the year. Consolidated's average gas wellhead
prices are generally higher and less volatile than industry spot prices since
its average price reflects a mix of longer-term contracts. However, due to
market-sensitive contracts, Consolidated's gas prices generally follow
industry trends. Consolidated's average oil wellhead price in 1994 declined
to $14.45 a barrel, compared with $15.66 in 1993, consistent with the
continued overall decline in world oil prices.
The Company's total gas production in 1994 was 119.5 Bcf, down from 129.5 Bcf
in 1993. Oil production was 3.4 million barrels, down 15 percent from 3.9
million barrels in 1993. The low gas prices that prevailed nationwide during
most of 1994 were the basis for Consolidated's decision to shut in a portion
of its offshore production in the latter part of the year, resulting in lower
gas production for the year. The lower oil production during 1994 was due
largely to normal production declines at older properties, in addition to the
partial shut-in of production.
During 1994, Consolidated participated in the drilling of 81 gross wells (35
net), compared with 65 gross wells (22 net) drilled in 1993. The following
table sets forth 1994 drilling activity by region:
______________________________________________________________________________
Gross Wells Drilled
Exploratory Development
______________________________________________________________________________
Onshore (Southwest and West). . . . . . . 16 30
Gulf of Mexico . . . . . . . . . . . 12 10
Appalachian Region . . . . . . . . . . - 6
Canada . . . . . . . . . . . . . . - 7
__ __
Total. . . . . . . . . . . . . . 28 53
== ==
______________________________________________________________________________
Of the total 81 wells in which the Company participated during 1994, 56 were
successful, a 69 percent success rate. Of the 28 exploratory wells drilled, 5
were successful.
During 1994, Consolidated drilled two wells at a deep-water project in the
Gulf of Mexico known as Viosca Knoll 826. This project, in which the Company
holds a 50 percent interest, represents the largest single addition to
Consolidated's reserves in its history, adding reserves equivalent to 190 Bcf
of gas. Facilities are being designed with Oryx Energy Company, the operating
partner, to produce up to 25,000 barrels of oil and 30 million cubic feet of
natural gas a day. Production is expected to begin in early 1997. Viosca
Knoll 826 will make use of an innovative floating production facility called a
Spar, a 700-foot-long cylindrical structure that will be towed to the site,
turned on end and anchored to the sea floor with cables. This is the first
time a spar will be used in the Gulf of Mexico as a production platform.
10
<PAGE>
ITEM 1. BUSINESS (Continued)
Development will continue during 1995 at Popeye, a deep-water natural gas
discovery in the Green Canyon area of the Gulf of Mexico. Consolidated
entered into an agreement in 1992 with Shell Offshore, Inc., under which the
Company acquired half of Shell's 75 percent interest in this property. In
return, Consolidated will pay some $60 million for development of the field.
Other participants in the joint venture are Mobil Oil Exploration and
Producing Southeast and BP Exploration Inc. Participation in the Popeye and
Viosca Knoll 826 projects is providing Consolidated access to new technologies
and the experience necessary to better evaluate future deep-water
opportunities.
Despite difficult industry conditions, Consolidated remains committed to its
exploration and production operations. The Company plans to increase its
exploration and production spending by 3 percent in 1995 to $170.2 million,
including funds for the development of Popeye and Viosca Knoll 826.
Although Consolidated drilled 6 wells (3 net) in the Appalachian Basin during
1994, there is no drilling planned for this area in 1995. In the past, gas
from this area commanded a higher price because of its location in proximity
to major gas markets. However, as a result of industry changes and revised
rate structures, pipeline companies can transport gas to these markets at low
commodity rates that negate somewhat the location premium associated with
these reserves. The Company expects to continue production from these
properties and plans to maintain its strong acreage position in the
Appalachian Basin. Drilling activity can be resumed with very short lead
times if market and economic conditions warrant. Selected Appalachian
properties were sold during 1994, but the acreage and reserves were not
material.
Total Company-owned proved gas reserves at year-end were 972 Bcf, up from 960
Bcf at the end of 1993. Proved oil reserves were 46.5 million barrels,
compared with 27.9 million barrels in 1993. New reserves added in 1994,
including volumes attributable to Viosca Knoll 826, exceeded the volumes of
gas and oil produced by Consolidated during the year. (See "Company-Owned
Reserves," page 22.)
Consolidated was the successful bidder on 12 leases offered in the federal
government's Gulf of Mexico lease sales in 1994, acquiring 10 blocks off
Louisiana and 2 blocks off Texas. At year-end 1994, Consolidated held 2.4
million net acres of exploration and production properties, down from 2.6
million at year-end 1993. The Company's lease holdings include about 1.6
million net acres in the Appalachian area, 354,700 in the offshore Gulf of
Mexico, and 447,700 in the inland areas of the Southwest, Gulf Coast and West.
The Company will continue to review its property inventory during 1995, and
sales of selected properties are possible depending on economic conditions.
Included in the properties which may be sold is Consolidated's 21 percent
interest in heavy oil properties in Alberta, Canada. Proved reserves
associated with the Canadian properties approximated 1 Bcf of gas and 5.3
million barrels of oil at December 31, 1994. On an energy-equivalent basis,
these reserves represent about 3 percent of Consolidated's total proved
reserves at that date.
GAS SALES AND TRANSPORTATION
Total gas sales in 1994 were 618 Bcf, up 2 percent from the 604 Bcf sold in
1993. Transportation volumes were 725 Bcf in 1994, a 23 percent increase from
the 587 Bcf transported in 1993. (Five-year statistics are on page 13.)
11
<PAGE>
ITEM 1. BUSINESS (Continued)
GAS SALES CUSTOMERS
At December 31, 1994, the Company's distribution subsidiaries served almost
1.7 million residential customers, about 125,000 commercial customers and
about 1,700 industrial customers in Ohio, Pennsylvania, Virginia and West
Virginia.
______________________________________________________________________________
Residential
Customers Total and Commercial Industrial Wholesale Nonregulated
______________________________________________________________________________
December 31,
1994 1,799,649 1,797,433 1,697 14 505
1993 1,777,157 1,774,922 1,688 31 516
1992 1,759,284 1,757,139 1,694 32 419
1991 1,737,947 1,735,803 1,698 31 415
1990 1,717,880 1,715,824 1,651 32 373
______________________________________________________________________________
RESIDENTIAL AND COMMERCIAL SALES
Sales of gas to residential customers in 1994 were 206 Bcf, down 6 Bcf from
1993, while sales to commercial customers were 69 Bcf, down 4 Bcf compared
with 1993. Residential and commercial gas sales volumes decreased as slightly
warmer weather in 1994 resulted in lower gas usage by space-heating customers.
The weather in the Company's retail service areas in 1994 was 3 percent warmer
than in 1993 and 4 percent warmer than normal. The volume decline due to the
weather was partially offset by the net addition of about 22,500 residential
and commercial customers, including about 8,200 at Virginia Natural Gas.
INDUSTRIAL SALES
Industrial sales in 1994 were 9 Bcf, down 3 Bcf compared with 1993. Due to
both availability and price, many industrial users now buy gas directly from
producers, from marketers, or on the spot market, and contract with the
subsidiary companies for transportation service. Total gas deliveries (sales
and transportation) to industrial customers were 130 Bcf in 1994, compared
with 128 Bcf in 1993.
WHOLESALE SALES
Total wholesale sales were .3 Bcf in 1994, down from 81 Bcf in 1993. The
sharp decline in sales volumes reflects CNG Transmission's abandonment of its
traditional sales service with the implementation in late 1993 of FERC Order
636. In addition, the 1993 wholesale sales include sales by CNG Transmission
of approximately 58 Bcf of gas from storage inventory in anticipation of the
transition to restructured services.
NONREGULATED SALES
Nonregulated gas sales in 1994 were 333 Bcf, up from 226 Bcf in 1993. Sales
of Company-produced gas to nonaffiliates were 89 Bcf, compared with 88 Bcf in
1993. Gas sales by CNG Energy Services were 190 Bcf in 1994, compared with
100 Bcf in 1993. Volumes related to gas brokering activity were 54 Bcf in
1994, up from 38 Bcf in 1993.
GAS TRANSPORTATION
Total transportation volumes in 1994 amounted to 725 Bcf, up from 587 Bcf in
1993. The increase in transportation volumes compared to 1993 occurred mainly
in the first quarter of 1994 consistent with the cold weather experienced
early in the year. Total volumes transported by the distribution subsidiaries
for commercial, industrial and off-system customers were up 6 Bcf over 1993.
12
<PAGE>
ITEM 1. BUSINESS (Continued)
GAS SALES, SUPPLY AND TRANSPORTATION STATISTICS
(Excludes affiliated transactions)
<TABLE>
<CAPTION>
________________________________________________________________________________
__________________________________
Years Ended December 31, 1994 1993
1992 1991 1990
________________________________________________________________________________
__________________________________
<S> <C> <C>
<C> <C> <C>
GAS SALES REVENUES (Millions)
Regulated
Residential and commercial. . . . . . . $1,628.3 $1,595.1
$1,428.7 $1,373.1 $1,361.0
Industrial . . . . . . . . . . . . 45.8 55.4
50.0 46.0 64.2
Wholesale . . . . . . . . . . . . 5.2 422.7
190.8 426.8 528.9
Nonregulated . . . . . . . . . . . . 723.6 541.8
282.0 237.0 280.2
________ ________
________ ________ ________
Total . . . . . . . . . . . . $2,402.9 $2,615.0
$1,951.5 $2,082.9 $2,234.3
======== ========
======== ======== ========
AVERAGE SALES RATES PER MCF
Regulated
Residential and commercial. . . . . . . $ 5.91 $ 5.60
$ 5.09 $ 5.25 $ 5.39
Industrial . . . . . . . . . . . . 4.89 4.43
4.00 4.09 4.22
Wholesale . . . . . . . . . . . . * 5.24
* 4.49 4.77
Nonregulated . . . . . . . . . . . . 2.17 2.40
2.10 2.01 2.27
Weighted average. . . . . . . . . $ 3.89 $ 4.33
$ 4.35 $ 4.29 $ 4.45
======== ========
======== ======== ========
GAS REQUIREMENTS (BCF)
Regulated gas sales
Residential and commercial. . . . . . . 275.3 285.0
280.7 261.7 252.5
Industrial . . . . . . . . . . . . 9.4 12.5
12.5 11.2 15.2
Wholesale . . . . . . . . . . . . .3 80.7
21.2 95.0 110.9
Nonregulated gas sales. . . . . . . . . 332.8 226.0
134.4 118.1 123.4
________ ________
________ ________ ________
Total sales . . . . . . . . . . 617.8 604.2
448.8 486.0 502.0
Used and unaccounted for . . . . . . . . 48.3 44.0
51.7 34.5 44.7
________ ________
________ ________ ________
Total requirements . . . . . . . . 666.1 648.2
500.5 520.5 546.7
======== ========
======== ======== ========
GAS SUPPLY (BCF)
Purchased gas. . . . . . . . . . . . 559.6 485.2
370.6 377.2 434.4
Storage (input) withdrawal . . . . . . . (13.0) 33.5
1.9 10.5 (34.8)
Gas produced
Gulf region. . . . . . . . . . . . 76.4 81.6
78.9 84.2 89.4
Appalachian area . . . . . . . . . . 27.8 29.4
33.1 35.3 43.5
Other areas. . . . . . . . . . . . 15.3 18.5
16.0 13.3 14.2
________ ________
________ ________ ________
Total produced . . . . . . . . . 119.5 129.5
128.0 132.8 147.1
________ ________
________ ________ ________
Total supply . . . . . . . . . . 666.1 648.2
500.5 520.5 546.7
======== ========
======== ======== ========
PURCHASED GAS COSTS (MILLIONS)** . . . . . $1,375.8 $1,349.5
$1,132.1 $1,093.6 $1,440.7
======== ========
======== ======== ========
AVERAGE PURCHASE RATES PER MCF** . . . . . $ 2.46 $ 2.78
$ 3.05 $ 2.90 $ 3.32
======== ========
======== ======== ========
GAS TRANSPORTATION
Revenues (Millions). . . . . . . . . . $ 293.7 $ 222.5
$ 201.0 $ 154.9 $ 147.5
======== ========
======== ======== ========
Gas Transported (Bcf) . . . . . . . . . 724.9 587.5
613.1 446.7 377.8
======== ========
======== ======== ========
________________________________________________________________________________
__________________________________
<FN>
* Demand charges and low sales volumes produce an average rate which is not
meaningful.
** Includes transportation charges.
</TABLE>
13
<PAGE>
ITEM 1. BUSINESS (Continued)
MARKET EXPANSION
In recent years Consolidated has pursued a broad program designed to expand
its interstate pipeline system and extend its marketing territory.
Consolidated's principal objective has been to build long-term supply
relationships with customers in the growing markets at the perimeter of its
system, markets which offer opportunities for growth in throughput due to
their increasing demand for energy. Consolidated has concentrated its
transmission expansion efforts toward potentially high-volume, weather
sensitive markets and areas with growing power generation needs located
primarily in the Northeast and along the East Coast. These markets are
particularly attractive in that gas space heating is not yet as widely used in
these areas as in the Company's traditional service areas of western
Pennsylvania, eastern Ohio, West Virginia and upstate New York. Because of
its large gas storage capacity and the location of its gridlike pipeline
system in close proximity to these markets, Consolidated has an opportunity to
be an important gas supplier to utilities with growing space heating markets
and for customers seeking an environmentally clean, efficient fuel for
electric generation.
MARKETING HUBS
With the transmission construction program complete, the Company is now
pursuing new growth opportunities available for its expanded pipeline system.
In July 1994, the CNG/Sabine Center "superhub" began operations. This market
center, developed by CNG Transmission and Texaco's Sabine Pipe Line Company,
offers intra-hub transfers, short-term parking, wheeling and an accounting
service for gas supplies. The hub makes use of the gas transmission and
storage system of CNG Transmisson, enabling customers, such as utilities,
interstate pipelines, large end users and marketers, to deliver or receive gas
at various points in six Midwestern and Northeastern states, including
interconnections with every major pipeline in those areas. In October 1994,
the SEC granted formal approval for Consolidated's participation in the
center. A partnership comprised of Sabine Hub Services Inc., a subsidiary of
Sabine Pipe Line Company, and CNG Market Center Services, Inc., a subsidiary
of CNG Power, operate the hub.
In addition, during September 1994, East Ohio Gas and Williams Energy
Ventures, Inc. (Williams) established a gas trading hub at Lebanon, Ohio.
East Ohio Gas operates and manages the hub, which is a point on "Streamline,"
a computerized network for cash-market natural gas trades developed by
Williams. The hub is expected to be developed in two phases. The Lebanon
Streamline point is separate from, but complementary to, the CNG/Sabine
Center.
PIPELINE EXPANSION
CNG Transmission and Texas Eastern are bidding to serve the growing markets in
the Mid-Atlantic and Southeast markets. In November 1994, they announced
plans for a joint project called "WinterNet" to provide up to 400 million
cubic feet per day of natural gas service to meet the winter seasonal and peak
needs of these markets. WinterNet facilities would include additional
pipeline capacity along CNG Transmission's and Texas Eastern's pipeline
systems, storage on CNG Transmission's system, liquefied natural gas storage
capacity and new pipeline capacity into North Carolina. If the proposal
receives required approvals, the project would be phased in over a three-year
period beginning in 1997, with construction expected to cost between $350
million and $400 million.
14
<PAGE>
ITEM 1. BUSINESS (Continued)
MARKETING ALLIANCE
In November 1994 CNG Energy Services formed a marketing alliance with two
Canadian firms: Hydro-Quebec, the largest electric power producer in North
America, and Noverco, the majority shareholder of Gaz Metropolitain, one of
Canada's largest natural gas distributors. This alliance will offer energy
services to customers throughout the northeastern and midwestern United States
and eastern Canada by allowing them to draw on the combined capabilities of
three companies with some $44 billion (in U.S. dollars) of assets in
production, storage, transmission and distribution of both gas and
electricity.
ADDITIONAL USES FOR NATURAL GAS
During 1994, Consolidated 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 promising as business entities strive to comply with provisions of the
Federal Clean Air Act, legislation which applies strict anti-pollution
standards to factories, fleet and mass transit vehicles, and electric power
plants. The law is likely to increase demand for natural gas, but the extent
thereof will depend on how the Act is implemented and enforced. Gas demand
could also increase as the result of the Energy Policy Act of 1992. This Act
requires and encourages large vehicle fleets to operate on alternative fuels
such as natural gas. The Energy Policy Act also created a new class of
independent power producers exempt from utility regulation, which could lead
to the construction of additional gas-fueled generating facilities.
Consolidated is also pursuing other technological opportunities, including gas
cooling equipment, fuel cell power generation, coal drying processes and the
promotion of natural gas powered vehicles (NGVs). Fleet operators and mass
transit authorities are using NGVs for both fuel cost efficiencies and to
reduce environmental pollution. Despite the environmental benefits of NGVs,
it appears unlikely that such vehicles will replace a significant number of
gasoline powered vehicles in the near future, given the lack of a nationwide
network of refueling facilities and the current cost of retrofitting vehicles.
However, beginning in 1997, the Clean Air Act could require 22 of the
country's most polluted regions to convert a portion of their fleet vehicles
to natural gas. Consolidated supplies natural gas to utilities that serve
Baltimore, Washington, D.C., and New York, three metropolitan areas directly
affected by this provision of the Act.
15
<PAGE>
ITEM 1. BUSINESS (Continued)
RATE MATTERS (See Note 2 to the consolidated financial statements, page 55.)
The Company's total average unit selling price for gas in 1994 was $3.89 per
Mcf, down 10 percent from $4.33 in 1993. In 1992, the average unit selling
price was $4.35 per Mcf. The decline in 1994 was due primarily to a lower
average rate for nonregulated gas sales. Average sales prices in 1993 were
higher for all retail categories and for sales of the Company's gas production
compared with 1992. However, the sales from storage inventory at lower rates
under alternative FERC-approved tariff schedules reduced the overall selling
price for 1993 to slightly below the 1992 rate.
The Company's utility subsidiaries continue to seek general rate increases on
a timely basis to recover increased operating costs and to ensure that rates
of return are compatible with the cost of raising capital. In addition to
general rate increases, subsidiary companies make separate filings with their
respective regulatory commissions to reflect changes in the costs of purchased
gas.
The following is a summary of rate activity during 1994 and to date.
CNG TRANSMISSION
CNG Transmission received FERC approval to implement Order 636 effective
October 1, 1993, in accordance with the terms of a comprehensive stipulation
and agreement reached with customers and others. On July 29, 1994, the FERC
approved recovery, through a direct bill mechanism, of $9.8 million of
transition costs. These billings began August 1, 1994, subject to refund, and
are in addition to the $177.9 million of transition costs CNG Transmission
direct billed and began collecting in December 1993.
On December 30, 1993, CNG Transmission filed a general rate filing with the
FERC requesting an annual revenue increase of $106.6 million. The rate
increase request, as revised, is intended to cover higher operating costs,
increased plant investment, and the recovery of transition costs related to
stranded facilities resulting from Order 636. CNG Transmission initially
filed for recovery of $9.2 million of stranded facilities costs in this case,
but subsequently reduced that amount to $4.7 million to reflect actual amounts
incurred. The increase went into effect on July 1, 1994, subject to refund.
CNG Transmission is currently in settlement discussions with the FERC Staff
and intervenors concerning this case.
In a December 30, 1994 filing, CNG Transmission requested recovery of an
additional $.7 million of stranded upstream transportation service costs. The
FERC approved recovery of these costs, subject to refund, on January 27, 1995.
HOPE GAS
On October 29, 1993, the Public Service Commission of West Virginia (PSC)
granted Hope Gas an indicated $1.9 million annual revenue increase effective
November 1, 1993. On March 30, 1994, the PSC issued an order on
reconsideration, resulting in an additional increase in annual revenues of $.3
million. The latter increase was effective March 30, 1994. The order
reflects a return on equity of 10.55 percent. In its filing, Hope Gas had
requested an $8.2 million annual revenue increase and a return on equity of
12.30 percent.
On January 4, 1995, Hope Gas filed with the PSC for an $11.8 million annual
revenue increase. The rate increase request is intended to reflect higher
costs associated with the addition, repair and replacement of pipelines
serving customers. If approved, the new rates would become effective November
1, 1995.
16
<PAGE>
ITEM 1. BUSINESS (Continued)
EAST OHIO GAS
On July 14, 1994, The Public Utilities Commission of Ohio (PUCO) approved a
stipulation and recommendation allowing East Ohio Gas to recover transition
costs passed on to it by upstream pipeline companies. Accordingly, East Ohio
Gas will recover the unrecovered gas cost portion of transition costs from its
tariff customers through the gas cost recovery (GCR) mechanism. Gas supply
realignment costs billed by the pipelines will be recovered by East Ohio Gas
from its sales customers, through the GCR mechanism, and from its
transportation customers, through a surcharge.
On November 3, 1994, the PUCO approved a proposed settlement of East Ohio Gas'
general rate case which will increase annual revenues by $68.6 million. Under
the settlement, new rates take effect in two phases: a $62.4 million revenue
increase began November 8, 1994, and an additional $6.2 million increase will
become effective November 8, 1995. The settlement reflects an imputed return
on equity of 12.15 percent. In its filing, East Ohio Gas had requested a
$99.1 million annual revenue increase and a return on equity of 12.64 percent.
PEOPLES NATURAL GAS
On July 21, 1994, the Pennsylvania Public Utility Commission (PA PUC) approved
a general rate increase of $7.5 million in annual revenues for Peoples Natural
Gas. The new rates became effective July 22, 1994. In its October 1993
filing, Peoples Natural Gas had requested an annual revenue increase of $28.4
million.
On July 22, 1994, Peoples Natural Gas began to recover, through a volumetric
surcharge, the non-gas cost related portion of Order 636 transition costs
billed by upstream pipeline companies. The surcharge is being adjusted on a
quarterly basis to reflect the level of transition costs billed by the
pipelines and transition cost recovery decisions made by the FERC. Peoples
Natural Gas will continue to recover gas cost related transition costs through
its periodic GCR filings.
On December 2, 1994, the PA PUC approved a nongeneral rate case filed by
Peoples Natural Gas in June 1994. Approval of the filing enables Peoples
Natural Gas to recover postretirement benefits other than pensions on a
prospective basis, effective the date of approval.
On February 1, 1995, Peoples Natural Gas filed a general rate case with the PA
PUC seeking $32.8 million in additional annual revenues. The rate increase
request is intended to cover higher operating expenses and plant investment.
If approved, the new rates would become effective no later than November 2,
1995.
VIRGINIA NATURAL GAS
On September 1, 1994, Virginia Natural Gas filed a general rate filing with
the Virginia State Corporation Commission requesting an annual revenue
increase of $9.9 million. The requested rate increase reflects additional
plant investment and higher operating and maintenance expenses. The new rates
went into effect, subject to refund, on October 1, 1994.
17
<PAGE>
ITEM 1. BUSINESS (Concluded)
EXECUTIVE OFFICERS OF THE COMPANY (Note 1)
______________________________________________________________________________
Name, Age and Business Experience
Position (Note 2) During Past Five Years
______________________________________________________________________________
George A. Davidson, Jr. (56) Mr. Davidson was elected to his present
Chairman of the Board and position on May 19, 1987, and has been a
Chief Executive Officer, Director since October 1985.
and Director
Lester D. Johnson (63) Mr. Johnson was elected to his present
Vice Chairman and position on January 1, 1995, and has
Chief Financial Officer, been a Director since May 1992. He
and Director served as Executive Vice President and
Chief Financial Officer from March 1992
to January 1995. From January 1986 to
March 1992, he served as Senior Vice
President and Chief Financial Officer.
Stephen E. Williams (46) Mr. Williams was elected to his present
Senior Vice President and position on January 1, 1993. He served
General Counsel as Associate General Counsel from
September 1992 to January 1993. From
April 1987 to September 1992, he served
as General Counsel and Secretary of CNG
Transmission.
David M. Westfall (47) Mr. Westfall was elected to his present
Senior Vice President, Financial position on January 1, 1995. He served
as Senior Vice President at CNG
Transmission from January 1988 to
January 1995.
David J. Dzuricky (43) Mr. Dzuricky was elected to his present
Vice President and Treasurer position on August 1, 1993. He served
as Vice President and Treasurer of
Virginia Natural Gas from July 1992 to
August 1993, and as its Vice President,
Treasurer and Controller from January
1991 to July 1992, and Vice President,
Treasurer, Secretary and Controller from
June 1990 to January 1991. From January
1988 to June 1990, he served as
Treasurer of CNG Transmission.
Stephen R. McGreevy (44) Mr. McGreevy was elected to his present
Vice President, Accounting position on March 1, 1993. He served as
and Financial Control Controller from January 1986 to March
1993.
Laura J. McKeown (36) Ms. McKeown was elected to her present
Secretary position on May 16, 1989.
Thomas F. Garbe (42) Mr. Garbe was elected to his present
Controller position on March 1, 1993. He served as
Senior Assistant Controller from May
1991 to March 1993 and as Assistant
Controller from January 1986 to May
1991.
______________________________________________________________________________
Notes:
(1) The Company has been advised that there are no family relationships
between any of the officers listed, and there is no arrangement or
understanding between any of them and any other person pursuant to which
the individual was elected as an officer.
(2) The By-Laws of the Company provide that each officer shall hold office
until a successor is chosen and qualified.
18
<PAGE>
ITEM 2. PROPERTIES
GENERAL INFORMATION ON FACILITIES (Maps are on pages 20 and 21.)
The total gross investment of the Company and its subsidiaries in property,
plant and equipment was $7.7 billion at December 31, 1994. The largest
portion of this investment (61%) is in facilities located in the Appalachian
area. Another significant portion (23%) is located in the Gulf of Mexico.
Of the $7.7 billion investment, $3.5 billion is in production and gathering
systems, of which 58 percent is invested in the Gulf of Mexico and the Gulf
coast and 27 percent in the Appalachian area. The Company's production
subsidiary, CNG Producing, accounts for $2.9 billion of the $3.5 billion
investment, and CNG Transmission and the distribution subsidiaries account for
the remaining $600 million. In addition to the wells and acreage listed
elsewhere in ITEM 2, this investment includes 7,079 miles of gathering lines
which are located almost entirely within the Appalachian area.
The Company's investment in its gas distribution network includes 28,599 miles
of pipe, exclusive of service pipe, the cost of which represents 61% of the
$1.6 billion invested in the total function.
The Company's storage operation, the largest in the industry, consists of 26
storage fields, 331,834 acres of operated leaseholds, 2,039 storage wells and
816 miles of pipe. The investment in storage properties is $665 million,
including $105 million of cushion gas stored.
Of the $1.5 billion invested in transmission facilities, 69% represents the
cost of 7,403 miles of pipe required to move large volumes of gas throughout
the Company's operating area.
The Company has 107 compressor stations with 470,093 installed compressor
horsepower. Some of the stations are used interchangeably for several
functions.
The Company's investment in its fully integrated natural gas system is
considered suitable to do all things necessary to bring gas to the consumer.
The Company's properties provided the capacity to meet a record system peak
day sendout, including transportation service, of 9.1 Bcf on January 18, 1994.
19
<PAGE>
Map of Principal Facilities at December 31, 1994
(GRAPHIC MATERIAL OMITTED)
20
<PAGE>
Map of Exploration and Production Areas at December 31, 1994
(GRAPHIC MATERIAL OMITTED)
21
<PAGE>
ITEM 2. PROPERTIES (Continued)
GAS AND OIL PRODUCING ACTIVITIES (See Note 18(A) to the consolidated financial
statements, page 72.)
Properties and activities subject to cost-of-service rate regulation are shown
together with non-cost-of-service properties (those subject to contractual
arrangements, and Canadian properties) and activities in the statistical
presentations which follow.
COMPANY-OWNED RESERVES
Estimated net quantities of proved gas and oil reserves at December 31, 1992
through 1994, follow:
<TABLE>
<CAPTION>
________________________________________________________________________________
_______________________
December 31, 1994 1993
1992
________________________________________________________________________________
_______________________
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 . . . . . . 730 901 761
885 794 918
Cost-of-service . . . . . . . 71 71 75
75 80 80
______ ______ ______
______ ______ ______
Total . . . . . . . . . . 801 972 836
960 874 998
====== ====== ======
====== ====== ======
Oil Reserves (000 Bbls)
Non-cost-of-service . . . . . . 20,379 46,255 21,936
27,596 27,449 29,238
Cost-of-service . . . . . . . 256 256 287
287 283 283
______ ______ ______
______ ______ ______
Total . . . . . . . . . . 20,635 46,511 22,223
27,883 27,732 29,521
====== ====== ======
====== ====== ======
________________________________________________________________________________
_______________________
</TABLE>
CNG Producing, East Ohio Gas, Hope Gas, Peoples Natural Gas and CNG
Transmission file Form EIA-23 with the Department of Energy. The reserves
reported at December 31, 1993, as well as those which will be reported at
December 31, 1994, are not reconcilable with Company-owned reserves because
they are calculated on an operated basis and include working interest reserves
of all parties.
QUANTITIES OF GAS AND OIL PRODUCED
Net quantities (net before royalty) of gas and oil produced during each of the
last three years follow:
______________________________________________________________________________
Years Ended December 31, 1994 1993 1992
______________________________________________________________________________
Gas Production (Bcf)
Non-cost-of-service . . . . . . . . . 114 124 121
Cost-of-service . . . . . . . . . . 6 6 7
_____ _____ _____
Total . . . . . . . . . . . . . 120 130 128
===== ===== =====
Oil Production (000 Bbls)
Non-cost-of-service . . . . . . . . . 3,333 3,907 4,508
Cost-of-service . . . . . . . . . . 24 29 31
_____ _____ _____
Total . . . . . . . . . . . . . 3,357 3,936 4,539
===== ===== =====
______________________________________________________________________________
The average sales price (including transfers to other operations as determined
under Financial Accounting Standards Board rules) per Mcf of non-cost-of-
service gas produced during the calendar years 1992 through 1994 was $2.05,
$2.24 and $2.16, respectively. The respective average sales prices for oil
were $18.15, $15.66 and $14.45 per barrel. The average production (lifting)
cost per Mcf equivalent of non-cost-of-service gas and oil produced during the
years 1992 through 1994 was $.37, $.33 and $.32, respectively.
22
<PAGE>
ITEM 2. PROPERTIES (Continued)
PRODUCTIVE WELLS
The number of productive gas and oil wells in which the subsidiary companies
have an interest at December 31, 1994, follow:
______________________________________________________________________________
Gas Wells Oil Wells
Gross Net Gross Net
______________________________________________________________________________
Non-cost-of-service* . . . . . . . . 5,358 4,559 879 411
Cost-of-service . . . . . . . . . . 2,124 1,764 3 3
_____ _____ ____ ____
Total. . . . . . . . . . . . . 7,482 6,323 882 414
===== ===== ==== ====
______________________________________________________________________________
* Includes 81 gross (21 net) multiple completion gas wells and 6 gross (2
net) multiple completion oil wells.
ACREAGE
The following table sets forth the gross and net developed and undeveloped
acreage of the subsidiary companies at December 31, 1994:
______________________________________________________________________________
Developed Acreage Undeveloped Acreage
Gross Net Gross Net
______________________________________________________________________________
Non-cost-of-service. . . . 1,593,623 1,197,233 1,103,074 735,837
Cost-of-service . . . . . 436,105 433,759 41,060 37,445
_________ _________ _________ _________
Total. . . . . . . . 2,029,728 1,630,992 1,144,134 773,282
========= ========= ========= =========
______________________________________________________________________________
Approximately 28% of the foregoing non-cost-of-service undeveloped net acreage
and 100% of the cost-of-service undeveloped net acreage is located in the
Appalachian area.
NET WELLS DRILLED IN THE CALENDAR YEAR
The number of non-cost-of-service net wells completed during each of the last
three years follow (there were no cost-of-service wells completed during this
three-year period):
______________________________________________________________________________
Exploratory Development Total
Productive Dry Productive* Dry Productive Dry
______________________________________________________________________________
Years Ended December 31,
1994 . . . . . . . 2 10 22 1 24 11
1993 . . . . . . . 2 6 13 1 15 7
1992 . . . . . . . 1 3 54 10 55 13
______________________________________________________________________________
* Includes Canadian completions: 1994 - 1 well, 1993 - 1 well and 1992 - 0
wells.
As of December 31, 1994, 8 gross (3 net) non-cost-of-service wells were in
process of drilling, including wells temporarily suspended. As of December
31, 1994, Consolidated was engaged in waterflood projects in Oklahoma and
Texas, a gas injection program in the Gulf of Mexico, and an enhanced oil
recovery program in Alberta, Canada.
23
<PAGE>
ITEM 2. PROPERTIES (Concluded)
GAS PURCHASE CONTRACT RESERVES (AT DECEMBER 31, 1994) AND AVAILABILITY OF
SUPPLY (CALENDAR YEAR 1995)
Gas purchase reserves under contract with independent producers in the
Appalachian area total 638 Bcf at December 31, 1994. In addition, at December
31, 1994, Consolidated had gas supply contracts with various other producers
and marketers with contract lengths ranging from a few months to ten years.
The volume of gas available to Consolidated under these supply contracts
totals 375 Bcf if all volumes are requested. These gas purchase contract
reserve and gas supply contract volume amounts are as contained in the
February 14, 1995 report of Ralph E. Davis Associates, Inc. Of the total 638
Bcf under contract from Appalachian producers, the volume of gas expected to
be purchased in 1995 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 375 Bcf available under contract
from other producers and marketers, approximately 239 Bcf of gas will be
available to Consolidated in 1995, assuming all volumes are requested. There
were no gas purchases from pipeline companies in 1994, as Consolidated
converted its remaining gas purchase contracts with interstate pipeline
companies to firm transportation contracts during 1993.
The Company anticipates that substantial volumes of gas will be available for
purchase during 1995 on the spot market. Due to the nature of spot market
transactions, the volumes of such gas available to Consolidated in 1995 cannot
be reasonably estimated. However, for the calendar year 1995, Consolidated
expects its distribution subsidiaries to have approximately 383 Bcf of firm
transport capacity available on upstream pipelines and 121 Bcf of storage
capacity available to meet their customer requirements.
The volumes expected to be available from Company-owned wells in 1995 amount
to 128 Bcf of gas and 3,988 thousand barrels of oil. Included in these
amounts are 122 Bcf of gas and 3,962 thousand barrels of oil expected to be
available from the Company's non-cost-of-service properties. The foregoing
volumes are based on the Company's current production estimates of proved gas
and oil reserves. Actual production may differ from these amounts due to a
number of factors, including changing market conditions and the acquisition or
sale of reserves.
24
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
Reference is made to "Environmental Matters," page 41, and to Note 15 to the
consolidated financial statements, page 68, for environmental-related
information.
Reference is made to "Rate Matters," page 16, for descriptions of certain
regulatory proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable
PART II
ITEM 5. MARKET FOR THE COMPANY'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
This information is included in Note 18(C) to the consolidated financial
statements, page 77, and reference is made thereto.
25
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
________________________________________________________________________________
_______________________________________
SUMMARY OF FINANCIAL DATA (Thousand $) 1994 1993
1992 1991 1990
________________________________________________________________________________
_______________________________________
<S> <C> <C>
<C> <C> <C>
EARNINGS
Gas sales . . . . . . . . . . . . . $ 2,402,861 $ 2,615,036 $
1,951,545 $ 2,082,927 $ 2,234,347
Gas transportation, storage and other. . . . 633,167 569,049
569,305 524,079 480,524
Total operating revenues . . . . . . . 3,036,028 3,184,085
2,520,850 2,607,006 2,714,871
Purchased gas, transport capacity
and other purchased products . . . . . . 1,531,114 1,673,374
1,063,605 1,237,227 1,344,588
Operation and maintenance, depreciation . . . 968,892 972,314
945,665 924,242 911,407
Taxes, other than income taxes . . . . . . 192,617 181,053
169,315 160,632 158,459
Operating income before income taxes . . . 343,405 357,344
342,265 284,905 300,417
Income taxes . . . . . . . . . . . . 82,427 99,906
68,623 54,844 52,123
Interest charges. . . . . . . . . . . 87,501 79,475
83,433 87,829 92,873
Other income-net, including change in
accounting principle. . . . . . . . . 9,694 27,953
4,749 26,381 8,349
Net income . . . . . . . . . . . . 183,171 205,916
194,958 168,613 163,770
Per share of common stock
Income before change in accounting principle. $1.97 $2.03
$2.19 $1.94 $1.91
Cumulative effect of applying SFAS No. 109 . - .19
- - -
Net income . . . . . . . . . . . . $1.97 $2.22
$2.19 $1.94 $1.91
Average common shares outstanding . . . . . 92,999,693 92,808,156
89,127,805 86,836,920 85,683,172
Return on average stockholders' equity . . . 8.4% 9.6%
9.7% 9.0% 9.3%
Times fixed charges earned . . . . . . . 3.53 3.95
3.41 2.86 2.73
________________________________________________________________________________
_______________________________________
DIVIDENDS - CASH
Paid per common share . . . . . . . . . $1.94 $1.92
$1.90 $1.88 $1.84
Payout ratio . . . . . . . . . . . 98.5% 86.5%
86.8% 96.9% 96.3%
Declared per common share. . . . . . . . $1.94 $1.925
$1.905 $1.885 $1.85
________________________________________________________________________________
_______________________________________
ASSETS
Total assets . . . . . . . . . . . . $ 5,518,673 $ 5,437,188 $
5,158,871 $ 5,026,775 $ 5,020,026
Property, plant and equipment
Total investment . . . . . . . . . . 7,676,956 7,346,028
7,087,102 6,749,165 6,433,527
Accumulated depreciation . . . . . . . 3,650,310 3,429,760
3,212,202 3,010,776 2,820,771
Capital expenditures and acquisitions. . . . 437,785 342,569
441,518 493,033 559,514
________________________________________________________________________________
_______________________________________
CAPITAL STRUCTURE
Total common stockholders' equity . . . . . $ 2,184,334 $ 2,176,432 $
2,132,838 $ 1,889,783 $ 1,844,594
Long-term debt . . . . . . . . . . . 1,151,973 1,158,648
1,111,956 1,159,123 1,128,513
____________ ____________
____________ ____________ ____________
Total capitalization. . . . . . . . . $ 3,336,307 $ 3,335,080 $
3,244,794 $ 3,048,906 $ 2,973,107
============ ============
============ ============ ============
Long-term debt ratio . . . . . . . . . 34.5% 34.7%
34.3% 38.0% 38.0%
Shares of common stock outstanding at year-end. 93,027,847 92,933,828
92,557,017 87,321,917 86,327,073
Common stockholders' equity per share . . . $23.48 $23.42
$23.04 $21.64 $21.37
________________________________________________________________________________
_______________________________________
</TABLE>
26
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
NET INCOME
Net income in 1994 was $183 million, an 11 percent decrease from the $206
million earned in 1993. On a per share basis, 1994 earnings were $1.97
compared with $2.22 earned in 1993. Net income in 1992 was $195 million, or
$2.19 a share.
Warmer weather, higher operating costs, lower average wellhead gas prices,
reduced gas production and higher interest expense contributed to the earnings
decline in 1994. Weather in Consolidated's retail service areas was warmer
than 1993 and warmer than normal for the fifth consecutive year. Normal
weather represents a measure of temperature experienced over a 30-year period.
Normal weather would have added about $.12 a share to the $1.97 a share
reported for 1994.
The higher operating costs are being addressed through cost containment efforts
at all subsidiaries. Also, five of the Company's regulated subsidiaries have
recently implemented or are pursuing rate increases that include higher
operating expense levels, as well as recovery of investments in new facilities
(see "Federal and State Regulatory Matters").
In 1993, colder weather, higher prices for natural gas production and increased
gas deliveries resulting from pipeline expansion projects were major factors for
the earnings improvement over 1992. Weather in Consolidated's retail service
areas was colder than in 1992, but warmer than normal. Normal weather in 1993
would have added about $.06 a share to the $2.22 a share reported.
Earnings in both 1993 and 1992 included the positive impact of deferred tax
benefits. In 1993, deferred tax benefits of $17.4 million, or $.19 a share,
resulting from the mandatory adoption of Statement of Financial Accounting
Standards (SFAS) No. 109, are reported as a separate component of net income as
the cumulative effect of the accounting change. By contrast, deferred tax
benefits recognized in 1992 under the previously applicable accounting standard
reduced income tax expense in that year by $13.0 million, or $.15 a share.
Results for 1993 were negatively impacted by higher income taxes due to the
increase in the federal corporate income tax rate from 34 percent to 35 percent
enacted in August 1993. The effects of this rate change included an $11.4
million, or $.12 a share, adjustment to previously recorded deferred tax
balances and a $2.7 million, or $.03 a share, increase in current taxes to
reflect the new tax law retroactive to January 1, 1993.
The expansion of the Company's transmission operations, increased gas storage
service revenues, and higher wellhead prices for gas, offset by warmer than
normal weather, were major factors contributing to 1992 earnings. If weather
in the retail service areas had been normal in 1992, earnings would have been
$.16 a share higher than the $2.19 reported. The increase in average gas
wellhead prices for the year was offset to a large extent by lower gas and oil
production and lower average oil wellhead prices.
27
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
OPERATING REVENUES
Operating revenues include revenues from gas and oil sales, transportation of
gas, storage service, brokering activities and by-product operations.
Total operating revenues in 1994 were $3,036.0 million, a decrease of $148.1
million compared to 1993 operating revenues of $3,184.1 million. Regulated gas
sales revenues were down $393.9 million in 1994 primarily due to the abandonment
by CNG Transmission Corporation (CNG Transmission) of its traditional sales
service with the implementation of Federal Energy Regulatory Commission (FERC)
Order 636 in October 1993. Retail sales revenues were higher in 1994 as higher
average sales prices received from all customer classes more than offset a
decline in gas volumes sold resulting from the warmer weather in 1994.
Nonregulated gas sales revenues increased $181.8 million, representing a
significant increase in volumes sold due to a full year of operation at CNG
Energy Services Corporation (together with its predecessor companies, CNG
Energy Services) partially offset by a decline in the average sales price.
Revenues from gas transportation and storage services rose $76.3 million
reflecting CNG Transmission's first full year of operations under FERC Order
636. Other operating revenues declined $12.3 million, primarily due to lower
oil sales volumes and prices.
Total operating revenues were up $663.2 million in 1993 with the increase due to
higher gas sales revenues. Regulated gas sales revenues increased $403.7
million due to higher retail sales volumes and rates and the sales of gas from
storage inventory by CNG Transmission. Nonregulated gas sales revenues rose
$259.8 million due to higher gas wellhead prices and production and the initial
year of marketing activities by CNG Energy Services. Gas transportation and
storage revenues were up $25.8 million, with most of the increase attributable
to higher transport volumes following CNG Transmission's implementation of FERC
Order 636. Other operating revenues declined $26.1 million due chiefly to
lower oil and condensate sales volumes and prices.
The total average unit selling price of gas in 1994 was $3.89 per thousand
cubic feet, down 10 percent from $4.33 in 1993. In 1992, the average unit
selling price was $4.35 per thousand cubic feet. The decline in 1994 was due
primarily to a lower average rate for nonregulated gas sales. Average sales
prices in 1993 were higher for all retail categories and for sales of the
Company's gas production compared with 1992. However, the sales from storage
inventory at lower rates under alternative FERC-approved tariff schedules
reduced the overall selling price for 1993 to slightly below the 1992 rate.
OPERATING EXPENSES
Operating expenses, including taxes, decreased 5 percent in 1994 to $2.78
billion. Operating expenses in 1993 were $2.93 billion, up 30 percent from
$2.25 billion in 1992.
Purchased gas costs consistently represent the largest expense item for
Consolidated. Purchased gas costs were $1,424.0 million in 1994, $1,594.4
million in 1993 and $990.6 million in 1992. 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. Lower
spot market gas prices and lower recoveries of previously deferred gas costs by
the distribution subsidiaries, partially offset by increased volume
requirements, were the primary factors for the decline in 1994. Increased
volume requirements, CNG Transmission's billing of its October 1, 1993, balance
of unrecovered gas and transportation costs under FERC Order 636, and higher
spot market gas prices were the principal reasons for the level of costs in
1993. The sales of approximately 58 billion cubic feet (Bcf) of gas from
storage inventory by CNG Transmission and increased recoveries of previously
deferred gas costs also contributed to the higher expense in 1993.
28
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Transport capacity and other purchased products expense includes the cost of
pipeline capacity not associated with gas purchased and the cost of liquids and
by-products purchased for resale. This expense increased $28.1 million and $6.0
million in 1994 and 1993, respectively, primarily due to increased transport
capacity purchased from other pipeline companies by CNG Transmission and CNG
Energy Services.
Combined operation and maintenance expense increased $11.9 million in 1994, to
$689.6 million. The increase in operation expense of $9.9 million, to $600.4
million, was due principally to higher payroll costs, including weather-related
overtime during the unusually cold weather early in 1994, and overhead costs.
Maintenance expense was up $2.0 million, or 2 percent, to $89.2 million.
In 1993, combined operation and maintenance expense increased $19.9 million, or
3 percent from 1992. Operation expense was up $11.8 million to $590.5 million
reflecting increased payroll and benefit expenses and overhead costs.
Maintenance expense in 1993 was up $8.1 million to $87.2 million largely
because of additional work performed with respect to distribution and
transmission mains, compressor station maintenance and environmental-related
costs (see "Environmental Matters"). The adoption in 1993 of SFAS No. 106 did
not have a significant impact on operation expense. Reference is made to
Note 5 to the consolidated financial statements for additional information
regarding SFAS No. 106.
Depreciation expense increased in both 1994 and 1993 for the regulated
subsidiaries due principally to the higher level of plant investment. The
higher amount in 1993 reflects, for the most part, depreciation charges for the
Virginia intrastate pipeline which was placed in service during 1992.
Amortization of gas and oil producing properties decreased in 1994 due to lower
overall production and the recognition of additional reserves in the Gulf of
Mexico. Amortization of gas and oil properties declined in 1993 compared with
1992 due primarily to lower oil production.
Taxes, other than income taxes, increased $11.5 million in 1994 compared with
an $11.7 million increase in 1993. Both increases were due in large part to
higher property taxes.
Income taxes declined $17.5 million in 1994 compared to the prior year primarily
as a result of lower pretax earnings and an $11.4 million adjustment recorded in
1993 to deferred income tax expense due to the increase in the federal corporate
income tax rate. Income taxes increased $31.3 million in 1993 as a result of
higher pretax earnings and the additional deferred income taxes related to the
tax rate increase in that year. Income taxes for 1994 and 1993 were determined
under SFAS No. 109, while taxes for 1992 were determined under the previous
accounting standard. Certain deferred tax benefits which reduced income tax
expense in 1992 under the previous accounting standard were also a significant
factor in the comparison between 1993 and 1992. Reference is made to Note 6 to
the consolidated financial statements for information regarding the adoption of
SFAS No. 109, as well as for information on the effects of the 1993 increase in
the federal corporate income tax rate.
OTHER INCOME
Total other income was $9.7 million in 1994, $10.5 million in 1993 and $4.7
million in 1992. Interest revenues were $1.7 million higher in 1994 reflecting
CNG Transmission's billing of Order 636 transition costs in December 1993 and
August 1994. Interest revenues were up $1.5 million in 1993 due primarily to
the recognition of interest in connection with certain regulatory programs.
Interest revenues in 1992 reflect lower revenues in connection with take-or-pay
recoveries by the subsidiaries and the lower interest rates which prevailed
during that year. The changes in "Other-net" in the Consolidated Statement of
Income reflect the differing levels of income recognized from the Company's
external investments and gains on purchases of debentures for sinking funds in
1993 and 1992.
29
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
INTEREST CHARGES
During 1993, the Company called $266.2 million of its higher-cost borrowings,
while issuing $300.0 million of lower rate debentures. Interest on long-term
debt increased $3.5 million in 1994 reflecting a full year of interest expense
on the debentures issued in 1993. Interest on long-term debt was lower in 1993
due to the redemptions and repayments of debenture borrowings. Other interest
expense increased in 1994 primarily due to higher interest on refund obligations
to customers. Other interest expense declined in 1993 compared to 1992 due
primarily to lower commercial paper discount rates. The amount of interest
expense capitalized has declined in the past two years reflecting the completion
of pipeline expansion projects and lower interest rates.
FOURTH QUARTER RESULTS
Consolidated's net income for the fourth quarter of 1994 was $73.8 million
compared with $86.1 million earned in the 1993 fourth quarter, a decrease of
$12.3 million. On a per share basis, the 1994 quarter was $.79 compared with
$.93 in 1993. The weather in Consolidated's retail service areas was 22
percent warmer than in the 1993 fourth quarter, thereby significantly reducing
throughput and operating results. Warm weather prevailed over much of the
country, depressing gas wellhead prices. In response to the low prices,
Consolidated shut in a portion of its Gulf of Mexico properties, thereby
reducing gas production during the quarter. Consolidated's average gas
wellhead prices were down $.42 per thousand cubic feet compared with the 1993
fourth quarter.
______________________________________________________________________________
QUARTERS ENDED DECEMBER 31, 1994 1993
______________________________________________________________________________
(In Millions)
Operating revenues . . . . . . . . . . $ 788.6 $1,030.2
Operating expenses . . . . . . . . . . (666.8) (895.0)
________ ________
Operating income before income taxes . . . . 121.8 135.2
Income taxes . . . . . . . . . . . . (27.3) (35.4)
Other income/expenses-net . . . . . . . . (20.7) (13.7)
________ ________
Net income . . . . . . . . . . . . . $ 73.8 $ 86.1
======== ========
Per common share (in dollars). . . . . . . $.79 $.93
Average shares outstanding (thousands). . . . 93,026 92,923
______________________________________________________________________________
NEW ACCOUNTING STANDARDS
Effective January 1, 1994, the Company adopted the provisions of SFAS No. 112,
"Employers' Accounting for Postemployment Benefits." The standard requires the
accrual of a liability for certain postemployment benefit obligations. The
adoption of this standard did not have a material effect on the Company's
financial position, results of operations or cash flows.
30
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
COMPONENTS OF THE BUSINESS
OPERATING INCOME BEFORE INCOME TAXES
Operating income before income taxes for Consolidated's business components for
the last three years is shown in the table below.
CNG Energy Services markets a portion of Company-owned production, and arranges
gas supplies, transportation, storage and related services for customers. In
addition, Consolidated received FERC approval during 1994 to purchase and
resell electricity at market-based rates, services which will be offered by CNG
Power Services, an affiliate of CNG Energy Services. Amounts pertaining to the
operations of CNG Energy Services and CNG Power Services are included in the
caption "Other" in the table below. The 1992 results of CNG Trading Company, a
predecessor to CNG Energy Services, remain in the exploration and production
component.
______________________________________________________________________________
OPERATING INCOME BEFORE INCOME TAXES 1994 1993 1992
______________________________________________________________________________
(In Millions)
Distribution . . . . . . . . . . . $159.0 $166.9 $176.6
Transmission . . . . . . . . . . . 146.3 143.4 120.1
Exploration and production . . . . . . 34.0 47.3 38.8
Other* . . . . . . . . . . . . . 7.6 5.7 17.0
Corporate and eliminations . . . . . . (3.5) (6.0) (10.2)
______ ______ ______
Total . . . . . . . . . . . . $343.4 $357.3 $342.3
====== ====== ======
______________________________________________________________________________
*Includes CNG Energy Services, CNG Power (formerly CNG Energy), CNG Power
Services, Consolidated LNG, CNG Research and CNG Coal.
Due to the regulated nature of the distribution and transmission components of
Consolidated's business, operating results can be affected by regulatory delays
when price increases are sought through general rate filings to recover certain
higher costs of operations. Weather is also an important factor since a major
portion of the gas sold or transported by the distribution and transmission
operations is ultimately used for space heating.
The following presents the operating results for each of the Company's business
components. Reference is made to Note 17 to the consolidated financial
statements for additional disaggregated information pertaining to the Company's
operations.
DISTRIBUTION
"Distribution" represents the results of Consolidated's retail gas distribution
subsidiaries, including their minor gas and oil production activities. During
1994, The Public Utilities Commission of Ohio (PUCO) approved the merger of the
Company's River Gas subsidiary into The East Ohio Gas Company (East Ohio Gas).
The Company now has five retail gas distribution subsidiaries.
OPERATING INCOME BEFORE INCOME TAXES
Operating income before income taxes for the gas distribution operations
declined $7.9 million in 1994, to $159.0 million. Warmer weather and higher
costs of operations were the principal reasons for the decline. Overall,
weather in Consolidated's retail service area was 3 percent warmer than 1993
and 4 percent warmer than normal. The higher operating costs were addressed in
rate filings made by the subsidiaries during the year. Two subsidiaries were
granted rate increases and another began collecting higher rates, subject to
refund. However, the increases were placed into effect in the latter part of
the year and did not have a significant impact on 1994 results (see "State
Regulatory Issues").
31
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Operating results for the gas distribution operations in 1993 were down $9.7
million, or 6 percent, from 1992. Higher costs of operations more than offset
the impact of slightly colder weather and a minor increase in throughput
experienced in 1993. Overall, weather in the retail service areas in 1993 was
2 percent colder than in 1992, but 1 percent warmer than normal. The colder
weather, the net addition of about 17,800 residential and commercial gas sales
customers and the full year impact of general rate increases placed into effect
by two subsidiaries in the latter part of 1992 contributed favorably to 1993
results.
Operating results for 1992 reflected weather in Consolidated's retail service
areas which was 3 percent warmer than normal for the full year but 8 percent
warmer than normal for the five principal heating months. The net addition of
some 21,000 residential and commercial gas sales customers, the benefit of a
full year of general rate increases granted to two subsidiaries in the prior
year, and the impact of general rate increases placed into effect by two
subsidiaries in the latter part of 1992 contributed to operating results for
1992.
OPERATING REVENUES
Revenues of the gas distribution operations rose $31.7 million in 1994, a 2
percent increase compared with 1993. Gas sales revenues rose $23.6 million due
to increases in the average sales price received from residential and commercial
customers, partially offset by reduced sales volumes which reflected warmer than
normal weather. Gas sales were impacted by general rate increases placed into
effect in the latter part of the year at three of Consolidated's distribution
subsidiaries (see "State Regulatory Issues") and the full year impact of a
general rate increase that went into effect in late 1993 at Hope Gas, Inc.
(Hope Gas). Gas transportation and storage revenues were up $6.5 million
reflecting increased transportation volumes, while other operating revenues
increased $1.6 million.
Operating revenues of the gas distribution operations in 1993 increased $170.8
million. Gas sales revenues rose $171.6 million due to both higher sales
volumes and rates. Colder weather and an increase in the number of customers
served were the principal reasons for the sales volume increase. The full year
impact of general rate increases placed into effect in late 1992 by The Peoples
Natural Gas Company (Peoples Natural Gas) and Virginia Natural Gas, Inc.
(Virginia Natural Gas) and the increase which became effective in late 1993 for
Hope Gas, contributed approximately $21.8 million to sales revenues in 1993.
The recovery in current rates of previously incurred gas cost increases also
contributed to the higher revenues in 1993. Gas transportation and storage
revenues declined $.7 million due primarily to lower storage service revenues.
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. "Normal weather," as the term is used in the gas industry,
represents the mean of temperatures experienced, measured in terms of degree
days, over a 30-year period. A degree day is a measure of the coldness of the
weather based on the extent to which the daily mean temperature falls below 65
degrees Fahrenheit. The 30-year average, which is calculated by a federal
agency, is updated approximately every 10 years. For Consolidated, "normal
weather" is determined using the weighted average of the normal degree days
experienced in its retail service territories.
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 economics and market
conditions.
32
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
_______________________________________________________________________________
DISTRIBUTION THROUGHPUT 1994 1993 1992
_______________________________________________________________________________
(In Billion Cubic Feet)
Sales. . . . . . . . . . . . . 285.0 297.8 293.6
Transportation. . . . . . . . . . 151.1 145.4 143.5
_____ _____ _____
Throughput . . . . . . . . . . 436.1 443.2 437.1
===== ===== =====
_______________________________________________________________________________
Warmer weather was the primary factor in the decline in gas sales during 1994,
while transportation volumes were up 4 percent. Although the impact was
partially offset by the net addition of about 22,500 customers, the weather was
3 percent warmer than in 1993 resulting in lower space-heating sales.
Residential and commercial gas sales volumes declined by 6.4 Bcf and 3.3 Bcf,
respectively, compared to 1993. Industrial sales volumes were down 3.1 Bcf to
9.4 Bcf, while transportation volumes were up 5.2 Bcf to 121.1 Bcf. Gas
transported for commercial customers was 24.4 Bcf in 1994, up 3.3 Bcf, while
transportation to off-system customers declined 2.8 Bcf to 5.6 Bcf in 1994.
Gas sales of the distribution subsidiaries were somewhat higher in 1993 compared
with 1992 due to slightly colder weather while transportation volumes remained
relatively unchanged. The net addition of approximately 17,800 customers in
1993 also contributed to the higher sales volumes in that year. The weather in
1993 was 2 percent colder than in 1992 resulting in higher space-heating sales.
Residential gas sales increased 4.2 Bcf to 212.3 Bcf in 1993, and commercial
sales volumes were virtually unchanged at 72.7 Bcf. Industrial sales volumes
were flat with 1992 at 12.5 Bcf, while transportation volumes were up 1.5 Bcf to
116.0 Bcf. Gas transported for commercial customers was 21.1 Bcf in 1993, up
1.4 Bcf compared with 1992, while transportation to off-system customers
declined by 1.0 Bcf to 8.3 Bcf in 1993.
Sales growth in Consolidated's residential service areas in Ohio, Pennsylvania
and West Virginia has generally been limited since such areas have experienced
minimal population growth, and the vast majority of households in these areas
already use natural gas for space heating. Opportunity for growth in the retail
sales market is expected to continue at Virginia Natural Gas, due to customer
conversions from other energy sources and the past and potential future
expansion of its service territory. Since Consolidated's acquisition of this
subsidiary in 1990, it has experienced an annual customer growth rate of about
4 percent, well above the 1 percent rate for Consolidated's other distribution
subsidiaries. In 1994, Virginia Natural Gas connected about 8,200 new
residential and commercial customers. The completion in 1992 of the 135-mile
intrastate pipeline in Virginia has provided Virginia Natural Gas and its
customers with new gas supply sources through access to Consolidated's
transmission system and storage facilities and has afforded additional
opportunities for growth in both gas sales and transportation, especially in
the power generation markets.
TRANSMISSION
"Transmission" includes the results of the gas transmission, storage, by-product
and certain other activities of CNG Transmission and the activities of CNG
Storage Service Company. Gas and oil production activities of CNG Transmission
are included in exploration and production operations.
Changing regulatory policies intended to increase competition in the natural gas
industry have been the principal factor affecting the transmission operations
over the past several years. Beginning with open access transportation and
culminating with the significant service restructuring required by FERC Order
636, the role of the Company's transmission operations has changed from that of
primarily a merchant, or wholesaler, of gas to one that provides a range of gas
transportation, storage, and other related services.
33
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
With its implementation of Order 636 effective October 1, 1993, CNG Transmission
abandoned its traditional sales service which consisted of various elements of
gas sales, transportation and storage that were offered and priced as a single
bundled service. Customers now have even greater access to the Company's
pipeline and storage capacity, together with a range of options available with
respect to gas transportation and storage services.
OPERATING INCOME BEFORE INCOME TAXES
Operating income before income taxes increased $2.9 million, or 2 percent, in
1994 to $146.3 million. Operating results for 1994 reflect the first full year
of applying the straight fixed variable rate design under which operating income
is less influenced by changes in throughput than in the past. Significant
factors affecting 1994 operating results included increased transportation and
storage service revenues, competition from other pipelines, and higher operating
costs not yet reflected in rates. The higher operating costs are being
addressed in CNG Transmission's latest general rate filing with the FERC.
Higher rates requested in this filing went into effect July 1, 1994, subject to
refund.
Operating results for 1993 increased $23.3 million, or 19 percent, over 1992.
The improvement was due partly to expanded service to customers in the Northeast
as a result of the Company's pipeline construction program, increased throughput
to affiliated distribution companies, and higher gas storage service and
by-product revenues. Colder weather and, to a lesser extent, sales of gas from
storage inventory and certain other steps taken to facilitate the transition to
Order 636 also contributed to the 1993 results.
The most significant factors affecting 1992 results were the expansion of
transportation service to both new customers and existing wholesale customers
and end users on the East Coast, including power generation customers, and
increased demand by traditional Northern Market customers. Colder weather and
increased storage service revenues also contributed to 1992 results. The
increased transportation to utilities and end users in the Northeast and along
the East Coast was the result of the completion of several of the Company's
pipeline expansion projects. The impact of these positive factors was partially
offset by higher operating costs in 1992.
OPERATING REVENUES
Total operating revenues of the transmission operations declined by $524.5
million in 1994, to $459.3 million. CNG Transmission abandoned its traditional
sales service pursuant to the October 1, 1993 implementation of Order 636. Gas
sales revenues in 1993 were $631.1 million. Increases during 1994 in
transportation and storage service revenues of $92.9 million and $22.9 million,
respectively, reflected the impact of the first full year of services provided
under Order 636. Revenues from the sale of by-products declined by $1.4 million
in 1994 as a result of lower prices.
In 1993, operating revenues were up $341.1 million. Gas sales revenues rose
$290.0 million due chiefly to billings by CNG Transmission of its October 1,
1993, balance of certain Order 636 transition costs and the sales of
approximately 58 Bcf of gas from storage inventory in anticipation of the
implementation of Order 636. Gas transportation revenues were up $35.7 million
and storage service revenues increased $12.6 million, both reflecting the
increased level of services provided to customers. Revenues from the sale of
by-products were also higher in 1993, increasing $4.5 million primarily as the
result of higher propane and ethane sales volumes.
34
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
TRANSMISSION THROUGHPUT
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.
_______________________________________________________________________________
TRANSMISSION THROUGHPUT 1994 1993 1992
_______________________________________________________________________________
(In Billion Cubic Feet)
Sales. . . . . . . . . . . . . - 100.1 42.4
Transportation. . . . . . . . . . 748.4 610.9 596.8
_____ _____ _____
Throughput* . . . . . . . . . . 748.4 711.0 639.2
===== ===== =====
_______________________________________________________________________________
*Includes intercompany activity.
Consolidated's transmission operations total throughput of 748.4 Bcf in 1994
exceeded 1993's record throughput level by 5 percent. The 1994 throughput
consisted solely of transportation volumes as CNG Transmission abandoned its
traditional sales service with the October 1, 1993 implementation of Order 636.
The increase of 137.5 Bcf of transportation volumes compared to 1993 occurred
mainly in the first quarter of 1994 consistent with the cold weather experienced
early in the year.
Total transmission throughput volumes in 1993 increased 71.8 Bcf compared with
1992. Wholesale gas sales volumes increased 57.7 Bcf in 1993 to 100.1 Bcf.
The increase in sales volumes was due to the sales by CNG Transmission of
approximately 58 Bcf of gas from storage inventory in anticipation of the
transition to restructured services. These sales, which were made at reduced
prices under alternative FERC-approved tariff schedules, increased available
capacity to provide future storage service while reducing certain transition
costs under Order 636. Total gas transportation volumes in 1993 increased 14.1
Bcf to 610.9 Bcf. The increase in transportation volumes occurred in the fourth
quarter of 1993 following implementation of Order 636 and was due primarily to
volumes transported for customers in the Northern Market area and Virginia.
The changing regulatory environment has created a number of opportunities for
pipeline companies to expand and serve new markets. The Company has taken
advantage of selected market expansion opportunities, concentrating the efforts
toward potentially high-volume, weather-sensitive markets and areas with growing
power generation needs located primarily in the Northeast and along the East
Coast. This expansion takes advantage of Consolidated's network of underground
storage facilities and the location and nature of its gridlike pipeline system
as a link between the country's major longline gas pipelines and the increasing
energy demands of East Coast markets.
35
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
EXPLORATION AND PRODUCTION
"Exploration and production" includes the results of CNG Producing Company
(CNG Producing), the gas and oil production activities of CNG Transmission and,
in 1992, the results of CNG Trading Company.
OPERATING INCOME BEFORE INCOME TAXES
Exploration and production operating income was $34.0 million in 1994, a
decrease of $13.3 million. The effect of the decline in total operating
revenues due to lower prices and production was partially offset by decreases
in royalty expense and depreciation and amortization of $9.4 million and $21.2
million, respectively. The lower level of royalty expense is attributable
primarily to reduced gas and oil production during 1994. Lower production,
together with the recognition of additional proved gas and oil reserves in the
Gulf of Mexico, resulted in lower depreciation and amortization expense for
1994. Reserves equivalent to 190 Bcf of gas at Viosca Knoll 826, a deep-water
project in the Gulf of Mexico in which Consolidated holds a 50 percent interest,
were added in 1994 and represent the largest single addition of reserves in the
Company's history.
In 1993, operating income was $47.3 million, up $8.5 million, or 22 percent,
compared with 1992. Positive factors affecting operating results in 1993
included higher wellhead prices for natural gas and slightly higher gas
production. Consolidated's gas wellhead prices in 1993 averaged $2.24 per
thousand cubic feet, a 9 percent increase from 1992. The positive factors were
partially offset by lower oil prices and production, and lower margins on the
brokering of gas. The average oil wellhead price realized of $15.66 per barrel
was 14 percent below 1992 levels.
Operating income in 1992 reflected the impacts of higher gas wellhead prices
and reduced operation and maintenance expense which were offset somewhat by
lower gas and oil production and lower wellhead oil prices. Gas wellhead prices
followed industry trends, falling early in the year but recovering and
strengthening as the year progressed. Consolidated's gas wellhead prices in
1992 averaged $2.05 per thousand cubic feet. The decline in operation and
maintenance expense resulted from cost containment programs and, to a lesser
extent, the lower gas and oil production levels. Overall, gas production for
1992 was down 4 percent and oil production was down 14 percent.
GAS AND OIL PRODUCTION AND PRICES
The following table sets forth Consolidated's gas and oil production and average
wellhead prices for the exploration and production operations for the last three
years:
_______________________________________________________________________________
PRODUCTION 1994 1993 1992
_______________________________________________________________________________
GAS (BCF)
Nonregulated. . . . . . . . . . 113.7 123.5 121.3
Regulated* . . . . . . . . . . 5.8 6.0 6.7
_______ _______ _______
Total. . . . . . . . . . . 119.5 129.5 128.0
======= ======= =======
OIL (000 BBLS)
Nonregulated. . . . . . . . . . 3,333.0 3,906.8 4,507.7
Regulated* . . . . . . . . . . 23.8 29.1 31.3
_______ _______ _______
Total. . . . . . . . . . . 3,356.8 3,935.9 4,539.0
======= ======= =======
AVERAGE WELLHEAD PRICES
(NONREGULATED ONLY)
Gas (per Mcf) . . . . . . . . . $ 2.16 $ 2.24 $ 2.05
Oil (per Bbl) . . . . . . . . . $ 14.45 $ 15.66 $ 18.15
_______________________________________________________________________________
*Cost-of-service.
36
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Gas wellhead prices were strong in the first quarter of 1994 but declined and
remained considerably below 1993 levels for most of the balance of the year.
Consolidated's average gas price was down $.08 a thousand cubic feet from 1993.
The low prices for natural gas that prevailed nationwide during most of 1994
were the basis for Consolidated's decision to shut in a portion of its offshore
production during the latter part of the year, resulting in lower gas production
for the year. Consolidated's average oil price declined 8 percent in 1994,
consistent with the continued overall decline in world oil prices. The lower
oil production during 1994 was due largely to normal production declines at
older properties, in addition to the partial shut-in of production.
Gas wellhead prices in 1993 were above 1992 levels for most of the year. For
the year, Consolidated's average gas wellhead price was up $.19 a thousand cubic
feet over 1992. Gas production increased slightly in 1993, although reduced
deliverability at certain properties and the sale of selected properties in the
Appalachian area held production down. The reduced deliverability was due in
part to the postponement in past years of workover activity due to the weak
prices in gas markets. Following world oil price trends, Consolidated's average
oil price declined in 1993 as prices remained weak through most of the year and
fell sharply near year-end. The lower oil production in 1993 was attributable
primarily to normal production declines at older properties.
OPERATING REVENUES
Total operating revenues declined $47.0 million in 1994. Gas sales revenues
decreased $23.0 million primarily due to lower prices received during 1994. Gas
sales volumes were flat compared with 1993 as lower sales of produced gas were
offset by an increase in brokered gas volumes. Oil and condensate revenues were
down $20.3 million which reflected lower volumes and prices for both oil
production and brokering activities. Revenues from oil and condensate
production decreased $13.2 million, while revenues from oil brokering were down
$7.1 million. Other revenues declined $3.7 million due principally to business
interruption insurance reimbursements related to Hurricane Andrew received in
1993.
Exploration and production revenues increased $17.0 million in 1993 compared
with 1992. Gas sales revenues rose $43.5 million due to higher prices received,
an increase in the volume of gas brokering activity and slightly higher gas
production. However, a large portion of this gain was offset by lower oil and
condensate revenues. Oil and condensate revenues declined $35.5 million as
lower prices and volumes adversely affected revenues from both oil production
and brokering activities. Revenues from the sale of oil and condensate
production declined $20.8 million, while revenues from oil brokering were down
$14.7 million. Other revenues were up $9.0 million in 1993 as the result of
increased royalties received due to the higher gas prices and business
interruption insurance reimbursements.
OTHER
Consolidated's "Other" operations reported operating income before income taxes
of $7.6 million in 1994, compared with operating income of $5.7 million in 1993.
A large portion of both the operating revenues and operating results of the
"Other" operations in both periods is attributable to CNG Energy Services.
Operating income before income taxes of CNG Energy Services was $2.8 million in
1994, an increase of $2.2 million over 1993. Gas sales by CNG Energy Services
totaled 203.8 Bcf in 1994, up from 125.2 Bcf in 1993. While total throughput of
CNG Energy Services in 1993 consisted entirely of gas sales volumes, 1994 total
throughput includes 7.0 Bcf of gas transportation volumes. Operating revenues
of CNG Energy Services were $486.3 million in 1994, an increase of $160.7
million compared with 1993.
37
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
RECENT DEVELOPMENTS
As indicated in Note 1 to the consolidated financial statements, CNG Producing
and CNG Transmission follow the full cost method of accounting for their gas and
oil producing activities prescribed by the Securities and Exchange Commission
(SEC). Under this method, the total capitalized costs, net of related deferred
taxes, are subject to a limitation based on the present value of estimated
future net revenues expected to be received from the production of proved
reserves. If net capitalized costs exceed this amount at the end of any
quarter, a permanent impairment of the assets is required to be charged to
expense in that period.
Consolidated has never been required to recognize such an impairment under the
SEC full cost rules. However, there are a number of factors, including prices,
which determine whether or not an impairment is required. Average gas wellhead
prices for 1994 were below those of 1993 and weakened in the early part of 1995.
Ample gas supplies nationwide due to the warm weather during the 1994-1995
heating season coupled with high levels of gas inventory available from storage,
have contributed to gas prices falling below the levels experienced at the end
of 1994. Should the current level of gas prices not improve and there are no
factors such as lower production costs or proved reserve additions to mitigate
the adverse impact of the low prices, the recognition of an impairment of the
Company's gas and oil producing properties will be required at the end of the
first quarter of 1995. In addition, the Company is reviewing other assets which
may result in the recognition of additional charges. Based on current
competitive conditions, the Company is also considering a variety of cost
cutting and restructuring measures, including work force reduction programs, the
implementation of which may have a material adverse impact on 1995 earnings.
(See "Recent Developments," page 8.)
Depending on the magnitude of any charges to 1995 net income resulting from the
above, the Company's ability to issue additional senior debt may be restricted
under the indenture relating to the Company's outstanding senior debentures.
However, the Company has adequate alternative financing resources available to
meet expected operating and capital requirements.
FEDERAL AND STATE REGULATORY MATTERS
FERC ORDER 636
FERC Order 636, issued in 1992, allows pipelines to recover 100 percent of all
prudently incurred costs resulting from the transition to the new rules
(transition costs). The FERC has identified four types of transition costs:
(1) purchased gas costs that would have been recovered from customers through
the purchased gas adjustment provisions of previous tariffs, but which are
unrecovered at the termination of "bundled" services; (2) gas supply
realignment (GSR) costs required to reform or terminate contracts to purchase
gas from producers; (3) stranded costs, which are the cost of facilities or
transportation arrangements no longer necessary or uneconomic after
restructuring; and (4) the costs of installing new facilities that may be
required to comply with the new rules.
CNG Transmission received FERC approval to implement Order 636 effective
October 1, 1993, in accordance with the terms of a comprehensive stipulation
and agreement (Settlement) reached with customers and others. On July 29, 1994,
the FERC approved recovery, through a direct bill mechanism, of $9.8 million of
transition costs. These billings began August 1, 1994, subject to refund, and
are in addition to the $177.9 million of transition costs CNG Transmission
direct billed and began collecting in December 1993. In accordance with the
Settlement, CNG Transmission can seek recovery through March 1995 of additional
transition costs (unrecovered purchased gas and sales-related transportation
costs) incurred relating to transactions prior to October 1, 1993.
38
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
As part of the Settlement, CNG Transmission will absorb up to $3.5 million of
GSR costs. GSR costs, however, were minimized since certain of the Company's
distribution subsidiaries agreed to the assignment from CNG Transmission of its
Appalachian gas purchase contracts in consideration for favorable cost
allocation provisions contained in the Settlement. The distribution
subsidiaries should generally be able to pass through to their customers the
costs associated with the assigned contracts in recognition of the other
benefits received in the Settlement.
The full extent of stranded costs for CNG Transmission are unknown at this time.
In its December 31, 1993, general rate filing with the FERC, CNG Transmission
requested recovery of $9.2 million of stranded facilities costs, but
subsequently reduced that amount to $4.7 million to reflect actual amounts
incurred. In a December 30, 1994 filing, CNG Transmission requested recovery
of an additional $.7 million of stranded upstream transportation service costs.
The FERC approved recovery of these costs, subject to refund, on January 27,
1995.
Although a final overall estimate of new facilities costs to be incurred by CNG
Transmission has not yet been determined, such costs may approach $50 million.
The Settlement allows CNG Transmission to file with the FERC for rate increases
to recover both stranded costs and new facilities costs. The Settlement also
provides CNG Transmission additional rights to defer recognition of certain
stranded costs pending rate case review. Parties to the Settlement have also
agreed not to challenge certain construction projects that CNG Transmission may
determine will assist it in rendering unbundled services.
The Company's distribution subsidiaries have taken appropriate actions to adapt
to the new environment created by Order 636 and should generally be able to
recover transition costs passed through to them by their former pipeline
suppliers.
On July 14, 1994, the PUCO approved a stipulation and recommendation allowing
the recovery of transition costs by East Ohio Gas. Accordingly, East Ohio Gas
will recover the unrecovered gas cost portion of transition costs from its
tariff customers through the gas cost recovery (GCR) mechanism. Gas supply
realignment costs billed by the pipelines will be recovered by East Ohio Gas
from its sales customers, through the GCR mechanism, and from its transportation
customers, through a surcharge.
On July 22, 1994, Peoples Natural Gas began to recover, through a volumetric
surcharge, the non-gas cost related portion of Order 636 transition costs billed
by upstream pipeline companies. The surcharge is being adjusted on a quarterly
basis to reflect the level of transition costs billed by the pipelines and
transition cost recovery decisions made by the FERC. Peoples Natural Gas will
continue to recover gas cost related transition costs through its periodic GCR
filings.
Other portions of the Company's operations have also been affected by Order 636.
CNG Producing and CNG Energy Services are developing new marketing strategies
and contracts to address customer needs for intermediate and long-term gas
supplies as well as other services which will be required in this "post-Order
636" era.
Based on management's current estimates, the operating environment under Order
636 and any uncertainties pertaining to the recovery of transition costs should
not have a material adverse effect on the Company's financial position, results
of operations or cash flows. Reference is made to Note 2 to the consolidated
financial statements for additional information regarding Order 636 transition
costs.
39
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
CNG TRANSMISSION
On December 30, 1993, CNG Transmission filed a general rate filing with the FERC
requesting an annual revenue increase of $106.6 million. The rate increase
request, as revised, is intended to cover higher operating costs, increased
plant investment, and the recovery of transition costs related to stranded
facilities. The increase went into effect on July 1, 1994, subject to refund.
CNG Transmission is currently in settlement discussions with the FERC Staff and
intervenors concerning this case.
STATE REGULATORY ISSUES
On October 29, 1993, the Public Service Commission of West Virginia (PSC)
granted Hope Gas an indicated $1.9 million annual revenue increase effective
November 1, 1993. On March 30, 1994, the PSC issued an order on
reconsideration, resulting in an additional increase in annual revenues of $.3
million. The latter increase was effective March 30, 1994. The order reflects
a return on equity of 10.55 percent. In its filing, Hope Gas had requested an
$8.2 million annual revenue increase and a return on equity of 12.30 percent.
On July 21, 1994, the Pennsylvania Public Utility Commission (PA PUC) approved
a general rate increase of $7.5 million in annual revenues for Peoples Natural
Gas. The new rates became effective July 22, 1994. In its October 1993 filing,
Peoples Natural Gas had requested an annual revenue increase of $28.4 million.
On September 1, 1994, Virginia Natural Gas filed a general rate filing with the
Virginia State Corporation Commission requesting an annual revenue increase of
$9.9 million. The requested rate increase reflects additional plant investments
and higher operating and maintenance expenses. The new rates went into effect,
subject to refund, on October 1, 1994.
On November 3, 1994, the PUCO approved a proposed settlement of East Ohio Gas'
general rate case which will increase annual revenues by $68.6 million. Under
the settlement, new rates take effect in two phases: a $62.4 million revenue
increase began November 8, 1994, and an additional $6.2 million increase will
become effective November 8, 1995. The settlement reflects an imputed return
on equity of 12.15 percent. In its filing, East Ohio Gas had requested a $99.1
million annual revenue increase and a return on equity of 12.64 percent.
On December 2, 1994, the PA PUC approved a nongeneral rate case filed by Peoples
Natural Gas in June 1994. Approval of the filing enables Peoples Natural Gas to
recover postretirement benefits other than pensions on a prospective basis,
effective the date of approval.
On January 4, 1995, Hope Gas filed with the PSC for an $11.8 million annual
revenue increase. The rate increase request is intended to reflect higher costs
associated with the addition, repair and replacement of pipelines serving
customers. If approved, the new rates would become effective November 1, 1995.
On February 1, 1995, Peoples Natural Gas filed with the PA PUC a general rate
case seeking $32.8 million in additional annual revenues. The rate increase
request is intended to cover higher operating expenses and plant investment. If
approved, the new rates would become effective no later than November 2, 1995.
40
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
ENVIRONMENTAL MATTERS
The Company and its subsidiaries are subject to various federal, state and local
laws and regulations relating to the protection of the environment. These laws
and regulations govern both current and future operations and potentially extend
to plant sites formerly owned or operated by the Company and its subsidiaries,
or their predecessors.
The Company has taken a proactive position with respect to environmental
concerns. As part of normal business operations, subsidiaries periodically
monitor their properties and facilities to identify and resolve potential
environmental matters, and the Company conducts general environmental surveys on
a continuing basis at its operating facilities to monitor compliance with
environmental laws and regulations. As part of this process, voluntary surveys
at subsidiary sites have been conducted to determine the extent of any possible
soil contamination due to hazardous substances, such as mercury, and when
contamination has been discovered remediation efforts are undertaken. Further,
on August 16, 1990, CNG Transmission entered into a Consent Order and Agreement
with the Commonwealth of Pennsylvania Department of Environmental Resources
(DER) in which CNG Transmission has agreed with the DER's determination of
certain violations of the Pennsylvania Solid Waste Management Act, the
Pennsylvania Clean Streams Law and the rules and regulations promulgated
thereunder. No civil penalties have been assessed as of this date. Pursuant to
the Order and Agreement, CNG Transmission is performing sampling, testing and
analysis, and conducting a program of remediation at some of its Pennsylvania
facilities. Total remediation costs in connection with these sites and the
Order and Agreement are not expected to be material with respect to
Consolidated's financial position, results of operations or cash flows. Based
on current information, the Company has recognized a gross estimated liability
amounting to $20,552,000 at December 31, 1994, 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
$12,797,000 at December 31, 1994, is included in the Consolidated Balance Sheet
under the caption "Deferred charges and other assets." Also, uncontested claims
amounting to $3,735,000 at December 31, 1994, were recognized for
environmental-related costs probable for recovery through joint-interest
operating agreements.
The total charges to operating expenses for environmental-related costs were
$7,646,000, $9,049,000 and $4,228,000, respectively, for the years ended
December 31, 1992 through 1994. Reference is made to Note 15 to the
consolidated financial statements for the components of these expenses.
Environmental-related capital expenditures for monitoring or complying with laws
and regulations were not material in 1992 or 1993.
CNG Transmission and certain of the Company's distribution subsidiaries are
subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments of
1990 (1990 amendments) which added significantly to the existing requirements
established by the Federal Clean Air Act. As a result of the 1990 amendments,
these subsidiaries are required to install Reasonably Available Control
Technology (RACT) at some compressor stations to reduce nitrogen oxide
emissions. The subsidiaries will have until May 31, 1995, to comply with the
requirement to install RACT. Compliance requires capital expenditures to
similarly retrofit some of the compressor engines along the Company's pipeline
system. In this regard, approximately $23.3 million was expended during 1994 to
install emission control equipment. In addition, up to $17 million is expected
to be expended in 1995 to complete installation of emission control equipment.
The Company anticipates completing the installation of emission controls by the
May 31, 1995 deadline required in the 1990 amendments. While the Company
believes that it will be in compliance with the 1990 amendments, additional
compliance requirements which may be imposed by state regulation could require
additional capital expenditures. In any event, the total actual capital
expenditures required to comply with the 1990 amendments are expected to be
recoverable through future regulatory proceedings.
41
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Consolidated has determined that it is associated with 16 former manufactured
gas plant sites, five of which are currently owned by subsidiaries. Studies
conducted by other utilities at their former manufactured gas plants have
indicated that their sites contain coal tar and other potentially harmful
materials. None of the 16 former sites with which Consolidated 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.
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 and its subsidiaries may encounter in
the future cannot be predicted. Additional environmental liabilities may result
in the future as more stringent environmental laws and regulations are
implemented and as the Company obtains more specific information about its
existing sites and production facilities. At present, no estimate of any such
additional liability, or range of liability amounts, can be made. However, the
amount of any such liabilities could be material.
EFFECTS OF INFLATION
Although inflation rates have been moderate, any change in price levels has an
effect on operating results due to the capital intensive and regulated nature of
Consolidated's major business components. Consolidated attempts to minimize the
effects of inflation through cost control, productivity improvements and
regulatory actions where appropriate.
For the Company's rate-regulated subsidiaries, increases in operating costs are
not generally subject to immediate recovery due to the time lag inherent in the
rate-making process. Also, only the historical cost of property, plant and
equipment is recoverable in revenues through depreciation. While the
rate-making process gives no recognition to the current cost of replacing
properties, Consolidated believes, based on past regulatory practices, that it
will be allowed to earn a return on the increased cost of its property
investment as replacement occurs.
For the exploration and production operations, gas and oil prices are based on
market supply and demand rather than the level of costs. Therefore,
Consolidated's exploration and production operations focus on balancing
production and sales levels with operating costs to minimize the effects of
inflation.
FINANCIAL CONDITION
DIVIDEND AND COMMON STOCK MATTERS
In December 1994, 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 1994 were $180.4 million compared with $178.1 million in 1993 and $168.5
million in 1992.
During 1994, a total of 24,614 original issue shares were issued through various
Company-sponsored plans, including 7,668 shares acquired by employees through
the exercise of outstanding stock options. A total of 70,276 shares were issued
during the year upon conversion of $3,795,000 principal amount of the Company's
7 1/4% Convertible Subordinated Debentures.
42
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Continued)
Under the Company's stock repurchase plan, up to 4 million shares of the
outstanding common stock can be repurchased through December 31, 1995. The
shares may be purchased in the open market from time-to-time, depending on
market conditions. The Company may also acquire shares of its common stock
through certain provisions of the 1991 Stock Incentive Plan and the Long-Term
Incentive Plan. The shares repurchased or acquired are held as treasury stock
and are available for reissuance for general corporate purposes or in connection
with various employee benefit plans. No treasury shares were held by the
Company at December 31, 1993. During 1994, no open market purchases were made
by the Company. The Company acquired 6,141 shares in 1994 through the
provisions of its incentive plans at a cost of $257,000, or an average price of
$41.85 a share. All of these shares were sold before year-end to the System's
Thrift Plans.
CAPITAL SPENDING
The current capital budget for 1995 is estimated at $444.6 million, a 2 percent
increase compared with total capital spending in 1994. The estimated 1995
budget has been allocated as follows: distribution, $164.8 million;
transmission, $91.0 million; exploration and production, $170.2 million; and
other, $18.6 million. The higher total level of capital expenditures
anticipated for 1995 reflects increased spending for exploration and production
operations, including funds for development of Viosca Knoll 826 and Popeye, two
deep-water projects in the Gulf of Mexico. Transmission and distribution
operations expenditures will primarily be for enhancements and improvements in
the pipeline network and related facilities. The "Other" category includes
expenditures to upgrade information systems technology at CNG Energy Services.
Although the Company plans to increase spending in 1995 for its exploration and
production operations, it will continue to monitor its investment in these
operations in light of changing market conditions.
Funds required for the capital spending program, as well as for other general
corporate purposes and possible asset acquisitions, are expected to be obtained
principally from internal cash generation. Although the Company does not expect
to require long-term financing in 1995 to support capital spending, it may turn
to the market to take advantage of other opportunities and to have more
financial flexibility.
CAPITAL RESOURCES AND LIQUIDITY
Because of the seasonal nature of the regulated subsidiaries' heating business,
a substantial portion of the Company's cash receipts are obtained in the first
half of the year. However, cash requirements for capital expenditures,
dividends, long-term debt retirement and working capital do not track this
pattern of cash receipts. Consequently, additional cash needs are satisfied
through the sale of short-term commercial paper notes or by the issuance of
long-term debt. As shown in the Consolidated Statement of Cash Flows, net cash
provided by operating activities was $631.3 million, $470.9 million and $405.4
million for the years 1994, 1993 and 1992, respectively. Higher rates put into
effect at CNG Transmission during the year and the recovery of Order 636
transition costs contributed to the increase in operating cash flows in 1994.
Higher gas sales and transportation revenues in 1993 and refunds made to
customers in 1992 amounting to $63 million in connection with the final
settlement of a CNG Transmission rate case were the primary factors for the
increase in net operating cash flows in 1993 compared with 1992.
43
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (Concluded)
During 1993, the Company retired $279,650,000 principal amount of its
debentures, of which $266,150,000 represents debentures called at the option of
the Company. The Company used short-term borrowings and internally-generated
funds to redeem an aggregate of $118,150,000 of debentures in May and June of
1993. On August 16, 1993, an additional $148,000,000 of debentures were
redeemed. On August 24, 1993, the Company sold $150 million of 5 3/4%
debentures, using the net proceeds from the sale, along with available funds, to
repay short-term debt incurred in connection with the August 16 redemption.
Also, in December 1993, the Company sold $150 million of 6 5/8% debentures. The
net proceeds from this sale were used to repay short-term borrowings in
connection with the May and June redemptions and to finance capital
expenditures.
The Company has shelf registrations with the SEC for the sale of up to $500
million of debt securities. The amount and timing of any future sale of these
debt securities will depend on the ability of the Company to issue senior debt
under the financing restrictions contained in the Company's indenture and credit
agreement, capital requirements, including financing necessary to enable
Consolidated to pursue asset acquisition opportunities, and financial market
conditions.
At December 31, 1994, the Company had a $300 million credit agreement with a
group of banks. At various times during 1994, the Company utilized borrowings
under this agreement primarily to provide temporary financing for capital
expenditures. The maximum amount outstanding at any one time during 1994 was
$150 million. There were no amounts outstanding under this credit agreement at
December 31, 1994 or 1993.
The Company's embedded long-term debt cost, excluding current maturities, at
year-end 1994 was 7.74 percent, compared with 7.75 percent for 1993 and 8.18
percent for 1992. The long-term debt to capitalization ratio was 34.5 percent
at the end of 1994, and 34.7 percent and 34.3 percent at year-end 1993 and 1992,
respectively. Under the provisions of the indenture covering the Company's
outstanding senior debenture issues, the ratio cannot exceed 60 percent. The
Company's senior debentures are rated A1 by Moody's Investors Service, AA- by
Standard & Poor's, AA- by Duff and Phelps, and AA by Fitch Investors Service.
The Company utilizes short-term borrowings to finance gas inventories and other
working capital requirements. Funds from the sale of commercial paper notes
were used for these purposes in 1994, of which $440 million was outstanding at
year-end. Bank lines of credit amounting to $475 million are available to
provide backup if the sale of commercial paper notes is not feasible. In
addition to these credit lines, the Company may utilize unused portions of its
credit agreement to provide support for commercial paper notes.
SUMMARY OF FINANCIAL DATA
The Company's Summary of Financial Data is on page 26.
44
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
SUPPLEMENTARY DATA
This information is included in the Notes to Consolidated Financial Statements
and reference is made thereto as follows: Gas and Oil Producing Activities --
Note 18(A), page 72; Quarterly Financial Data -- Note 18(B), page 76.
FINANCIAL STATEMENTS
INDEX
______________________________________________________________________________
Page
______________________________________________________________________________
Report of Independent Accountants. . . . . . . . . . . . 46
Consolidated Statement of Income for the Years 1992 through 1994 . 47
Consolidated Balance Sheet at December 31, 1993 and 1994 . . . . 48
Consolidated Statement of Cash Flows for the Years 1992 through 1994 50
Notes to Consolidated Financial Statements. . . . . . . . . 51
Schedule II - Valuation and Qualifying Accounts . . . . . . . Note 2
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.
______________________________________________________________________________
45
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (Continued)
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of
Consolidated Natural Gas Company
In our opinion, the consolidated financial statements listed in the
accompanying index on page 45 present fairly, in all material respects, the
financial position of Consolidated Natural Gas Company and subsidiaries (the
Company) at December 31, 1994 and 1993, and the results of their operations and
their cash flows for each of the three years in the period ended December 31,
1994, in conformity with generally accepted accounting principles. These
financial statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for the
opinion expressed above.
As discussed in Note 1 to these consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," and Statement of
Financial Accounting Standards No. 109, "Accounting for Income Taxes," in 1993.
PRICE WATERHOUSE LLP
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
February 21, 1995
46
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
________________________________________________________________________________
______________________________________
For the Years Ended December 31,
1994 1993* 1992*
________________________________________________________________________________
______________________________________
(Thousands of Dollars)
<S>
<C> <C> <C>
OPERATING REVENUES
Regulated gas sales. . . . . . . . . . . . . . . . . .
$1,679,235 $2,073,187 $1,669,519
Nonregulated gas sales. . . . . . . . . . . . . . . . .
723,626 541,849 282,026
__________ __________ __________
Total gas sales. . . . . . . . . . . . . . . . . .
2,402,861 2,615,036 1,951,545
Gas transportation and storage . . . . . . . . . . . . . .
409,632 333,332 307,467
Other . . . . . . . . . . . . . . . . . . . . . .
223,535 235,717 261,838
__________ __________ __________
Total operating revenues (Note 2). . . . . . . . . . . .
3,036,028 3,184,085 2,520,850
__________ __________ __________
OPERATING EXPENSES
Purchased gas. . . . . . . . . . . . . . . . . . . .
1,424,020 1,594,373 990,604
Transport capacity and other purchased products . . . . . . . .
107,094 79,001 73,001
Operation expense . . . . . . . . . . . . . . . . . .
600,421 590,459 578,697
Maintenance . . . . . . . . . . . . . . . . . . . .
89,154 87,207 79,128
Depreciation and amortization (Note 3) . . . . . . . . . . .
279,317 294,648 287,840
Taxes, other than income taxes . . . . . . . . . . . . . .
192,617 181,053 169,315
__________ __________ __________
Subtotal . . . . . . . . . . . . . . . . . . . .
2,692,623 2,826,741 2,178,585
__________ __________ __________
Operating income before income taxes. . . . . . . . . . .
343,405 357,344 342,265
Income taxes (Note 6) . . . . . . . . . . . . . . . . .
82,427 99,906 68,623
__________ __________ __________
Operating income . . . . . . . . . . . . . . . . .
260,978 257,438 273,642
__________ __________ __________
OTHER INCOME
Interest revenues . . . . . . . . . . . . . . . . . .
5,006 3,317 1,801
Other-net . . . . . . . . . . . . . . . . . . . . .
4,688 7,214 2,948
__________ __________ __________
Total other income. . . . . . . . . . . . . . . . .
9,694 10,531 4,749
__________ __________ __________
Income before interest charges. . . . . . . . . . . . .
270,672 267,969 278,391
__________ __________ __________
INTEREST CHARGES
Interest on long-term debt . . . . . . . . . . . . . . .
88,788 85,265 93,594
Other interest expense. . . . . . . . . . . . . . . . .
7,992 4,995 7,170
Allowance for funds used during construction . . . . . . . . .
(9,279) (10,785) (17,331)
__________ __________ __________
Total interest charges . . . . . . . . . . . . . . .
87,501 79,475 83,433
__________ __________ __________
Income before cumulative effect of change
in accounting principle. . . . . . . . . . . . . . . .
183,171 188,494 194,958
Cumulative effect of applying SFAS No. 109 (Note 6) . . . . . . .
- 17,422 -
__________ __________ __________
NET INCOME. . . . . . . . . . . . . . . . . . . . .
$ 183,171 $ 205,916 $ 194,958
========== ========== ==========
Earnings per share of common stock
Income before cumulative effect of change
in accounting principle. . . . . . . . . . . . . .
$1.97 $2.03 $2.19
Cumulative effect of applying SFAS No. 109 (Note 6) . . . . .
- .19 -
_____ _____ _____
Net Income. . . . . . . . . . . . . . . . . . .
$1.97 $2.22 $2.19
===== ===== =====
Average common shares outstanding (thousands). . . . . . . .
93,000 92,808 89,128
________________________________________________________________________________
______________________________________
*Certain amounts reclassified for comparative purposes.
The Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
47
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
________________________________________________________________________________
_________________________
At December 31,
1994 1993*
________________________________________________________________________________
_________________________
(Thousands of Dollars)
<S>
<C> <C>
ASSETS
PROPERTY, PLANT AND EQUIPMENT (Note 3)
Gas utility and other plant . . . . . . . . . . . . . . $
4,546,753 $ 4,362,996
Accumulated depreciation and amortization . . . . . . . . .
(1,686,788) (1,607,606)
___________ ___________
Net gas utility and other plant. . . . . . . . . . .
2,859,965 2,755,390
___________ ___________
Exploration and production properties. . . . . . . . . . .
3,130,203 2,983,032
Accumulated depreciation and amortization . . . . . . . . .
(1,963,522) (1,822,154)
___________ ___________
Net exploration and production properties . . . . . . .
1,166,681 1,160,878
___________ ___________
Net property, plant and equipment . . . . . . . . . .
4,026,646 3,916,268
___________ ___________
CURRENT ASSETS
Cash and temporary cash investments . . . . . . . . . . .
31,923 27,122
Accounts receivable
Customers . . . . . . . . . . . . . . . . . . .
407,145 461,108
Unbilled revenues and other . . . . . . . . . . . . .
146,653 176,005
Allowance for doubtful accounts . . . . . . . . . . . .
(7,507) (7,640)
Inventories, at cost
Gas stored - current portion (LIFO method) (Note 7) . . . . .
190,196 140,848
Materials and supplies (average cost method). . . . . . . .
35,072 38,784
Unrecovered gas costs (Note 2) . . . . . . . . . . . . .
13,135 18,602
Deferred income taxes - current (Note 6). . . . . . . . . .
60,103 23,685
Prepayments and other current assets . . . . . . . . . . .
188,019 192,212
___________ ___________
Total current assets . . . . . . . . . . . . . .
1,064,739 1,070,726
___________ ___________
REGULATORY AND OTHER ASSETS (Note 8)
Unamortized abandoned facilities . . . . . . . . . . . .
40,955 52,676
Other investments . . . . . . . . . . . . . . . . .
54,682 39,600
Deferred charges and other assets (Notes 2, 5, 6 and 15) . . . .
331,651 357,918
___________ ___________
Total regulatory and other assets . . . . . . . . . .
427,288 450,194
___________ ___________
Total assets . . . . . . . . . . . . . . . . . $
5,518,673 $ 5,437,188
=========== ===========
________________________________________________________________________________
_________________________
*Certain amounts reclassified for comparative purposes.
The Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
48
<PAGE>
ITEM 8.
(Cont.)
<TABLE>
<CAPTION>
________________________________________________________________________________
_________________________
At December 31,
1994 1993*
________________________________________________________________________________
_________________________
(Thousands of Dollars)
<S>
<C> <C>
STOCKHOLDERS' EQUITY AND LIABILITIES
CAPITALIZATION
Common stockholders' equity (Note 9)
Common stock, par value $2.75 per share,
200,000,000 authorized shares
Issued, 1994 - 93,027,847 shares, 1993 - 92,933,828 shares . . $
255,827 $ 255,568
Capital in excess of par value . . . . . . . . . . . .
458,628 454,081
Retained earnings (Note 11) . . . . . . . . . . . . .
1,469,879 1,466,783
___________ ___________
Total common stockholders' equity . . . . . . . . . .
2,184,334 2,176,432
Long-term debt (Note 12) . . . . . . . . . . . . . . .
1,151,973 1,158,648
___________ ___________
Total capitalization . . . . . . . . . . . . . .
3,336,307 3,335,080
___________ ___________
CURRENT LIABILITIES
Current maturities on long-term debt . . . . . . . . . . .
4,000 -
Commercial paper (Note 13) . . . . . . . . . . . . . .
440,000 455,000
Accounts payable. . . . . . . . . . . . . . . . . .
357,611 345,126
Estimated rate contingencies and refunds (Note 2). . . . . . .
83,404 57,456
Amounts payable to customers. . . . . . . . . . . . . .
96,140 27,602
Taxes accrued. . . . . . . . . . . . . . . . . . .
94,413 112,098
Dividends declared . . . . . . . . . . . . . . . . .
45,119 45,073
Other current liabilities. . . . . . . . . . . . . . .
90,061 98,145
___________ ___________
Total current liabilities. . . . . . . . . . . . .
1,210,748 1,140,500
___________ ___________
DEFERRED CREDITS
Deferred income taxes (Note 6) . . . . . . . . . . . . .
758,633 783,511
Accumulated deferred investment tax credits. . . . . . . . .
33,229 35,849
Deferred credits and other liabilities (Note 6) . . . . . . .
179,756 142,248
___________ ___________
Total deferred credits. . . . . . . . . . . . . .
971,618 961,608
___________ ___________
COMMITMENTS AND CONTINGENCIES (Note 16)
___________ ___________
Total stockholders' equity and liabilities . . . . . . . $
5,518,673 $ 5,437,188
=========== ===========
________________________________________________________________________________
_________________________
</TABLE>
49
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
________________________________________________________________________________
______________________________________
For the Years Ended December 31,
1994 1993 1992
________________________________________________________________________________
______________________________________
(Thousands of Dollars)
<S>
<C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income. . . . . . . . . . . . . . . . . . . .
$ 183,171 $ 205,916 $ 194,958
Adjustments to reconcile net income to net cash
provided by operating activities
Cumulative effect of applying SFAS No. 109. . . . . . . .
- (17,422) -
Depreciation and amortization . . . . . . . . . . . .
279,317 294,648 287,840
Deferred income taxes-net . . . . . . . . . . . . .
(60,744) (19,782) 47,470
Investment tax credit. . . . . . . . . . . . . . .
(2,567) (2,620) (2,691)
Changes in current assets and current liabilities
Accounts receivable-net . . . . . . . . . . . . .
81,896 (107,292) 1,034
Inventories . . . . . . . . . . . . . . . . .
(48,566) (22,212) 20,977
Unrecovered gas costs . . . . . . . . . . . . . .
5,467 249,549 (91,805)
Accounts payable. . . . . . . . . . . . . . . .
11,198 13,831 (31,168)
Estimated rate contingencies and refunds. . . . . . . .
25,948 (21,930) (32,704)
Amounts payable to customers. . . . . . . . . . . .
68,538 24,393 (30,964)
Taxes accrued. . . . . . . . . . . . . . . . .
(17,685) 16,909 (1,285)
Other-net . . . . . . . . . . . . . . . . . .
(2,901) (5,022) 14,566
Changes in other assets and other liabilities. . . . . . .
108,219 (137,571) 28,879
Other-net. . . . . . . . . . . . . . . . . . .
37 (446) 250
_________ _________ _________
Net cash provided by operating activities . . . . . . .
631,328 470,949 405,357
_________ _________ _________
CASH FLOWS USED IN INVESTING ACTIVITIES
Plant construction and other property additions . . . . . . .
(416,051) (333,056) (437,375)
Proceeds from dispositions of property,
plant and equipment-net. . . . . . . . . . . . . . .
164 4,716 18,148
Cost of other investments-net . . . . . . . . . . . . .
(14,902) (567) (1,949)
_________ _________ _________
Net cash used in investing activities. . . . . . . . .
(430,789) (328,907) (421,176)
_________ _________ _________
CASH FLOWS PROVIDED BY (OR USED IN) FINANCING ACTIVITIES
Issuance of common stock . . . . . . . . . . . . . . .
279 13,066 207,158
Issuance of debentures. . . . . . . . . . . . . . . .
- 295,098 148,175
Purchase of debentures. . . . . . . . . . . . . . . .
- (283,208) (134,918)
Credit agreement borrowings (or repayments)-net . . . . . . .
- - (66,000)
Commercial paper borrowings (or repayments)-net . . . . . . .
(15,601) (5,015) 38,181
Dividends paid . . . . . . . . . . . . . . . . . .
(180,415) (178,125) (168,524)
Other-net . . . . . . . . . . . . . . . . . . . .
(1) (91) 10,092
_________ _________ _________
Net cash provided by (or used in) financing activities . . .
(195,738) (158,275) 34,164
_________ _________ _________
Net increase (or decrease) in cash and
temporary cash investments. . . . . . . . . . . .
4,801 (16,233) 18,345
CASH AND TEMPORARY CASH INVESTMENTS AT JANUARY 1 . . . . . . .
27,122 43,355 25,010
_________ _________ _________
CASH AND TEMPORARY CASH INVESTMENTS AT DECEMBER 31 . . . . . .
$ 31,923 $ 27,122 $ 43,355
========= ========= =========
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid for
Interest (net of amounts capitalized) . . . . . . . . . .
$ 91,011 $ 92,880 $ 96,029
Income taxes (net of refunds). . . . . . . . . . . . .
$ 154,860 $ 109,998 $ 35,238
Non-cash financing activities
Conversion of 7 1/4% Convertible Subordinated Debentures. . . .
$ 3,795 $ - $ -
________________________________________________________________________________
______________________________________
The Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
50
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Methods of allocating costs to accounting periods by the subsidiary companies
subject to federal or state accounting and rate regulation may differ from
methods generally applied by nonregulated companies. However, when the
accounting allocations prescribed by regulatory authorities are used for
ratemaking, the economic effects thereof determine the application of
generally accepted accounting principles. Significant accounting policies of
Consolidated Natural Gas Company (the Company) and subsidiaries within this
framework are summarized in this Note.
PRINCIPLES OF CONSOLIDATION
The Company owns all of the capital stock of its subsidiaries. The
consolidated financial statements represent the accounts of the Company and
its subsidiaries after the elimination of intercompany transactions.
The subsidiary companies follow the equity method of accounting for
investments in partnerships and corporate joint ventures when the subsidiary
is able to influence the financial and operating policies of the investee.
For such investments where the subsidiary is not able to influence the
business policies of the investee, the cost method is applied.
REVENUE RECOGNITION
Revenues from gas sales and transportation services are recognized in the same
period in which the related gas volumes are delivered to customers. The
subsidiaries bill and recognize sales revenues from residential and certain
commercial and industrial customers on the basis of scheduled meter readings.
In addition, revenues are recorded for estimated deliveries of gas to these
customers from the meter reading date to the end of the accounting period.
For wholesale and other commercial and industrial customers, revenues are
based upon actual deliveries of gas to the end of the period.
UNRECOVERED GAS COSTS
Where permitted by regulatory authorities, the subsidiaries defer the
difference between certain gas costs incurred, including transition costs
under Federal Energy Regulatory Commission (FERC) Order 636 and transportation
costs, and the amount of such costs included in current rates. Such
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 such costs are recovered through adjusted rates.
HEDGING AND OTHER ENERGY PRICE MANAGEMENT ACTIVITIES
The nonregulated subsidiaries utilize natural gas and crude oil futures
contracts to hedge a portion of their transactions against the risk of market
price fluctuations. Gains and losses on these contracts are deferred and
subsequently recognized in the period the related hedged transaction occurs.
Cash flows from hedging transactions are reported in the Consolidated
Statement of Cash Flows as an operating activity -- consistent with the
category of the cash flows from the transaction being hedged.
In October 1994, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 119, "Disclosure about
Derivative Financial Instruments and Fair Value of Financial Instruments."
The standard requires certain disclosures about derivative financial
instruments but does not affect the financial accounting for derivatives.
Reference is made to Note 14 for the disclosures required under SFAS No. 119.
51
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
GAS UTILITY AND OTHER PLANT
The property, plant and equipment accounts are stated at the cost incurred or,
where required by regulatory authorities, "original cost." Additions and
betterments are charged to the property accounts at cost. Upon normal
retirement of a plant asset, its cost is charged to accumulated depreciation
together with costs of removal less salvage. The costs of maintenance,
repairs and replacing minor items are charged principally to expense as
incurred.
EXPLORATION AND PRODUCTION PROPERTIES
CNG Producing and CNG Transmission follow the full cost method of accounting
for gas and oil producing activities prescribed by the Securities and Exchange
Commission (SEC). Under the full cost method, all costs directly associated
with property acquisition, exploration, and development activities are
capitalized, with the principal limitation that such amounts not exceed the
present value of estimated future net revenues to be derived from the
production of proved gas and oil reserves.
The gas and oil producing activities of the distribution subsidiaries are
subject to cost-of-service rate regulation and are exempt from the accounting
methods prescribed by the SEC.
DEPRECIATION AND AMORTIZATION
Depreciation and amortization are recorded over the estimated service lives of
plant assets by application of the straight-line method or, in the case of gas
and oil producing properties, the unit-of-production method.
Under the full cost method of accounting, amortization is also accrued on
estimated future costs to be incurred in developing proved gas and oil
reserves, and on estimated dismantlement and abandonment costs net of
projected salvage values. However, the costs of investments in unproved
properties and major development projects are excluded from amortization until
it is determined whether or not proved reserves are attributable to such
properties.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION
The subsidiaries subject to cost-of-service rate regulation capitalize the
estimated costs of equity funds and/or borrowed funds used during the
construction of major projects. Under regulatory practices, those companies
are permitted to include the costs capitalized in rate base for rate-making
purposes when the completed facilities are placed in service. The remaining
subsidiaries capitalize interest costs as part of the cost of acquiring
certain assets. Generally, interest is capitalized on unproved properties and
major construction and development projects on which amortization is not yet
being 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: 1992 - 3 7/8% to 9 1/4%; 1993 - 3 1/4% to 8 7/8%
and 1994 - 3 3/8% to 8 1/4%. There were no equity funds capitalized in those
years.
INCOME TAXES
The current provision for income taxes represents amounts paid or currently
payable. Investment tax credits which were deferred where required by
regulatory authorities are being amortized as credits to income over the
estimated service lives of the related properties.
Effective January 1, 1993, the Company adopted the provisions of SFAS No. 109,
"Accounting for Income Taxes." The adoption of SFAS No. 109 changed the
Company's method of accounting for income taxes from the deferred method to an
asset and liability approach. The cumulative effect of this accounting change
increased 1993 net income by $17,422,000, or $.19 per share, resulting
primarily from the reduction in deferred income tax balances associated with
the Company's nonregulated activities.
52
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
PENSION AND OTHER BENEFIT PROGRAMS
PENSION PROGRAM
The subsidiaries have qualified noncontributory defined benefit pension plans
covering all employees. Benefits payable under the plans are based primarily
on each employee's years of service, age and base salary during the five years
prior to retirement. Net pension costs are determined by an independent
actuary, and the plans are funded on an annual basis to the extent such
funding is deductible under federal income tax regulations. Plan assets
consist primarily of equity securities, fixed income securities and insurance
contracts. The pension program also includes the payment of supplemental
pension benefits to certain retirees depending on retirement dates.
As required by SFAS No. 87, "Employers' Accounting for Pensions," Consolidated
has recognized a liability for the unfunded accumulated benefit obligation
relating to its supplemental pension benefit plans. An amount equal to the
liability, less a required reduction in common stockholders' equity, net of
applicable deferred taxes, has also been recognized as an intangible asset.
Such amounts recognized are subject to future revision based on both changes
in assumptions and changes in the financial status of the supplemental pension
benefit plans.
OTHER POSTRETIREMENT BENEFITS
In addition to pension plans, the subsidiaries sponsor defined benefit
postretirement plans covering both salaried and hourly employees and certain
dependents. The plans provide medical benefits as well as life insurance
coverage. These benefits are provided through insurance companies and other
providers with the annual cash outlays based on the claim experience of the
related plans.
Employees who retire from System companies on or after attaining age 55 and
having rendered at least 15 years of service, or employees retiring on or
after attaining age 65, are eligible to receive benefits under the plans. The
plans are both contributory and noncontributory, depending on age, retirement
date, the plan elected by the employee, and whether the employee is covered
under a collective bargaining agreement. Most of the medical plans contain
cost-sharing features such as deductibles and coinsurance. For certain of the
contributory medical plans, retiree contributions are adjusted annually.
Effective January 1, 1993, Consolidated adopted the provisions of SFAS No.
106, "Employers' Accounting for Postretirement Benefits Other Than Pensions."
Statement No. 106 requires that the estimated future costs of providing
postretirement benefits be recognized as an expense and a liability during the
employees' service periods. As permitted under the standard, the Company
elected to amortize the accumulated postretirement benefit obligation existing
at the date of adoption (transition obligation) over a 20-year period. Prior
to 1993, amounts paid for postretirement benefits were recognized as an
expense in the period paid.
POSTEMPLOYMENT BENEFITS
Effective January 1, 1994, the Company adopted the provisions of SFAS No. 112,
"Employers' Accounting for Postemployment Benefits." This Statement covers
benefits such as salary continuation, severance pay and disability-related
benefits provided to inactive and former employees prior to retirement. The
standard requires the accrual of a liability for the postemployment benefit
obligations if certain specified conditions are met. The adoption of this
standard did not have a material effect on Consolidated's financial position,
results of operations or cash flows.
53
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
ENVIRONMENTAL EXPENDITURES
Environmental-related expenditures associated with current operations are
generally expensed as incurred. Expenditures for the assessment and/or
remediation of environmental conditions related to past operations are charged
to expense or are deferred pending probable recovery. In this connection, a
liability is recognized when the assessment or remediation effort is probable
and the future costs are estimable. Estimated future costs for the
abandonment and restoration of gas and oil properties are accrued currently
through charges to depreciation.
Claims for recovery of environmental-related costs from insurance carriers and
other third parties or through regulatory procedures are recognized separately
as assets when future recovery is deemed probable.
GAINS AND LOSSES ON REACQUISITION OF DEBT
Gains and losses (including redemption premiums) on the purchase or redemption
of the Company's debentures are generally deferred and then included in income
over the original lives of the applicable debenture issues to give recognition
to the economic effect of the rate-making process on certain subsidiaries.
The portion not deferred is recognized in the period of the transaction.
EARNINGS PER SHARE
Earnings per share of common stock is computed based on the weighted average
number of common shares outstanding during the period. Under the methods
prescribed by generally accepted accounting principles, the assumed exercise
of outstanding stock options is not considered to have a dilutive effect on
earnings per share. Also, the conversion of the Company's outstanding
convertible subordinated debentures has not been assumed in determining
earnings per share since such conversion would be antidilutive.
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.
54
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2. RATE MATTERS
Certain increases in prices by subsidiaries and other rate-making issues are
subject to final modification in regulatory proceedings. The related
accumulated provisions pertaining to these matters were $17,777,000 and
$52,210,000 at December 31, 1993 and 1994, including interest. These amounts
are reported in the Consolidated Balance Sheet under "Estimated rate
contingencies and refunds" together with $39,679,000 and $31,194,000,
respectively, which are primarily refunds received from suppliers and
refundable to customers under regulatory procedures.
As approved by the FERC, CNG Transmission has billed its customers, including
certain affiliates, an aggregate of $187.7 million, representing unrecovered
purchased gas costs and unrecovered sales-related transportation costs,
resulting from its transition to restructured services under FERC Order 636.
Of the total amount billed by CNG Transmission to the distribution
subsidiaries, $52,277,000 is included in the Consolidated Balance Sheet at
December 31, 1994, under "Deferred charges and other assets," representing
remaining amounts to be recovered from their customers.
The Company's distribution subsidiaries have incurred or are expected to incur
obligations to upstream pipeline companies, including additional billings from
CNG Transmission, for transition costs under FERC Order 636. The total
estimated liability for such costs was $81,592,000 and $69,451,000 at December
31, 1993 and 1994, respectively. Additional amounts are likely to be accrued
in the future once these pipeline companies receive final FERC approval to
recover their remaining transition costs. Based on management's current
estimates, the distribution subsidiaries' portion of such additional costs
could be in the range of $40 million.
Based on regulatory actions in two jurisdictions and the past rate-making
treatment of similar costs in the other jurisdictions, management believes
that the distribution subsidiaries should generally be able to pass through
all Order 636 transition costs to their customers.
3. PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION
Total provisions for depreciation of property, plant and equipment for the
years ended December 31, 1992 through 1994, including amounts charged to
accounts other than "Depreciation and amortization" in the Consolidated
Statement of Income, were equivalent to approximately 4.3%, 4.2% and 3.7%,
respectively, of the average capitalized investment subject to depreciation
and amortization in those periods.
Amortization of capitalized costs under the full cost method of accounting for
Consolidated's exploration and production operations amounted to $1.19 per
thousand cubic feet (Mcf) equivalent of gas and oil produced in 1992, $1.18 in
1993, and $1.15 in 1994.
Costs of unproved properties capitalized under the full cost method of
accounting that are excluded from amortization at December 31, 1994, and the
years in which such excluded costs were incurred, follow:
______________________________________________________________________________
DECEMBER 31, Incurred in Years Ended December 31,
1994 1994 1993 1992 Prior
______________________________________________________________________________
(In Thousands)
Property acquisition costs $ 26,337 $ 11,307 $ 5,667 $ 1,131 $ 8,232
Exploration costs . . . 34,015 16,644 6,036 5,761 5,574
Capitalized interest . . 32,210 1,146 2,033 2,257 26,774
________ ________ ________ ________ ________
Total . . . . . $ 92,562 $ 29,097 $ 13,736 $ 9,149 $ 40,580
======== ======== ======== ======== ========
______________________________________________________________________________
55
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
There are no significant properties, as defined by the SEC, excluded from
amortization at December 31, 1994. 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.
4. PENSION COSTS
Net pension costs, which were determined by an independent actuary and which
include the costs of defined benefit pension plans and pension supplements,
included the following components:
______________________________________________________________________________
Years Ended December 31, 1994 1993 1992
______________________________________________________________________________
(In Thousands)
Service cost - benefits earned during the period $ 28,509 $ 27,266 $ 26,435
Interest cost on projected benefit obligation . 59,006 56,834 54,748
Return on plan assets . . . . . . . . . (33,363) (89,441) (73,754)
Net amortization and deferral . . . . . . (60,228) (303) (9,926)
Special voluntary retirement programs. . . . 800 800 800
________ ________ ________
Net pension credits . . . . . . . . $ (5,276) $ (4,844) $ (1,697)
======== ======== ========
______________________________________________________________________________
In 1989, Peoples Natural Gas offered special retirement incentives to certain
salaried and hourly employees. The additional pension payments resulting from
these incentives are being paid from the assets of the applicable pension
plans. The estimated cost of these additional benefits, amounting to
approximately $8,000,000, was deferred and is being amortized to expense over
a 10-year period which began October 1, 1990, in accordance with the rate-
making treatment approved by the Pennsylvania Public Utility Commission.
The following table sets forth the funded status of the plans, as determined
by an independent actuary, at December 31, 1993 and 1994:
<TABLE>
<CAPTION>
________________________________________________________________________________
____________________
Plans Where Assets
Plans Where
Exceed Accumulated
Accumulated Benefits
Benefits
Exceed Assets
December 31, 1994 1993
1994 1993
________________________________________________________________________________
____________________
(In
Thousands)
<S> <C> <C>
<C> <C>
Actuarial present value of:
Vested benefit obligation . . . . . . $ 600,111 $ 656,308
$ 13,717 $ 15,728
========== ==========
======== ========
Accumulated benefit obligation . . . . $ 625,900 $ 683,559
$ 13,717 $ 15,728
========== ==========
======== ========
Projected benefit obligation . . . . . $ 832,431 $ 918,079
$ 13,717 $ 15,728
Plan assets at fair value. . . . . . . 1,178,505 1,190,909
- -
__________ __________
________ ________
Plan assets in excess of (or less than)
projected benefit obligation . . . . 346,074 272,830
(13,717) (15,728)
Unrecognized net loss (or gain). . . . . (242,721) (170,333)
1,901 2,495
Unrecognized net obligation (or asset) . . (86,620) (95,940)
1,970 3,780
Unrecognized prior service cost. . . . . 7,053 7,535
3,067 3,792
Recognition of minimum liability . . . . - -
(6,938) (10,067)
__________ __________
________ ________
Prepaid pension cost (or pension liability) $ 23,786 $ 14,092
$(13,717) $(15,728)
========== ==========
======== ========
________________________________________________________________________________
____________________
</TABLE>
56
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The projected benefit obligation at December 31, 1993 and 1994, was determined
using an annual discount rate of 6.5% 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 8.0% per annum.
The minimum liability recognized relating to the Company's supplemental
pension benefit plans was $10,067,000 and $6,938,000 at December 31, 1993 and
1994. The related intangible asset recognized as of those dates amounted to
$7,572,000 and $5,037,000, respectively. These amounts are included in the
Consolidated Balance Sheet under "Deferred credits and other liabilities" and
"Deferred charges and other assets." Adjustments of the minimum liability and
intangible asset due to changes in assumptions or the financial status of the
plans resulted in a credit to retained earnings of $361,000 and $386,000 at
December 31, 1993 and 1994, respectively.
5. OTHER POSTRETIREMENT BENEFITS
As described in Note 1, the Company adopted the provisions of SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions,"
effective January 1, 1993. As permitted under the standard, the Company
elected to amortize the accumulated postretirement benefit obligation existing
at the date of adoption (transition obligation) of $288,393,000 over a 20-year
period.
Net periodic postretirement benefit cost for the years ended December 31, 1993
and 1994, as determined by an independent actuary, included the following
components:
______________________________________________________________________________
Years Ended December 31, 1994 1993
______________________________________________________________________________
(In Thousands)
Service cost - benefits attributed to service
during the period. . . . . . . . . . . . $12,708 $10,549
Interest cost on accumulated postretirement
benefit obligation . . . . . . . . . . . 24,380 23,208
Return on plan assets . . . . . . . . . . . (28) -
Amortization of transition obligation. . . . . . 14,420 14,420
Net amortization and deferral . . . . . . . . 4 -
_______ _______
Net periodic postretirement benefit cost . . . . $51,484 $48,177
======= =======
______________________________________________________________________________
The following table reconciles the plans' combined funded status, as
determined by an independent actuary, with amounts included in the
Consolidated Balance Sheet at December 31, 1993 and 1994:
______________________________________________________________________________
December 31, 1994 1993
______________________________________________________________________________
(In Thousands)
Accumulated postretirement benefit obligation:
Retirees. . . . . . . . . . . . . . $ 208,685 $ 165,819
Fully eligible active plan participants . . . 41,433 58,465
Other active plan participants . . . . . . 85,757 102,900
_________ _________
Total accumulated postretirement benefit
obligation. . . . . . . . . . . . 335,875 327,184
Plan assets at fair value. . . . . . . . . 2,717 -
_________ _________
Accumulated postretirement benefit obligation
in excess of plan assets. . . . . . . . (333,158) (327,184)
Unrecognized prior service cost. . . . . . . (6,930) -
Unrecognized net loss . . . . . . . . . . 21,113 22,821
Unrecognized transition obligation. . . . . . 259,553 273,973
_________ _________
Accrued postretirement benefit liability . . . $ (59,422) $ (30,390)
========= =========
______________________________________________________________________________
57
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The weighted average discount rate used in determining the accumulated
postretirement benefit obligation at December 31, 1993 and 1994, was 7.25% and
8.25%, respectively. The average assumed annual rate of salary increase for
the applicable life insurance plans was 5.5%.
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation for the medical plans is 9.5% for 1995,
declining gradually to 5.5% 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, 1994, would be increased by $31.5 million. A 1% change would also
increase the aggregate of the service and interest cost components of net
periodic postretirement benefit cost for 1994 by $5.2 million.
The majority of the estimated postretirement benefit costs and the transition
obligation is attributable to Consolidated's rate-regulated subsidiaries.
Accordingly, these subsidiaries have obtained, or are seeking to obtain,
approval for rate relief from their respective regulatory commissions for the
increased level of expense resulting from the adoption of the standard. In
this regard, regulatory authorities having jurisdiction over the Company's
subsidiaries have indicated their intention to generally allow inclusion in
rates of postretirement benefit costs determined on an accrual basis, subject
to prudency and certain other conditions. As a result, the Company's rate-
regulated subsidiaries have generally deferred the differences between SFAS
No. 106 costs and amounts currently included in rates pending expected
recovery of Statement No. 106 costs and related deferrals in regulatory
proceedings. The amount of SFAS No. 106 costs deferred at December 31, 1993
and 1994, was $27,662,000 and $55,185,000, respectively, which is included in
the Consolidated Balance Sheet under "Deferred charges and other assets."
The FERC and certain state regulatory authorities have indicated that when
SFAS No. 106 costs are recovered in rates, amounts collected must be deposited
in irrevocable trust funds dedicated for the sole purpose of paying
postretirement benefits. In response to these requirements, two subsidiaries
began funding postretirement benefit costs via voluntary employees'
beneficiary associations (VEBAs) during 1994. No other subsidiary companies
prefund postretirement benefit costs, but rather pay claims as presented.
Prior to the adoption of SFAS No. 106, postretirement benefit costs were
expensed as paid. The cost of such benefits was $17,948,000 for the year
ended December 31, 1992.
58
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
6. INCOME TAXES
As detailed in Note 1, the Company adopted the provisions of SFAS No. 109,
"Accounting for Income Taxes," effective January 1, 1993. The cumulative
effect of this accounting change increased net income in 1993 by $17,422,000,
or $.19 per share, due primarily to the reduction in deferred tax balances
associated with the Company's nonregulated activities.
"Income taxes" in the Consolidated Statement of Income include the following:
______________________________________________________________________________
Years Ended December 31, 1994 1993 1992
______________________________________________________________________________
(In Thousands)
Current provision
Federal . . . . . . . . . . $126,362 $ 99,029 $18,378
State. . . . . . . . . . . 19,376 23,279 5,466
Deferred income taxes-net
Federal . . . . . . . . . . (50,443) (6,688) 35,941
State. . . . . . . . . . . (10,301) (13,094) 11,529
Investment tax credit . . . . . . (2,567) (2,620) (2,691)
________ ________ _______
Total. . . . . . . . . . . $ 82,427 $ 99,906 $68,623
======== ======== =======
______________________________________________________________________________
In August 1993, the federal corporate income tax rate was increased from 34%
to 35%, retroactive to January 1, 1993. As required by Statement No. 109,
existing deferred tax assets and liabilities were adjusted to reflect this
enacted tax rate change. As a result, deferred income tax expense was
increased in the third quarter of 1993 by $11,429,000, or $.12 per share. In
addition, income taxes based on pretax earnings for the year 1993 increased by
$2,692,000, or $.03 per share, because of the higher rate. The total
adjustment to the net deferred income tax liability included in the
Consolidated Balance Sheet as a result of the increase in the federal
corporate income tax rate amounted to $26,707,000.
Income taxes differed from the amounts shown in the next table that were
computed by applying the statutory federal income tax rate of 34% (1992) and
35% (1993 and 1994) to reported income before taxes. The reasons for the
differences follow:
______________________________________________________________________________
Years Ended December 31, 1994 1993 1992
______________________________________________________________________________
(In Thousands)
Income before taxes. . . . . . . $265,598 $288,400 $263,581
======== ======== ========
Computed "expected" tax expense. . . $ 92,959 $100,940 $ 89,618
Increases (or reductions) in tax
resulting from:
Production tax credit . . . . . (7,987) (8,435) (7,506)
Investment tax credit . . . . . (2,567) (2,620) (2,691)
Deferred tax reversals . . . . . - - (15,325)
State income taxes . . . . . . 5,899 6,620 11,217
Effect of increase in federal
corporate income tax rate
on deferred income taxes. . . . - 11,429 -
Miscellaneous . . . . . . . . (5,877) (8,028) (6,690)
________ ________ ________
Income taxes . . . . . . . $ 82,427 $ 99,906 $ 68,623
======== ======== ========
Effective tax rate . . . . . . 31.0% 34.6% 26.0%
______________________________________________________________________________
59
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The current and noncurrent deferred income taxes reported in the Consolidated
Balance Sheet at December 31, 1994, represent the net expected future tax
consequences attributable to temporary differences between the carrying
amounts of nontax assets and liabilities and their tax bases. These temporary
differences and the related tax effect were as follows:
______________________________________________________________________________
1994
Deferred income Deferred income
December 31, taxes taxes-current
______________________________________________________________________________
(In Thousands)
Deferred tax liabilities:
Excess of tax over book depreciation . . $444,310 $ -
Exploration and intangible well
drilling costs . . . . . . . . . 277,565 -
Allowance for funds used during
construction. . . . . . . . . . 41,086 -
FERC Order 636 transition costs . . . . 16,705 -
Unrecovered gas costs . . . . . . . - 4,227
Other. . . . . . . . . . . . . 76,607 -
________ ________
Total liabilities . . . . . . . . 856,273 4,227
________ ________
Deferred tax assets:
Tax basis step-up in connection with
acquisition of subsidiary . . . . . 20,751 -
Deferred investment tax credits . . . . 20,044 -
Overheads capitalized for tax purposes. . 12,330 -
Amounts payable to customers . . . . . - 35,809
Supplier and other refunds. . . . . . - 8,079
Other. . . . . . . . . . . . . 44,515 20,442
Valuation allowance . . . . . . . . - -
________ ________
Total assets. . . . . . . . . . 97,640 64,330
________ ________
Total deferred income taxes. . . . . $758,633 $(60,103)
======== ========
______________________________________________________________________________
A regulatory liability amounting to $62,574,000 has been recorded representing
the reduction to previously recorded deferred income taxes associated with
rate-regulated activities that are expected to be refundable to customers, net
of certain taxes collectible from customers. Also, a regulatory asset
corresponding to the recognition of additional deferred income taxes not
previously recorded because of past rate-making practices amounting to
$106,644,000 has been recorded at December 31, 1994. These regulatory amounts
are included in the Consolidated Balance Sheet under "Deferred credits and
other liabilities" and "Deferred charges and other assets," respectively.
7. GAS STORED
Based upon the average price of gas purchased during 1994, the current cost of
replacing the inventory of "Gas stored - current portion" exceeded the amount
stated on a LIFO basis by approximately $153,291,000 at December 31, 1994.
A portion of gas in underground storage used as a pressure base and for
operational balancing is included in "Property, Plant and Equipment" in the
amounts of $123,564,000 and $126,496,000 at December 31, 1993 and 1994,
respectively.
60
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
8. REGULATORY AND OTHER ASSETS
UNAMORTIZED ABANDONED FACILITIES
In 1988, Consolidated LNG received FERC approval for the abandonment of its
interest in liquefied natural gas facilities at Cove Point, Maryland. In
connection with the abandonment, Consolidated LNG recorded a deferred asset in
accordance with the provisions of SFAS No. 90, "Accounting for Abandonments
and Disallowances of Plant Costs." This deferred asset, which represents the
present value of allowable costs expected to be recovered, is being amortized
over the 10-year recovery period which began March 1, 1988, as prescribed in
the FERC order.
LAKEWOOD COGENERATION PROJECT
CNG Power (formerly CNG Energy) holds a 34% limited partnership interest in
Lakewood Cogeneration, L.P. (Lakewood Partnership), a partnership formed to
construct, own and operate a cogeneration facility in Lakewood, New Jersey.
CNG Lakewood, Inc., a wholly owned subsidiary of CNG Power Services, owns a 1%
general partnership interest in the Lakewood Partnership. This facility began
commercial operations in November 1994 and uses natural gas to produce
electricity for sale to an electric utility and steam for sale primarily to
customers in an industrial park. At December 31, 1994, Consolidated's total
investment in the project amounted to $18,738,000.
9. COMMON STOCKHOLDERS' EQUITY
A summary of the changes in stockholders' equity follows:
61
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
<CAPTION>
________________________________________________________________________________
______________________________________
Summary of Changes in Common Stockholders' Equity
________________________________________________________________________________
______________________________________
Common Stock Capital in Excess
Issued of Par Value
Treasury Stock
Number of Value
Retained Number of
Shares at Par Paid-In Other
Total Earnings Shares Cost
________________________________________________________________________________
______________________________________
(In Thousands)
<S> <C> <C> <C> <C> <C>
<C> <C> <C>
Balance at December 31, 1991. . . 87,567 $240,809 $201,101 $40,280
$241,381 $1,415,576 (245) $ (7,983)
Net income. . . . . . . . . - - - -
- 194,958 - -
Cash dividends declared
Common stock ($1.905 per share) . - - - -
- (171,473) - -
Common stock issued
Public offering . . . . . . 4,600 12,650 180,962 -
180,962 - - -
Stock options . . . . . . . 113 312 3,688 -
3,688 - - -
ESOP and DRP* . . . . . . . 107 295 4,401 -
4,401 - - -
System Thrift Plans . . . . . 105 289 4,561 -
4,561 - - -
Stock awards . . . . . . . 65 177 2,137 -
2,137 - - -
Purchase of treasury stock . . . - - - -
- - (95) (3,481)
Sale of treasury stock. . . . . - - 1,894 -
1,894 - 339 11,436
Reissuance of treasury stock under
Stock Incentive Plan. . . . . - - 5 -
5 - 1 28
Pension liability adjustment. . . - - - -
- 216 - -
______ ________ ________ _______
________ __________ ______ ________
Balance at December 31, 1992. . . 92,557 254,532 398,749 40,280
439,029 1,439,277 - -
Net income. . . . . . . . . - - - -
- 205,916 - -
Cash dividends declared
Common stock ($1.925 per share) . - - - -
- (178,771) - -
Common stock issued
Stock options . . . . . . . 238 654 8,834 -
8,834 - - -
Stock awards-net . . . . . . 66 180 2,925 -
2,925 - - -
DRP* . . . . . . . . . . 58 159 2,697 -
2,697 - - -
System Thrift Plans . . . . . 15 43 679 -
679 - - -
Purchase of treasury stock . . . - - - -
- - (29) (1,417)
Sale of treasury stock. . . . . - - (83) -
(83) - 29 1,417
Pension liability adjustment (Note 4) - - - -
- 361 - -
______ ________ ________ _______
________ __________ ______ ________
Balance at December 31, 1993. . . 92,934 255,568 413,801 40,280
454,081 1,466,783 - -
Net income. . . . . . . . . - - - -
- 183,171 - -
Cash dividends declared
Common stock ($1.94 per share) . - - - -
- (180,461) - -
Common stock issued
Conversion of debentures . . . 70 193 3,669 -
3,669 - - -
Stock awards-net . . . . . . 16 45 621 -
621 - - -
Stock options . . . . . . . 8 21 258 -
258 - - -
Purchase of treasury stock . . . - - - -
- - (6) (257)
Sale of treasury stock. . . . . - - (1) -
(1) - 6 257
Pension liability adjustment (Note 4) - - - -
- 386 - -
______ ________ ________ _______
________ __________ ______ ________
Balance at December 31, 1994. . . 93,028 $255,827 $418,348 $40,280
$458,628 $1,469,879 - $ -
====== ======== ======== =======
======== ========== ====== ========
________________________________________________________________________________
______________________________________
*Employee Stock Ownership Plan and Dividend Reinvestment Plan.
</TABLE>
62
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
COMMON STOCK OFFERING
In September 1992, the Company issued, through a public offering, 4,600,000
shares of its common stock at a price to the public of $43.50 per share. The
net proceeds of the offering, after deducting the underwriting discount and
expenses, were $193,612,000. The proceeds from the stock sale were used to
finance capital expenditures of the subsidiaries.
UNISSUED SHARES
At December 31, 1994, 106,972,153 shares of common stock were unissued. Of
these, a total of 17,314,627 shares have been registered with the SEC for
possible issuance under various benefit plans. Shares acquired by these plans
can consist of original issue shares, treasury shares or shares purchased in
the open market. In addition, 741,356 shares have been registered with the
SEC for possible issuance to shareholders under the Dividend Reinvestment Plan
and 4,559,353 shares are registered for issuance upon conversion of the
Company's convertible subordinated debentures.
TREASURY STOCK
Under a stock repurchase plan approved by the Board of Directors, the Company
can purchase in the open market up to 4,000,000 shares of its common stock
through December 31, 1995. The Company may also acquire shares of its common
stock through certain provisions of the 1991 Stock Incentive Plan and the
Long-Term Incentive Plan. Shares repurchased or acquired are held as treasury
stock and are available for reissuance for general corporate purposes or in
connection with various employee benefit plans. When treasury shares are
reissued, the difference between the market value at reissuance and the cost
of shares is reflected in "Capital in excess of par value." The cost of any
shares held as treasury stock is shown as a reduction in common stockholders'
equity in the Consolidated Balance Sheet. No treasury shares were held at
December 31, 1993 or 1994.
STOCK AWARDS AND STOCK OPTIONS
1991 STOCK INCENTIVE PLAN
The 1991 Stock Incentive Plan provides for the granting of stock awards, stock
options and other stock-based awards to employees of the Company and its
subsidiaries. The maximum number of shares available for issuance in each
calendar year is determined in accordance with a formula contained in the
plan. During 1994, 3,430,097 shares were available for issuance under the
plan.
Stock awards granted under the plan may be in the form of restricted stock or
deferred stock. Shares issued as restricted stock awards are held by the
Company until the attached restrictions lapse. Deferred stock awards
generally consist of a right to receive shares at the end of specified
deferral periods. The market value of the stock award on the date granted is
recorded as compensation expense over the applicable restriction or deferral
period.
Stock options granted under the plan allow the purchase of common shares at a
price not less than fair market value at the date of grant and not less than
par value.
Stock appreciation rights may also be granted, either alone or in tandem with
stock options. These rights permit the recipient to receive, upon exercise,
the excess of the fair market value of a share on the date of exercise over
the grant price. The grant price is generally the fair market value of the
stock on the date of grant. As of December 31, 1994, no stock appreciation
rights have been granted under the plan.
The 1991 Stock Incentive Plan also provides for the granting of performance
awards, dividend equivalents, or other awards which may be based on, or
related to, shares of the Company's common stock. The granting of stock
awards constitutes a non-cash financing activity of the Company.
63
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
LONG-TERM INCENTIVE PLAN
The Company's Long-Term Incentive Plan, which provided for the issuance of
common shares to key employees as either restricted stock awards or stock
options, terminated by its terms on November 9, 1991. However, the provisions
of the plan continue with respect to any restricted stock awards and stock
options granted prior to the termination date.
Shares of common stock issued as restricted stock awards under the plan are
held by the Company until certain restrictions lapse, which ordinarily occurs
equally on the third through sixth award anniversaries. The market value of
the stock when awarded is recorded as compensation expense over the six-year
period.
Stock options granted under the plan allow the purchase of common shares at a
price not less than fair market value at the date of grant and not less than
par value. The options generally are exercisable in four equal annual
installments commencing with the second anniversary of the grant and expire
after 10 years from the date of grant.
A summary of stock option activity under both plans for the years ended
December 31, 1992 through 1994, follows:
______________________________________________________________________________
Number Option Price
of Shares Per Share
______________________________________________________________________________
(In Thousands)
Shares under option:
At January 1, 1992 . . . . . . . 1,226 $32.50 - $50.75
Granted . . . . . . . . . . . 659 $34.75 - $47.25
Exercised . . . . . . . . . . (113) $34.38 - $44.00
Cancelled . . . . . . . . . . (59) $34.38 - $50.75
_____
At December 31, 1992. . . . . . . 1,713 $32.50 - $50.75
Granted . . . . . . . . . . . 552 $44.88 - $55.00
Exercised . . . . . . . . . . (238) $33.25 - $50.75
Cancelled . . . . . . . . . . (65) $34.75 - $50.75
_____
At December 31, 1993. . . . . . . 1,962 $32.50 - $55.00
Granted . . . . . . . . . . . 651 $34.75 - $45.13
Exercised . . . . . . . . . . (8) $34.38 - $43.88
Cancelled . . . . . . . . . . (48) $34.75 - $50.75
_____
At December 31, 1994. . . . . . . 2,557 $32.50 - $55.00
=====
______________________________________________________________________________
At December 31, 1994, options were exercisable for the purchase of 691,421
shares. Stock options become exercisable for the purchase of 440,494 shares
in 1995, 544,976 in 1996, 437,583 in 1997, and 442,129 shares thereafter.
64
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
10. PREFERRED STOCK
The Company's authorized cumulative preferred stock consists of 2,500,000
shares at a par value of $100 each. There were no shares of preferred stock
issued or outstanding at December 31, 1993 or 1994.
11. DIVIDEND RESTRICTIONS
The indenture relating to the Company's senior debenture issues and the
preferred stock provisions of its Certificate of Incorporation contain
restrictions on dividend payments by the Company and acquisitions of its
capital stock. Under the indenture provisions (there being no preferred stock
outstanding), $667,595,000 of consolidated retained earnings was free from
such restrictions at December 31, 1994. The indenture also imposes dividend
limitations on the subsidiaries, but at December 31, 1994, these limitations
did not restrict their ability to pay dividends to the Company.
12. LONG-TERM DEBT
Long-term debt, excluding current maturities, follows:
____________________________________________________________________________
December 31, 1994 1993
____________________________________________________________________________
(In Thousands)
Debentures
6 5/8%, Due December 1, 2013 . . . . . . $ 150,000 $ 150,000
5 3/4%, Due August 1, 2003. . . . . . . 150,000 150,000
5 7/8%, Due October 1, 1998 . . . . . . 150,000 150,000
8 3/4%, Due October 1, 2019 . . . . . . 150,000 150,000
8 3/4%, Due June 1, 1999 . . . . . . . 100,000 100,000
9 3/8%, Due February 1, 1997 . . . . . . 100,000 100,000
8 5/8%, Due December 1, 2011 . . . . . . 100,000 100,000
Unamortized debt discount . . . . . . . (8,262) (9,252)
Convertible Subordinated Debentures
7 1/4%, Due December 15, 2015. . . . . . 246,205 250,000
Unamortized debt discount . . . . . . . (1,970) (2,100)
9.94% Unsecured loan due January 1, 1999. . . 16,000 20,000
__________ __________
Total . . . . . . . . . . . . . $1,151,973 $1,158,648
========== ==========
______________________________________________________________________________
There are no debentures maturing in the year 1995. The aggregate principal
amounts of the Company's debentures maturing in the years 1996 through 1999
are: $6,250,000; $106,250,000; $156,250,000 and $113,375,000.
Discounts and the expenses incurred in connection with the issuance of
debentures are being amortized on a basis which will equitably distribute the
amount to "Interest on long-term debt" over the life of each debenture issue.
The Company's 7 1/4% Convertible Subordinated Debentures, which mature on
December 15, 2015, are convertible into shares of the Company's common stock
at any time prior to maturity at an initial conversion price of $54 per share.
Under additional terms of the issue, on December 15, 2000, the Company is
obligated to purchase, at the option of the holder, any debenture then
outstanding for 100% of the principal amount plus accrued interest.
The 9.94% unsecured loan due January 1, 1999, is an obligation of Virginia
Natural Gas. This $20,000,000 loan, which is being repaid in five annual
installments of $4,000,000 each, beginning January 1, 1995, has been
guaranteed by the Company.
65
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In March 1991, the Company entered into a credit agreement with a group of
banks that provides for the borrowing of up to $300,000,000. The 1991 Credit
Agreement initially was to expire on March 31, 1994; however, each year the
term of the agreement has, with the approval of the banks, been extended for a
period of one additional year. The current expiration date is March 31, 1997.
The loans under the 1991 Credit Agreement are in the form of revolving credits
and may, at the option of the Company, be structured either as syndicated
loans by a group of participating banks or money market loans by individual
participating banks. The loans may be borrowed, paid or prepaid and
reborrowed on a few days notice. Varying interest rate options are available
for syndicated loans, while the interest rate on money market loans is
determined from quotes rendered by the participating banks. A commitment fee
of 1/8 of 1% per annum is charged under the 1991 Credit Agreement. No
revolving credit loans were outstanding at December 31, 1993 or 1994.
13. SHORT-TERM BORROWINGS
The weighted average interest rate on the Company's commercial paper notes
outstanding at December 31, 1993 and 1994, was 3.35% and 5.86%, respectively.
Commercial paper notes are supported by unused lines of credit totaling
$475,000,000. These lines may be used if the sale of commercial paper is not
feasible. Each of the lines bears a commitment fee, but such fees, in the
aggregate, are not significant. In addition to these credit lines, the
Company may utilize unused portions of its 1991 Credit Agreement to provide
support for commercial paper notes.
There are no agreements or arrangements requiring compensating balances with
respect to either lines of credit or outstanding bank loans. Under the
Company's policy, bank deposits are maintained for normal operating purposes.
14. FINANCIAL INSTRUMENTS
FAIR VALUES
The estimated fair value of the Company's long-term debt, including current
maturities, was as follows at December 31, 1993 and 1994:
______________________________________________________________________________
1994 1993
Carrying Fair Carrying Fair
December 31, Amount Value Amount Value
______________________________________________________________________________
(In Thousands)
Long-term debt $1,166,205 $1,095,492 $1,170,000 $1,255,351
______________________________________________________________________________
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.
66
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
DERIVATIVE FINANCIAL INSTRUMENTS
The vast majority of Consolidated's hedging activities involve publicly-traded
futures contracts which can be settled through the purchase or delivery of
commodities and, therefore, does not involve financial instruments within the
scope of SFAS No. 119. However, the nonregulated subsidiaries periodically
enter into price swap agreements to modify their exposure to natural gas price
risk under existing sales contracts. Under these agreements, the subsidiaries
make payments to, or receive payments from, counterparties generally based on
the difference between fixed and variable gas prices specified in the
contracts. Settlement takes place under the agreements on a monthly basis,
and amounts received or paid are recognized as an adjustment to nonregulated
gas sales revenues to correspond with the recognition of the related hedged
transaction.
At December 31, 1994, the Company's nonregulated subsidiaries had swap
agreements of varying duration outstanding with several counterparties to
exchange monthly payments on aggregate notional quantities of 25.8 billion
cubic feet (Bcf) of gas over the ensuing 3 years. The aggregate notional
quantities do not represent the quantities or amounts exchanged by the parties
and, thus, are not a measure of the exposure of Consolidated through its use
of derivatives. The amounts exchanged are calculated on the basis of monthly
notional quantities and other terms of the agreements. Under the swap
agreements, fixed prices averaged $2.22 per Mcf and variable prices averaged
$1.85 per Mcf based upon market conditions at December 31, 1994. Expected
profits on anticipated sales related to the hedged transactions should
generally offset the estimated unrealized losses on the swap agreements.
The use of derivative financial instruments exposes the Company to market risk
and credit risk. Market risk represents the potential loss that can be caused
by a change in the market value of a particular commitment. Credit risk
relates to the risk of loss that Consolidated would incur as a result of
nonperformance by counterparties pursuant to the terms of their contractual
obligations. The Company does not have a significant exposure to any
individual counterparty to its derivative activities. Management has
operating procedures in place to evaluate market and credit risks and believes
that the Company's exposure to risks associated with derivative financial
instruments is not material in relation to Consolidated's financial position,
results of operations or cash flows.
67
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
15. ENVIRONMENTAL MATTERS
The Company and its subsidiaries are subject to various federal, state and
local laws and regulations relating to the protection of the environment.
These laws and regulations govern both current and future operations and
potentially extend to plant sites formerly owned or operated by the Company
and its subsidiaries, or their predecessors.
The Company has taken a proactive position with respect to environmental
concerns. As part of normal business operations, subsidiaries periodically
monitor their properties and facilities to identify and resolve potential
environmental matters, and the Company conducts general environmental surveys
on a continuing basis at its operating facilities to monitor compliance with
environmental laws and regulations. As part of this process, voluntary
surveys at subsidiary sites have been conducted to determine the extent of any
possible soil contamination due to hazardous substances, such as mercury, and
when contamination has been discovered remediation efforts are undertaken.
Further, on August 16, 1990, CNG Transmission entered into a Consent Order and
Agreement with the Commonwealth of Pennsylvania Department of Environmental
Resources (DER) in which CNG Transmission has agreed with the DER's
determination of certain violations of the Pennsylvania Solid Waste Management
Act, the Pennsylvania Clean Streams Law and the rules and regulations
promulgated thereunder. No civil penalties have been assessed as of this
date. Pursuant to the Order and Agreement, CNG Transmission is performing
sampling, testing and analysis, and conducting a program of remediation at
some of its Pennsylvania facilities. Total remediation costs in connection
with these sites and the Order and Agreement are not expected to be material
with respect to Consolidated's financial position, results of operations or
cash flows. Based on current information, the Company has recognized a gross
estimated liability amounting to $20,552,000 at December 31, 1994, 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
$12,797,000 at December 31, 1994, is included in the Consolidated Balance
Sheet under the caption "Deferred charges and other assets." Also,
uncontested claims amounting to $3,735,000 at December 31, 1994, 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:
______________________________________________________________________________
Years Ended December 31, 1994 1993 1992
______________________________________________________________________________
(In Thousands)
Recurring costs for ongoing operations $3,479 $3,381 $4,032
Mandated remediation and other
compliance costs . . . . . . . 214 3,963 2,816
Voluntary remediation costs . . . . 507 1,185 703
Other . . . . . . . . . . . 28 520 95
______ ______ ______
Total. . . . . . . . . . . $4,228 $9,049 $7,646
====== ====== ======
______________________________________________________________________________
Environmental-related capital expenditures for monitoring or complying with
laws and regulations were not material in 1992 or 1993.
68
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
CNG Transmission and certain of the Company's distribution subsidiaries are
subject to the Federal Clean Air Act and the Federal Clean Air Act Amendments
of 1990 (1990 amendments) which added significantly to the existing
requirements established by the Federal Clean Air Act. As a result of the
1990 amendments, these subsidiaries are required to install Reasonably
Available Control Technology (RACT) at some compressor stations to reduce
nitrogen oxide emissions. The subsidiaries will have until May 31, 1995, to
comply with the requirement to install RACT. Compliance requires capital
expenditures to similarly retrofit some of the compressor engines along the
Company's pipeline system. In this regard, approximately $23.3 million was
expended during 1994 to install emission control equipment. In addition, up
to $17 million is expected to be expended in 1995 to complete installation of
emission control equipment. The Company anticipates completing the
installation of emission controls by the May 31, 1995 deadline required in the
1990 amendments. While the Company believes that it will be in compliance
with the 1990 amendments, additional compliance requirements which may be
imposed by state regulation could require additional capital expenditures. In
any event, the total actual capital expenditures required to comply with the
1990 amendments are expected to be recoverable through future regulatory
proceedings.
Consolidated has determined that it is associated with 16 former manufactured
gas plant sites, five of which are currently owned by subsidiaries. Studies
conducted by other utilities at their former manufactured gas plants have
indicated that their sites contain coal tar and other potentially harmful
materials. None of the 16 former sites with which Consolidated 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.
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 and its subsidiaries 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.
16. COMMITMENTS AND CONTINGENCIES
Lease arrangements of the subsidiaries are principally for office space,
business machines and transportation equipment. None of these arrangements,
individually or in the aggregate, are material capital leases. Rental expense
incurred in the years 1992 through 1994 was not material, and future rental
payments required under leases in effect at December 31, 1994, are not
material.
It is estimated that Consolidated's 1995 capital budget will amount to
$444,600,000, and that approximately $170,200,000 of that amount will be
directed to gas and oil producing activities. In connection with the capital
budget, the subsidiaries have entered into certain contractual commitments.
The subsidiaries have claims and suits pending against them, but, in the
opinion of management and counsel, the ultimate liability will not have a
material effect on Consolidated's financial position, results of operations or
cash flows.
69
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
17. DISAGGREGATED INFORMATION
As an integrated natural gas company, Consolidated operates in all phases of
the natural gas business with activities conducted principally in the United
States. As such, the Company's operations are conducted in one industry
segment as defined under current generally accepted accounting principles.
The following table presents disaggregated information pertaining to
Consolidated's operations within the natural gas segment.
Distribution represents Consolidated's retail gas distribution subsidiaries,
including their minor gas and oil production activities. 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, 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, and the activities of CNG Storage Service Company. CNG
Transmission is an interstate pipeline company regulated by the FERC.
Exploration and production includes the results of CNG Producing and the gas
and oil production activities of CNG Transmission. These operations are
located throughout the United States and in the Gulf of Mexico. CNG Producing
also owns a working interest in a heavy oil program in Alberta, Canada.
The activities of CNG Energy Services, CNG Power, CNG Power Services,
Consolidated LNG, CNG Research and CNG Coal are included in the "Other"
category. CNG Energy Services markets a portion of Company-owned production,
and arranges gas supplies, transportation, storage and related services.
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.
70
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
<TABLE>
<CAPTION>
________________________________________________________________________________
_______________________________________________
Exploration Corporate
and
and
Distribution Transmission
Production Other Eliminations Total
________________________________________________________________________________
_______________________________________________
(In
Thousands)
<S> <C> <C> <C>
<C> <C> <C>
1994
Operating revenues
Nonaffiliated . . . . . . $1,804,317 $ 348,141 $
411,876 $ 471,694 $ - $3,036,028
Affiliated . . . . . . . 1,296 111,147
77,564 44,966 (234,973) -
__________ __________
__________ _________ __________ __________
Total. . . . . . . . . 1,805,613 459,288
489,440 516,660 (234,973) 3,036,028
Other operating expenses . . . . 1,579,259 259,078
299,872 508,303 (233,206) 2,413,306
Depreciation and amortization . . 67,401 53,944
155,558 736 1,678 279,317
__________ __________
__________ _________ __________ __________
Operating income before
income taxes. . . . . . . $ 158,953 $ 146,266 $
34,010 $ 7,621 $ (3,445) $ 343,405
========== ==========
========== ========= ========== ==========
Capital expenditures . . . . . $ 146,882 $ 108,647 $
166,022 $ 15,198 $ 1,036 $ 437,785
Identifiable assets. . . . . . $2,595,615 $1,543,790
$1,372,747 $ 283,799 $ (277,278) $5,518,673
________________________________________________________________________________
_______________________________________________
1993
Operating revenues
Nonaffiliated . . . . . . $1,772,816 $ 689,772 $
437,125 $ 284,372 $ - $3,184,085
Affiliated . . . . . . . 1,112 293,984
99,301 73,401 (467,798) -
__________ __________
__________ _________ __________ __________
Total. . . . . . . . . 1,773,928 983,756
536,426 357,773 (467,798) 3,184,085
Other operating expenses . . . . 1,541,741 789,894
312,393 351,800 (463,735) 2,532,093
Depreciation and amortization . . 65,295 50,418
176,738 292 1,905 294,648
__________ __________
__________ _________ __________ __________
Operating income before
income taxes. . . . . . . $ 166,892 $ 143,444 $
47,295 $ 5,681 $ (5,968) $ 357,344
========== ==========
========== ========= ========== ==========
Capital expenditures . . . . . $ 115,376 $ 113,385 $
110,746 $ 1,757 $ 1,305 $ 342,569
Identifiable assets. . . . . . $2,519,247 $1,574,047
$1,363,065 $ 267,033 $ (286,204) $5,437,188
________________________________________________________________________________
_______________________________________________
1992
Operating revenues
Nonaffiliated . . . . . . $1,602,617 $ 442,719 $
445,118 $ 30,396 $ - $2,520,850
Affiliated . . . . . . . 523 200,012
74,306 12,173 (287,014) -
__________ __________
__________ _________ __________ __________
Total. . . . . . . . . 1,603,140 642,731
519,424 42,569 (287,014) 2,520,850
Other operating expenses . . . . 1,365,514 478,828
299,827 25,095 (278,519) 1,890,745
Depreciation and amortization . . 61,002 43,803
180,830 445 1,760 287,840
__________ __________
__________ _________ __________ __________
Operating income before
income taxes. . . . . . . $ 176,624 $ 120,100 $
38,767 $ 17,029 $ (10,255) $ 342,265
========== ==========
========== ========= ========== ==========
Capital expenditures . . . . . $ 114,670 $ 225,288 $
99,073 $ 1,768 $ 719 $ 441,518
Identifiable assets. . . . . . $2,086,856 $1,688,026
$1,387,289 $ 181,587 $ (184,887) $5,158,871
________________________________________________________________________________
_______________________________________________
</TABLE>
71
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
18. 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:
______________________________________________________________________________
December 31, 1994 1993
______________________________________________________________________________
(In Thousands)
Capitalized costs of
Proved properties. . . . . . . . . $2,796,911 $2,685,856
Unproved properties . . . . . . . . 255,490 232,312
__________ __________
Subtotal. . . . . . . . . . . . $3,052,401 $2,918,168
__________ __________
Accumulated depreciation of
Proved properties. . . . . . . . . $1,855,398 $1,723,113
Unproved properties . . . . . . . . 86,887 78,352
__________ __________
Subtotal. . . . . . . . . . . . 1,942,285 1,801,465
__________ __________
Net capitalized costs . . . . . . . $1,110,116 $1,116,703
========== ==========
______________________________________________________________________________
TOTAL COSTS INCURRED
The following costs were incurred by subsidiaries in their gas and oil
producing activities during the years 1992 through 1994:
______________________________________________________________________________
Years Ended December 31, 1994 1993 1992
______________________________________________________________________________
(In Thousands)
Property acquisition costs
Proved properties. . . . . . . . . $ 4,000 $ 132 $ 7,926
Unproved properties . . . . . . . . 18,998 18,224 14,378
________ ________ ________
Subtotal . . . . . . . . . . . 22,998 18,356 22,304
Exploration costs . . . . . . . . . 48,514 47,934 30,860
Development costs . . . . . . . . . 82,020 40,516 42,059
________ ________ ________
Total . . . . . . . . . . . . $153,532 $106,806 $ 95,223
======== ======== ========
______________________________________________________________________________
72
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
RESULTS OF OPERATIONS
The elements of the "results of operations for gas and oil producing
activities" that follow are as required and defined by the FASB. Consolidated
cautions that these standardized disclosures do not represent the results of
operations based on its historical financial statements. In addition to
requiring different determinations of revenues and costs, the disclosures
exclude the impact of interest expense and corporate overheads.
______________________________________________________________________________
Years Ended December 31, 1994 1993 1992
______________________________________________________________________________
(In Thousands)
Revenues (net of royalties) from:
Sales to nonaffiliated companies. . . $201,820 $204,614 $155,481
Transfers to other operations. . . . 55,007 88,241 135,280
________ ________ ________
Total . . . . . . . . . . . 256,827 292,855 290,761
________ ________ ________
Less: Production (lifting) costs . . . 42,723 49,177 55,281
Depreciation and amortization . . 150,936 173,171 176,463
Income tax expense. . . . . . 15,446 18,400 13,509
________ ________ ________
Results of operations . . . . . . . $ 47,722 $ 52,107 $ 45,508
======== ======== ========
______________________________________________________________________________
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, 1992 through 1994, and changes
in the reserves during those years, are shown in the two schedules which
follow:
______________________________________________________________________________
Years Ended December 31, 1994 1993 1992
______________________________________________________________________________
(In Bcf)
PROVED DEVELOPED AND UNDEVELOPED RESERVES* - GAS
At January 1 . . . . . . . . . . . 885 918 918
Changes in reserves
Extensions, discoveries and other additions 111 55 141
Revisions of previous estimates . . . . 16 46 (23)
Production . . . . . . . . . . . (114) (124) (121)
Purchases of gas in place . . . . . . 8 - 19
Sales of gas in place. . . . . . . . (5) (10) (16)
_____ _____ _____
At December 31. . . . . . . . . . . 901 885 918
===== ===== =====
PROVED DEVELOPED RESERVES* - GAS
At January 1 . . . . . . . . . . . 761 794 855
At December 31. . . . . . . . . . . 730 761 794
* Net before royalty.
______________________________________________________________________________
Included in the caption "Extensions, discoveries and other additions" for 1992
and 1994 are 79 and 56 Bcf, respectively, of proved undeveloped reserves for
which development costs will be incurred in future years. The preceding
proved developed and undeveloped gas reserves at December 31, 1992 through
1994, include United States reserves of 917, 884 and 900 Bcf which, together
with the Canadian reserves and the gas reserves reported under "Cost-of-
Service Properties," are as contained in reports of Ralph E. Davis Associates,
Inc., independent geologists.
73
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
______________________________________________________________________________
Years Ended December 31, 1994 1993 1992
______________________________________________________________________________
(In Thousand Bbls)
Proved developed and undeveloped reserves* - Oil
At January 1 . . . . . . . . . . . 27,596 29,238 31,014
Changes in reserves
Extensions, discoveries and other additions 24,709 1,978 2,104
Revisions of previous estimates . . . . (2,791) 290 390
Production . . . . . . . . . . . (3,333) (3,907) (4,508)
Purchases of oil in place . . . . . . 77 - 245
Sales of oil in place. . . . . . . . (3) (3) (7)
______ ______ ______
At December 31. . . . . . . . . . . 46,255 27,596 29,238
====== ====== ======
Proved developed reserves* - Oil
At January 1 . . . . . . . . . . . 21,936 27,449 30,070
At December 31. . . . . . . . . . . 20,379 21,936 27,449
* Net before royalty.
______________________________________________________________________________
Included in the caption "Extensions, discoveries and other additions" for 1994
are 22,305 thousand barrels of proved undeveloped reserves for which
development costs will be incurred in future years. The foregoing proved
developed and undeveloped oil reserves at December 31, 1992 through 1994,
include United States reserves of 23,493, 21,917 and 40,918 thousand barrels,
respectively. These, together with the Canadian reserves and the oil reserves
reported under "Cost-of-Service Properties," are as contained in reports of
Ralph E. Davis Associates, Inc.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES
THEREIN
The following tabulation has been prepared in accordance with the FASB's rules
for disclosure of a standardized measure of discounted future net cash flows
relating to Company-owned proved gas and oil reserve quantities.
______________________________________________________________________________
December 31, 1994 1993 1992
______________________________________________________________________________
(In Thousands)
Future cash inflows . . . . . . . . $2,303,024 $2,336,553 $2,421,422
Less: Future development
and production costs . . . . . 626,344 529,592 572,576
Future income tax expense. . . . 490,079 537,966 473,475
__________ __________ __________
Future net cash flows . . . . . . . 1,186,601 1,268,995 1,375,371
Less annual discount (10% a year) . . . 482,109 500,732 557,019
__________ __________ __________
Standardized measure of discounted future
net cash flows . . . . . . . . . $ 704,492 $ 768,263 $ 818,352
========== ========== ==========
______________________________________________________________________________
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.
74
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
It is not intended that the FASB's standardized measure of discounted future
net cash flows represent the fair market value of Consolidated's proved
reserves. The Company cautions that the disclosures shown are based on
estimates of proved reserve quantities and future production schedules which
are inherently imprecise and subject to revision, and the 10% discount rate is
arbitrary. In addition, present costs and prices are used in the
determinations and no value may be assigned to probable or possible reserves.
The following tabulation is a summary of changes between the total
standardized measure of discounted future net cash flows at the beginning and
end of each year.
<TABLE>
<CAPTION>
________________________________________________________________________________
_______________________
Years Ended December 31, 1994
1993 1992
________________________________________________________________________________
_______________________
(In Thousands)
<S> <C>
<C> <C>
Standardized measure of discounted future net
cash flows at January 1. . . . . . . . . . . . $ 768,263
$ 818,352 $ 881,131
Changes in the year resulting from
Sales and transfers of gas and oil produced
during the year, less production costs . . . . . . (214,104)
(243,678) (235,480)
Prices and production and development costs
related to future production . . . . . . . . . (153,962)
12,635 (70,092)
Extensions, discoveries and other additions,
less production and development costs . . . . . . 144,342
99,662 108,734
Previously estimated development costs
incurred during the year. . . . . . . . . . . 46,568
4,838 24,914
Revisions of previous quantity estimates . . . . . . 4,228
66,506 (66,504)
Accretion of discount . . . . . . . . . . . . 108,417
109,287 123,976
Income taxes . . . . . . . . . . . . . . . 33,029
(41,395) 84,126
Purchases and sales of proved reserves in place-net . . 4,122
(5,439) 17,548
Other (principally timing of production) . . . . . . (36,411)
(52,505) (50,001)
_________
_________ _________
Standardized measure of discounted future net
cash flows at December 31 . . . . . . . . . . . $ 704,492
$ 768,263 $ 818,352
=========
========= =========
________________________________________________________________________________
_______________________
</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, 1993 and 1994,
net capitalized costs of cost-of-service properties amounted to $27,320,000
and $25,244,000, respectively. Related proved reserves of gas and oil are
located in the United States, and at December 31, 1992 through 1994, amounted
to 80, 75 and 71 Bcf of gas and 283, 287 and 256 thousand barrels of oil,
respectively. Production for the years 1992 through 1994 amounted to 7, 6 and
6 Bcf of gas and 31, 29 and 24 thousand barrels of oil, respectively.
Future revenues associated with production of the foregoing gas and oil
reserves would be based upon cost-of-service ratemaking and historical asset
costs, with rate of return levels determined by various state regulatory
commissions.
75
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Cont.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(B) QUARTERLY FINANCIAL DATA
A summary of the quarterly results of operations for the years 1993 and 1994
follows. Because a major portion of the gas sold or transported by the
Company's distribution and transmission operations is ultimately used for
space heating, both revenues and earnings are subject to seasonal
fluctuations, and third quarter results are usually the least significant of
the year for Consolidated. Seasonal fluctuations are further influenced by
the timing of price relief granted under regulation to compensate for certain
past cost increases.
<TABLE>
<CAPTION>
________________________________________________________________________________
____________________
Quarter
First Second
Third* Fourth
________________________________________________________________________________
____________________
(In
Thousands)
<S> <C> <C>
<C> <C>
1994
Total operating revenues . . . . . . . . $1,213,596 $582,008
$451,829 $ 788,595
Operating income before income taxes . . . . 217,439 22,141
(17,990) 121,815
Net income. . . . . . . . . . . . . 130,918 3,069
(24,557) 73,741
Earnings per share of common stock. . . . . 1.41 .03
(.26) .79
1993
Total operating revenues . . . . . . . . $1,131,526 $549,070
$473,348 $1,030,141
Operating income before income taxes . . . . 200,169 29,508
(7,520) 135,187
Income before cumulative effect of
change in accounting principle . . . . . 125,714 6,636
(29,965) 86,109
Cumulative effect of applying SFAS No. 109 . . 17,422 -
- -
Net income. . . . . . . . . . . . . 143,136 6,636
(29,965) 86,109
Earnings per share of common stock**:
Income before cumulative effect of
change in accounting principle. . . . . 1.36 .07
(.32) .93
Cumulative effect of applying SFAS No. 109 . .19 -
- -
Net income . . . . . . . . . . . . 1.55 .07
(.32) .93
* Net income for the 1993 third quarter was reduced to reflect additional
deferred income taxes of $11,429,000, or $(.12) per share, resulting from
the increase in the federal corporate income tax rate (see Note 6 to the
consolidated financial statements).
** 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
outstanding.
________________________________________________________________________________
____________________
</TABLE>
76
<PAGE>
ITEM 8. CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
(Concl.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
(C) COMMON STOCK MARKET PRICES AND RELATED MATTERS
At December 31, 1994, there were 40,828 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 1993 and
1994 follow. Restrictions on the payment of dividends are discussed in Note
11.
______________________________________________________________________________
Quarter
First Second Third Fourth
______________________________________________________________________________
Market Price Range
1994 - High . . . . . . . . $47 $40 $41 1/8 $39
- Low . . . . . . . . $38 3/4 $36 3/4 $37 1/2 $33 3/8
1993 - High . . . . . . . . $49 7/8 $53 5/8 $55 3/8 $53 1/4
- Low . . . . . . . . $43 1/2 $48 5/8 $48 3/8 $42 5/8
Dividends Declared per Share
1994 . . . . . . . . . . $.485 $.485 $.485 $.485
1993 . . . . . . . . . . $.48 $.48 $.48 $.485
______________________________________________________________________________
77
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
Not applicable
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY
Information concerning the directors of the Company is hereby incorporated by
reference to the Company's definitive proxy statement filed with the
Commission pursuant to Regulation 14A within 120 days after the close of the
Company's fiscal year. Information concerning the executive officers of the
Company is on page 18 of this Report.
ITEM 11. EXECUTIVE COMPENSATION
This information is hereby incorporated by reference to the Company's
definitive proxy statement filed with the Commission pursuant to Regulation
14A within 120 days after the close of the Company's fiscal year.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
This information is hereby incorporated by reference to the Company's
definitive proxy statement filed with the Commission pursuant to Regulation
14A within 120 days after the close of the Company's fiscal year.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
This information is hereby incorporated by reference to the Company's
definitive proxy statement filed with the Commission pursuant to Regulation
14A within 120 days after the close of the Company's fiscal year.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the last quarter of the calendar year
1994, the year for which this Form 10-K is being filed.
DOCUMENTS FILED AS A PART OF THIS REPORT
Financial Statements
All of the financial statements filed as a part of this Report are included in
ITEM 8 and reference is made to the index on page 45.
78
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
Consent Of Independent Accountants
We hereby consent to the incorporation by reference in the Prospectuses
constituting part of the Registration Statements on Form S-3 (Nos. 33-1040,
33-49469 and 33-52585) and Form S-8 (Nos. 2-77204, 2-97948, 33-40478 and 33-
44892) of Consolidated Natural Gas Company of our report dated February 21,
1995, appearing on page 46 of this Form 10-K. We also consent to the
references to us under the heading "Experts" in such Prospectuses.
PRICE WATERHOUSE LLP
600 Grant Street
Pittsburgh, Pennsylvania 15219-9954
March 29, 1995
EXHIBITS
______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
______________________________________________________________________________
(3) Articles of Incorporation and By-Laws:
(3A) Certificate of Incorporation of Consolidated Natural Gas
Company, restated October 4, 1990 (incorporated by reference
to Exhibit A-1 to the Application-Declaration of Consolidated
Natural Gas Company on Form U-1, File No. 70-7811)
(3B) By-Laws of Consolidated Natural Gas Company, last amended
March 1, 1993 (incorporated by reference to Exhibit (3B)
filed with Consolidated Natural Gas Company's Form 10-K for
the year ended December 31, 1992, File No. 1-3196)
(4) Instruments Defining the Rights of Security Holders, Including
Indentures:
(4A) (1) Indentures of Consolidated Natural Gas Company:
Indentures of Consolidated Natural Gas Company are
incorporated by reference to previously filed material as
indicated on the list filed herewith
(2) Note Purchase Agreement of Virginia Natural Gas:
Note Purchase Agreement dated as of January 1, 1989, between
Virginia Natural Gas, Inc. and the Aid Association for
Lutherans relating to $20,000,000 principal amount of 9.94%
Senior Notes, Series A, due January 1, 1999 (incorporated by
reference to Exhibit B-1 to the Application-Declaration of
Consolidated Natural Gas Company on Form U-1, File No.
70-7667)
(4B) Section 203 of the Delaware General Corporation Law,
"Business Combinations With Interested Stockholders,"
effective February 2, 1988 (incorporated by reference to
Exhibit (4B) filed with Consolidated Natural Gas Company's
Form 10-K for the year ended December 31, 1987, File No.
1-3196)
Other portions of the Delaware General Corporation Law
affecting security holder rights are considered routine and
are not filed hereunder
79
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Continued)
EXHIBITS (Continued)
______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
______________________________________________________________________________
(10) Material Contracts:
(Exhibits (10A) through (10E) and Exhibit (10G) listed below are
incorporated by reference to the Exhibit with the same designation
filed with Consolidated Natural Gas Company's Form 10-K for the
year ended December 31, 1987, File No. 1-3196; Exhibits (10H) and
(10I) listed below are incorporated by reference to the Exhibit
with the same designation filed with Consolidated Natural Gas
Company's Form 10-K for the year ended December 31, 1989, File No.
1-3196; Exhibit (10K) listed below is incorporated by reference to
the Exhibit with the same designation filed with Consolidated
Natural Gas Company's Form 10-K for the year ended December 31,
1992, File No. 1-3196)
(10A) Form of Split Dollar Insurance Agreement between
Consolidated Natural Gas Company and certain employees and
Directors
(10B) Form of Supplemental Death Benefit Payment Agreement
between Consolidated Natural Gas Company and certain
employees and Directors
(10C) Consolidated Natural Gas Company Supplemental Retirement
Benefit Plan
(10D) System Supplemental Retirement Plan for Certain Management
Employees of Consolidated Natural Gas Company and Its
Participating Subsidiaries
(10E) Form of agreement between Consolidated Natural Gas Company
and nonemployee Directors for deferral of payment of
retainer and attendance fees, effective before 1987
(10F) Deferred Compensation Plan for Directors of Consolidated
Natural Gas Company, effective for years beginning with
1987, as amended December 13, 1994, 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) Description of Consolidated Natural Gas Company Annual
Executive Incentive Program, as amended December 13, 1994,
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
(10L) Description of Consolidated Natural Gas Company Non-
Employee Directors' Restricted Stock Plan, is filed
herewith
80
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(Concluded)
EXHIBITS (Concluded)
______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
______________________________________________________________________________
(11) Statement re Computation of Per Share Earnings:
Computations of Earnings Per Share of Common Stock, Primary
Earnings Per Share, and Fully Diluted Earnings Per Share of
Consolidated Natural Gas Company and Subsidiaries for the years
ended December 31, 1992 through 1994, 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 1990-1994,
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 14, 1995, 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, 1994, are filed herewith
(23B) Consent letter of John T. Boyd Company, Mining and
Geological Engineers, authorizing the use of coal reserve
estimates in Consolidated Natural Gas Company's Form 10-K
for the year ended December 31, 1994, is filed herewith
(23C) Consent of Price Waterhouse LLP - included as part of this
ITEM 14
______________________________________________________________________________
81
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CONSOLIDATED NATURAL GAS COMPANY
________________________________
(Registrant)
GEORGE A. DAVIDSON, JR.
By___________________________
(George A. Davidson, Jr.)
Chairman of the Board
March 29, 1995 and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on March 29, 1995.
GEORGE A. DAVIDSON, JR. PAUL E. LEGO
________________________________ ________________________________
(George A. Davidson, Jr.) (Paul E. Lego)
Chairman of the Board Director
and Chief Executive Officer,
and Director
THEODORE LEVITT
________________________________
L. D. JOHNSON (Theodore Levitt)
________________________________ Director
(L. D. Johnson)
Vice Chariman
and Chief Financial Officer, MARGARET A. MCKENNA
and Director ________________________________
(Margaret A. McKenna)
Director
S. R. MCGREEVY
________________________________
(S. R. McGreevy) STEVEN A. MINTER
Vice President, Accounting ________________________________
and Financial Control (Steven A. Minter)
Director
WILLIAM S. BARRACK, JR.
________________________________ WALTER R. PEIRSON
(William S. Barrack, Jr.) ________________________________
Director (Walter R. Peirson)
Director
J. W. CONNOLLY
________________________________ RICHARD P. SIMMONS
(J. W. Connolly) ________________________________
Director (Richard P. Simmons)
Director
RAY J. GROVES
________________________________ LOIS WYSE
(Ray J. Groves) ________________________________
Director (Lois Wyse)
Director
82
<PAGE>
APPENDIX TO FORM 10-K
The following graphic material which appeared in the paper format version of
the document is omitted from this electronic format document:
Map of Principal Facilities at December 31, 1994 (Page 20)
This map shows the primary operating areas of Consolidated Natural Gas Company
in Ohio, Pennsylvania, Virginia and West Virginia. The map shows the principal
cities served at retail including Cleveland, Akron, Youngstown, Canton, Warren,
Lima, Ashtabula and Marietta in Ohio; Pittsburgh (a portion), Altoona and
Johnstown in Pennsylvania; Norfolk, Newport News and Williamsburg in Virginia;
and Clarksburg and Parkersburg in West Virginia. The map also shows the
general location of Consolidated's pipelines and joint venture pipelines,
including gas sale or transport connections with wholesale customers and gas
purchase or transport connections with other pipelines. Also shown on the map
are the general location of certain compressor facilities and the general
location of underground storage fields.
Map of Exploration and Production Areas at December 31, 1994 (Page 21)
This United States map shows the general areas in which Consolidated conducts
its exploration and production activities. These areas include: the Gulf of
Mexico, offshore Louisiana and Texas; the Gulf Coast Basin; Permian Basin;
Anadarko Basin; Arkoma Basin; Black Warrior Basin; San Juan Basin; Williston
Basin; Michigan Basin; Rocky Mountain Basins and the Appalachian Region. Also
shown is the general location of Consolidated's Canadian exploration and
production properties in Alberta, Canada.
<PAGE>
EXHIBIT INDEX
______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
______________________________________________________________________________
(3) Articles of Incorporation and By-Laws:
(3A) Certificate of Incorporation of Consolidated Natural Gas
Company, restated October 4, 1990 (incorporated by reference to
Exhibit A-1 to the Application-Declaration of Consolidated
Natural Gas Company on Form U-1, File No. 70-7811)
(3B) By-Laws of Consolidated Natural Gas Company, last amended
March 1, 1993 (incorporated by reference to Exhibit (3B) filed
with Consolidated Natural Gas Company's Form 10-K for the year
ended December 31, 1992, File No. 1-3196)
(4) Instruments Defining the Rights of Security Holders, Including
Indentures:
(4A) (1) Indentures of Consolidated Natural Gas Company:
Indentures of Consolidated Natural Gas Company are incorporated
by reference to previously filed material as indicated on the
list filed herewith
(2) Note Purchase Agreement of Virginia Natural Gas:
Note Purchase Agreement dated as of January 1, 1989, between
Virginia Natural Gas, Inc. and the Aid Association for Lutherans
relating to $20,000,000 principal amount of 9.94% Senior Notes,
Series A, due January 1, 1999 (incorporated by reference to
Exhibit B-1 to the Application-Declaration of Consolidated
Natural Gas Company on Form U-1, File No. 70-7667)
(4B) Section 203 of the Delaware General Corporation Law, "Business
Combinations With Interested Stockholders," effective
February 2, 1988 (incorporated by reference to Exhibit (4B)
filed with Consolidated Natural Gas Company's Form 10-K for the
year ended December 31, 1987, File No. 1-3196)
Other portions of the Delaware General Corporation Law affecting
security holder rights are considered routine and are not filed
hereunder
(10) Material Contracts:
(Exhibits (10A) through (10E) and Exhibit (10G) listed below are
incorporated by reference to the Exhibit with the same designation
filed with Consolidated Natural Gas Company's Form 10-K for the year
ended December 31, 1987, File No. 1-3196; Exhibits (10H) and (10I) listed
below are incorporated by reference to the Exhibit with the same
designation filed with Consolidated Natural Gas Company's Form 10-K for
the year ended December 31, 1989, File No. 1-3196; Exhibit (10K) listed
below is incorporated by reference to the Exhibit with the same
designation filed with Consolidated Natural Gas Company's Form 10-K for
the year ended December 31, 1992, File No. 1-3196)
(10A) Form of Split Dollar Insurance Agreement between Consolidated
Natural Gas Company and certain employees and Directors
(10B) Form of Supplemental Death Benefit Payment Agreement between
Consolidated Natural Gas Company and certain employees and
Directors
(10C) Consolidated Natural Gas Company Supplemental Retirement Benefit
Plan
<PAGE>
______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
______________________________________________________________________________
(10) Material Contracts (Continued):
(10D) System Supplemental Retirement Plan for Certain Management
Employees of Consolidated Natural Gas Company and Its
Participating Subsidiaries
(10E) Form of agreement between Consolidated Natural Gas Company and
nonemployee Directors for deferral of payment of retainer and
attendance fees, effective before 1987
(10F) Deferred Compensation Plan for Directors of Consolidated Natural
Gas Company, effective for years beginning with 1987, as amended
December 13, 1994, 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) Description of Consolidated Natural Gas Company Annual Executive
Incentive Program, as amended December 13, 1994, 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
(10L) Description of Consolidated Natural Gas Company Non-Employee
Directors' Restricted Stock Plan, is filed herewith
(11) Statement re Computation of Per Share Earnings:
Computations of Earnings Per Share of Common Stock, Primary Earnings
Per Share, and Fully Diluted Earnings Per Share of Consolidated Natural
Gas Company and Subsidiaries for the years ended December 31, 1992
through 1994, 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 1990-1994, 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 14, 1995, 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, 1994, are filed herewith
<PAGE>
______________________________________________________________________________
SEC
Exhibit
Number Description of Exhibit
______________________________________________________________________________
(23) Consents of Experts and Counsel (Continued):
(23B) Consent letter of John T. Boyd Company, Mining and Geological
Engineers, authorizing the use of coal reserve estimates in
Consolidated Natural Gas Company's Form 10-K for the year ended
December 31, 1994, is filed herewith
(23C) Consent of Price Waterhouse LLP - included as part of ITEM 14
______________________________________________________________________________
EXHIBIT 4A(1)
INDENTURES OF CONSOLIDATED NATURAL GAS COMPANY
The Indentures and Supplemental Indentures between Consolidated Natural Gas
Company and its debenture Trustees, as listed below, are incorporated by
reference to material previously filed with the Commission as indicated:
Manufacturers Hanover Trust Company (now Chemical Bank)
Indenture dated as of May 1, 1971 (Exhibit (5) to Certificate of
Notification at Commission File No. 70-5012)
Eleventh Supplemental Indenture thereto dated as of December 1, 1986
(Exhibit (5) to Certificate of Notification at Commission File No.
70-7079)
Thirteenth Supplemental Indenture thereto dated as of February 1, 1989
(Exhibit (5) to Certificate of Notification at Commission File No.
70-7336)
Fourteenth Supplemental Indenture thereto dated as of June 1, 1989
(Exhibit (5) to Certificate of Notification at Commission File No.
70-7336)
Fifteenth Supplemental Indenture thereto dated as of October 1, 1989
(Exhibit (5) to Certificate of Notification at Commission File No.
70-7651)
Sixteenth Supplemental Indenture thereto dated as of October 1, 1992
(Exhibit (4) to Certificate of Notification at Commission File No.
70-7651)
Seventeenth Supplemental Indenture thereto dated as of August 1, 1993
(Exhibit (4) to Certificate of Notification at Commission File No.
70-8167)
Eighteenth Supplemental Indenture thereto dated as of December 1, 1993
(Exhibit (4) to Certificate of Notification at Commission File No.
70-8167)
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)
December 22, 1994
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 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) "Stock Credit" means a credit that is equivalent to one share
of CNG Common Stock.
(e) "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 retainer and fees
for attendance at meetings.
(f) "Director" means any individual serving on the Board of
Directors of the Company who is not an employee of the Company
or any of its subsidiaries.
(g) "Participant" means a Director who has filed an election to
participate under Section 3.1 with regard to any Plan Year.
(h) "Plan Administrator" means a Committee consisting of the
Secretary, Assistant Secretary, and the Controller of the
Company.
(i) "Plan Year" means the calendar year.
ARTICLE II
2.1 Participation in the Plan. Any individual who is a non-employee
Director may participate in the Plan.
1
<PAGE>
ARTICLE III
3.1 Election to Participate. 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 as soon as practicable following the end of the
Plan Year during which the Participant ceased to be a Director. Except for the
election for the 1987 Plan Year which may be made during January 1987, 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
within thirty days after 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 to defer delivered to the Secretary, any
Compensation will be paid directly to the Director.
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. If a Participant fails to make an election as to
mode 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 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 Common Stock
equivalent equal 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.
(c) Current Directors who have been accumulating Cash Credits
under the prior plan, will have a one-time opportunity to
convert some or all of those Cash Credits to Stock Credits on
the Election Form dated January 1987.
2
<PAGE>
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 in one installment as soon as
practicable following the end of the Plan Year in which the
Participant ceases to be a 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 account balance prior to his
or her termination of service as a Director or acceleration of
payment of any installments if the Plan Administrator finds
that continued deferral will result in financial hardship to
the Participant. Under this paragraph, conversion of Stock
Credits to cash will be made by multiplying the number of Stock
Credits converted by the Closing Price of the Common Stock on
the day the request is received.
(b) Distribution of a Participant's Cash Credit account balance
shall be made in cash. Distribution of his or her Stock Credit
account balance shall also 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.
(c) At the one-time election of a Participant made in writing to
the Secretary, all or any designated portion of the Stock
Credit account may be changed to, and such Participant shall
instead be credited with, a Cash Credit account as of the first
day of the calendar quarter following the quarter in which the
election is made. The amount credited to the Cash Credit
account shall be determined by multiplying the number of shares
of Common Stock to which the Stock Credit account is then
equivalent and as to which such election has been made, by the
Closing Price of the Company's Common Stock on the last
business day of the last month of the calendar quarter
preceding the date of the election to convert. Any Stock
Credits attributable to dividends paid on Common Stock during
the calendar quarter in which the election is made shall be
credited before making the conversion. Such election may be
made by a Participant, regardless of his or her age, at any
time prior to the end of the Plan Year in which the Participant
ceases to be a Director. An election by a Participant under
this Section 3.3(c) shall be irrevocable.
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
3
<PAGE>
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
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.
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 converted to cash and distributed in a lump sum to such person or
persons or the survivors thereof, including corporations, unincorporated
associates 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 in accordance with the Participant's will or in
the absence of a will, to the administrator of 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 whole and fractional shares of Common Stock
to which the Participant's Stock Credit account is equivalent by the Closing
Price of Common Stock on the last business day during the last month prior to
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 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 maintenance of the Plan.
ARTICLE V
5.1 Funding. The rights of a Participant to payment of benefits under
the Plan shall be those of an unsecured creditor of the Company. 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 payment 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.
4
<PAGE>
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.
5
CONSOLIDATED NATURAL GAS COMPANY
ANNUAL EXECUTIVE INCENTIVE PROGRAM
__________________________________
APPROVED 10-22-90
EFFECTIVE 01-01-91
AMENDED 07-09-91 (BONUS PAYMENT ALTERNATIVES)
AMENDED 07-13-92 (15% CAP ON BONUS POOL PERFORMANCE MEASURES)
1. ESTABLISHMENT OF BONUS POOL
___________________________
The Compensation and Benefits Committee of the Board of Directors annually
compares Consolidated's performance against performance goals that are approved
by the Committee at the beginning of each year. The performance measures may
be changed from time to time as deemed appropriate by the Committee.
The performance measures are as follows:
PERFORMANCE MEASURE (P.M.) HOW MEASURED (1) WTG.
____________________________ __________________________________ ____
1. Fixed Charge Coverage Ratio Against Internally Established Goal 20%
2. Return on Equity Against Peer Group ROE Average 40%
3. Net Income Against Internally Established Goal 20%
4. Cash Flow Against Internally Established Goal 20%
The Compensation and Benefits Committee will establish an annual bonus pool
as follows:
Weighted Average % Differential Between Goals and Actual Performance =
20% x % differential between goal and actual P.M. #1 + 40% x % differential
between CNG and Peer P.M. #2+
20% x % differential between goal and actual P.M. #3 + 20% x % differential
between goal and Actual P.M. #4
The Weighted Average % Differential as calculated by the above formula
determines the % of Corporate Net Income, not to exceed 3.25%, that will be
allocated to the bonus pool.
(1)Note:
_____
The % differential between the goal and actual performance for each
performance measure will not exceed +15%. The Compensation and Benefits
Committee approved putting an upside cap of +15% on each performance
measure to keep any one performance measure from substantially impacting
the overall weighting which is used to reflect overall performance and
determine bonus pool size.
2. ALLOCATION OF BONUS POOL TO SUBSIDIARY COMPANIES
________________________________________________
The Chairman will determine the distribution of the Bonus Pool to each
eligible subsidiary by comparing each company's performance against performance
measures that are established and approved by the Chairman at the beginning of
each performance year. The performance measures may be changed from time to
time as deemed appropriate by the Chairman and/or the Compensation and Benefits
Committee.
1
<PAGE>
Approximately 80% of the Bonus Pool will be allocated to participating
subsidiaries based on their respective actual performance compared to the
approved goals.
Approximately 20% of the Bonus Pool will be allocated at the discretion of
the Chairman.
The Subsidiary Performance Measures are as follows:
BUSINESS UNIT PERFORMANCE MEASURE WTG.
___________________________ _____________________________________ ____
CNG Corporate #1 Controllable O&M Expense vs. Goal 30%
#2 Net Income vs. Goal (Sum of Operating 30%
Co. N.I. Goals)
#3 Corporate ROE vs. Peer Group ROE Avg. 40%
Transmission & Distribution #1 Net Income vs. Goal 20%
#2 Cash Flow vs. Goal 20%
#3 Controllable O&M Expense vs. Goal 20%
#4 Throughput vs. Goal 20%
#5 Net Income to Net Plant vs. Goal 20%
Exploration & Production #1 Net Income vs. Goal 20%
#2 Cash Flow vs. Goal 20%
#3 Finding & Development Costs vs. Goal 20%
#4 Reserve Additions vs. Goal 20%
#5 Net Income to Net Plant vs. Goal 20%
Note:
_____
Operating companies may substitute an approved negotiated goal for one of
the Performance Measures other than net income or cash flow. The substituted
goal must be approved by the CEO and is subject to peer review.
Where Controllable O&M Expense Goals are established, it is recognized that
circumstances may change during the course of a performance period and
unanticipated expenses may be incurred over which the companies, or departments
at CNG Corporate, have no control. In those cases, i.e., unanticipated legal
expenses relating to unforeseeable legal proceedings, the effected company
president or CNG Corporate department head may make an "exception request" in
writing to the CEO either asking for a revision to the goal or that a
particular expense be excluded when comparing actual performance to goal. If
the expense is excluded, then any additional income generated from the expense
should also be excluded from appropriate net income amounts.
The operating company presidents will distribute 80% of their total
allocation based on their respective company's performance and retain 20% for
discretionary allocation based on individual participant contribution/
performance.
3. ESTABLISHMENT OF PERFORMANCE GOALS
__________________________________
The performance goals for the System and each operating company are to be
constructed with reference to five major sources of information: (1) the
Annual Long-Range Financial Forecast presented at the December or January
Board of Directors meeting; (2) actual performance for the prior year; (3)
information submitted at the November Business Plan Reviews; (4) management's
desire to achieve "stretch" goals; and, (5) compatibility with the System's
stated strategic objectives.
2
<PAGE>
The Long-Range Financial Forecast acts as a base line in developing
performance goals. Because this forecast is used in preparing longer-range
financial plans, it is generally conservative in nature. However, the minimum
earnings standards which the System must achieve to be a satisfactory
performer in the financial markets is usually higher than the forecast.
Actual performance for the prior year is primarily a reference point for
System performance measures. Investor expectations of growing earnings and
possible stock price appreciation are critical to our incentive award plan.
Historical performance is also valuable in assessing the reasonableness of
individual operating companies' performance goals.
In the November Business Plan Reviews, operating company managements
assess the opportunities and risks that their companies face relative to
achievement of the coming year's goals. This "upside/downside" analysis is
useful in documenting performance potential relative to issues that are
controllable by management. It also helps clarify the degree and magnitude of
risks that are external to the Company.
"Stretch" goals are useful in that they measure individual company's
attempts to achieve excellence. There is no question that the "stretch" goals
adopted by management are near the upper limit of what is achievable in
today's uncertain business environment. Nonetheless, an incentive award
system is aimed at eliciting superior performance from management.
Finally, the Corporate Strategy assigns special roles to the various
business units. Recognizing this, the performance measures, in part, relate
to these special roles, although profitability will remain the primary
yardstick of achievement.
4. PARTICIPANT ELIGIBILITY
_______________________
All employees on System Executive Payroll.
5. PARTICIPANT BONUS ALLOCATION GUIDELINES
_______________________________________
1. Based on participant's salary at end of performance year. Pro-rated
based on number of months of eligibility during performance year.
2. Based on participant's performance rating for performance year. To
be eligible, participant's performance must at least meet
expectations of the position.
3. Bonus Thresholds, Targets and Maximums are as follows:
<TABLE>
________________________________________________________________________________
________________
(a) (b)
(c)
THRESHOLD Bonus TARGET Bonus
MAX. Bonus
Executive As % of 12/31 As % of 12/31
As % of 12/31
Salary/Grade Base Salary Base Salary
Base Salary
________________________________________________________________________________
________________
<S> <C> <C>
<C>
12 - 15 20% 50%
70%
9 - 11 18% 45%
63%
7 - 8 16% 40%
56%
5 - 6 14% 35%
49%
3 - 4 12% 30%
42%
1 - 2 10% 25%
35%
________________________________________________________________________________
________________
(a) -15% total weighted average deviation from goals
(b) 0% total weighted average deviation from goals
(c) +15% total weighted average deviation from goals
</TABLE>
3
<PAGE>
Note:
_____
In recognition of the role that the operating company presidents have in
planning and achieving Corporate goals, their respective bonuses will be
weighted 30% with respect to the attainment of the Corporate goals used to
establish the bonus pool.
6. INCENTIVE AWARD PAYMENT ALTERNATIVES (AMENDED 07/09/91)
_______________________________________________________
1. Cash
2. Stock (CNG Common - $2.75 Par Value)
If an incentive award is paid, at the discretion of the Company, up to
50% of the award payment may be made with CNG common stock. If a portion of
the incentive award is given in stock, it will be in 25% increments of the
total award, i.e., 25% or 50%.
If stock awards are given, the dollar value of the stock award portion
will be calculated as follows:
The dollar value will be increased by a factor reflecting the short-term
cost of money. The Chase Manhattan prime interest rate in effect on March 1,
or the next business day following March 1 if that day falls on a weekend,
following the performance year will be used for this calculation. Once the
factor has been applied, the enhanced dollar value of the stock award portion
will be divided by the closing price of the Company's common stock on March 15
or the preceding business day if that day falls on a weekend, to determine the
number of shares of stock to be awarded. Only whole shares of stock will be
awarded. Uneven amounts will be rounded up to the next whole share.
If stock awards are given and a stock deferral election was NOT made:
1. All stock awards will be issued only in the name of the participant.
2. All stock awards will have a six-month holding period requirement or
restriction.
3. By letter of agreement (Attachment A) between the Company and the
participant, issuances of Common Stock ($2.75 par value) will be
registered in the name of the participant, but will be subject to
forfeiture and other terms, conditions and restrictions specified in
the Letter of Agreement and the 1991 Stock Incentive Plan.
4. Risk of forfeiture - If a participant leaves the employment of the
Company prior to the end of the six-month holding period, the
employee's rights to the stock will be forfeited. The only
exceptions would be termination of employment for death, permanent
and total disability, retirement or involuntary termination by the
Company. If one of the exception events occurs during the six-month
holding period, the stock award will be payable in full as soon as
practical following the event.
5. The participant shall not sell, assign, transfer, pledge, hypothecate
or make any other disposition of any shares of the awarded stock
until the six-month holding/restriction period has lapsed.
6. During the six-month holding period, the participant has the right to
vote the Stock and to receive dividends thereon. Any dividends paid
during the restricted holding period will be taxable to the employee
and will be treated and shown as W-2 earnings subject to withholding
during the holding period.
7. Stock certificates will be distributed at the end of the six-month
holding period and taxes will be due and payable upon receipt of the
stock certificate based on the market value of the stock at the end
of the holding period. The taxable event occurs at the time the
restrictions lapse.
4
<PAGE>
Note:
_____
The only additional restriction which is applicable only to Section 16
"Insiders" is when the "insiders" sell their bonus stock, which is a
reportable event, the sale of the stock will be subject to 16(b) short-swing
profit liabilities.
If stock awards are given and a stock deferral election had been made:
1. The deferred restricted stock will have a six-month holding period
requirement or restriction, i.e., (March 15 of the payment year -
September 15 of the payment year). Stock certificates will not be
issued for deferred restricted stock. Therefore, there are no voting
rights associated with deferred restricted stock.
2. The participant's "stock credit account" will be credited with common
stock equivalents, as determined on March 15 of the payment year, at
the end of the restricted holding period.
3. Risk of forfeiture - If a participant terminates employment with the
Company prior to the end of the six-month holding period, the
participant forfeits all rights to the awarded stock. The only
exceptions are death, permanent and total disability, retirement or
involuntary termination by the Company. If one of the exception
events occurs, payment will be made in accordance with the Executive
Incentive Deferral Plan.
4. Dividend equivalent payments will be credited to the participant's
stock credit account during the restriction period.
If the Company elects to pay a portion of the incentive award in stock, a
participant may elect to receive an additional 25% of the total award in stock
in lieu of 25% cash payment. If this option is elected by the participant, the
Chase Manhattan enhancement factor stated above will also be applied to this
portion of the award to determine the number of shares of stock to be awarded
instead of a cash payment. If this option is elected by the participant, this
stock is subject to the same six-month holding period requirement stated above.
If a participant opts for this method of payment, an irrevocable election to
do so must be made by January 31 OF THE PAYMENT YEAR on a form provided
specifically for this purpose by the Company (Attachment B). If a deferral
election is made, the 25% stock in lieu of cash election must be made at the
same time the deferral election is made (by January 31 of the performance year).
Taxes:
______
1. If no deferral election is made-
________________________________
Appropriate taxes will be withheld on the cash portion of the bonus
at time of payment. If a portion of the bonus is paid in restricted
stock, there is no tax liability at time of award. However, there is
a tax liability at ordinary income tax rates on the full value of the
shares (reflecting appreciation or depreciation) when the
restrictions lapse at the end of the six-month holding period when
the participant receives the stock certificate and is informed of
their tax liability. A participant has twenty-one calendar days
following the end of the holding period to remit a check to the
Company for applicable withholding taxes. If a participant fails to
remit a check to the Company within the twenty-one day period,
satisfying their full tax liability, the appropriate taxes will be
withheld from the participant's regular payroll check(s).
2. If a deferral election is made-
_______________________________
Social Security taxes (FICA) on the cash portion of the award which
is deferred will be withheld at the time of the award from the cash
portion not deferred or from the participant's regular payroll
check(s). All other taxes on the cash deferral will be payable on
the deferred payment date(s). With the exception of Social Security
tax, which is payable on the dollar value of the stock equivalents
posted to the participant's "stock credit account" at the end of the
restriction period, all other applicable taxes will be deferred until
the deferral payment date(s). The applicable Social Security tax
will be withheld from the
5
<PAGE>
participant's regular pay check(s) as soon as possible following the
end of the restriction period. If other arrangements are to be made
to fulfill the Social Security obligation, it is the responsibility
of the participant to make those arrangements directly with his/her
payroll department in a timely fashion so the obligation is fulfilled
within twenty-one calendar days from the end of the restriction period.
7. DEFERRED PAYMENT
________________
Participants may make an irrevocable election by January 31 of the
performance year, on a form provided by the Company specifically for deferral
and award payment purposes, to defer to their retirement date the receipt of
any amount of their prospective bonus awards as follows:
1. If cash is the method of payment determined by the Company for the
total incentive award, the participant may defer cash payment in
increments of 10%.
2. If a combination of cash and stock is the method of payment
determined by the Company, the participant may defer payment of the
cash portion and/or the stock portion in increments of 25%.
Details of the deferral program are covered in Attachment C - Executive
Incentive Deferral Plan.
12/13/94
6
<PAGE>
Attachment A
ANNUAL EXECUTIVE INCENTIVE PROGRAM
RESTRICTED STOCK AWARD
RESTRICTED STOCK AWARD AGREEMENT dated as of March 16, 1992, between
Consolidated Natural Gas Company, a Delaware corporation (CNG), and
____________, an employee of CNG or one of its subsidiary corporations
(Employee).
WHEREAS, on March 16, 1992, the Compensation and Benefits Committee of
the Board of Directors of CNG awarded Employee shares of common stock ($2.75
par value) of CNG (the awarded stock) pursuant to the CNG 1991 Stock Incentive
Plan (the Plan), a copy of which is attached as Exhibit A and made a part
hereof.
NOW, THEREFORE, in consideration of the mutual covenants hereinafter set
forth, intending to be legally bound, and for other good and valuable
consideration, the parties hereto hereby agree as follows:
1. The above described award is subject to all the terms and conditions
of the Plan and of this Agreement. For purposes of this Agreement,
the term "awarded stock" shall include any shares of common stock or
other securities of CNG which may be acquired by Employee with
respect to awarded stock as a result of a stock split or stock
dividend or other extraordinary corporate transaction affecting
shares. If there is any conflict between the provisions of this
Agreement and the provisions of the Plan, the provisions of the Plan
shall govern.
2. The certificate representing ________ shares of awarded stock,
registered in the name of Employee, will be held by CNG, together
with a stock power which shall be executed in favor of CNG by
Employee, until such time as the restriction on the awarded stock
shall lapse. Except as otherwise provided in the Plan, all
restrictions on the shares of awarded stock shall lapse on September
16, 1992.
1
<PAGE>
If Employee shall die, become permanently and totally disabled, or
reach age 65, all restrictions shall lapse and cease to be effective
as of the end of the month in which Employee dies, attains age 65, or
is deemed to be permanently and totally disabled. For purposes of
this agreement, Employee shall be deemed to be permanently and
totally disabled if Employee is terminated due to disability and is
eligible as a result thereof for a disability pension under CNG's
pension plan then in effect or benefits under CNG's long-term
disability plan then in effect.
3. While the certificate is held by CNG, Employee shall have the right
to vote the awarded stock and to receive dividends thereon.
4. Employee shall not sell, assign, transfer, pledge, hypothecate or
make any other disposition of any shares of the awarded stock until
the restriction on such shares shall have lapsed.
5. Subject to the provisions of the Plan and except as provided in
Section 2 hereof, Employee shall forfeit his/her then remaining
rights to any awarded stock as to which restriction has not then
lapsed if his/her employment with CNG or any of its subsidiary
corporations shall terminate for any reason.
6. If Employee has elected to defer, under the terms of the CNG
Executive Incentive Deferral Plan, the receipt of awarded stock set
forth in paragraph 2, no certificate representing such deferred
awarded stock will be issued. The restrictions on such stock award
set forth herein shall be applicable to deferred stock awards except
that Employee shall not have the right to vote deferred stock. A
stock credit will be recorded on September 16, 1992,
2
<PAGE>
on the books of the Company in accordance with the terms of the CNG
Executive Incentive Deferral plan reflecting the awarded stock.
Dividend equivalent payments will be credited to Employee's stock
credit account on the deferred awarded stock during the restriction
period.
7. Upon lapse of the restriction on awarded shares and as a condition to
the delivery of certificate therefor, CNG shall withhold from the
employee's wages all taxes which it is required to withhold under
federal, state, and local laws.
8. This agreement shall be governed by the laws of the State of
Delaware. This Agreement constitutes the entire agreement between the
parties with respect to the awarded stock under the Plan, and
supersedes any prior agreements or documents with respect to such
awarded stock. No amendment, alteration, suspension, discontinuation
or termination of this Agreement which may impose any additional
obligation upon CNG or any subsidiary or impair the rights of
Employee with respect to the awarded stock shall be valid unless in
each instance such amendment, alteration, suspension, discontinuation
or termination is expressed in a written instrument duly executed in
the name and on behalf of CNG and by Employee.
IN WITNESS WHEREOF, CNG has caused this Restricted Stock Award Agreement
to be duly executed by an authorized officer and Employee has hereunto set
his/her hand and seal, all as of the date and year first above written.
CONSOLIDATED NATURAL GAS COMPANY
By __________________________
Secretary
__________________________L.S.
Employee
3
<PAGE>
Attachment B
Consolidated Natural Gas System
EXECUTIVE Instructions:
DEFERRAL AND AWARD - Complete this form to irrevocably
PAYMENT ELECTIONS defer the receipt of all or a portion
of the incentive award.
CGS 873 10/91 - Complete a Beneficiary Designation Form
(CGS 874) if this is your first
deferral election or if you wish to change a
prior designation.
- Completion of this form does not guarantee
that an incentive award will
be paid for any performance year.
- Must be submitted by January 31 of the
performance year to:
Human Resources Department
Consolidated Natural Gas Company
CNG Tower
625 Liberty Avenue
Pittsburgh, PA 15222-3199
___________________________________________________________________
/ Last Name (Please print) / First Name / Middle /
/ / / Initial /
/__________________________________________________________________/
/ Subsidiary Company / Social Security Number /
/__________________________________________________________________/
I hereby authorize the deferral of the receipt of my incentive award to my
date of retirement by making the following irrevocable election: (BOTH
ALTERNATIVES MUST BE COMPLETED)
CASH ONLY PAYMENT ALTERNATIVE
For performance year 19___, if the Company pays the total award in cash, I
elect to defer ___% of the award (MUST BE IN 10% INCREMENTS).
1
<PAGE>
CASH AND RESTRICTED STOCK PAYMENT ALTERNATIVE
For performance year 19___, I elect to have an additional 25% of my total
incentive award paid in restricted stock in lieu of cash. ____ Yes
____ No.
I elect to defer:
_____ % of the cash portion of the award (MUST BE IN 25% INCREMENTS)
_____ % of the restricted stock portion of the award (MUST BE IN 25%
INCREMENTS)
Award payment and deferred elections will remain in effect for future
performance years unless revoked in writing or a new deferral election is
submitted. Applicable FICA taxes will be withheld on the total value of
the award on date of credit to the deferral account.
________________________________________
Signature Date
Forward WHITE PART to Human Resources - Retain CANARY PART for
your file.
2
<PAGE>
Attachment C
CONSOLIDATED NATURAL GAS COMPANY
EXECUTIVE INCENTIVE DEFERRAL PLAN
Effective 12/13/94
<PAGE>
CONSOLIDATED NATURAL GAS COMPANY
EXECUTIVE INCENTIVE DEFERRAL PLAN
Table of Contents
_________________
Section Page
_______ ____
1. Purpose 1
2. Definitions 1
3. Eligibility 2
4. Deferral of Awards 2
5. Payment of Deferred Amounts 7
6. Administration 10
7. General Provisions 11
<PAGE>
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.
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.
1
<PAGE>
(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 l6 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.
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.
(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
2
<PAGE>
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 3l 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 3l 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 (i) 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
3
<PAGE>
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 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 (depending
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
4
<PAGE>
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
5
<PAGE>
(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 l2 of the
Securities Exchange Act of 1934, Stock Credits credited to each
Participant's Stock Credit account shall be converted
6
<PAGE>
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's cash
credit [and] [and/or] Stock Credit accounts 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
7
<PAGE>
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.
8
<PAGE>
(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
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.
9
<PAGE>
(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.
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,
10
<PAGE>
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 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
11
<PAGE>
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
12
<PAGE>
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.
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
13
<PAGE>
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 l6 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.
14
CONSOLIDATED NATURAL GAS COMPANY
NON-EMPLOYEE DIRECTORS' RESTRICTED STOCK PLAN
The purpose of this Non-Employee Directors' Restricted Stock Plan (the
"Plan") is to assist Consolidated Natural Gas Company, a Delaware corporation
(the "Company"), in retaining and attracting highly qualified persons to serve
as non-employee Directors by enabling such Directors to acquire a proprietary
interest in the Company, and by providing to such Directors an incentive to
continue to serve the Company. The Plan provides for the automatic annual
grant to each non-employee Director of 100 shares of the Company's Common
Stock, par value $2.75 per share ("Common Stock"), subject to restrictions
(the "Restricted Stock").
1. AMOUNT AND SOURCE OF STOCK
The aggregate number and class of shares which may be granted as
Restricted Stock under the Plan is 15,000 shares of Common Stock, subject to
adjustment as provided in Section 7. Such shares may be authorized but
unissued shares of Common Stock of the Company or may be shares held in or
acquired for the treasury of the Company. Any Restricted Stock granted
hereunder which is forfeited pursuant to the terms of the Plan shall not be
available for grants under the Plan.
1
<PAGE>
2. ADMINISTRATION OF THE PLAN
The Plan shall be administered by the Compensation and Benefits Committee
of the Board of Directors of the Company (the "Committee"). In addition to
any other powers granted to the Committee, it shall have the following powers,
subject to the express provisions of the Plan:
a) to construe and interpret the Plan;
b) to make all determinations and take all other actions necessary or
advisable for the administration of the Plan, except that the persons entitled
to receive Restricted Stock and the dates and amounts of such awards shall be
determined as provided in Articles 4, 5 and 6, and the Committee shall have no
discretion as to such matters; and
c) to delegate to Officers or managers of the Company the authority to
perform administrative functions under the Plan.
Any determinations or actions made or taken by the Committee pursuant to
this Article shall be binding and final.
3. EFFECTIVE DATE AND TERM OF PLAN
The Plan shall be effective on September 14, 1993, the date on which it
was adopted by the Board, subject to subsequent approval by shareholders of
the Company holding not less than a majority of the shares present and voting
at a meeting of its shareholders (provided a quorum is present). Unless
earlier
2
<PAGE>
terminated by the Board, the Plan shall terminate at such time that no further
Common Stock is available for grants under the Plan.
4. ELIGIBILITY
Each Director of the Company who is not then, and has not been at any
time during the previous year, an employee of the Company or any parent or
subsidiary of the Company shall be eligible to receive Restricted Stock under
the Plan. Notwithstanding the foregoing, no Director who is serving on the
Board as a result of a nomination or appointment pursuant to the terms of any
debt instrument, preferred stock, underwriting agreement or other contract
entered into by the Company shall be eligible to participate in the Plan. No
person other than those specified in this Section 4 shall participate in the
Plan.
5. GRANTS OF RESTRICTED STOCK
Each person who is an eligible Director of the Company immediately
following the Annual Shareholders' Meeting shall receive an annual grant of
100 shares of Restricted Stock on the date of the Annual Shareholders'
Meeting.
6. TERMS OF RESTRICTED STOCK
Except as hereinafter provided, all Restricted Stock shall be subject to
the following terms and conditions:
(a) Rights and Restrictions. A participant granted Restricted Stock
shall be entitled to receive dividends on such Restricted Stock when, as and
3
<PAGE>
if dividends are declared and paid on Common Stock, such participant shall be
entitled to vote Restricted Stock on any matter submitted to a vote of holders
of Common Stock, and such participant shall have all other rights of a
shareholder of the Company except as otherwise expressly provided under this
Section 6. Until restrictions on Restricted Stock expire in accordance with
Section 6(b), a participant shall have no right to sell, transfer, give,
assign, pledge or otherwise encumber or dispose of such Restricted Stock
(except for transfers and forfeitures to the Company). Restricted Stock shall
be granted under the Plan for no consideration other than the services of the
Director to be performed during the period the restrictions set forth in this
Section 6 (the "Restrictions") are in effect.
(b) Expiration of Restrictions. The Restrictions on a Director's
Restricted Stock shall lapse in 25% installments on the anniversary date of
each grant or shall lapse in total upon the participant Director's retirement
at age 70, or the Director's ceasing to serve due to death or disability,
whichever first occurs. In the event of a "Change of Control" of the Company
as that term is defined in the Company's 1991 Stock Incentive Plan, all
Restrictions on all outstanding Restricted Stock will lapse and the Company
will repurchase all such shares which were awarded more than six months prior
to the Change of Control at the then fair market value.
(c) Forfeiture. A participant who ceases to serve the Company as a
Director shall, at the time he or she ceases to hold office, forfeit any
Restricted Stock as to which the Restrictions have not theretofore expired,
unless the participant ceases to serve as a Director as a result of the death
or following the disability of the Director; for this purpose, "disability"
shall
4
<PAGE>
have the meaning as established in the Company's long-term disability plan
provided, however, that, if a participant ceases to serve as a Director and
immediately thereafter he or she becomes employed by the Company or any
subsidiary of the Company, then, solely for purposes of the Plan, such
participant shall not be treated as having ceased service as a Director, and
employment by the Company or any subsidiary of the Company shall be treated,
for purposes of the Plan, as if such employment were service as a Director
(solely so that Restrictions on such participant's Restricted Stock shall
continue in effect until lapsed in accordance with Section 6).
(d) Certificates for Shares of Restricted Stock. Restricted Stock
granted under the Plan to a Director shall be evidenced by issuance of one or
more certificates in the name of the Director, bearing an appropriate legend
referring to the terms, conditions and Restrictions applicable to Restricted
Stock, and shall remain in the physical custody of the Secretary of the
Company until such time as the Restrictions on such shares have expired. In
addition, Restricted Stock shall be subject to such stop-transfer orders and
other Restrictions as the General Counsel of the Company shall deem advisable
under federal or state securities laws, rules and regulations thereunder or
the rules of any national quotation system or any national securities exchange
on which Common Stock is quoted or listed, and the General Counsel may cause a
legend or legends to be placed on any such certificates to make appropriate
reference to such Restrictions.
(e) Restricted Stock Agreement; Stock Powers. The Company and each
Director to whom Restricted Stock is granted hereunder shall enter into a
Restricted Stock Agreement in the form as the Board may approve, to
5
<PAGE>
evidence the grant of Restricted Stock hereunder. In addition, each Director
to whom Restricted Stock is granted shall execute one or more stock powers, in
such form as may be specified by the General Counsel, authorizing the transfer
of the Restricted Stock to the Company, in order to give effect to the
forfeiture provisions of Section 6(c).
7. ADJUSTMENT PROVISIONS
In the event of any recapitalization, reorganization, merger,
consolidation, spin-off, combination, repurchase, exchange of shares or other
securities of the Company, stock split or reverse split, liquidation,
dissolution or other similar corporate transaction or event which affects
Common Stock such that an adjustment is determined by the Board to be
appropriate in order to prevent dilution or enlargement of participants'
rights under the Plan, then the Board shall, in such manner as it may deem
equitable, (i) adjust any or all of the number and kind of shares reserved
under the Plan and the number and kind of shares which may thereafter be
issued to Directors as Restricted Stock and (ii), if participants holding
Restricted Stock would not be affected by the event in substantially the same
way as other holders of Common Stock, adjust the number and kind of shares
outstanding as Restricted Stock.
8. AMENDMENT TO THE PLAN
The Board may amend, alter, suspend, discontinue, or terminate the Plan
at any time without the approval or consent of the Company shareholders or
Plan participant, provided that (i), without the approval of the Company
shareholders, no amendment, alteration, suspension, discontinuation, or
termination of the Plan
6
<PAGE>
shall be made if shareholder approval is required by any federal or state law
or regulation, or any applicable listing requirement or rule of a securities
trading system or stock exchange on which the Common Stock is then quoted or
listed, or the Board in its discretion determines that obtaining such
shareholder approval is for any reason advisable; (ii) without the consent of
any affected Plan participant, no amendment, alteration, suspension,
discontinuation, or termination of the Plan may impair the rights of such
participant relating to any Restricted Stock theretofore granted to him or
her; and (iii) any Plan provision that specifies the Directors who may receive
Restricted Stock, the amount of Restricted Stock, and the timing of grants to
Directors, or is otherwise a "plan provision" within the meaning of Rule 16b-
3(c)(2)(ii) under the Exchange Act (as initially adopted in SEC Release No.
34-28869, February 8, 1991) or any successor provision thereto, shall not be
amended more than once every six months, other than to comport with changes in
the Internal Revenue Code of 1986, as amended, the Employee Retirement Income
Security Act of 1974, as amended, or the rules thereunder.
9. GENERAL PROVISIONS
(a) Compliance with Securities Laws and NASDAQ Requirements. No
Restricted Stock shall be granted and no shares shall be distributed in a
transaction subject to the registration requirements of the Securities Act of
1933, as amended, or any state securities law or subject to any requirement of
the National Association of Securities Dealers, Inc. (the "NASD") as a
condition to the quotation of the shares on any national quotation system or
under any listing agreement between the Company and any national securities
exchange, and no grant of Restricted Stock will confer upon any participant
rights to such
7
<PAGE>
distribution, until such laws and other obligations of the Company have been
complied with in full.
(b) No Right to Continue as a Director. Nothing contained in the Plan
or any Restricted Stock Agreement shall confer upon any Director any right to
continue to serve as a Director of the Company.
(c) Governing Law. The validity, construction and effect of the Plan
and any Restricted Stock Agreement shall be determined in accordance with the
laws of the State of Delaware, without giving effect to principles of
conflicts of laws.
Adopted by the Board of Directors: September 14, 1993.
As Approved by Shareholders: May 17, 1994.
8
EXHIBIT 11
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
COMPUTATION OF PER SHARE EARNINGS (Note 1)
(In Thousands, Except Per Share Data)
<TABLE>
<CAPTION>
________________________________________________________________________________
_______________________
Years Ended December 31, 1994
1993 1992
________________________________________________________________________________
_______________________
<S> <C>
<C> <C>
EARNINGS PER SHARE OF COMMON STOCK,
as Shown on the Consolidated Statement of Income
Income before cumulative effect of change in
accounting principle. . . . . . . . . . . . $183,171
$188,494 $194,958
Cumulative effect of applying Statement of
Financial Accounting Standards No. 109 (SFAS No. 109). -
17,422 -
________
________ ________
Net income . . . . . . . . . . . . . . . $183,171
$205,916 $194,958
========
======== ========
Average common shares outstanding . . . . . . . 93,000
92,808 89,128
________
________ ________
Earnings per share of common stock
Income before cumulative effect of change
in accounting principle . . . . . . . . . $ 1.97
$ 2.03 $ 2.19
Cumulative effect of applying SFAS No. 109. . . . -
.19 -
________
________ ________
Net income . . . . . . . . . . . . . . $ 1.97
$ 2.22 $ 2.19
========
======== ========
PRIMARY EARNINGS PER SHARE
Income before cumulative effect of change
in accounting principle . . . . . . . . . . $183,171
$188,494 $194,958
Cumulative effect of applying SFAS No. 109 . . . . -
17,422 -
________
________ ________
Net income . . . . . . . . . . . . . . . $183,171
$205,916 $194,958
========
======== ========
Average common shares outstanding . . . . . . . 93,000
92,808 89,128
Incremental shares resulting from
assumed exercise of stock options. . . . . . . 78
316 139
________
________ ________
Average common shares, as adjusted . . . . . . . 93,078
93,124 89,267
________
________ ________
Primary earnings per share
Income before cumulative effect of change
in accounting principle . . . . . . . . . $ 1.97
$ 2.02 $ 2.18
Cumulative effect of applying SFAS No. 109. . . . -
.19 -
________
________ ________
Net income . . . . . . . . . . . . . . $ 1.97
$ 2.21 $ 2.18
========
======== ========
________________________________________________________________________________
_______________________
</TABLE>
<PAGE>
EXHIBIT 11
(Cont.)
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
COMPUTATION OF PER SHARE EARNINGS (Note 1) (Continued)
(In Thousands, Except Per Share Data)
<TABLE>
<CAPTION>
________________________________________________________________________________
_______________________
Years Ended December 31, 1994
1993 1992
________________________________________________________________________________
_______________________
<S> <C>
<C> <C>
FULLY DILUTED EARNINGS PER SHARE (Note 2)
Income before cumulative effect of change
in accounting principle . . . . . . . . . . $183,171
$188,494 $194,958
Interest on 7 1/4% Convertible Subordinated
Debentures, net of tax effect . . . . . . . . 12,465
12,663 13,522
________
________ ________
Income before cumulative effect of change
in accounting principle, as adjusted. . . . . . 195,636
201,157 208,480
Cumulative effect of applying SFAS No. 109 . . . . -
17,422 -
________
________ ________
Net income, as adjusted. . . . . . . . . . . $195,636
$218,579 $208,480
========
======== ========
Average common shares outstanding . . . . . . . 93,000
92,808 89,128
Incremental shares resulting from
assumed exercise of stock options. . . . . . . 96
349 161
Shares issuable from assumed conversion of 7 1/4%
Convertible Subordinated Debentures . . . . . . 4,577
4,630 4,630
________
________ ________
Average common shares, as adjusted . . . . . . . 97,673
97,787 93,919
________
________ ________
Fully diluted earnings per share
Income before cumulative effect of change
in accounting principle, as adjusted . . . . . $ 2.00
$ 2.06 $ 2.22
Cumulative effect of applying SFAS No. 109. . . . -
.18 -
________
________ ________
Net income, as adjusted . . . . . . . . . . $ 2.00
$ 2.24 $ 2.22
========
======== ========
________________________________________________________________________________
_______________________
<FN>
Notes:
(1) This calculation is submitted in accordance with Regulation S-K
Item 601(b)(11) although not required by footnote 2 to paragraph 14
of APB Opinion No. 15 because it results in dilution of less than 3%.
(2) This calculation is submitted in accordance with Regulation S-K
Item 601(b)(11) although it is contrary to paragraph 40 of APB
Opinion No. 15 because the assumed conversion of the 7 1/4%
Convertible Subordinated Debentures produces an antidilutive result.
</TABLE>
EXHIBIT 12
CONSOLIDATED NATURAL GAS COMPANY AND SUBSIDIARIES
RATIO OF EARNINGS TO FIXED CHARGES
(Thousands of Dollars)
<TABLE>
<CAPTION>
________________________________________________________________________________
_____________________
Years Ended December 31, 1994 1993 1992
1991 1990
________________________________________________________________________________
_____________________
<S> <C> <C> <C>
<C> <C>
Earnings:
Income before cumulative
effect of change
in accounting principle . . . . $183,171 $188,494 $194,958
$168,613 $163,770
Add income taxes (excluding
cumulative effect of change
in accounting principle). . . . 82,427 99,906 68,623
54,844 52,123
________ ________ ________
________ ________
Income before income taxes . . 265,598 288,400 263,581
223,457 215,893
Distributed income from
unconsolidated investees, less
equity in earnings thereof . . . 560 2,960 (1,707)
(2,131) -
________ ________ ________
________ ________
Subtotal . . . . . . . . 266,158 291,360 261,874
221,326 215,893
________ ________ ________
________ ________
Add fixed charges:
Interest on long-term debt,
including amortization of
debt discount and expense
less premium . . . . . . . 88,788 85,265 93,594
96,528 82,905
Other interest expense . . . . 7,992 4,995 7,170
14,727 34,129
Portion of rentals deemed to
be representative of the
interest factor . . . . . . 8,486 8,378 7,822
7,460 7,653
________ ________ ________
________ ________
TOTAL FIXED CHARGES. . . . . . . 105,266 98,638 108,586
118,715 124,687
________ ________ ________
________ ________
TOTAL EARNINGS . . . . . . . . $371,424 $389,998 $370,460
$340,041 $340,580
======== ======== ========
======== ========
RATIO OF EARNINGS TO FIXED
CHARGES . . . . . . . . . . 3.53 3.95 3.41
2.86 2.73
======== ======== ========
======== ========
________________________________________________________________________________
_____________________
</TABLE>
EXHIBIT 21
SUBSIDIARIES OF CONSOLIDATED NATURAL GAS COMPANY
Percent Voting
Securities
Owned by
State of Immediate
Name of Company Incorporation Parent Company
_____________________________________________ _____________ ______________
CONSOLIDATED NATURAL GAS COMPANY . . . . Delaware
Subsidiary companies:
Consolidated Natural Gas Service Company, Inc. Delaware 100%
CNG Transmission Corporation . . . . . Delaware 100%
CNG Iroquois, Inc. . . . . . . . Delaware 100%
The East Ohio Gas Company*. . . . . . Ohio 100%
The Peoples Natural Gas Company . . . . Pennsylvania 100%
Virginia Natural Gas, Inc. . . . . . Virginia 100%
Hope Gas, Inc. . . . . . . . . . West Virginia 100%
West Ohio Gas Company . . . . . . . Ohio 100%
CNG Producing Company . . . . . . . Delaware 100%
CNG Pipeline Company . . . . . . . Texas 100%
CNG Energy Company**. . . . . . . . Delaware 100%
CNG Bear Mountain, Inc. . . . . . . Delaware 100%
CNG Market Center Services, Inc. . . . Delaware 100%
CNG Technologies, Inc. . . . . . . Delaware 100%
Granite Road CoGen, Inc. . . . . . Texas 100%
CNG Energy Services Corporation . . . . Delaware 100%
CNG Power Services Corporation . . . . Delaware 100%
CNG Lakewood, Inc. . . . . . . . Delaware 100%
CNG Storage Service Company . . . . . Delaware 100%
Consolidated System LNG Company . . . . Delaware 100%
CNG Research Company. . . . . . . . Delaware 100%
CNG Coal Company . . . . . . . . . Delaware 100%
CNG Financial Services, Inc. . . . . . Delaware 100%
*During 1994, The Public Utilities Commission of Ohio approved the merger of
the Company's former subsidiary, The River Gas Company, into The East Ohio
Gas Company.
**Effective January 16, 1995, CNG Energy Company was renamed CNG Power Company.
RALPH E. DAVIS ASSOCIATES, INC.
CONSULTANTS - PETROLEUM AND NATURAL GAS
3555 TIMMONS LANE - SUITE 1105
HOUSTON, TEXAS 77027
(713) 622-8955
February 14, 1995
CONSOLIDATED NATURAL GAS COMPANY
CNG Tower
625 Liberty Avenue
Pittsburgh, Pennsylvania 15222-3199
Report Covering Natural Gas Supply
And Owned Oil Reserves
December 31, 1994
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
(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 l943, Consolidated's gas supply was obtained from
company-owned production and by purchase from fields located within the
Appalachian area. From 1943 to 1993 Consolidated purchased gas from pipeline
companies which obtained their gas supply from fields in the Gulf Coast and
Southwest. Because of regulatory changes, Consolidated had been reducing the
volumes of gas purchased from pipeline companies since the mid-1980's. In 1993,
<PAGE>
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 14, 1995
Page 2
all remaining long-term gas purchase contracts with pipelines were converted to
firm transport contracts as the result of Federal Energy Regulatory Commission
(FERC) Order 636. Consolidated now purchases gas under contracts with
producers and marketers, and also purchases gas on the spot market. A
substantial part of these gas supplies are also obtained from fields in the Gulf
Coast and Southwest. Since 1957 Consolidated has also been engaged in
exploration and production of gas in Louisiana and the Texas Gulf Coast,
including offshore. During the twelve months ended December 31, 1994 most of
the gas produced and purchased by the Company was obtained from the Southwest.
All gas volumes herein are stated at a measuring base of 14.73 pounds per
square inch absolute.
Gas requirements for Consolidated (including Canadian sales) increased
from 648 billion cubic feet in 1993 to 666 billion cubic feet in 1994.
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, 1994, to be 321 billion cubic feet from company-owned wells and 638
billion cubic feet from gas purchase wells, for a total of 959 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
<PAGE>
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 14, 1995
Page 3
will locate appreciable new reserves. In addition, subsidiary companies had
remaining working interest oil reserves estimated at 535,507 barrels in the
Appalachian area.
CNG PRODUCING COMPANY
CNG Producing Company is Consolidated's primary exploration and production
subsidiary. As of December 31, 1994, the estimated proved working interest
reserves of CNG Producing Company are 743 billion cubic feet of gas and
46,107,012 barrels of crude oil and condensate. The foregoing totals include
approximately 1 billion cubic feet of gas and 5,337,287 barrels of heavy oil
reserves in Canada.
In the United States, CNG Producing Company has proved reserves in 10
states and the offshore area of the Gulf Coast. The majority of CNG Producing
Company's United States reserves are in the Gulf Coast and Mid-Continent areas.
The estimated proved reserves in the United States are 742 billion cubic feet
of gas and 40,769,725 barrels of crude oil and condensate.
The estimated Appalachian proved reserves as of December 31, 1994 for CNG
Producing Company, which are included in the total Appalachian reserves
disclosed earlier in this report, are 92 billion cubic feet of gas and 131,614
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, 1994 are 8 billion cubic feet.
<PAGE>
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 14, 1995
Page 4
SOUTHWEST GAS
During the past several years, the FERC has implemented new regulations
designed to increase competition in the natural gas industry. The FERC's latest
action, Order 636, is designed to further increase competition and continue the
significant restructuring of the interstate gas pipeline industry that began in
1985 with the establishment of open access transportation. As a result of Order
636, pipeline companies are now primarily contract carriers, providing
transportation for gas purchased by customers directly from other sources.
Since pipeline companies are no longer legally responsible for aggregating gas
supplies, these companies have greatly reduced, or have terminated, their
contracted gas volumes.
All long term gas supply contracts between Consolidated and its previous
pipeline suppliers have now been converted to firm transportation agreements.
Consolidated's subsidiaries have replaced a portion of these pipeline supplies
with volumes obtained under gas supply contracts with various gas producing
companies and marketing groups. These gas supply contracts have remaining
terms ranging from a few months to as long as ten (10) years. Purchase
entitlements under these contracts total approximately 375 billion cubic feet,
if all volumes are requested. This estimate gives no consideration to the
estimated volumes of spot market gas which may be purchased in the future.
GAS STORAGE
The Company owns and operates 26 gas storage fields, five of which are
owned and operated jointly with other companies. One storage field is owned
and operated jointly with Texas Eastern, one with Tennessee, one with North
Penn Gas, one with both Tennessee and National Fuel Gas Supply Corporation,
and another with both Texas Eastern and Transcontinental. Consolidated's net
injected gas stored at December 31, 1994, was 480 billion cubic feet (including
52 billion cubic feet of remaining non-recoverable native gas, and 60 billion
cubic feet of non-recoverable base gas).
<PAGE>
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 14, 1995
Page 5
The proximity of these storage fields to principal markets and their high
deliverability are important factors in enabling the Company to meet peak loads
and daily requirements during the heating season, and permit the gas purchased
to be taken relatively uniformly in summer and winter.
There are additional depleted, or nearly depleted, gas fields in the
Appalachian area which can be converted to storage fields if needed.
POTENTIAL SUPPLY SOURCES
In order to meet the demands for gas in its market area over the long-term
future, Consolidated may need additional supplies over those available from the
sources discussed above.
Canadian authorities have increased the volumes of gas which may be
imported into the United States. Gas presently being imported from Canada is
principally obtained from provinces in Western Canada. In the future, the
availability of additional gas will probably be dependent on gas from frontier
areas such as the MacKenzie Basin - Beaufort Sea area and/or the Arctic Islands.
Such additional gas from Canada may be available in part to Consolidated
directly or through other suppliers.
Other potential sources of gas include Alaska, Mexico, liquefied natural
gas from abroad, synthetic gas from coal or other feed stock and additional
coalbed methane.
SUMMARY AND CONCLUSIONS
We have estimated proved working interest crude oil and condensate reserves
owned by Consolidated from sources in the United States and Canada at 46,510,905
barrels as of December 31, 1994 as follows:
<PAGE>
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 14, 1995
Page 6
Stock Tank Barrels
Appalachian Field Reserves 403,893
CNG Producing Company
Southwest 45,975,398
Appalachian 131,614
__________
Sub Total 46,107,012
TOTAL - OWNED OIL AND CONDENSATE RESERVES 46,510,905
We have estimated the gas reserves available to Consolidated from
sources in the United States and Canada at 2,465 billion cubic feet as of
December 31, 1994 as follows:
Billion
Cubic Feet
at 14.73 psia
Appalachian Field Reserves
Company-Owned Wells 229
Gas Purchase Contract Wells 638
Gas in Storage Reservoirs 480
___________
Sub-Total 1,347
CNG Producing Company Reserves
Company-Owned Wells
Southwest 651
Appalachian 92
___________
Sub-Total 743
Gas Supply Contracts 375
___________
TOTAL - CONTROLLED GAS RESERVES 2,465
Consolidated's requirements for the twelve months ended December 31, 1994,
including sales of gas produced in Canada, were approximately 666 billion cubic
feet.
Additional supplies are expected to become available from the Appalachian
area, the Gulf Coast and other areas and from company-owned reserves.
<PAGE>
RALPH E. DAVIS ASSOCIATES, INC.
Consolidated Natural Gas Company February 14, 1995
Page 7
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.
Thomas N. Sudderth
President
TNS:cg
<PAGE>
RALPH E. DAVIS ASSOCIATES, INC.
CONSULTANTS - PETROLEUM AND NATURAL GAS
3555 TIMMONS LANE - SUITE 1105
HOUSTON, TEXAS 77027
(713) 622-8955
March 24, 1995
CONSENT OF INDEPENDENT GEOLOGISTS
We hereby consent to the use of our report dated February 14, 1995,
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, 1994. We further consent to the filing hereof as an Exhibit to
said Annual Report on Form 10-K.
We also consent to the incorporation by reference into (i) the
Registration Statements on Form S-3 (Nos. 33-1040, 33-49469 and 33-52585) and
Form S-8 (Nos. 2-77204, 2-97948, 33-40478 and 33-44892) of Consolidated
Natural Gas Company, and (ii) the prospectuses made a part thereof, of our
estimates of Company-owned oil and gas reserves in the United States and
Canada included in Consolidated Natural Gas Company's Annual Report on Form
10-K for the year ended December 31, 1994. We also consent to the references
to us under the heading "Experts" in such Prospectuses.
RALPH E. DAVIS ASSOCIATES, INC.
Thomas N. Sudderth
President
JOHN T. BOYD COMPANY PITTSBURGH
MINING AND Four Gateway Center, Suite 1900
GEOLOGICAL 444 Liberty Avenue
ENGINEERS Pittsburgh, PA 15222-1212
(412) 562-1770
(412) 562-1953 FAX
DENVER
(303) 293-8988
(303) 293-2232 FAX
JOHN T. BOYD SENIOR VICE PRESIDENTS
Chairman Ronald L. Lewis
JAMES W. BOYD Lawrence M. Thomas
President
LAWRENCE D. GENT VICE PRESIDENTS
Executive Vice President David M. Carris
Russell P. Moran
BRADLEY CHARLES LEWIS Robert M. Quinlan
Assistant to the President James J. Schaeffer, Jr.
George V. Weisdack
March 24, 1995
CONSENT OF CONSULTING MINING
AND GEOLOGICAL ENGINEERS
We hereby consent to the use of our estimates of coal reserves in
Consolidated Natural Gas Company's Annual Report on Form 10-K for the year
ended December 31, 1994. We further consent to the filing hereof as an
Exhibit to said Annual Report on Form 10-K.
We also consent to the incorporation by reference into (i) the
Registration Statements on Form S-3 (Nos. 33-1040, 33-49469 and 33-52585) and
Form S-8 (Nos. 2-77204, 2-97948, 33-40478 and 33-44892) of Consolidated
Natural Gas Company, and (ii) the prospectuses made a part thereof, of our
estimates of coal reserves included in Consolidated Natural Gas Company's
Annual Report on Form 10-K for the year ended December 31, 1994. We also
consent to the references to us under the heading "Experts" in such
Prospectuses.
James W. Boyd
President
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED FINANCIAL STATEMENTS INCLUDED IN ITEM 8 OF CONSOLIDATED NATURAL
GAS COMPANY'S ANNUAL REPORT ON FORM 10-K FOR THE YEAR ENDED DECEMBER 31,
1994, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,859,965
<OTHER-PROPERTY-AND-INVEST> 1,166,681
<TOTAL-CURRENT-ASSETS> 1,064,739
<TOTAL-DEFERRED-CHARGES> 331,651
<OTHER-ASSETS> 95,637
<TOTAL-ASSETS> 5,518,673
<COMMON> 255,827
<CAPITAL-SURPLUS-PAID-IN> 418,348
<RETAINED-EARNINGS> 1,469,879
<TOTAL-COMMON-STOCKHOLDERS-EQ> 2,184,334
0
0
<LONG-TERM-DEBT-NET> 1,151,973
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 440,000
<LONG-TERM-DEBT-CURRENT-PORT> 4,000
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,738,366
<TOT-CAPITALIZATION-AND-LIAB> 5,518,673
<GROSS-OPERATING-REVENUE> 3,036,028
<INCOME-TAX-EXPENSE> 82,427
<OTHER-OPERATING-EXPENSES> 2,692,623
<TOTAL-OPERATING-EXPENSES> 2,775,050
<OPERATING-INCOME-LOSS> 260,978
<OTHER-INCOME-NET> 9,694
<INCOME-BEFORE-INTEREST-EXPEN> 270,672
<TOTAL-INTEREST-EXPENSE> 87,501
<NET-INCOME> 183,171
0
<EARNINGS-AVAILABLE-FOR-COMM> 183,171
<COMMON-STOCK-DIVIDENDS> 180,461
<TOTAL-INTEREST-ON-BONDS> 86,372
<CASH-FLOW-OPERATIONS> 631,328
<EPS-PRIMARY> 1.97
<EPS-DILUTED> 2.00
</TABLE>
